From $10 to $147 crude and everywhere in between, it’s been a memorable twenty years for Canada’s world-leading oil sands province. Graham Chandler looks at some of the highlights and game-changers.
In 1991, you could buy a litre of regular gasoline in Alberta’s capital, Edmonton, for a little under fifty cents. Up and down with crude prices it went. Today, it’s around $1.10. Not bad, considering the heady two decades in between.
Twenty years ago, world crude prices were $30 per barrel in the wake of Iraq’s invasion of Kuwait, but dropped again, readying for a steady and healthy rise. That stimulated business activity in Alberta, and by the late 1990s, oil production was growing dramatically— despite a drop to $10 in 1999, after the Asian economic crisis. Alberta rode the upward seesaw to $147 in 2008, before the plummet into world recession.
If the ups and downs of the past twenty years have shown anything, it’s that the fundamentals of Alberta’s oil patch have been strong and well-rooted. The reasons are manifold: advancing and innovative technology, strong resource base, vast infrastructure, attractive business climate and fair royalty regimes.
Technological innovations were the biggest game- changers. “Directional drilling and horizontal wells top my list for dramatic influences,” says Clint Tippett, president of the Petroleum History Society. Horizontal drilling, first developed for offshore wells, saw early application in Alberta in the late 1980s. Together with new rig designs and measurement-while-drilling (MWD) tools, horizontals opened up new reservoirs beginning in the ‘90s. Now drilling tools could lock into a horizontal producing zone—the pay zone—for distances up to 10 kilometres.
Horizontals were vital for increasing production from heavy oil and bitumen formations too. By the early 2000s, almost 10 percent of wells were horizontal and now that figure approaches 80 percent. Precise horizontal drilling considerably boosted oil sands recovery, making steam-assisted gravity drainage (SAGD) much more efficient since accurate placement of the upper injection well in relation to the lower producing well is critical for production optimization.
Precise horizontal drilling, along with dramatic innovations in multiple-fracturing (fracking) techniques—allowing up to 30 or more fracs in one horizontal hole—has also made it possible to revisit old fields previously deemed uneconomical and make them produce again. “Completion technology, our ability to fracture and stimulate wells made huge leaps in this period,” says Tippett. Now, tired fields like the Pembina in central Alberta are seeing renewed recoveries of up to 50 percent by drilling further horizontally into untapped pay zones.
Together with advances in microseismic technology, horizontal drilling and multi-fracking have opened new hydrocarbon sources from “tight” gas formations like shale rock too. Stealing the unconventional limelight from coal-bed methane (CBM), which was touted in the early 2000s as the source to replace depleting conventional gas production in the province, shale gas has become the darling of the industry.
And a natural gas game-changer for Alberta and the world. Its influence has been to depress North American natural gas prices from around $11 per mcf to a steady $4 range. Heretofore unreachable, gas volumes from the new fields are thought to contain a hundred-year supply for America. The low gas prices have driven many Alberta juniors to shift their emphasis to oil plays.
The Athabasca oilsands have long been Alberta’s and Canada’s largest petroleum resource. In the mid-2000s, they hit world-class status: second only to Saudi Arabia, at 175 billion recoverable barrels.
In the very early years, the challenge was how to economically liberate the oil from the sand. The first mining and upgrading projects began in Fort McMurray in 1967 and in 1978, but it was the 1990s that brought the technologies to reduce costs and create a surge in new projects.
Two major advances changed the game. “The adoption of truck and bucket technology quasi- revolutionized oilsands revenue,” says Tippett. It allowed the old and inefficient bucket-wheel excavators to be replaced, at least for the 20 percent of the oilsands that are surface-recoverable. The second was in 1991, when the big in situ breakthrough was announced— the first successful SAGD pilot test. It was SAGD that revolutionized economic recovery of the deeper 80 percent of bitumen deposits that are inaccessible with surface mining.
Production has steadily advanced. Following the 2008 economic lull, by 2011, there were over 60 producing oilsands projects in the Athabasca area and over 20 in the nearby Peace River region. In 2008, oilsands production exceeded conventional production for the first time, and the divide continues as conventional sources decline and synthetic crude production expands.
January 2011 saw a new royalty structure taking effect in the province. The new regime was announced in 2010 after months of consultation with the energy industry—needed to boost industry confidence after the royalty increases in 2007 that had been aimed at improving the government’s take. Now, the maximum royalty rate on conventional oil wells drops to 40 percent of revenue from 50 percent, and to 36 percent from 50 percent for natural gas. Incentives for new wells remain.
Oilsands royalties are unchanged with the new structure. The industry’s economics had already improved due to late 1990s changes in provincial royalties and federal taxes, which prompted a series of new project announcements. Other government changes in the regulatory environment made business economics better. “There is an overall sense that Alberta’s oil industry is not nearly as tightly regulated in the last twenty years,” says Tippett. “For example, prices and justifying exports are no longer regulated by the feds. Alberta’s Energy Resources Conservation Board (ERCB) has moved to a self-policing model and companies no longer spend months dealing with them. These changes help companies operate more efficiently.”
The corporate M & A scene has seen its share of roller coaster rides too. As Alberta’s oil industry grew more attractive with rising world prices and technological innovations, investment bankers kept busy. Major international deals affecting the province included the 1999 merger of powerhouses Exxon and Mobil—an $81 billion transaction. Two years later Conoco Inc. paid $6.3 billion for Gulf Canada Resources before merging with Phillips Petroleum in August 2002, to form another giant ConocoPhillips.
More locally, in 2002 Calgary-headquartered Encana was born of a merger between PanCanadian Petroleum and Alberta Energy Company. The marriage lasted eight years, then Encana split into two independent companies—natural gas-concentrated Encana and oil company, Cenovus Energy. Continuing apace, in 2007, Royal Dutch Shell completed its purchase of all outstanding shares of Shell Canada, a company that had been operating in Canada since 1913. Then another Canadian giant was created in 2009, when Suncor Energy and ex-crown corporation, Petro-Canada merged into a $43 billion entity.
Recent years have seen more overseas investors into the oilsands. “Some came because they had strategic interests and wanted control of oil resources,” says Tippett. “Others came because it was an attractive investment option.” He cites Statoil, the Chinese National Oil Company, the Japanese National Oil Company and South Korean utility companies. “The Asian companies are also partnering with some of Alberta’s upstream companies,” adds Tippett. “Part of that is expressing itself in attempts to export bitumen.” In the late 1990s and early 2000s, independent American oil and gas companies acquired several Canadian companies. “We had a fairly major influx of American companies due to the low exchange rate,” says Tippett. “There was also the perception of our resource potential being higher in Canada, and that it was cheaper and easier to find oil here.” One was Devon Energy, acquiring Anderson Exploration in 2001; the same year Burlington Resources picked up Canadian Hunter. And in 2008, Duvernay Oil was snatched up by Royal Dutch Shell for $5.9 billion.
Smaller, maneuverable companies appeared on the business scene too. “It’s a mode of building businesses that is not that common in Alberta,” says Tippett. “But there have been successful people who built businesses from the ground up, and then sold them to larger corporations.”
The postwar discoveries in Alberta sparked a long-lasting boom in pipeline construction that has continued in the past two decades. In the early 1990s, several pipeline systems expanded their capacity to transport greater volumes of natural gas to U.S. and Canadian markets. Oil lines began carrying more heavy crude oil and refined products. Oilsands areas were served by several new pipelines, transporting crude from western Canada into the Rocky Mountain States. On the heavy oil front, a major infrastructure piece was Husky’s Lloydminster Upgrader, completed in 1992. Taking feedstocks from heavy oil deposits of northeastern Alberta and into neighboring Saskatchewan, it upgrades it to refinery-ready synthetic oil.
“Throughout the past two decades, a number of major environmental practices were put into place,” says Tippett. “There has been an evolution in the handling of the environment and in consultations. We have to co-exist with other resource users, and have worked hard to better understand public concerns.” An example: In 2010, Canadian Natural Resources, Imperial Oil, Shell Canada, Suncor Energy, Syncrude Canada, Teck Resources and Total E&P Canada announced a plan to share data in a unified effort to advance oilsands tailings management.
Tailings ponds—massive lakes needed to allow clays, etc. to settle out of process water in order to recycle it—have increasingly headed the environmental list. Although operators now recycle up to 85 percent of water, research continues in methods to reduce tailings ponds. These include thickeners in the tailings that allow water to be recaptured, and mixing captured CO2 with tailings to produce solids.
Other advances over the twenty years have been reduction of land impacts: For example, horizontal drilling allows several wells to be drilled from a single pad, and flaring has been reduced to near zero.
Today, optimism abounds— especially in oilsands. “Oilsands rule, budget confirms,” trumpeted the Calgary Herald reporting on end-February’s provincial budget release. Royalties from both conventional and oilsands are outpacing expectations as the province’s GDP grows at 3 percent. Oilsands royalties are projected to double by 2014 to over $7 billion. Several projects are going forward and others expanding. More bitumen will be upgraded in Alberta as the province recently backed a new upgrader to process its own bitumen royalty-in-kind (BRIK). The joint venture, called North West Upgrading, is planned in three phases at a cost of $15 billion.
World consumption is rising again, towards pre-recession levels of 84 million bpd. And the International Energy Agency recently estimated demand will reach 110 million by 2025. CAPP is predicting Canada’s oilsands output to achieve 3.5 million bpd by then. Which bodes well for Alberta’s producers, as breakeven prices have dropped from earlier levels of $75 closer to $50 today—provided labor costs don’t go through the roof of an overheated economy. Alberta’s oilsands output is attractive.
Strong selling points are the massive reserves backed by a stable government, investment- friendly business climate and ready- made infrastructure, like current and planned bitumen pipelines to U.S. Midwest and Gulf Coast refineries. Although subject to resistance in certain quarters, U.S. Secretary of State Hilary Clinton has said she’s inclined to approve the latest proposal: TransCanada’s Keystone XL, which combined with existing conduits, would permit export of over 2 million bpd.
Just in case that doesn’t happen, the Alberta government in its latest Speech from the Throne announced a new policy on improving linkages with Pacific Rim markets—which could include Enbridge’s proposed Northern Gateway Pipeline that would send around a million bpd to Kitimat on the west coast for shipment to Asia. As Tippett hinted, it would be no surprise to see China eye an investment in this line. Kitimat is also the proposed site for an LNG liquefaction plant sometime in the next five years, the driver being Asian markets for Alberta and BC shale gas production; though Alberta’s conventional gas production will see gradual declines continue.
It’s not going to stop. Capital investment is expected to return to pre-recession levels this year. Driven by the oil sector, Statistics Canada expects investment in Alberta to reach $73.5 billion. A heady place, indeed.
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