Calgary oilman Mike Graham remembers the summer of 2003 in B.C. Forest fires were consuming half the province and threatened the city of Kelowna; it was the worst forest fire season on record. The provincial government’s bill for fighting all the fires was nearly $400 million – more than double the cost of the previous worst season, 1998.
That catastrophe is seared in Graham’s memory because at the time his company, EnCana Corp. (ECA-T), was putting together what would be the biggest purchase of oil and gas leases and drilling permits in B.C.’s history. With the costly 2003 forest fire season winding down, the September sale of oil and gas leases in northeast B.C. brought in $418 million – most of it paid by EnCana.
Presto, B.C.’s entire forest fire bill was covered, leaving money in the bank.
“I’ve thought of that many times,” Graham recalls with a chuckle. As executive vice-president of EnCana and president of the company’s Canadian Foothills Division, he has been the driving force behind the company’s B.C. exploration programs. EnCana’s bidding policy on leases and drilling permits is to make a big splash: acquiring rights that cover entire townships, rather than a section here and a section there. “It was a huge undertaking,” he says, “and a huge amount of money went into the B.C. coffers just when the forest fires were burning around Kelowna.”
That September 2003 lease sale started a resource boom the like of which this province has never seen before – so much so that, increasingly, the world’s energy giants look to B.C. rather than Alberta for their next Canadian natural gas bonanza. Geologists in Houston and Tulsa, as well as Calgary, are now studying maps of B.C., and since EnCana’s bold entry in the province, the hunt has been joined by Royal Dutch Shell (RDS.A), Exxon Mobil (XOM-N), Talisman (TLM-T), EOG Resources (EOG-N), Apache Corporation, Murphy Oil (MUR-N) and a host of other mid-sized and smaller companies. They’re all betting that B.C. is the next hot spot for natural gas on this continent – and pumping billions of dollars into the economy at a time when the traditional resource engine, forestry, is on the ropes. For the last few years, natural gas royalties have pumped considerably more money into Victoria’s coffers than stumpage fees from trees harvested – and that trend is likely to continue. Likewise, the amount of oil and gas money invested in B.C. has grown from about $1 billion annually in the 1990s to $4 billion annually since 2000.
In the first eight months of 2008, the $418-million record was broken three times: first in May with a $441-million lease sale, then again in July with a $610-million lease sale and again in August with a $501-million lease sale. In total, the province had already collected $2.08 billion from the industry for leases and permits by the end of August, with four more monthly auctions still to come; by year’s end, these lease sales, combined with the annual royalties paid by natural gas and oil producers, are expected to put B.C.’s petroleum revenues for 2008 somewhere just under $3 billion. To further cement the comparison, B.C.’s lease sales for 2008 have blown Alberta – with only $744 million by the end of August – out of the water.
The sale of petroleum leases and drilling permits points to the future. Companies lay out all that money – and it’s pure gravy for the province – for nothing more than the right to explore for oil and gas, and drill holes to test out the formations. If the oil companies don’t find anything, too bad. There are no refunds. But it is a well-educated gamble for the players, and the odds are that B.C.’s natural gas production – currently at about 3.8 billion cubic feet a day (compared with Alberta’s 14.2 billion cubic feet a day) – will increase significantly.
“There’s a good chance that within the next five to 10 years B.C.’s gas production will exceed Alberta’s gas production,” says Dave Pryce, Western Canada vice-president with the Calgary-based Canadian Association of Petroleum Producers (CAPP). “Alberta has been producing gas at a high rate for a number of years, and it is a challenge to maintain it. B.C. represents the growth potential for Canada.”
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Natural gas production in B.C. is nothing new. Concentrated in the northeast corner of the province, around the hub of Fort St. John, it has been providing a steady (albeit modest) flow of money and local jobs since the 1950s, ebbing and flowing with the boom and bust cycles that have characterized the Alberta oil patch. It remained a backwater for decades, partly due to the much more business-friendly jurisdiction next door, partly because of much more difficult terrain and partly because the geological potential was much better understood in Alberta. A significant impediment to growth was the fact that, until recently, drilling could take place only in the winter months when the swampy, muskeg-like terrain was frozen solid.
For most of the 1980s and ’90s, the annual revenue from lease and drilling permit sales was below $100 million, and only twice in those two decades did it climb above $200 million. Revenues from the sale of oil and gas, combined with those lease sales, struggled to reach $500 million annually – until 2000, the beginning of what has turned into a boom. So what finally brought B.C. to the attention of Mike Graham and his colleagues in the oil patch? In addition to the convergence of attractive government policy and high gas prices, add a third element in the form of a new technology. Call it an unconventional truth, because EnCana and most of the rest of the oil patch are pinning their B.C. dreams on something called unconventional gas.
Conventional gas and oil lie in reservoirs in rock formations at various levels, and of various geological ages. A conventional gas well is a vertical hole that penetrates one of these reservoirs, and the gas under pressure flows up the hole, through the wellhead, into a processing plant, and ultimately into a pipeline network. What makes the gas flow is a high level of porosity in the rocks (think of a sponge) that contain the gas, and a high level of permeability that connects all those sponge-holes and lets the gas move through the reservoir rocks to the well.
Unconventional gas lies in much more dense, fine-grained rocks, or shales, which have a high level of porosity, but very little permeability. A vertical well passing through one of these zones will show the presence of gas, but that lack of permeability means very little of the gas will make it up the well hole. With the advent of horizontal drilling and reservoir fracturing (see “Unconventional Thinking,” p. 141), this form of gas exploration became possible. While the costs of horizontal drilling and reservoir fracturing are considerable, gas prices are now high enough to justify the expense – and the long-term forecasts indicate they will stay high. It is the natural gas equivalent of what has happened to Alberta oil sands development since crude oil prices topped $100 a barrel.
EnCana got the ball rolling on its unconventional resource program in 2001 with a play north of Fort St. John called Greater Sierra: a buried ancient marine reef that Graham compares with Australia’s Great Barrier Reef. “Greater Sierra really was the start of our whole-resource-play thinking,” Graham recalls. “We moved the whole company to a resource-play focus in North America.” Greater Sierra is a mature field now, and Graham estimates that EnCana has produced more than 500 million cubic feet of gas from the property’s nearly 1,000 wells and continues to
produce more than 200 million cubic feet of gas a day.
Success at Greater Sierra gave EnCana the confidence to make the huge 2003 lease purchases necessary for its Cutbank Ridge project, not far from the coal town of Tumbler Ridge. Graham says at the same time he was looking at unconventional gas, the provincial government was realigning its taxation levels, royalty programs and incentives in an effort to encourage just such a play. To remain economic, these resource plays need a natural gas price of more than US$8 per million British Thermal Units (BTUs). Even with a significant drop in price over the summer months – gas futures dropped by 42 per cent from early July to mid-August, tracking a similar drop in crude oil prices – forecasters are still looking at prices dropping no lower than US$9.10 per
million BTUs over the next 12 months.
Richard Neufeld, B.C.’s minister of energy mines and petroleum resources, is from the Peace River region and has been the industry’s champion for most of the 7½ years Gordon Campbell’s government has been in power. But getting the attention of his caucus colleagues over the years has been, well, a challenge.
“There was a disconnect,” he concedes. “Remember that there is not a lot of north-south travel in British Columbia. Folks up there don’t come to Vancouver to shop; they go to Edmonton. The links with Alberta are long and well established. We didn’t even have a road connecting the northeast with the rest of B.C. until 1953.” So what finally raised his cabinet colleagues’ consciousness? “The money,” says Neufeld. “When we started seeing hundreds of millions of dollars – then over a billion – they noticed.”
The goal of the new policies, says Neufeld, was to create an oil and gas industry environment that competes with other jurisdictions, particularly Alberta. “I know that if you take less out of a whole bunch you get more money than if you try to take a lot out of a little. We eliminated the corporation capital tax and the sales tax on drilling rigs. And we made it all broadly based so it didn’t just apply to a few companies – they all could take advantage of it.”
The first step was to make the province’s oil and gas commission – which issues permits for oil and gas activity, monitors industry performance and enforces regulatory compliance – a streamlined, one-window agency for permit applications. Step two was to provide financial incentives for industry – up to 10 per cent of the cost of drilling a well – to conduct summer drilling as well as winter drilling. EnCana, again, stepped up on this one and developed an innovative series of wooden mats that could support a drilling rig on the soggy summer ground without doing any ecological damage. Neufeld says turning B.C.’s industry into a year-round operation was one of his key goals, and that has largely taken place.
Shales and “tight gas” formations have been known for decades, mostly because the industry was often drilling vertically through them to get to the good stuff farther down. Two changes in drilling and well-completion technology – horizontal drilling and reservoir fracturing (“fracing” in industry parlance) – have changed the outlook on these tight gas and shale gas reservoirs dramatically. Engineers discovered that if you could just make the drill bit bend on its way into the reservoir and then run horizontally instead of vertically – for maybe a kilometre or two – you’d end up exposing 1,000 metres of the shale or sandstone instead of the mere 100 metres you get with a straight vertical hole.
The well starts out as a vertical hole, but pressure on one side causes the drill hole to slowly bend in a large curve until it is running horizontally through the shale or tight gas formation. But that’s just the first part. The next step in the process, fracing, involves injecting a gas or a liquid, under great pressure, into that long horizontal hole to fracture the rock so the gas can flow much more easily. Sand is then injected to keep the cracks open after the fracing, making sure that the reservoir doesn’t seal itself up again.
In recognition of the higher costs of drilling for unconventional gas, the province also implemented a net profit royalty system a year ago. In simple terms, it gives a producer a break on gas royalty payments in the early days of production and increases it to a higher rate once the companies have recovered their capital investment. And when neighbouring Alberta decided last year to increase its royalty take from gas and oil production, B.C. quite deliberately maintained the status quo, turning the so-called Alberta advantage into the B.C. advantage. “B.C. has the attention of the industry right now,” says CAPP’s Pryce. “They’ve made some very positive fiscal moves to attract the industry and make sure B.C.’s resource is competitive with other jurisdictions. They’ve adjusted royalties to the point where companies can make an adequate rate of return. There’s a multiplier effect.”
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This convergence of positives leads to two gas plays that promise to dominate the industry’s exploration in B.C. for the next few years: Montney and Horn River. Montney is a tight gas geological zone (for precision, there’s an Upper Montney and a Lower Montney) that EnCana and other companies are pursuing in the B.C. foothills area near Dawson Creek. Horn River is a shale gas deposit farther north, just west of EnCana’s existing Greater Sierra project. Both are estimated to have natural gas in place – and again, EnCana is leading the pack. (EnCana is the biggest oil and gas rights holder in the province, with 1.8 million hectares acres in its control.)
“The Montney now is a world-class gas play, maybe the biggest play in North America,” says Graham. “We talk of Montney as an enormous resource, with gas in place as high as 500 trillion cubic feet across the whole Montney – maybe bigger. It’s going to change B.C. We think we can produce a billion cubic feet a day just out of that play.” To put 500 trillion cubic feet in context, consider that the National Energy Board puts B.C.’s existing proven conventional natural gas reserves at 52 trillion cubic feet, of which 17 trillion cubic feet has already been produced. What can’t be predicted, assuming the 500 trillion cubic feet estimate holds up, is how much of that can be produced economically – but even if it’s only 10 per cent, it nearly doubles B.C.’s existing reserves all by itself. EnCana says it is already producing 120 million cubic feet of gas a day from its Montney wells.
It’s not for nothing that last summer Royal Dutch Shell (which refused a request to talk in any detail about its B.C. holdings) announced the acquisition, for $5.9 billion, of Calgary-based junior oil company Duvernay Oil Corp. One of Duvernay’s main attractions was a significant land position in B.C.’s Montney play. Shell was also rumoured to be the main buyer in May’s $441-million sale of B.C. oil and gas rights.
Meanwhile the Horn River shale gas play – farther north and west, in a much more remote part of the province – is estimated by EnCana to contain 200 trillion cubic feet of gas. It is now being compared favourably with a huge shale gas play in Texas called the Barnett Shale, which currently produces about five billion cubic feet of gas a day and is the largest gas field in the U.S. It is no accident that the same companies active in the Barnett Shale – EnCana, EOG Resources, Devon Energy, Murphy Oil and Apache – are key players in B.C.’s Horn River. EnCana’s Graham says Horn River is superior in most respects – geographic area, thicker rock formations and better-producing wells – than Barnett, with the last two wells drilled initially producing five million cubic feet of gas a day.
These two plays alone – Horn River and Montney – have the potential to help vault B.C. into the No. 1 spot in the country for natural gas production. But there’s more: Talisman Energy has been drilling what are called deep wells in the Monkman area (again, not far from Tumbler Ridge) and said in its 2008 second-quarter report that production from a series of these wells was setting records for the company, averaging 137 million cubic feet a day. According to CAPP’s Pryce, B.C. has produced the biggest wells over the past decade from deeper basins and will likely continue to have those high-volume wells. “They are high-risk but very high-reward wells.”
Jock Finlayson, executive vice-president of the Business Council of B.C., points out that all this activity is still confined to the northeast and wonders aloud what’s in the rest of the province – and in the offshore area west of Prince Rupert. He also notes the seeming schizophrenia in what are clearly two fundamentally contradictory policies: while B.C. is hell-bent on turning the province into the next oil and gas powerhouse, it is also leading the charge in greenhouse gas reductions, imposing carbon taxes and weaning society from fossil fuels. Aren’t the two goals in serious conflict?
“They’re not,” responds Energy Minister Neufeld, with some hesitation in his voice. “I would say that for decades we’ll be using fossil fuels. Fossil fuels feed the world in so many ways we don’t even realize. We’re innovative folks, but it would be a mess if we took it out. Natural gas is still the cleanest fossil fuel we know of today. More than 50 per cent of our gas goes south, and it replaces coal.”
And that represents a potential carbon dioxide cloud on the province’s energy horizon, according to Finlayson. Natural gas is indeed cleaner than coal, but it is still a CO2-emitting fossil fuel. How is the province going to account for the greenhouse gas emissions that will be represented by what looks like a long-term doubling of B.C.’s natural gas production, with the biggest chunk of it destined for export to the U.S.?
“[The provincial government is] looking at aggressive targets to reduce the carbon footprint associated with natural gas production, like flaring from gas wells. And they are working hard with industry to reduce CO2, hopefully through carbon capture,” says Finlayson. “But what will the government have to pay if production doubles, for example, when there is an increase in emissions?”
Worse than that, who is going to “own” the CO2 emissions from gas exported to, say, California? Not California, says Finlayson, because they’ve made it very clear that in their view it’s the producer who has to account for that, not the consumer. And Canada’s decision to sign the Kyoto accord will make it hard to argue otherwise. “Under Kyoto, it’s the producers of fossil fuels who carry the can,” he says. “Even though it’s the consumers who are the source of the emissions. Canada got hoodwinked under the Kyoto agreement into signing on to a European vision – put the burden on the producers.”
Finlayson sees serious negotiations ahead for B.C. and for Canada as a whole as it tries to engage the U.S. in the development of continental greenhouse gas reduction strategies, as well as the cap-and-trade formulas now being discussed at state and provincial levels. “I can see a day in the not-too-distant future where the U.S. ends up putting in place a national regulatory framework for greenhouse gas emissions,” says Finlayson. “It will be a cap-and-trade formula. If it happens, the equation will change dramatically for Canada, and instead of the debate between the feds and provinces, the issue will be how does Canada make sure we don’t have a carbon trade barrier at the border. The U.S. will take the view that’s our responsibility. This is a big issue.”
Because the provincial government’s drive for energy superpower status has largely been under the radar, as far as public perception goes, that obvious conflict has not had a lot of play – either in the media or in political discourse. When the province is staring at a potential annual energy haul from lease sales and gas royalties that could exceed $5 billion in the years ahead, it’s very hard to focus on the inconsistency.
That $5 billion a year will build a lot of hospitals and schools.