With a softening of the U.S. market for natural gas, many in the business are wondering if plans for increased Canadian supply will weaken as well. Executives and observers are united in their belief, however, that deeper discoveries in western Canada will allow the country to at least continue to supply abut 15% of U.S. daily gas demand. Additional supply may be awhile. "If you look at the West Coast and Arctic regions' potential to add significant reserves and production, it will take two decades for this to occur, with the Northwest Territories five years away," says Ernie Sapieha, chief executive of Calgary's Compton Petroleum Corp. "If you look at the East Coast, although currently producing, it will probably be 10 years away from full ramp-up, due to limited infrastructure. I think the Western Canada Sedimentary Basin is going to play a more and more important role in the next five years in terms of incremental growth profile." The outlook for the Canadian gas industry in 2002 was the central focus of a recent Calgary conference organized by consulting firm Ziff Energy Group. A broad range of perspectives from producers, marketers and end-users was presented, yet a few themes were constant when predicting how the year will turn out. The biggest question-Will production grow in 2002?-is double-ended, involving price and geology. A six-month slump in gas prices, where spot deals at the AECO-C trading hub in southeastern Alberta briefly dropped below C$2 per gigajoule in October, showed up in declining rig counts for much of the fall. With producers such as Rio Alto Exploration Ltd. and Canadian Natural Resources Ltd. vowing to limit capital spending during the traditionally busy winter drilling season, it's likely that Canadian gas production will fall this year because of high decline rates from existing fields. "If you look at what the industry is trying to do in just backfilling decline, my personal view is that once the effect of Ladyfern is felt, then it's going to be difficult to grow production in Canada without new big discoveries," said Jim Emme, vice president of exploration at Anadarko Petroleum Corp. and former president of the firm's Canadian unit. "I think a lot of companies will be struggling just to keep production flat. It's going to take some breakthrough plays by individual companies, such as continued success in the frontiers or Deep Basin, for Canada as a whole to grow production." Emme says finding new reserves that more than offset decline rates, estimated at 25% to 30% annually for new holes, will make it difficult for Canadian production to continue to climb. Also sanguine about the prospects of more gas heading south of the 49th parallel in 2002 and following years is one of the most informed but impartial observers of the Canadian energy industry. Ken Vollman, who chairs the National Energy Board after spending nearly three decades with the federal regulator, says gas-directed drilling in Canada doubled in the early 1990s to 4,000 wells per year, increasing deliverability by 30%. More recently, gas drilling has doubled again to 8,000 wells per year, yet production increased only 10%. Producers will be hard-pressed, especially if soft prices persist, to increase output from the expected 2001 rate of 17 billion cubic feet (Bcf) per day, he says. Marketable production in 2000 averaged 16.3 Bcf a day. "There is more gas to be found in the Western Canada Sedimentary Basin but it is in deeper and more complex plays," he says. "Most of the remaining gas must be exploited from smaller and smaller pools, so it will be more expensive and take longer to develop new supplies. In a volatile and uncertain gas-price environment, the challenge to increase gas supply has become greater." Gary Morsches, senior vice president and chief executive of the eastern division of Mirant Americas Inc., noted a major difference between 2002 and last year when it comes to prices is the absence of lucrative arbitrage opportunities to convert gas into electricity. "We've seen spark spreads-the difference between the sale price, your power output and your fuel input-come down 40% in the last few months and that's really from the forward curve dampening out," he explains. "That driver is not there because there is not the economics right now for people to go in and arbitrage plant costs, build a plant, lay out the first few years and guarantee a big return." If prices languish Another big difference is the faltering economy, hit hard by the terrorist attacks of September 11. Experts question whether the estimated 3- to 6 Bcf a day (depending on the source) lost because of demand destruction and fuel substitution will come back. Weak oil prices-the result of a spat between Russia and OPEC members over production cuts to prop up crude values-could put a cap on any rally in gas prices. "Somewhere in the $2.50 to $3.50 per million Btu range is where most people see prices reverting to in 2002. But the fluctuations from that level could be significant and I think we all have to get used to that volatility," says Anadarko's Emme. Compton's Sapieha believes keeping a lid on service costs, which took double-digit jumps last year, will be particularly important in 2002 if gas prices continue to languish. How much the economy recovers this year will be key to gas prices, which he hopes will average C$3.75 to C$4 per gigajoule at the AECO-C. "If you take off C75 cents for royalties, that leaves C$3," he says. "If you've got C60 cents in operating costs, that leaves a producer with a healthy C$2.40, which is big dough. If prices are around C$3.75, it will be a good year." With commodity prices this year expected to be about 30% or 40% lower than 2001, drilling activity will decline, helping to boost gas prices in the second half due to reduced supply. However, Sapieha notes that bulging storage inventories-which hit a record 3.13 trillion cubic feet (Tcf) in late November in the U.S.-and a mild start of winter could mitigate the effect on prices that dwindling production and lower drilling on both sides of the border will have. While Morsches avoids predicting prices, the recent contango behavior of Nymex futures, where forward strips for 2003 and 2004 are higher than the current year, indicates prices will rise in 2002. Like Emme, he believes volatility will be high and contribute to big swings in prices. Morsches expects to see some signs this year of changes in seasonal pricing patterns. The increased consumption of gas for power generation is altering the use of storage, with peak power demand spelling an end to the custom of injecting gas into underground caverns in the summer and fall and pulling it out in the winter and spring. "You are going to see increased shoulder-period injections and you're not going to be able to inject in the summer because it will be needed to meet peak demand," he predicts. "It's going to magnify seasonality out there and it's certainly going to continue to drive price volatility." Shallow wells While LNG and northern gas supplies are still years away from affecting markets and prices, coalbed-methane pilots in Canada will pick up speed in 2002. But most players see the nonconventional gas as the wave of the future and not affecting the tides of supply and prices this year. Depending on who's doing the estimating, CBM reserves in western Canada have been pegged at 300- to 3,000 Tcf. The potential is too big to ignore and PanCanadian Energy Corp, for example, is participating in a C$30-million program involving 112 wells. The joint venture with partner MGV Energy Inc., the Canadian subsidiary of Quicksilver Resources Inc., hopes to make a decision this year on whether a commercial project is viable. While CBM may be the future, PanCanadian's present includes a heavy focus on shallow gas in Alberta and plans to expand into Montana. Terry Schmidtke, general manager of PanCanadian's Great Plains business unit, says Upper and Lower Cretaceous formations in southeastern Alberta will continue to play an important role in supplying Canadian and U.S. markets. In this region, daily volumes in wells can drop 40% in the first year from 100,000 cubic feet per day before stabilizing at a much smaller decline and allowing years of low output. Still, it contributed more than 1 Bcf a day to provincial supply in 2001. Schmidtke says there is plenty of opportunity left in a region where well maps make a full pincushion look roomy. "In southern Alberta south of Medicine Hat, we see that as an untapped area," he explains. "If you look at [that area], there is not a lot of wells in it. We see that as a huge opportunity with 3- to 5 Tcf of shallow gas that can be brought forward. We really think that's going to have a significant impact on supply." His optimism is based on PanCanadian's success in expanding its prospects beyond the usual suspects of the Milk River, Medicine Hat and Second White Specks. The formations are generally found 500 to 3,000 feet below the dry plains of southern Alberta. Improved technology, better commodity prices and increased awareness of bypassed pay are giving appeal to "supershallow" formations such as the Bearspaw, Dino Park, Foremost and Belly River of the Upper Cretaceous. The firm often develops shallow volumes in combination with deeper Viking and Glauconite production, getting more bang for its drilling, completion and tie-in bucks. The wider selection of targets is allowing a geographic expansion for PanCanadian, which has worked aggressively to lower costs by using a cookie-cutter model to bang down holes cheaply and quickly. "You could run that reserve potential down into northern Montana because the Western Canada Sedimentary Basin doesn't stop at the Canadian border, so there are opportunities even going much farther south," Schmidtke says. This year, PanCanadian expects to drill 900 to 1,000 shallow wells in Montana and southern Alberta. Schmidtke says increased pipeline capacity to out-of-state markets is needed to prevent a glut from hurting the economics of any Montana production. This means it could take several years before increased volumes from the state start affecting supply-demand fundamentals on a wider scale, especially if PanCanadian has success and is followed by other companies. Larger prizes While PanCanadian is big on small wells, many other firms will be looking this year for larger prizes found in the deeper and more complex plays of northwestern Alberta, northeastern British Columbia and the Northwest Territories. Ladyfern in northeastern British Columbia is a Slave Point-Keg River discovery that added about 450 million cubic feet of daily production in the first half of 2001. It demonstrates the potential of new supplies coming from deeper formations, says Emme of Anadarko. "If you look at this part of the basin, there is only one Slave Point penetration for every 100 square kilometers, which is about one U.S. township or 36 square miles," he says. "The area is very much underdrilled and continues to yield big discoveries." But access to land in northern British Columbia, where unhappy native bands have blockaded several projects to protest land-claim disputes, remains a wildcard and could disrupt exploration and development programs this year. Anadarko was one of many U.S.-based E&P firms to scoop up Canadian firms or assets in the past two years. The buying frenzy reshaped the Canuck oil patch more than a chocoholic on a strict diet, but Emme does not see the intense grab for gas assets repeating in 2002. "I think you'll see more consolidation. There will be fewer but bigger deals," he says. The pending merger of Phillips Petroleum Co. and Conoco Inc., announced last November but expected to close this year, shows Emme's prediction is already coming true. Compton's Sapieha says consolidation last year created a pool of experienced and talented executives in Canada who are looking to start over. Divestitures by buyers rationalizing assets, such as Devon Energy Corp. after swallowing Anderson Exploration Ltd., could create good foundations for new firms. "Acquisitions by themselves are not going to grow the supply of gas and oil. I think it's what you do with the undeveloped acreage and drilling," he says. "The way that supply is going to increase is from significant drilling programs...and smaller companies, once they get going, do contribute a substantial amount of exploration drilling." While forecasts for 2002 are about as clear as a Jackson Pollack painting, the National Energy Board's Vollman offers one prediction that is probably as close to a sure bet as anything these days in the energy industry: "If we combine this supply-demand behavior and prices, where there is a lag in the supply response and there's a quick response in demand, I believe we have a market that is inherently volatile."