Technology key to enduring depressed crude oil prices

Canadian heavy oil, bitumen production outlook [52,136 bytes]
Announced major oilsands profects [150,979 bytes]

Barring unforeseen events, the petroleum industry should expect no early relief from depressed crude oil prices and tough petroleum industry economics. As a result, many development projects will remain in jeopardy of being postponed or canceled.

But advances in technology can help companies cope with the current price climate by shaving exploration and production costs.

This general outlook was shared by several speakers at last month's Canadian Energy Research Institute (CERI) conference.

Among the regions and sectors expected to benefit from technological advances, said the speakers, are: Eastern Canada's Grand Banks, the deepwater Gulf of Mexico, and Canadian oilsands and heavy oil projects.

Oil price outlook

Steve Terry, managing director of London-based Petroleum Economics Ltd. (PEL), said his firm's base-case view is that oil prices will remain flat for the foreseeable future.

Terry said there is plenty of oil available at $10/bbl, and that prices over the next 10-15 years will depend on how supply is managed. PEL forecasts a price of $18/bbl, in current dollars, for Brent crude in 2005.

The analyst said he prefers managed markets to free markets for oil. He added that, until recently, key Organization of Petroleum Exporting Countries (OPEC) members Saudi Arabia, Kuwait, and Abu Dhabi have done a good job of controlling supply and maintaining economic rent in the oil business.

He said OPEC began to change when Venezuela invited foreign companies back into its oil industry. That, he said, diluted the ability to manage the market.

For this reason, Terry warned against allowing foreign companies with sophisticated technology into Saudi Arabia or Kuwait.

Terry concludes that, if oil prices of $16-18/bbl are to be achieved, it will require a wider supply-management effort, and the role of management must be shared by a number of significant producers.

Grand Banks

The Grand Banks off Newfoundland presents one of the best E&P opportunities anywhere in the world, with highly competitive economics and strong exploration prospects, says Petro-Canada Vice-Pres. Gary Bruce.

Within 10 years, predicts Bruce, the 127,000-square-mile area will be producing more than half of Canada's light and medium crude. After 2000, he expects a new field to be developed there every 2-3 years.

There have been 115 exploration wells drilled in the area, 60% of them in the Jeanne d'Arc basin, where Hibernia field is now producing and Terra Nova field is scheduled to come on stream late in 2000. Seventeen fields have been discovered to date in the Jeanne d'Arc basin, containing 1.6 billion bbl of recoverable oil and 4 tcf of natural gas.

Other basins in the area have barely been explored.

Bruce says there are a number of reasons why the Grand Banks is attractive to his company and its partners Mobil Corp., Chevron Corp., Amoco Corp., Norsk Hydro AS, and Murphy Oil Corp.:

Total potential recoverable reserves in the Jeanne d'Arc basin are postulated at 5 billion bbl.
Finding costs in the basin are an average $1.25/bbl-about half the finding cost in Western Canada.
The fields are large, with Hibernia holding an estimated 615 million bbl, and Terra Nova holding 400 million bbl.
Recent improvements in offshore technology such as new floating production systems have lowered production costs and made smaller reservoirs economic to develop.
A profit-sensitive, generic royalty regime, established by the province of Newfoundland and Labrador, ensures reasonable rates of return for participants and removes uncertainty surrounding the fiscal regime.

Bruce says industry interest in the Grand Banks is strong. Ten exploration licenses were acquired at a 1998 lease sale, and related commitments total $175 million.

Delineation wells are being drilled this year at Hebron and Whiterose fields, and exploration wells are planned at the Nautilus and Riverhead prospects, all in the Jeanne d'Arc basin.

Bruce said Grand Banks operators have not cut their exploration or development budgets as a result of low oil prices, but if the current climate persists, exploration in 2000 could be reduced or eliminated until cash flows improve.

Development and operating costs on the Grand Banks are very competitive with costs elsewhere, he says. Based on recovering 370 million bbl from Terra Nova field, Petro-Canada estimates capital costs, in constant (1997) U.S. dollars, at $4.86/bbl. Operating costs are projected to be $2.64/bbl. Taken together, these two components combine for a total extraction cost of $7.50/bbl.

When taxes are included, said Bruce, Terra Nova would break even if the price of West Texas intermediate (WTI) crude averages $10.50/bbl, in constant (1997) U.S. dollars, over Terra Nova's life span. Companies will get an acceptable return at WTI prices above $16/bbl, he says.

Bruce added that operating cost will go down as more projects come on stream and share infrastructure. Marginal fields can be developed by tying them into stand-alone developments, further reducing costs.

Deepwater gulf

Daniel R. Pickering, managing director, research, for Simmons & Co. International, Houston, said the deepwater Gulf of Mexico has shown impressive growth in the past decade and is still strong. But the game is getting tougher, he warned, and growth will slow.

Pickering says the industry has delivered on promises to reduce costs, accelerate development, and increase production on deepwater projects. Development costs for Auger field in 1994 were $1.1 billion, or $5/bbl. In contrast, costs for Mars field in 1996 and Me

nsa field in 1997 were, respectively, $1.3 billion or $2.50/bbl, and $300 million, or $2.50/bbl. As proof of reduced development times, Exxon Corp.'s Diana project, estimated in 1994 to come on production in 2002, is now scheduled for production this year. And Shell Oil Co.'s Ram-Powell project, projected in 1994 to come on stream in 1999, began production in September 1997.

Water depths also have increased greatly, from 1,500 ft for Tahoe field in January 1994, to 5,300 ft for Mensa field in November 1997. Likewise, produc-ing from deepwater U.S. leases has skyrocketed from 79,000 b/d in 1989 to 448,000 b/d in August 1998.

The number of deepwater pros- pects in the producing or planning stage has also increased, from 49 in mid-1995 to 120 now, says Pickering. And total leased acreage has risen to 19 million acres now from 2 million acres in 1994.

Technological advances have made this play one of the world's hottest. But Pickering expects spending in the deepwater gulf to be down in 1999.

It remains, however, one of the strongest areas for the industry and will continue to be a key area for the foreseeable future, he says.

Oilsands

Mark A. Konopczynski, manager of oilsands for Imperial Oil Ltd. (IOL), said continued turbulence can be expected in oilsands developments over the long term.

Cost will continue to be king in the low-margin business, and producers with existing low-cost infrastructure and high-quality resources will set the pace. Improved prices will be necessary to increase production.

Konopczynski said the oilsands business will continue to face severe pressure as long as low prices continue. Development optimism during 1994-97 faltered in 1998 as heavy crude prices crashed, and many companies have written down heavy oil assets.

A list of planned oilsands projects is shown in the table on this page.

He said opportunities for expansion of the Syncrude Ltd. oilsands plant, in which IOL has a 25% interest, and the Suncor Inc. plant-both of which are in northern Alberta-appear more certain because they are generally insulated from the cyclic nature of light-heavy price spreads and have the significant advantage of infrastructure developed over 25 years. But at today's prices, the ability of even these projects to finance growth is in question, he says.

Konopczynski said IOL's Cold Lake heavy oil development in Alberta is the most successful in situ operation in Canada and the second-largest thermal heavy oil operation in the world, next to the Duri project in Indonesia. He said IOL has systematically pursued phased development to minimize risk.

IOL plans to spend $1.25 billion (Canadian) in additional development at Cold Lake to keep its existing operations running at maximum capacity for the next 25 years. It also plans to expand the complex with Phases 11-13-the Makheses development-which will increase production by 30,000 b/d and add 290 million bbl of proven reserves.

A cogeneration facility will give Makheses a price tag of about $650 million, said Konopczynski.

Canadian heavy oil

Larry Fisher, senior research director for CERI, said that, at a reference price of $18 (U.S.)/bbl for WTI crude at Cushing, Okla., from 2000 onward, development of better-than-average quality heavy oil resources is economic. This reference case assumes a relatively quick price recovery, however.

Technology gains will be needed to commercialize lower-quality resources, such as those that are developed with steam-assisted gravity drainage (SAGD).

Fisher said heavy oil drilling is now at a snail's pace, and the die has been cast for a production decline, with no reversal of that trend in sight. Based on CERI's analysis, production of heavy oil will decline by 100,000 b/d over the next 5 years, then grow as confidence in markets returns (see graph, p. 20).

A supply price of more than $10 (Canadian)/bbl will make a lot of heavy oil supply economic, and long-term prices in the range of $15-20 (Canadian)/bbl will likely provide a balance between supply and demand, said Fisher.

CERI predicts that diluent supply will be ample throughout the forecast period. Thermal bitumen growth could exceed projections, but more upgrading (and capital investment) would be needed.

Fisher admonished that the CERI analysis is an assumption, not a forecast. Because of the dynamics of the market, he said, it is virtually certain that the future will unfold differently.