North American Outlook

Strong activity levels continue

Fueled by consistently high prices, as well as growing gas demand, drilling totals will approach record levels in Canada and Mexico. Rig capacity in the US will be pressured by second-half plans.

US by Kurt S. Abraham, Managing/International Editor; Canada by Robert Curran, Calgary; Mexico by Sergio M. Galina Hidalgo, Mexico City

UNITED STATES

Last February, we predicted an excellent year for upstream activity in the US, noting that some of the psychological barriers (a resurgent Iraq and fears of oversupply are examples) that limited operators' thinking during 2003 had lost their impact. Now, six months later, we see nothing of major consequence to slow down activity for the balance of the year, particularly in the drilling market.

Confounding some of the so-called, expert analysts on Wall Street and in the US government, but not surprising observers within the industry, oil and gas prices have remained consistently strong for the last 18 months. This strength in prices has ensured that US drilling totals grow, perhaps to the point of straining capacity. Although West Texas Intermediate prices came down marginally from the very high levels (above $40/bbl) of April and May, they showed remarkable resiliency throughout June and July by holding firm in the mid-$30s. Indeed, as this issue was preparing to go to press, WTI was climbing back to a six-week high.

High oil prices are the result of limited, spare productive capacity; competition between the US and China for crude imports (spurred by strong demand growth); and historically low volumes of oil storage inventories in OECD countries. Meanwhile, natural gas prices remain equally firm in the US, hovering in the neighborhood of $5/Mcf. Interestingly, US operators now base their collective planning on expectations of gas prices at $4.50 or higher. Strong gas prices are driven by unabated demand growth, including governmentally mandated fuel switching, principally for environmental reasons. The impact of this trend cannot be emphasized enough, particularly when 80% or more of US drilling is already gas-related.

Highlights of World Oil's revised 2004 forecast include:

• Second-half US drilling will reach 19,273 wells, about 15% more than in the first six months.
• Full-year 2004 drilling in the US will total 36,077 wells and 193.7 million ft of hole, up 18% and 22%, respectively, from World Oil's estimates of 2003 drilling.
• US Gulf of Mexico drilling will rise 5% in the second half of 2004.
• The US rig count will have to average between 1,275 and 1,300 rigs in the second half to achieve the expected well total.

World Oil's mid-year survey update of 18 US major drillers (integrated companies and independents with large drilling programs) and 125 independents indicates a very strong second half is on tap. In line with our staff's calculations, these firms collectively will boost drilling 19%, including coalbed methane (CBM) wells. When CBM wells are excluded from the total, conventional drilling will rise 16%. Always more conservative, the major drillers will increase their activity 9.6%. The more volatile, ever-optimistic independents will hike drilling dramatically during second-half 2004. Combined, the two groups will boost exploration drilling to 9.5% of the total, up from 7.1% in the first half of the year. CBM activity will jump 60.8% higher.

Although most states will see activity increases in the second half of 2004, our US forecast does reveal some interesting regional differences. Onshore, Texas remains the busiest state, by far, with an 8.6% gain in second-half drilling, to 5,060 wells. Perhaps as much as 90% of activity will target natural gas. Oklahoma is next busiest, and the state's drilling should jump 13% higher in the second half. On a percentage basis, Kansas (up 29.4%), Colorado (up 50.0%), North Dakota (up 161.5%), Ohio (up 29.7%) and West Virginia (up 61.8%) will post some of the more impressive gains. In particular, the Colorado and West Virginia totals are based on strong, conventional gas and/or CBM programs.

On the disappointing side, Wyoming, Kentucky, Illinois and Tennessee all expect activity to decline in the second half, as reported by their respective state agencies. It should be pointed out that Wyoming is coming off a very busy first half of 2004, when the state was second nationwide in new wells drilled. The 10% decline appears to be in conventional wells, as World Oil's survey indicates a second-half increase in CBM wells planned.

Perhaps the greatest disappointment remains the Gulf of Mexico. Activity was only mediocre last year, and the first half of 2004 has been incrementally worse, with the rig count dropping 11% from 2003's average. Some of these results reflect the fact that some larger operators are concentrating a majority of their funds in a few high-profile deepwater wells. Additionally, some of the larger oil companies are also focusing on improving return on investment, deliberately holding back money and under-spending budgets. This trend is not expected to change before the end of the year, hence prospects for a near-term recovery are not encouraging.

Citigroup Smith Barney's mid-year survey of operators' E&P spending plans indicates that worldwide expenditures will rise a robust 7.5% this year. The firm now expects North American spending to rise 1.8% vs. last December's projection of only an 0.7% gain. In the US, spending growth has been revised upward to 4.6%, compared to last December's 0.6% projection.

On the other hand, Canadian spending is now forecast to decline 4.0% this year, up from a 0.9% gain projected earlier. This change reflects a combination of overspending in late 2003, plus an increased focus on mergers and acquisitions throughout western Canada this year. In Mexico, state oil company Pemex is expected to spend $10.5 billion, up an impressive 26.5% from 2003's level. Worldwide, Pemex is one of seven large oil companies planning to implement spending increases of more than $500 million.

According to Citigroup Smith Barney, US independent producers have been emboldened by the continued strength of oil and gas prices. Compared to last December, when independents collectively planned to hike spending 2.5%, these same firms now expect to boost their expenditures 8.0%, to $20.94 billion. In contrast, major companies will implement a slight drop (0.2%) in collective spending to $13.48 billion, although this is better than the 2.0% drop envisioned last December.

CANADA

Optimism abounds, as Canada's oil patch finds itself in the middle of a boom that has lasted for more than 18 months. Financial results have been outstanding, and drilling has continued at near-record levels throughout 2004. As always, there are concerns: about sustainability of price levels, the amount of conventional oil and gas remaining, or how the left-leaning coalition government may impact business.

Of all the possible dark clouds on the horizon, Canada's Liberal minority government is the most worrisome. The Liberals did not secure enough seats in Parliament to gain a clear majority, so they have teamed up with the left-wing New Democratic Party (NDP), which espouses increased spending, enhanced social programs and higher taxation. Analysts expect the Liberals to concede some policy issues to ensure NDP's continued support.

Of specific note is NDP's campaign pledge to fight for ratification of the Kyoto Accord, which Liberals had quietly let slip. Some projections show that Kyoto ratification might cost the oil patch C$40 billion (US$30.2 billion), depending on the legislative tools used to achieve emission reductions.

On the business side, natural gas reserves arguably remain Canadian companies' number-one concern. Producers replaced about 102% of production during 2003, but massive, negative reserve revisions knocked the replacement ratio down to 65%, according to Daily Oil Bulletin (DOB). The largest revisions came from Shell, down 335 Bcf, and ExxonMobil, down 159 Bcf. Since 1999, producers have written down gas reserves by 6.4 Tcf.

Collective wisdom says that Canada's natural gas future lies to the far north, in the McKenzie Delta, or on the West and East coasts, or in the virtually untapped coalbed methane reserves. For the first time, Alberta's Energy and Utilities Board (EUB) booked CBM reserves in 2003, albeit a mere 35 Bcf.

A recent National Energy Board (NEB) report pegged Canada's gas potential at 501 Tcf, of which 286 Tcf remain undiscovered. Of this, one third (96 Tcf) is in western Canada. The report warns that much of the remaining gas lies in shallower pools with higher decline rates. High drilling activity will be required to maintain current output.

The oil outlook is quite different, as activity continues apace in Alberta's oil sands. The province's bitumen output averaged 964,000 bpd in 2003, more than 50% greater than conventional production (629,300 bopd). That gap is almost certain to widen, as evidenced by EUB's 2003 estimate of oil sands reserves (174.5 billion bbl) versus 1.6 billion bbl of crude reserves.

Meanwhile, the National Energy Board's latest forecast suggests that oil sands output will top two million bpd by 2015, with more than 40 new projects announced for completion by that time. Their collective, expected cost exceeds C$60 billion (US$45.4 billion).

The bullish oil outlook, and the likelihood that higher prices will be the norm, has brought a royalty revenue bonanza, particularly for Alberta. In its last fiscal year (April 2003 to March 2004) Alberta netted nearly C$7.7 billion (US$5.8 billion) in royalties, putting it close to becoming Canada's only debt-free provincial government.

Alberta's success has been noticed on the East Coast. During recent federal election campaigns, Newfoundland and Nova Scotia appeared to secure promises from all three national political parties that the provinces would keep 100% of offshore oil and gas revenues. Previously, they shared revenues with the federal government.

High prices resulted in a record year for Canadian producer profits, despite the Canadian dollar's massive gains in value versus its American counterpart in fourth-quarter 2003. Industry profits totaled C$15.8 billion (US$11.9 billion) on revenues of C$95.8 billion (US$72.4 billion), according to DOB. However, first-quarter 2004 numbers (although still robust) have dropped from first-quarter 2003, as evidenced by results posted by EnCana Corp. EnCana's first-quarter profits were US$290 million (C$383.6 million), well off the US$837 million (C$1.11 billion) posted in first-quarter 2003. The company cited a new accounting method and the strong Canadian dollar as primary reasons.

EnCana also featured prominently in this year's merger and acquisition activity, shelling out US$2.7 billion (C$3.57 billion) in cash for Denver-based Tom Brown, which held about 325 MMcfd of equivalent gas production, 1.2 Tcf of proved gas reserves, and two million net, undeveloped acres. The deal closed in mid-May 2004.

More recently, Chevron Canada Resources sold its conventional, western Canadian oil and gas holdings to Enerplus Resources Fund, Acclaim Energy Trust and Paramount Resources Ltd., all of Calgary, for C$1.1 billion (US$836 million). Other big deals during first-half 2004 included two by Petro-Canada. The firm bought into EnCana's Buzzard field (UK North Sea) for $C1.15 billion (US$869.4 million) in May by acquiring Intrepid Energy North Sea Ltd. (29.9% interest in the field). The company also acquired Denver-based Prima Energy Corp. for C$719 million (US$543.6 million).

Murphy Oil finalized deals that effectively eliminated its Canadian presence. The firm sold C$550 million (US$415.8 million) of assets to Pengrowth Corp. and the rest, about C$280 million (US$211.7 million), to one or more unidentified buyers. Nationwide, Sayer Securities tracked M&A deals worth about C$3.8 billion (US$2.87 billion) in first-quarter 2004, up about 36% from first-quarter 2003's amount.

Land sales. High activity levels are reflected by a boost in land sales through first-half 2004, due primarily to a huge increase in Alberta. The 31.7% increase in Alberta's land sale revenue single-handedly drove overall first-half revenues upward across Canada, as bonus levels in British Columbia and Saskatchewan were lower.

In western Canada, governments collected C$697 million (US$526.9 million) for 2.03 million hectares (C$343/ha) through June, compared to C$633 million for 2.49 million ha (C$254/ha) during first-half 2003. Of this, Alberta took in C$540 million for 1.46 million ha (C$369/ha) up 31.7% from C$410 million for 1.53 million ha (C$268/ha), according to DOB.

British Columbian revenues dropped 10.9%, to C$119.6 million for 310,621 ha (C$385/ha) from C$134.2 million for 307,800 ha (C$436/ha). Saskatchewan's 2004 revenues were C$36.7 million for 242,747 ha (C$151.26/ha), down 57.3% from C$86 million for 572,800 ha (C$125/ha) in 2003. Another highlight was the massive C$124.9 million collected in work permit bids by Northwest Territories for 219,513 ha.

Fig. 1. In search of new gas reserves, Akita Equtak Rig 63 drills on behalf of Devon Energy in the Mackenzie Delta region of Canada's Northwest Territories. (Photo courtesy of Devon Energy Corp.)

Drilling. Through the first five months of 2004, drilling surged to record levels, with DOB reporting 8,633 completions, or 33% higher than the 6,491 completed through May 2003. The figure surpasses the previous five-month record (8,407) set in 2001, noted DOB.

Producers are targeting gas in more than 70% of the wells drilled, while exploration has increased about 14% over last year, again driven by Alberta. Well permits are up 6.4%, with 10,931 licenses issued through May. Rig usage rose through first-half 2004, with an average 411 rigs working, up 6% from 388 in 2003. The six-month, all-time high is 434, set in 2001. All indicators show industry on track for another record drilling year in 2004.

The Canadian Association of Oilwell Drilling Contractors' (CAODC) 2004 forecast for new wells drilled remains at 18,023, unchanged from last October's projection. Rig utilization is expected to average 58%, with 394 rigs working out of a 681-unit fleet. In 2003, utilization was 63%, with 422 rigs working. The break-even point cited by the drillers is 55% utilization.

Meanwhile, the Petroleum Services Association of Canada (PSAC) is much more bullish, projecting that drilling will fall just short of 2003's record (21,802 wells), at 21,660 wells. The Canadian Association of Petroleum Producers (CAPP) is closer to PSAC's well total than that of CAODC. CAPP predicts another nationwide figure in excess of 20,000 wells, although the group expects the 2004 figure to be down about 5% from 2003's level.

World Oil's mid-year survey (see table) of 30 Canadian operators, large and small, indicates that PSAC and CAPP are on the right path with their projections. This group's data, which represent nearly half of all Canadian drilling, point toward a well total very close to last year's 21,000-plus figure. These data show that it may be possible to set yet another national drilling record in 2004. However, if that happens, the total will finish less than 1% ahead of 2003's number. Furthermore, the World Oil survey group indicates that the drilling pace will only speed up slightly for the balance of the year.

Production. Canadian production levels continue to decline, both for crude oil and natural gas. On the oil side, the shift from light and medium blends to heavy, bitumen and synthetic crudes has accelerated. Overall liquids production stood at 2.6 million bpd through first-half 2004, down 10% from the same time last year, at 2.9 million bpd. Natural gas output fell slightly, to 17.1 Bcfd from 17.2 Bcfd.

Oil sands development dominates Alberta, with $6.1 billion in spending planned for 2004, up 10.9% from 2003's level. Alberta officials are touting oil sands as the future of North American supply, promoting the vast resource to the US as a stable source of crude from America's closest ally.

OPTI Canada Inc., which partners with Nexen Inc. on the $3.4-billion, Long Lake steam-assisted gravity drainage (SAGD) project, recently completed a C$301-million initial public offering. The firm is exploring whether to develop a regional upgrader for the area with other producers.

Long Lake is 25 mi southeast of Fort McMurray and includes a 72,000-bpd upgrader that will use coke instead of gas to fuel its synthetic crude process. Work should start later this year, and the project will go onstream by 2007. A second optional phase would double upgrader capacity by 2011, to handle increased bitumen production of its own or from other producers.

In the same region, Canadian Natural Resources is evaluating whether to seek partners for its recently approved, C$4.9-billion Horizon oil sands project, although it is prepared to pursue the project on its own, regardless. Plant construction should begin in fourth-quarter 2004, and the facility will be fully operational in 2012.

To reduce costs and emissions, Suncor is pursuing the cogeneration angle for a second phase of its Firebag SAGD project. The Firebag and Millenium expansions should increase Suncor's capacity by 35,000 bpd, raising total output to 260,000 bpd.

On the East Coast, results remain mixed. On the positive side, Husky is proceeding with development offshore of Newfoundland's White Rose field, albeit in the very early stages. However, the firm has said that White Rose's gas potential may ultimately exceed its oil potential. First oil is expected in early 2006. During this summer, ConocoPhillips planned to shoot 6,000 km of 2D seismic offshore, in the Laurentian basin between Newfoundland and Nova Scotia.

On the negative side, the Canada-Newfoundland Offshore Petroleum Board recently lowered its estimates of Terra Nova field's reserves. Oil reserves are estimated at 354 million bbl, 13% lower than the previous level. Gas reserves have been chopped back to 44.9 Bcf, down 83% from the previous estimate of 269 Bcf.

EnCana also recently abandoned its Weymouth A-45 deepwater well offshore Nova Scotia. EnCana held a 55% share of the well's US$76 million cost. Its other partners were Shell Canada (30%) and Ocean Rig (15%).

MEXICO

The last 12 months brought many political and operational changes to the country's energy sector. For instance, three new energy ministers appointed three different undersecretaries of hydrocarbons. Then, there was the disappearance of major directorates in the corporate unit of national oil company Pemex. Last but not least, a reforming of the company's upstream operative structure took place. How these changes have affected Pemex, and its operational and investment strategies, is yet to be properly assessed.

The good news is that in 2003, the number of exploration and development wells drilled increased dramatically for the third straight year to 593, including 49 offshore. The official forecast for 2004 is a hefty 1,018 wells to be drilled, 157 of them for exploration. Natural gas wells represented two-thirds of the total drilled last year, yet it is interesting to note that the number of oil wells completed jumped to 124 from 28 the previous year, and offshore wells grew two-fold.

In addition, the country's annual rate of growth in the volume of oil and condensate produced was close to 6% in 2003, and more than 1% for the period through May 2004. Regarding natural gas output, 2003 marked the end of a five-year, steady descent in the production rate. Thus, the annual growth rate was around 1.8% last year and 1.5% for the first five months of 2004. In summary, Mexico is producing 3.4 million bopd and 4.560 Bcfgd. Oil exports have peaked during the past 16 months, at 1.86 million bopd, roughly a 9% increase over the 2002 average.

Pemex Exploration and Production investments for 2004 will be a record-high of $12 billion. As in the past few years, the greatest share of investment will take place in the northern Burgos gas basin, the Cantarell heavy oil complex, the Ku-Maloob-Zaap basin in the Bay of Campeche, and the Grijalva Delta's super-light oil basin in the southern state of Tabasco, plus the Strategic Gas Project (PEG).

The 40,000-sq-mi Burgos basin is Mexico's most promising area for non-associated natural gas development. In the last three years, 1,049 wells have been drilled in this area, and it currently produces 1.031 Bcgfd. This represents a 380% increase over the past 10 years. In 2003, PEG activities included the drilling of 42 exploratory wells and 6,000 sq mi of 3D seismic studies. It also accounted for the completion of 34 gas- and 15 oil-producing wells.

Cantarell produced an average 2.096 million bopd and 770 MMcfgd during 2003. Both rates are all-time records for the field. Meanwhile, Ku-Maloob-Zaap is being developed to maintain the country's heavy oil production platform. Officials expect that by 2011, it will produce 800,000 bopd and 282 MMcfd of associated natural gas. The Grijalva Delta basin project is most strategic to Pemex, due to its production of 60,000 bpd of low-sulfur, 44° API oil and 217 MMcfgd.

The bad news, in 2003, was that proven oil reserves decreased 5.9%, to 18.9 billion bbl, bringing the production/ reserves ratio to 11 years, a three-decade low. Although last year's oil reserves replacement ratio was a relatively high 45% (compared to the past decade's average of 26%), this figure is still far from the official 75% goal for 2006. Driven by strong internal demand, natural gas imports grew 28%, bringing the annual growth rate of gas imports to an average 48% during the 2000 – 2003 span. This is a bad sign for the already tight, natural gas market in North America.

Last year was also a very significant period in the history of Mexico's oil sector, because the first round of Multiple Service Contracts (MSCs) in the Burgos basin was bid. Five of the seven blocks were awarded to private companies to begin operations in 2004. Pemex hopes that the $4.35-billion joint investment for the five blocks will boost non-associated gas production by 430 MMcfd in 2006.

Nevertheless, the two major opposition political parties (PRI and PRD) argue that such contracts violate the Mexican constitution. Both parties have already tried to stop the contracts in Congress and through direct lawsuits, contesting the contracts' legality and denouncing senior Pemex officials. The hot political discussion around the issue creates a cloud of uncertainty, not only over the viability of a second round of bidding originally programmed to start between May and July 2004, but also over the risk for the companies operating the blocks awarded in the past round.

Influential senators have warned that if the Supreme Court of Justice rules that the MSCs are unconstitutional, the companies would not be refunded for expenses already made. This is because the contracts would have been “illegitimate” when originally signed. This is not the kind of message that potential investors want to hear.