CANADA

Canada's oil and gas business has had a tumultuous year. Last Halloween, the federal finance minister proposed new rules that effectively ended tax benefits previously enjoyed by Canada's ubiquitous trusts. Wage inflation from myriad oil-sands projects in Alberta thrust labor costs skyward.

Then, as rising finding costs intersected with startlingly low commodity prices, gas rig counts in Western Canada have skidded downward. Resource trusts are scrambling to reposition themselves and junior firms are struggling to hold value in the face of expensive capital and shrinking margins.

Meanwhile, the Canadian dollar has risen to heights not seen in three decades and numerous U.S. companies are shucking off their north-of-the-border assets, joining those who exited earlier this decade. And, the province of Alberta has recently announced it will revise its royalty regime, with an eye to sharply increase government takes.

Woes in western gas

Underpinning all this turmoil is the reality that the Western Canadian Sedimentary Basin (WCSB), the source of most of Canada's current production, is growing old.

The WCSB is overwhelmingly gas-prone, but average per-well productivity has been falling at an alarming rate of 7% per year. Natural gas drilling has more than tripled since 1998, but production has only managed to remain flat. A new gas well in 1996 averaged initial rates of 740,000 cubic feet per day, but a new well in 2006 averaged just 200,000 per day. Canada's gas reserve life is now 8.5 years, versus the 20-plus years it posted at the start of gas deregulation a couple of decades ago.

And it's far more expensive to extract the gas. In testimony before the Alberta Royalty Review Board in June, ConocoPhillips reported that cost differences between Canada and the U.S. have risen sharply. In 2003, Canada's costs were 14% higher than the U.S.; in 2004, they were 18% higher; and, in 2005 and 2006, 40% higher.

Of all gas produced in North America, gas from Western Canada was the most expensive. ConocoPhillips' cost to find a thousand cubic feet of Canadian gas was nearly three times more in 2006 than it was in 2003, the company reported.

When low commodity prices are layered on top of high costs and smaller well recoveries, something has to give.

"We've seen a dramatic fall-off in the last year in Canadian gas drilling, particularly in shallow horizons," says Paul Ziff, chief executive of Calgary-based research and consulting firm Ziff Energy Group. "Our operating cost analysis shows that for at least a year, for new gas, on average, the price has not supported continued investment."

Indeed, operators have voted with their checkbooks, and sharply cut spending on gas drilling. During the first nine months of 2007, rig activity dropped 30%. The Canadian Association of Petroleum Producers (CAPP) estimates that industry spending in the WCSB will be C$26.5 billion in 2007, a C$5.2-billion drop from the 2006 level. The downturn is precipitous: the Canadian Association of Oilwell Drilling Contractors forecasts that the industry will drill 6,000 fewer wells in 2007 than it did in 2006.

"It's no longer viable to focus solely on gas in Western Canada," says Bill Gwozd, Ziff Energy vice president, gas services.

Furthermore, while gas production in Western Canada has remained flat for several years, that trend will not continue. Conventional gas production is irrevocably declining, and tight gas and coalbed-methane (CBM) production are not growing fast enough to take up the slack.

From current production of 16.6 billion cubic feet (Bcf) per day, Ziff Energy forecasts that Canada's output will slide to 13.1 Bcf a day by 2015, says Gwozd.

And, although oil-sands production is projected to grow dramatically during the coming years, conventional oil production continues to slip in the WCSB. Robust oil prices have spurred close looks at oil opportunities, but conventional prospects are limited and it's very difficult for companies to make new discoveries.

A swinging door

Canadian drilling is sluggish, but property sales and acquisitions are setting a brisk pace. "We've seen a number of international companies come to Canada to acquire heavy-oil properties for their portfolios," says Mark McMurray, managing director, corporate development, at Calgary-based M&A advisory firm Rundle Energy Partners.

At the same time, quite a few U.S. companies have decided to exit Canada, pushed by the expanding Canadian dollar and sky-high costs.

It's a turnaround from a few years ago, when U.S. and Canadian companies alike were jockeying for positions in unconventional gas. As gas prices expanded, CBM and high-density developments in shallow gas became viable; even shale-gas plays were sought. A number of firms aggressively grew their positions in these unconventional plays.

"In the past 18 months, those companies have been severely hurt by retracting gas prices, and much of their investment inventory has been left stranded," says McMurray. "Their properties are marginally economic to uneconomic at $5 gas."

More assets are pouring into the marketplace from the Canadian juniors as well. These firms have suffered a crisis of shareholder disappointment, and their available capital has shrunk significantly. Their financial stress is now driving a tremendous number of asset divestitures.

The trusts have also shifted their strategies. For the past decade, they were primarily accumulators and consolidators, but now they are actively selling and merging. And the buying they do is more disciplined.

It's not exactly fire-sale time, however. "We actually see a very stable transaction market, and deals are being done at fair and at premium values," says McMurray. "There is a full blend of types of assets in the marketplace, from every area and level of maturity. Now is a good time to be a buyer in Canada."

That's apparently the same thought that drove the recent C$5-billion offer for Prime West Energy Trust by Taqa North Ltd., a subsidiary of Abu Dhabi National Energy Co. Prime West owns a mixture of conventional and unconventional gas assets, including tight gas, shallow gas in southeastern Alberta, and CBM. Some U.S. assets in the Northern Rockies are also in the mix.

Altogether, Taqa has spent $8 billion in the past year buying Western Canadian oil and gas properties, including $540 million for Pioneer Natural Resources' unit Pioneer Canada, and $2 billion for Pogo Producing Co.'s Northrock Resources. The Pioneer assets are shallow gas and Horseshoe Canyon CBM, and the Northrock portfolio included Deep Basin tight gas, CBM and a broad spread of acreage.

Indeed, companies with financial flexibility can make some very attractive unconventional purchases these days. "Resource plays in shallow gas and CBM can be acquired competitively now, as long as the buyer has the medium- to long-term timeframe to wait for a window when those investments become viable again."

State of drilling

Of course, companies are still drilling wells throughout Canada. Certain plays continue to offer attractive economics, or enough exploration promise to warrant tests.

One of the bright spots in gas drilling is the WCSB's Deep Basin play. Activity in the Deep Basin has held steady, due both to regulatory changes and lease expirations. Up until a year ago, operators were required to pressure-isolate and separately gauge each zone, so dual completions were the norm. Now blanket mingling is allowed.

Lots of companies are infill drilling, tightening spacing to up to four wells per section. Down-spacing is not regionally approved yet, but is allowed on a field-by-field basis. Furthermore, lease terms in the Deep Basin tend to be short and operators continue to drill in the face of looming expirations.

Additionally, the Triassic Montney play is rapidly migrating to horizontal completions, and exploration continues for Doig pools as well.

The Puskaw area, along the eastern flank of the Peace River Arch, is another locus of activity. This is a light-oil play in the Devonian. Activity was kicked off by a 5,000-barrel-per-day well drilled in 2005, and operators have found that prospects show up nicely on 3-D seismic.

And, two recent land sales in British Columbia have drawn attention to an emerging shale-gas play. In August, companies spent C$149.7 million, and in September they bid C$265.2 million on B.C. leases. Some of the most sought-after lands were in the Horn River Basin, where Apache Canada, EOG Resources Canada, EnCana Corp. and Nexen Inc. all have activity.

Over on the East Coast, the story of the year was the first exploratory well drilled in the Orphan Basin, some 400 kilometers offshore Newfoundland, by a Chevron-led consortium. The Great Barasway F-66 was a particularly challenging well, drilled in extremely harsh conditions in 2,400 meters of water to a depth of 7,404 meters. The well was spud in August 2006, and the rig was released in April 2007.

"It's still a tight hole, and we're waiting on tenterhooks for results from that well," says John Dunn, an analyst with energy-research and consulting firm Wood Mackenzie in Scotland. Further wells are planned in Orphan Basin, likely in 2009-10. "There's considered to be significant potential in that area."

Onshore, Corridor's McCully Field in New Brunswick has evolved into a promising project. "It's very important for the area as a whole. And in addition to what has already been found, there is deeper potential as well."

Finally, in Canada's Far North, a notable 2007 event was Imperial Oil's lease buy in the Beaufort Sea. The company, along with affiliate ExxonMobil Canada, bid C$585 million for a work program on a 500,000-acre federal offshore license. Terms call for work to begin during the coming five years.

"It's an extremely remote and challenging region, but this marks the intention of these companies to do something in the Arctic," says Dunn. Additionally, Chevron and ConocoPhillips each received licenses in the same sale.

A balanced approach

So what strategies are Canadian operators currently pursuing? Lessons can be taken from one of the perennial top drillers and producers in Canada. Devon Canada Corp., a unit of Oklahoma City-based independent Devon Energy, has a blend of projects across the WCSB.

"About two-thirds of our production is gas and one-third is oil, although our reserve base is evenly split between the two commodities," says Chris Seasons, president, Devon Canada Corp.

Devon Canada produces 160,000 barrels of oil equivalent (BOE) per day, and has proved reserves of 687 million BOE. The company's 2007 capital budget is C$1.35 billion.

"A good chunk of our investments are in gas, but we've upped our investments in oil during the last two years as pricing has shifted," says Seasons.

Devon has two main components to its oil business: thermal and cold-flow heavy oil. It also has a smaller position in conventional oil.

The company's main project is Jackfish, a thermal heavy-oil venture in the Athabasca oil sands about 140 kilometers south of Fort McMurray, Alberta. Jackfish is a 35,000-barrel-per-day project with reserves of 300 million barrels. Construction has been completed at Jackfish, and Devon will soon be circulating steam in 24 SAGD (steam-assisted gravity drainage) well pairs. Target production levels are expected in about 18 months, and bitumen will continue to be pumped at that pace for approximately 25 years. The company owns a 100% interest in the project.

On deck is Jackfish 2, a similar-sized venture that lies 10 kilometers west of Jackfish. Devon is awaiting regulatory approvals on this project, which will also produce 35,000 barrels per day. "It hasn't been sanctioned by the government, nor has it been sanctioned internally yet," says Seasons. The company hopes to receive government approval by mid-2008.

Oil-sands projects bring unique infrastructure challenges, and Jackfish is no exception. To transport its bitumen production, Devon has invested in Access Pipeline, along with 50% partner MEG Energy. The line runs from north of Jackfish some 340 kilometers to a 350,000-barrel tank farm near Edmonton to the south. It's a two-line system, with a 24-inch blend line and a 16-inch diluent line. Devon designed Jackfish to run on either condensate or crude, which gives it flexibility to change its diluent supply.

The company also produces more than 32,000 BOE per day of cold-flow heavy oil in the Lloydminster area of Alberta. This project has been a resounding success, with volume growth of more than 20% annually for the past few years. This year, Devon will drill approximately 400 shallow wells in the area, which enjoys all-season access.

"The project is very flexible, and activity can be quickly ramped up or down," Seasons says. Devon also has plenty of room to expand, as it holds more than 800,000 net acres of undeveloped leasehold in the play.

Conventional oil-some 15,000 barrels a day-is another facet of its Canadian business. Swan Hills, a 50-year-old accumulation, is its largest field. "It's late in its life, but we continue to be pleasantly surprised by the opportunities to increase recovery." Devon is expanding a hydrocarbon-miscible flood at Swan Hills, and it has also installed a pilot for a CO2 flood. Currently, the aging field makes 320,000 barrels of water per day along with its oil.

Natural gas drilling is the final column of Devon's Canadian business. "We've reduced our gas activity 10% to 15% per year each of the last two years," says Seasons, "but we still spend two-thirds of our budget on gas."

Although the company is running fewer rigs, the decrease is not due to a lack of prospects. The firm holds a four- to five-year inventory of drilling locations on its 6.3 million undeveloped acres (out of 8.4 million total acres) in Western Canada.

Rather, the pullback is due to high costs and low prices. Those high costs are starting to moderate: This year, Devon expects service costs to hold flat or even come down a bit. "It's a mixed bag: Dayrates on rigs are dropping, but labor costs are flat to rising, fuel costs are going up, and materials such as bits and mud are flat to up."

In total, Devon will drill more than 350 gas wells in Western Canada in 2007. Most of the money is flowing to the Foothills and Deep Basin plays to drill wells deeper than 2,500 meters. Targets are multiple, stacked pay zones containing sweet, liquids-rich gas.

Approximately 45 wells will develop CBM reservoirs. Devon makes about 14 million cubic feet per day from Horseshoe Canyon coals, but CBM is not a big part of its Canadian business.

"We still have decent opportunities in gas in Western Canada to make an acceptable rate of return for our investors," says Seasons. "But we have eliminated some plays or put them on hold."

Notably, Devon Canada is maintaining its position in the Mackenzie Delta in the Northwest Territories, although it has no immediate activity planned. It has held all of its acreage, and expects a federal decision on the much-delayed Mackenzie Valley pipeline near the end of next year. In the meantime, it has partnered with Talisman Energy on some exploration acreage in the pipeline corridor, not far from Norman Wells.

Overall, the company remains bullish on Canada, and would like to ramp up activity. "We're just waiting for the conditions to set up properly for us. We certainly have seen some rays of hope in pricing in the service part of the sector. Now we're waiting to see what happens with the Alberta royalty-review decisions."

Growing cash flow

For one junior Canadian firm, Western Canada provides the base from which it launches greater aspirations.

Canadian Superior Energy Inc. has an aggressive growth strategy, says president and chief operating officer Mike Coolen. Western Canada supplies the cash flow for the company, and helps fuel its high-impact exploration activities in Trinidad and Eastern Canada.

In Western Canada, Calgary-based Canadian Superior has 179 net wells and produces approximately 3,000 BOE per day. This year, it will spend about half its capital budget on its 240,000 gross acres in Alberta, half of which are undeveloped.

To date it has drilled 20 wells in its 2007 program. "We had a very long, wet spring in Western Canada, so we didn't get to do as much drilling in the first half of the year as we like to," says Coolen. "Happily, the second half of the year has been very busy."

Its Drumheller core area offers a mixture of conventional gas and CBM, and most wells are within known fields. To complement these assets, the company also drills some higher-reward exploration prospects in such areas as Windfall, Boundary Lake and Cecil.

"We certainly moderate our CBM program based on price, and we have shifted much of our Western Canada capital to higher-reward, higher-working-interest conventional prospects." The net result is a similar level of activity to last year.

Despite the well-publicized problems with Canadian costs, netbacks in Western Canada remain very attractive, says Coolen. The company has been able to keep its costs in line, and for the past three years its operating costs have averaged less than C$8 per BOE. And it's been able to post steady growth in production, on average 10% per year.

"We think the time is right in Western Canada for acquisitions, and we're looking to expand our position in Alberta, particularly in the Foothills play," he notes.

In a unique differentiator to its fellow junior firms, Canadian Superior also holds a huge position in Eastern Canada's offshore. Indeed, its 2.6 million acres (100% interest) make it by far the largest acreage-holder on the Scotian shelf.

"There hasn't been any recent exploration drilling offshore Nova Scotia, but we're anxious to get back and drill another well there," says Greg Noval, executive chairman. "We plan to spud our Mariner prospect within the next 12 months."

While the company is active in Trinidad & Tobago, and is working to acquire licenses in another high-opportunity offshore province, Canadian Superior sees outstanding potential that remains to be tapped in Canada. "But it's very important that we have royalty and taxation regimes that allow that potential to be achieved, because the economics have to work. High costs and low commodity prices can make margins too small to justify drilling of smaller prospects," says Coolen.

Expanding the oil sands

For the smallest companies, international exploration may be beyond their financial or technical resources. Canada is rich in oil and gas, however, and although the WCSB is mature, opportunities still abound.

An interesting program to expand the Athabascan oil sands across Alberta's border into Saskatchewan is being carried out by micro-cap Oilsands Quest Inc., headquartered in Calgary. The firm took the contrarian view that the oil-sands resources might have potential beyond its traditional boundaries, says Simon Raven, chief geologist.

Oilsands Quest's area of interest is immediately adjacent to EnCana Corp.'s Borealis project, which is under commercial development, and 50 kilometers west of Suncor Energy's producing Firebag project.

Since the 2005-06 winter season, the company has drilled 174 holes in Saskatchewan on the eastern flank of the WCSB. "We're right on the edge of the basin, and our exploration strategy was to find oil-sand deposits that lapped up against that edge."

Now, it's moving toward commercialization with reservoir testing and pilot-plant design under way at its Axe Lake discovery. "We have excellent porosities and permeabilities, very clean reservoir, and up to 30 meters of net pay." Cores indicate that bitumen saturations, by weight, average 14%. To date, no interbedded shales or top or bottom water have been identified. Depth to the deposit is ideal, approximately 200 meters.

This winter, Oilsands Quest will perform a reservoir field-test at Axe Lake. With the information gained from this testing, it plans to start a pilot plant for production, using low-pressure SAGD methods, including the possibility of heated-solvent SAGD.

"We have more than a township of well-defined drilling completed, and we have a high confidence in the discovered resource base of 1.5 billion barrels in place," says Raven.

In addition, the company continues to explore its more than 24 townships of lands (1,000 square miles) that lie outside the Axe Lake project. Included in that are three townships in Alberta, adjacent to its Saskatchewan acreage. The company operates as one entity, but keeps the projects separate due to differences in provincial regulations. Undiscovered bitumen resources across its lands are estimated at 10 billion barrels.

The infrastructure that Oilsands Quest has built is impressive. For this winter's drilling season, the company will operate three camps totaling more than 350 beds in Saskatchewan and Alberta, and construct 200 kilometers of roads and trails, and a main 54-kilometer road that connects its leases to a highway. It supplies all its own power and fuel, and its leases are 110 kilometers from the nearest town.

The company has two rigs working flat out at present, and this will jump to eight this winter. It already has licenses in hand for 97 holes in its fall program in Saskatchewan, and this winter plans additional drilling and seismic. It will drill up to 30 holes in Alberta.

"For a small company, we are covering a lot of ground."

Shale-gas prospects

Emerging opportunities in shale gas are the target of another small Calgary firm. Triangle Petroleum Corp. president Ron Hietala has been pushing his firm to capitalize on knowledge that has been acquired by U.S. companies pursuing shale gas.

There has always been a transfer of business and technical knowledge between the two countries. "We've seen hydraulic fracturing, horizontal drilling, application of onshore 3-D seismic and CBM projects all begin in the U.S. and then get transferred on a large scale to Canada."

Commercialization of shale gas is very close in Canada, and the people at Triangle believe that shale opportunities will prove to be even larger than those in the country's tight-gas and CBM plays. "We think there are company-making opportunities in both Western and Eastern Canada."

Triangle has shale experience, as it is currently active in the Fayetteville play in Arkansas' Arkoma Basin, and was previously in the Barnett in the Fort Worth Basin, Texas.

Although the firm is looking at projects across Canada, the first two to come together are in the Atlantic provinces.

In Nova Scotia's Windsor sub-basin, part of the broader Maritimes Basin, the company has taken a 516,000-acre farm-out, says Clarence Campbell, vice president of exploration. Triangle acquired rights to the licenses by agreeing to fulfill a previous operator's existing C$800,000-work commitment.

Triangle's interest in the area keyed off of a 1970s-vintage well that was drilled to evaluate conventional oil and gas targets. The #1 Noel displayed all of the attributes needed for a shale-gas play. It encountered a thick, organic-rich section of Upper Devonian and Mississippian Horton Bluff shale. Gas responses and density porosities were identified on log suites, and abundant gas shows were recorded on mudlogs. Total organic carbon levels obtained from well cuttings indicated desirable thermal maturity.

This September, Triangle finished drilling its first well at a location less than two kilometers from the Noel well. It cased the test to total depth of 1,330 meters and now is working on frac design. The company cored 400 meters in the basal portion of shale, ran an extensive suite of logs, and has a comprehensive rock-evaluation program under way.

At present, it is drilling its second test, a step-out of several kilometers from its first. The company has brought a completions expert onboard who has deep experience in the Barnett and Fayetteville plays. It is also shooting 48 kilometers of 2-D and 40 square kilometers of 3-D seismic across its acreage.

"As further encouragement, we've identified a seismic signature that corresponds with the shale section," says Campbell. "We think the potential is substantial."

Nova Scotia has proved to be a pleasant place to work. The government people are friendly and energetic, and are motivated to help operators have success.

Furthermore, with four or five operators now busy in Nova Scotia and New Brunswick, services are much easier to come by than in the past.

"Companies work cooperatively, and we've been able to fit our program into windows of availability," says Andy Prefontaine, Triangle land manager. "The slowdown in Alberta has helped us also. There's new attention in Eastern Canada, and we're seeing reasonable, competitive rates."

Of course, one of the most attractive aspects of the region is its proximity to major natural gas markets in the Northeast U.S. Triangle's acreage block is just 48 kilometers from the Maritimes & Northeast Pipeline, which runs through Nova Scotia and New Brunswick and down into the U.S.

"Our initial results are encouraging," says Hietala. "We hope to start a development program in 2008."

The company has a second shale project in the Moncton/Sackville sub-basin in New Brunswick, also part of the greater Maritimes Basin. It farmed into 70,000 acres in the area around Stoney Creek Field, not far from Corridor Resources' McCully project. Triangle is watching Corridor's work in the Frederick Brook shale at McCully with interest, and is currently researching the area.

"We have hundreds of meters of shale in New Brunswick, and we're doing rock work, collecting samples and interpreting a 2-D seismic program which we have access to," says Campbell. Next year it plans to drill its first well in that province.

So, across the vast stretch of Canada, companies are realigning their portfolios, rearranging capital spending and striving to trim costs. And, for those that are financially limber, there are promising new ventures that beckon.

The ground-floor truth is that Canada's exports of oil and gas, both conventional and unconventional, are sorely needed on the world market. It's only a matter of time before gas prices push back upward, as declining supply and growing consumption will inevitably demand.

ANGST IN ALBERTA

Alberta is Canada's powerhouse producer, and it supplies the lion's share of Canada's total energy production. But oil and gas companies are facing some stiff jumps in royalty payments. The provincial government requested a review of Alberta's royalty system, and the panel charged with the task recommended hefty increases for all types of resources.

The panel proposed changes to Alberta's royalty structures that included raising oil-sands royalties after payout of costs from 25% to 33%, and applying a sliding scale of volume and price to natural gas and conventional oil wells, with a maximum royalty rate of 50%.

Notably, the panel recommended against grandfathering existing projects; it said all provisions should apply to all participants at the same time.

The conclusions of the royalty-review panel shocked the industry. The scale and comprehensiveness of the recommendations were beyond any scenarios that had been anticipated.

Most participants expected a hard look at oil-sands developments, but there was widespread surprise at the royalty increases proposed for conventional oil and gas production.

A recent analysis by energy investment-banking firm Tristone Capital Inc., Calgary, takes issue with many aspects of the panel's conclusions: "The disincentives created by the royalty regime will see Alberta lag in competitiveness relative to other jurisdictions and capital will flow out of the province."

The royalty panel's report manhandled the beloved industry yardstick of rates-of-return, mainly by understating capital and operating costs, Tristone contends. Additionally, the method of structuring gas-well royalties will have the net effect of removing incentives to drill deeper, higher-deliverability wells.

The provincial government planned to make its decision on the panel's recommendations in late October. At last report, regulators were considering more evidence and reviewing the analysis again.

There are a number of companies-especially oil-sands companies-that will take a significant hit in terms of absolute value if the current recommendations are implemented, says Andrew Strachan, head of Wood Mackenzie's new Calgary office.

"Projects are now facing extra royalty charges, in addition to high acquisition, service and labor costs. However, the proposed changes to conventional gas projects may have more of a profound impact across the board, as already tight margins will be further squeezed for large and small E&Ps alike, rendering many of the province's gas plays uneconomic."