BRITISH COLUMBIA

British Columbia offers the oil and gas industry one of the most favorable places left to explore in North America. The province is far from mature, and it presents a wealth of opportunities in both conventional and unconventional plays. It even hosts the possibility of offshore exploration. Last year was exceptional: 1,041 wells were drilled in British Columbia, an all-time high and a remarkable surge from the 643 drilled in 2002. The industry's capital, operating and royalty expenditures during 2003 hit C$5.6 billion, another provincial record, and British Columbia produced 1.1 trillion cubic feet (Tcf) of natural gas and some 16 million barrels of oil from 4,500 wells. Oil and gas account for an ample slice of British Columbia's economy. In 2003, the industry supplied C$2.1 billion to the province, roughly 8% of its total revenues. A great number of jobs, both direct and indirect, are tied to oil and gas. And, natural gas is a major export. The province, home to 3.9 million people, consumes about 35% of the gas that it produces and sells the remainder to the U.S. and Alberta. Once considered a difficult place to drill by operators, British Columbia has made a remarkable turnaround in recent years. Premier Gordon Campbell has stated that he intends to make British Columbia "the most competitive jurisdiction in North America for oil and gas investment and development." Indeed, broad reforms have been sweeping the province. Personal and corporate income taxes have been cut, the corporate capital tax has been eliminated, red tape has been reduced, and an energy plan has been developed. Specific actions directed at the industry include the formation of a single-window Oil & Gas Commission, the elimination of the provincial sales tax on oil and gas machinery and equipment, the creation of an offshore oil and gas team, and the development of a heartlands oil and gas strategy. "There are all kinds of business opportunities available in British Columbia in the oil and gas industry, from seismic to drilling to production to processing plants," says Minister of Energy & Mines Richard Neufeld. "We're the only province in Canada that has increased our in-place supply during the past several years. That has caught the eye of industry. The resources in British Columbia are a little more costly to develop, but the returns are great. We are definitely underdrilled." Indeed, British Columbia is immense. Far larger than Texas, it holds total estimated resources of 18 billion barrels of oil, 110 Tcf of conventional natural gas and 90 Tcf of coalbed methane (CBM). But the only part of the province that has been developed for oil and gas is its northeast corner, and that's where its entire infrastructure lies. The challenge the province faces is luring companies into its vast interior basins, prodding them into looking for commercial CBM deposits, and encouraging them to drill deeper and for unconventional resources in its established producing areas. Furthermore, the province would like to open its offshore areas to exploration. Currently, there are provincial and federal moratoria in place that prohibit offshore activity. "We have a potential of 10 billion barrels of oil offshore, and 42 Tcf of natural gas, and we're actively working in the ministry to get the moratoria lifted," says Neufeld. "By 2010, we'd like to see something serious happening offshore, to see more activity in the interior basins, and to see increases in our production numbers and in-place supply numbers. "We expect to continue to have a vibrant oil and gas industry in British Columbia." Major changes Although it's difficult to separate the effects of higher commodity prices from that of an improved business climate, clearly drilling activity is surging and interest is strong. The changes in the administration of oil and gas activities have been widespread and sweeping. British Columbia has created a one-window agency to handle its regulatory affairs, it has instituted a results-based system, and it has undertaken an intensive deregulation effort. The province created its oil and gas commission in 1998. "The commission was given power that was previously under 16 different pieces of legislation to deal with oil and gas," says Derek Doyle, oil and gas commissioner. "That makes an enormous difference to industry. Instead of having to go to seven or eight government agencies to get a well permit, a company now goes to one place and everything is attended to." Indeed, aside from the Commission, the only agency a company has to interact with is the province's Workers Compensation Board. The impact of this approach has been significant: the average time for a permit review has dropped from 56 calendar days to 28 days. The Commission has also adopted a flexible, results-based approach. For example, if an operator is constructing a stream-crossing, instead of mandating specific setbacks and techniques, the commission gives the company the goals of protecting the fish habitat, the riverbanks and the riparian habitat adjacent to the stream. "The companies know how to meet these goals using best practices." Additionally, the Commission is steadily alleviating the regulatory burden. It has already reduced the number of in-place regulations by 36%, slashing them from 7,338 in 2001 to 4,688 at present. "Our overall vision is that we want to be the innovative regulatory leader on this continent in terms of oil and gas." As part of this effort, the Commission receives advice from eight industry committees that cover every aspect of the regulatory process. "They give us advice on what we can improve and how to improve it. So far, we've implemented 80% of their recommendations." For U.S. companies working in British Columbia, one of the greatest challenges lies in understanding the differences between the two countries, says Doyle. "The founding principals of the U.S. are life, liberty and the pursuit of happiness. In Canada, our founding principals are peace, order and good government. We tend to solve the same problems in very different ways." Case in point: instead of the U.S. process of preparing environmental impact statements on federal lands as projects are proposed, land-use planning is done in advance in British Columbia for all resources. The land and resource-management plans outline areas that can be drilled for oil and gas and what the basic rules are for each. Once a plan is adopted, litigation is virtually nonexistent. However, Canadians are also accustomed to being consulted, and industry is required to confer extensively with private landowners and aboriginal communities. "Companies have to be in line with the culture and the community in which they are endeavoring to operate. We promote prosperity through unity, and that's what we put our attention to on a daily basis." The productive northeast All of British Columbia's conventional oil and gas production flows from the northeastern portion of the province, the slice of the Western Canadian Sedimentary Basin that extends westward from Alberta. Although companies have been drilling in northeast British Columbia for decades, the region only hosts about 17,000 wells, as compared with some 220,000 wells next door in Alberta. To date, some 30 Tcf of gas has been discovered in northeast British Columbia, and up to 50 Tcf of undiscovered potential remains. Ten years ago, the province produced about 2 Bcf of gas per day; during 2003, it was producing 3 Bcf per day. Oil production is relatively minor, amounting to about 45,000 barrels per day, mainly from shallow Cretaceous and Triassic sediments. This year is shaping up as another banner year for British Columbia. "We anticipate about 1,300 wells will be drilled this year," says Mark Hayes, the ministry's manager of petroleum geology. "That's not a lot of wells compared to many other areas, but the average British Columbia well has initial production rates of 1 million cubic feet per day and is deeper than 1,000 meters." The province offers something for all tastes, from regional, tight-gas resource plays to high-impact, high-deliverability prospects to vast frontier areas replete with undrilled structures. Tight gas plays British Columbia overflows with an abundance of tight-gas reservoirs. These low-quality rocks have only recently been coaxed into commercial production, thanks to the combination of engineering advances and high commodity prices. Today, tight gas dominates activity, and EnCana Corp. is one of the major operators. The Calgary company has two multi-Tcf plays under way, at Cutbank Ridge in the Deep Basin and Greater Sierra in the Northern Plains. "We made our move into British Columbia in a big way a few years ago," says Mike Graham, president of EnCana's foothills and frontier division. "We work very closely with the Ministry of Energy & Mines and with all the producers." In the past, operators shied away from British Columbia because of regulatory concerns, the cost of doing business in the province and the lack of an established service sector. "Things have changed, and all the initiatives have really helped the industry." Today, EnCana is the largest landholder in British Columbia, with 4.5 million net acres. "In 2005, we're predicting our gas production in British Columbia to be a little more than 500 million cubic feet per day gross. In 1998, we produced less than 10 million cubic feet per day. It's been a huge growth area for us." The Cutbank Ridge project, southeast of Fort St. John and continuing across the provincial border with Alberta, targets the Lower Cretaceous Cadomin sands. The Cadomin is found at 2,100 to 3,000 meters, and is considered a basin-center gas accumulation. Here, the company is producing 41 million cubic feet per day, net to EnCana after royalties. During 2004, it expects to drill about 60 wells, all horizontal, and in five years it projects it will have 375 wells producing 300 million cubic feet per day. The entire play has the potential to produce an astonishing 4 Tcf. EnCana's other major British Columbia play is Greater Sierra, east of Fort Nelson. One of the largest regional resource plays discovered in Western Canada in the last decade, Greater Sierra is a carbonate platform play in the Upper Devonian Jean Marie. Currently, EnCana is producing about 250 million cubic feet of gas per day, net after royalties. The company estimates that Greater Sierra also contains more than 4 Tcf of resource potential. This year, it expects to drill 190 horizontal wells there. The targeted royalty program to encourage summer drilling has been particularly successful in Greater Sierra, notes Graham. EnCana has been running a year-around drilling program, using wood mats on the muskeg during the summer. "We find that we can actually drill the wells more cheaply in the summer, and we're a big proponent of the service-sector strategy and the summer royalty incentive." Last year, EnCana drilled just over 300 wells in British Columbia. This year, it will drill 400 to 450 wells, and it expects to maintain that pace for the next four to five years. "We have many, many years of drilling on both programs." Another interesting play is developing in the same area. Penn West Petroleum, also of Calgary, has been drilling vertical wells in the Mississippian Debolt along a subcrop trend. During the 2003 winter season, the company drilled 48 wells in its Wildboy area, of which 35 were vertical Debolt wells. The remaining 13 were horizontal Jean Marie tests. This winter, the company expects to drill another 40 wells into both zones. Calgary-based junior Duvernay Oil Corp. has its own tight-gas play in development, this one in the Triassic Doig in the Groundbirch area on the flank of the Peace River Arch. Duvernay holds 67 sections of land in the sour-gas play. "We've made a relatively large tight-gas discovery, and we expect to drill 30 wells a year for the next several years," says Mike Rose, president and chief executive officer. As defined by seismic, the Doig trend appears to be 80 kilometers long and three kilometers wide, and could eventually support more than 260 wells on spacing of four wells per section. "The reduced royalties on lower-rate wells certainly help the exploitation of tight-gas plays," he says. "Of course the better commodity prices are crucial. The combination gives us more of the column and a larger cut of the suite of plays that can be economically pursued." Companies do have to understand the limitations of the gathering and transmission system in northeast British Columbia, he notes, because there aren't many options. And, companies have to work hard to keep their operating costs down. That said, British Columbia certainly holds potential for more sizeable discoveries in basin-center gas and in deeper Paleozoic objectives. "I actually think there is a lot more gas to find." Shallow Cretaceous tight-gas plays are another area of growth in the province, says Hayes. The Spirit River Group is above what normally produces in the northeast, and it was traditionally bypassed. Today, more than 100 wells have been drilled to the Notikewin formation in the Fort St. John area. "There is huge upside potential in the shallow Cretaceous." Canadian Natural Resources Ltd. is the main driller in the Notikewin play. The company, which holds 1.6 million acres of net undeveloped land in the province, recently announced that it had identified up to 450 locations in the extensive play, which it said holds potential of about 400 Bcf. Conventional exploration British Columbia also offers operators significant, high-impact potential in conventional plays. One popular area is the Foothills play, which runs along the Rocky Mountain front on the west side of the basin. Since January 2003, 47 wells have been drilled in the Foothills, says Hayes. "A lot of structures are defined in the shallower Triassic Baldonnel section, and companies are starting to drill deeper on those structures." Dynamic Oil & Gas, the only exploration and production company headquartered in Vancouver, British Columbia, has been active in the Foothills at its Cypress/Chowade area, about 100 kilometers northwest of Fort St. John. The company is working with Starpoint Energy. Dynamic has participated in 10 wells in the area, and plans to drill several more development wells this year, including a reentry. "We are in a remote area, so operating costs are high. But we have been making use of the summer-drilling royalty incentives," says Wayne Babcock, president and chief executive officer. Its present focus is on improving its marketing options. "We have a 30-million-a-day gas plant in the budget, and we're looking at other possibilities, such as laying a pipeline to another facility." The government of British Columbia has been very sensitive to encouraging the industry, he says. Such changes as the streamlined permits and targeted royalty programs have been positive, and Dynamic would also like to see the government take further steps to develop more of a grassroots oil and gas industry in British Columbia. "The province needs the head-office jobs as well as the service-sector jobs," he says. "Exploring in British Columbia is like exploring in Alberta in the 1950s, except that we are using 21st century techniques. The big discoveries are going to made in British Columbia." A Foothills area that is expected to generate strong interest in the future is the Muskwa-Kechika, a 6.4-million hectare Management Area that lies west of Fort Nelson. Land-use planning was recently completed on the vast area, sometimes called the Serengeti of the North. Certain portions will be open for exploration, says Hayes, and the eastern part appears to have excellent potential. "There are existing pools and structural trends that are fairly well defined to the south, and the disturbed belt runs right into Muskwa-Kechika. It's a huge, virtually unexplored area." To date, 20 tenures have been sold and seismic programs are beginning. Interest is also growing in British Columbia's portion of the Liard Basin. High-rate, high-volume discoveries were made in the Foothills trend in hydrothermal dolomites in the Nahanni formation on the west side of the basin in the late 1960s, says Warren Walsh, senior petroleum geologist. In 1999, operators started finding Devonian Nahanni reservoirs on the east side, in the Northwest Territories portion of the basin. Other efforts are directed at fractured Mississippian carbonates and Permian cherts, found in conjunction with deeper Nahanni reservoirs. "There's been no recent activity looking at those reservoirs in British Columbia, and we see significant potential here." Finally, the hydrothermal dolomite plays similar to the 650-Bcf Ladyfern discovery in the Northern Plains are still of interest. Although the spurt of activity after Ladyfern has abated, a number of smaller discoveries were made and a number of embayment edges with good potential remain untested, says Hayes. Interior basins For those explorers with a true taste for the wilds, British Columbia's interior basins are high-risk areas that are remote from the province's infrastructure. Nonetheless, they are estimated to contain resources of some 18 Tcf of gas and 8 billion barrels of oil, and the province is keen to generate some activity. The major basins-the Bowser, Nechako and Whitehorse-are joined by a series of smaller Tertiary basins. "The interior basins have been overlooked," says Filippo Ferri, senior petroleum geologist at the ministry. "We're trying to raise the profile of these basins and attract industry interest." The rugged Bowser Basin is most intriguing. Only two wells have tested the 65,000-square-kilometer basin, both drilled more than 30 years ago. The basin is home to some whopping structures, and recent work has refined understanding of its thermal history. Now, much of the northern portion of the basin is thought to lie within the oil and gas window. The Nechako Basin, to the south, lies in the interior lowlands of the province. This basin, encompassing 75,000 square kilometers, has extensive surface volcanics. To date, it has been tested by only a dozen wells. Oil stains and gas shows were encountered, and potential source rocks have been identified. "The southern part of the basin has the greatest potential," says Ferri. It enjoyed a flurry of interest between 1980-86, when Canadian Hunter drilled six wells and acquired more than 1,100 kilometers of seismic and 5,000 kilometers of gravity data. The basin's attraction includes its proximity to natural gas transmission lines and its sizeable structures. To swing attention to its remote basins, the province is undertaking a new resource assessment, revamping its royalty structure, and proposing to supply funds for geophysical work, says Ferri. CBM potential The province's greatest estimated resource, and the one with the most questions attached to it, is CBM. "British Columbia has a long history of coal development and coal production, but coalbed gas is a new kind of development," says Mary Coward, senior project manager at the ministry. With its passage of the Coalbed Gas Act, the province confirmed that gas found in coal seams is regulated by the Oil & Gas Commission. The ministry has taken the first steps to attract industry by assessing the resource and making technical information available to companies. "We have been setting the stage." As yet, there are no commercial projects in British Columbia. During the past five years, approximately 40 CBM test wells have been drilled and presently one pilot project is under way in the southeast part of the province. "If you look at the province as a whole, you come up with a very large resource, in the range of 90 Tcf," says Barry Ryan, coal and CBM specialist. "It remains to be seen what portion of that volume can ever be recovered." About 60% of the province's coal lies in the east, where coalfields follow the Rocky Mountain chain, crossing and recrossing the border between British Columbia and Alberta. East of the disturbed belt, centered on Fort St. John, lies the immense Peace River coalfield. Northeast British Columbia has enjoyed the most CBM activity. Lower Cretaceous coals in the Gething formation have been prospected by such operators as Peace River Corp., based in Baton Rouge, Louisiana; Koch Exploration; EnCana Corp.; BP Canada, in partnership with Devon Energy Corp.; Talisman Energy, in partnership with Dallas-based CDX Gas; and Burlington Resources. The East Kootenay coalfields in Elk Valley in the extreme southeastern corner of the province have also been a focus for prospectors. Two pilot projects have been developed by EnCana, which has drilled 17 wells and is still pumping one of the pilots. In the same area, Shell Canada has said that it plans a four-well pilot in the future. In general terms, many of the early CBM pilots in the province targeted areas with thick coal sequences. "These pilots tended to be in the Foothills, where the coal is fairly deformed and, in some instances, seams are stacked," says Ryan. These areas are in compressional regimes, and operators found that, although the coals were thick and the gas contents impressive, the permeabilities were erratic and their distributions were poorly understood. Now, as knowledge of the intricacies of CBM production has grown, companies are looking for very particular geological situations. The interior basins in the center of the province have benefited from this new approach. These basins contain a number of Cretaceous and Tertiary coalfields. There is currently exploration in the Princeton area, where PetroBank Energy & Resources Ltd. has been focusing on the Similkameen coalfield. The company has taken 37,000 acres of leases and has drilled three test wells to determine coal quality. It has also completed a 125-kilometer, 2-D seismic program. Shortly, it expects to kick off a pilot program of between one and five wells. Another high-interest project is under way in the Klappan and Groundhog coalfields in the Bowser Basin, where Shell Canada is drilling a four-well program in Lower Cretaceous anthracite coals. Lastly, there is a fair amount of undisturbed Upper Cretaceous coal underlying the eastern side of Vancouver Island. The area had seen some exploration, but work was held up by a complex ownership situation. Vancouver Island is one of the few areas in the province where there are privately held oil and gas rights. "That situation is basically sorted out now, and I expect to see some exploration there next year," says Ryan. To encourage activity, the provincial government has crafted a competitive, CBM-specific royalty regime and a C$50,000 royalty credit that can be applied to each well, notes Coward. Large blocks of Crown gas rights are still available for purchase in areas prospective for CBM. Rolf Schmitt, project manager, has been heavily involved in public outreach on the impacts of CBM development. "We are putting a lot of effort into working with communities. We are seeing concerns in areas outside of the northeast, where there has not been previous oil and gas development." The challenge is to deliver accurate information and to engage the communities in discussing and understanding that information, he says. Communities' responses to proposed projects are mixed: "There can be some very strong opposition, and a lot of fear and apprehension. At the same time, there are many people who want the economic benefits the projects can offer." The offshore question Much the same issues confront the ministry in its drive to lift the federal moratorium on offshore oil and gas activity. The federal ban on offshore work has been in place since 1972, when it was instituted to curtail tanker traffic from Alaska down through western Canada's inside waters. British Columbia weighed in with its own overlapping moratorium in the late 1980s. Drilling and development are allowed off all of Canada's other coasts, however, including the fragile waters of the Beaufort Sea and even in the Great Lakes. In 2001, when Premier Campbell's administration took the reins of British Columbia's government, it began to look at the possibility of offshore oil and gas development. The province initiated scientific and technical reviews, and solicited community views about potential offshore development. "The province has concluded that there is no basis for continuing the moratorium," says Ross Curtis, assistant deputy minister. As a result of the decades-long ban on exploration, just 14 wells have been drilled and 30,000 kilometers of seismic have been acquired in the province's offshore. The Queen Charlotte Basin is 80,000 square kilometers in size; the Winona and Tofino basins encompass 41,000 square kilometers. Prior to the federal moratorium, much of the offshore was leased under exploration permits to firms such as Shell, Petro-Canada and ChevronTexaco. These rights have been suspended, and would be renegotiated if activity were allowed in the future. The benefits from a successful development of an offshore oil and gas industry would reach far into the province, says Curtis. Government revenues would increase, local and provincial employment opportunities would grow, new energy- and technology-intensive businesses could be attracted, and infrastructure would be enhanced. And, Canada's domestic energy supply could be fortified. "We've been looking at jurisdictions around the world, and how best to employ an offshore oil and gas industry in this province," says Steve Simons, communications director, offshore oil and gas team. "We've been working with coastal communities and interested stakeholders, primarily on education." The province is very concerned that First Nations and coastal communities benefit from any offshore development. To date, 45 communities in British Columbia have passed resolutions in support of lifting the federal moratorium. "We're right smack in the middle of the coast of British Columbia, so the offshore affects us no matter what happens," says Harry Mose, mayor of Port Hardy. The community of 4,800 people on the northern tip of Vancouver Island is very dependent on resources such as forestry and fishing, along with tourism. Among residents of Port Hardy, the interest is strong in lifting the moratoria and gathering more information. "We want to make an informed decision down the road on what we would like or not like to do." Certainly, Port Hardy has a wonderful environment, and its citizens are intent on looking after it. "At the same time, the general feeling is that the offshore is another resource that we can work with and still maintain the environment that we have here." Assuredly, the belief that resource development can exist in harmony with environmental values-and also be an engine for social progress-is widespread throughout British Columbia. That's the key message that the province is broadcasting to the rest of North America. STRATEGY In January 2003, British Columbia's premier, Gordon Campbell, Minister of Energy & Mines Richard Neufeld and others met with the Canadian Association of Petroleum Producers. The group composed an action plan, which resulted in the province's Oil and Gas Development Strategy. "The strategy has four pillars: roads, royalties, service sector and regulations," says Cameron Lewis, executive director of the ministry's oil and gas policy branch. The province has a vision for comprehensive improvements of the infrastructure, primarily in northeast British Columbia. Road improvements can provide better access to the resources, lower operating costs and allow a longer drilling season. The province has a royalty credit program, under which producers that have built resource roads can receive royalty credits up to 50% of the cost. "Just short of C$30 million has been approved so far, and the ministry is looking at getting approval for another C$30 million for 2005 and 2006," Lewis says. Under its service-sector strategy, the province is identifying the elements that are helping or hindering the growth of the service industry in northeast British Columbia. The ministry launched a study into procurement practices and procedures. It is also working on a marketing strategy for the provincial service firms, to help companies develop appropriate marketing campaigns. Furthermore, the ministry and industry are jointly funding a skills-development program. "The government has come to the table with C$500,000, which industry has matched, to put towards skills development in British Columbia's educational institutions." Around a dozen projects have already been funded through this program. The royalty program is aimed at encouraging deep exploration and marginal plays, expanding the drilling season into the summer months, and opening opportunities in unconventional resources and new basins. The terms of the programs vary, but are designed to encourage many types of work by granting royalty credits. Finally, regulations are being streamlined. Rules are being integrated and consolidated, with an emphasis on results rather than bureaucratic processes. The results to date have been gratifying, most particularly in the push for summer drilling and in marginal wells. "In the first year, summer drilling jumped 127%. It dropped by 4% the second year, but clearly we're at a new level for summer drilling." The drilling of marginal wells-most of which are tight-gas wells-has exploded, and these now comprise 60% to 70% of the total wells drilled in British Columbia. In the service-sector arena, 80 new businesses were opened last year in Fort Nelson, a town of 7,000 people that is an oilfield-service hub for the northeast. The ministry is still developing its unconventional royalty plan, which will likely be a net-profits regime. It expects to unveil this strategy during the next several months, and it has already received 11 industry proposals. "It's been an exciting year. We're working to increase activity, profits and royalties. We run on a much more entrepreneurial model than a lot of governments, and these programs are good for industry and good for British Columbia," says Lewis. AVAILABLE LAND One of the attractions of working in British Columbia is that the province owns 95% of the oil and gas rights. The government offers licenses and permits to the private sector to explore for and produce oil and gas. Companies can participate in monthly land sales, requesting parcels at auctions. Presently, the average per-hectare price (one hectare = 2.47 acres) is around C$400. During the last five years, annual sales have averaged C$360 million. In September 2003, the province set a Canadian record with a C$418-million land sale. Calgary-based EnCana Corp. dominated that sale, picking up 350,000 acres for C$369 million in its Cadomin play in the Deep Basin. David Richardson, manager of geology, titles division, notes that deep rights are available in most northeastern areas. "Title comes back to the Crown every month, and it's easy for a company with an idea in a deeper horizon to gather large tracts of land." That's because rights below depths drilled to or produced revert to the Crown. Because of its remoteness, British Columbia offers several features that enhance its land tenure process for explorers. A company can hold a lease in a frontier area once it proves that a pool exists, without having to bring the well on production. Also, the province is willing to negotiate its royalty regime to encourage production in areas with special circumstances. "We have a fair and flexible system, and we have a will to use that flexibility," says Richardson. "If a company has a resource that it wants to develop, and the money and staff to proceed, there are a lot of things we can do to facilitate development."