International Outlook: North America

Drilling activity will soar

Strong oil and gas prices finally produced results during the first half. US and Canadian operators will boost gas drilling further to exploit higher prices

Canada by Robert Curran, Calgary, Canada; Mexico by Sergio M. Galina Hidalgo, Consultant

United States. Last January, we cited the difficulties inherent to forecasting drilling activity, since there were several discontinuities among the leading indicators. The most glaring was the falling active rig count around the world, even as oil and gas prices were on the rise. The chaos in Venezuela and the run-up to the war in Iraq were thought by some to be the primary reason for rising oil prices. But with both situations in the past, operators are more comfortable in attributing higher oil prices to the overall tight supply/ demand situation.

Now with six more months of data, those earlier discontinuities appear to be fading, and thus suggest a strong second half. If Canadian rigs, which drop dramatically every spring, are excluded, the number of rigs running in the rest of the world was nearly 16% higher in June than at the beginning of 2003. Active rigs in the US were up almost 25% during the same period. The second half should be even better.

Highlights of World Oil’s revised 2003 forecast include:

• Second-half US drilling will reach 16,653 wells, about 30% more than in the first six months.
• Full-year 2003 drilling will total 29,519 wells and 149 million feet of hole, up 2% and down 3%, respectively, from World Oil’s 2002 estimates.
• U.S. Gulf of Mexico drilling will rise 7% in the second half.
• The U.S. rig count will average 1,107 rigs during the second half.

While a 30% increase in drilling may seem improbable, at least two factors skew the forecast. One is that during the first six months of 2003, there was an apparent decrease in rig efficiency (e.g., fewer wells drilled per active rig). In several states or districts, the number of wells drilled through June was significantly lower than rig averages would justify. However, this perceived efficiency decline is thought to result from the rapid run-up in the rig count.

More significant is a predicted resumption in drilling for coal bed methane in Wyoming, where CBM drilling virtually shut down during first-half 2003. But with the completion of an environmental impact statement, which addresses how to dispose of large volumes of water that must be lifted before gas can be produced, operators will more than quadruple drilling to 2,055 wells.

The average June WTI (West Texas Intermediate) crude oil price was up by $2.50 per barrel from the May average. Oil prices are not likely to fall significantly, because OECD inventories remain low by historical standards. Prices have also firmed on negative news for oil supplies. We expect prices to remain firm throughout the rest of 2003, possibly even rising to $36 per barrel by year end.

Gas injected for storage during June made up considerable ground following a slow start in early spring. As a result, the storage-level deficit relative to the 5-year average was reduced from 28% in May to 16% at the end of June. Gas imports from Canada were down slightly for the first quarter, and prospects for increased imports of LNG are iffy. Another issue for natural gas is a significant revision by the Energy Information Administration in the level of industrial natural gas for 2002. Industrial natural gas demand was earlier reported at 7.85 Tcf for 2002. That figure has been revised to 7.12 Tcf.

Citigroup Smith Barney’s mid-year survey of operators’ E&P spending plans indicates worldwide expenditures will rise 5.9% this year. Canada will post the largest rise, to 13.5%, while international growth projections are up 6.6%. Surprisingly, the firm’s US projection is up only 1.1%.

US independent producers plan to spend $18.1 billion this year, compared to $17.9 billion invested in 2002. The majors are more cautious, and plan to spend $14.2 billion in 2003, versus $14.1 billion a year ago.

Lehman Brothers’ operator survey produced similar results, except for a slightly improved US spending projection. Lehman Brothers projects that US spending will rise 2%. Independents will increase expenditures by 4.6%, while the majors will cut spending by 1.3%.

Apache Corp. became the fourth largest producer on the Gulf of Mexico OCS this year. The firm in 2002 produced 310 MMcfgd and 36,678 bpd of liquids. (Photo courtesy of Apache Corp. )

Canada. It’s been a strange year so far. High commodity prices have bolstered industry’s bottom-line, drilling is projected to hit record levels and oilsands activity is at an all-time high. Yet doubts still linger, as economic trends, market volatility and Canada’s unpredictable federal government promote an environment of uncertainty and caution. Among the industry’s top concerns are its current inability to replace natural gas reserves and uncertainty about the potential $40-billion cost of the Kyoto Accord.

On the reserves side, producers replaced approximately 82% of combined oil and gas production in 2002, according to a survey conducted by Calgary’s Daily Oil Bulletin. But when massive negative revisions to natural gas reserves are factored in, the replacement ratio drops to 42%.

Another looming problem is the possibility that more than 900 gas wells could be ordered shut down because they may endanger oilsands recovery. Alberta’s Energy and Utilities Board hastily arranged hearings to discuss its proposal to shut in about one Tcf of gas, about 2% of the province’s remaining reserves. The contentious shut-in plans are vehemently opposed by natural gas producers. On the other side are energy companies that have working or proposed oilsands facilities. A final written policy issue was due before the end of July, with the gas shut-in taking effect at the beginning of August.

As Canadian companies look further for other sources of natural gas, among the leading contenders are the vast, largely untapped reserves in the McKenzie Delta, far to the north, as well as coalbed methane deposits.

Northern Canadian gas prospects have improved. In April, Chevron Canada Resources reported that its North Langley K-30 well, in the McKenzie Delta, encountered gas. In addition, in late June, a deal was struck between TransCanada Pipelines, producers and local aboriginals for development of a C$4-billion pipeline running from the McKenzie Delta, south to Canada and the US.

Other prospects being considered include offshore West Coast development. The government of British Columbia (BC) is aggressively pursuing plans to begin issuing exploration permits in 2004, with seismic work beginning in 2005. As BC tries to get its fledgling offshore industry off the ground, activity continues on the East Coast, both onshore and offshore, with a number of new wells planned.

The Ladyfern area in northeastern British Columbia is a prolific gas- producing region for Canada. (Photo courtesy of Apache Corp.)

No matter what the industry’s circumstances, there will always be buyers and sellers, and this year has been no different. Some of the bigger sales include EnCana Corp.’s sale of its 10% interest in the Syncrude oilsands project for just over C$1 billion to Canadian Oil Sands Trust.

In the first quarter of 2003, approximately C$2.8 billion worth of assets and companies were publicly announced for sale, the biggest total for a single quarter in the last three years.

The first half of 2003 yielded drilling totals that show some promise. According to Daily Oil Bulletin records, there were 7,623 wells drilled through June, up almost 14% from last year’s halfway total, although still well off the record 8,961 drilled in 2001.

Of the wells drilled in 2003, 1,828 were oil, 5,018 were gas, and 692 were abandoned. Further testimony to the hectic pace is the 12,269 well permits issued so far in 2003, which is 51% higher than last year’s total and 11% higher than the previous record in 2001. Finally, the number of drilling rigs working in the first time that week of July was 424, the first time that the July count has topped 400 since 1997.

The Canadian Association of Oilwell Drilling Contractors’ latest activity forecast for 2003 is 17,532 wells. Rig utilization is expected to average 59% this year, with an average of 390 units working out of a 663-rig fleet. In 2002, rig utilization was 50%. Meanwhile, the Petroleum Services Association of Canada is projecting that 2003 will set a new record for wells drilled, at 18,300.

On the East Coast, optimism still remains despite some recent setbacks. Since April, Petro-Canada has announced two offshore dry holes in the Flemish Pass, about 280 mi east of St. John’s, Newfoundland. Imperial is proceeding with plans to drill a deepwater exploratory well on the Scotian Slope, about 190 mi southeast of Halifax. Nearby, at the proposed Mariner project, Canadian Superior Energy and El Paso have teamed up to drill an exploratory well.

Although offshore activity dominates East Coast activity, Corridor Resources has begun producing 2.3 MMcfgd from two wells near Sussex, New Brunswick, the first gas production in the province since 1991.

The shift from light and medium oil to heavy oil, bitumen and synthetic crude continued through first-half 2003 in Western Canada, and continued strong East Coast offshore volumes kept production mostly unchanged from last summer, at just over 2.9 MMbpd. Natural gas production was also flat, down only slightly from last year’s 17.2 Bcfd.

Oilsands development continues to dominate the western industry, not only by the scope, cost and impact of these massive projects, but also by domestic and geo-political concerns. In late June, Shell Canada Ltd. officially unveiled its C$5.7-billion Athabasca Oil Sands Project, 50 mi north of Fort McMurray, Alberta. The project began operations in April and is expected to reach its full output of 155,000 bpd in September.

Another project that recently received regulatory approval is the joint OPTI Canada/Nexen Canada Long Lake project, southeast of Fort McMurray. The C$3-billion in situ Steam Assisted Gravity Drainage (SAGD) project also includes an on-site upgrader. It is scheduled to begin steaming in 2006.

ConocoPhillips Canada secured regulatory approval for its C$1-billion Surmont SAGD project, which will be about 40 mi south of Fort McMurray. The company has not yet announced if it will proceed with the 25,000-bpd first phase operational by 2006.

To the south, at Cold Lake, Alberta, Imperial officially opened the newest phase of its Cold Lake heavy oil project, which produced an average 112,000 bpd in 2002. The C$650-million Mahkeses facility, which will add 30,000 bpd of production, also includes a 170-MW cogeneration facility. Imperial also started the engineering phase of its proposed 200,000-bpd Kearl Lake project, located about 30 mi north of Fort McMurray.

Mexico. As one of the larger countries for proven oil reserves, Mexico produces more than 3 million bopd, consumes more than 2 million bopd and exports more than 1.5 million bopd. Only Russia can similarly display such diverse capabilities. Mexico’s crude exports averaged 1.85 million bopd in first-quarter 2003, 15% higher than in first-quarter 2002. Increased production was due specifically to heavy oil, since light oil output declined about 75,000 bpd during the past year.

Although the number of exploratory wells has steadily increased in recent years, the amount of proven reserves has equally diminished. Officials say that 2002 was no exception, with Mexico’s proven reserves falling roughly 1.5 billion boe (excluding an 8-billion-bbl downward revision reported this year).

Strong demand growth has forced Mexico to increase gas imports. In 2002, imports comprised 12% of total supply, rising to 13% of 5.1 Bcfgd available in first-quarter 2003. These data are dramatic, given that imports accounted for only 8% of supply in first-quarter 2002.

Congress approved the $11-billion Pemex budget proposal for 2003. This was the second straight year that a major spending increase was mandated, a fact reflected in the drilling hike predicted. Last year, Pemex E&P invested about $7 billion in upstream projects. The most important project areas were the northern Burgos gas basin; the Cantarell heavy oil complex and the Ku-Maloob-Zaap basin in the Bay of Campeche.

The political environment around Pemex has been explosive. There was a scandal surrounding the former ruling party’s (PRI) 2000 presidential campaign being financed with Pemex funds, with a labor union serving as middleman. Nevertheless, the July 6, 2003, elections were a PRI victory, and a wake-up call for President Fox and his party (PAN).

Another battle has erupted over potential private investment in E&P via multiple service contracts (MSCs). Pemex proposed MSCs as a way to boost upstream gas activity, with bids scheduled during this year. Opposition politicians and social leaders have argued that MSCs violate the Mexican constitution, even though Pemex does not need Congress’ explicit approval to operate them. Strong opposition may drive away some bidders.

Cuba. Since early 2000, Cuba has hoped to sign new offshore oil and gas exploration contracts in a 43,000- sq-mi area in the Gulf of Mexico. The area has been divided into 59 blocks that can be licensed for E&P, although US companies remain barred from doing business with Cuba under US sanctions. There have only been two takers so far – Canada’s Sherritt International and Repsol.

Cuba imports 53,000 bpd of oil and refined products from Venezuela under a deal that allows for the sale of crude under preferential terms. However, this is only a third of what the nation consumes. The contract is set to expire in 2005. Cuba produces heavy, high-sulfur oil, and it’s production has more than doubled, to 55,000 bopd (mid-2003), in the last decade. Gas production – all associated – has surpassed 53 MMcfd.

In an interesting, but unrelated, development in nearby Bahamas, Kerr McGee received (in November 2002) a license to drill for oil in Bahamian waters.  

Table:What 20 Canadian drillers plan for 2003