North America

Drilling will be steady to up

Canadian drilling will be good, but down from last year’s record pace. Mexico and the U.S. should see flat levels on a first-half/second-half basis – an improvement from spring lows.

Canadian section by Robert Curran, Calgary, Canada

United States. Last February, World Oil’s forecast cautioned that the first half of 2002 would see reduced E&P activity, due principally to weak oil and gas prices that began in the third quarter of 2001. However, an improved second half was expected, since all the fundamentals were in place to support higher oil and gas prices, and thus, increased drilling. Now, with six more months of data, several disconnects are emerging that indicate mixed second-half results.

Although West Texas Intermediate (WTI) crude started the year below $20/bbl, it improved to $25 as the first half ended. WTI, in fact, averaged $26.25 for the second quarter of 2002. Natural gas prices followed a similar trend until summer, when storage builds caused them to weaken. This was the first disconnect – despite consistently rising prices, the number of working U.S. rigs declined through most of the first six months. June rig activity figures may finally be indicating a reversal, and they may be a precursor to an improved second half.

As opposed to much of the U.S., where second-half drilling will be higher, Texas enjoyed good activity levels early in 2002. A prime example is this well site in the Bossier Trend of Henderson County, in Texas Railroad District 5. (Photo courtesy of Ivanhoe Energy)

Highlights of World Oil’s revised 2002 forecast include:

• Second-half U.S. drilling will total 14,592 wells, about flat with the first six months.
• Full-year 2002 drilling will give rise to 29,233 wells and 146 million feet of hole, down 11% and 12%, respectively, from 2001.
• U.S. Gulf of Mexico drilling will drop 2.4% in the second half, totaling 911 wells for 2002.
• The U.S. rig count will average 840 rigs during the second half, bringing the yearly average to 826 rigs.

The second disconnect to emerge was an apparent rise in rig efficiency (e.g., more wells per rig) during the first six months of 2002. In several key states or districts, the number of wells drilled through June was significantly higher than rig averages would justify, and, if the trend carries through the last six months, year-end totals would exceed 2001 completion levels. This seeming rig efficiency improvement probably includes a carryover of 2001’s high activity levels and shallow oil well drilling with small rigs that fall below the Baker Hughes "radar."

A similar situation occurred in the Gulf of Mexico, where first-half wells totaled 461. When annualized, this would produce 920 wells for the year, or almost as many as in 2001. Many of these first-half wells were likely begun toward the end of 2001, but finished early this year, as rigs were starting to go out of service. World Oil’s second-half Gulf of Mexico forecast of 450 wells signals an activity decrease. However, if 2001 carry-over wells could be deducted from first-half drilling, an increase would probably be indicated.

At OPEC’s June meeting, the Saudi oil minister listed three conditions that the cartel would consider before increasing production quotas: 1) the OPEC basket price, which some Gulf sources have suggested needs to be above $25/bbl; 2) oil inventory levels; and 3) the world oil supply-demand outlook next year. Although WTI price averaged almost $2/bbl lower in June than in May, it was rising at month’s end. By July, it was more than $1 above the June average of $25.50. June marked the fourth consecutive month that OPEC’s basket price averaged above $22, which is the lower end of the target range. This basket price has been above $22 since March and is projected to remain within the target range ($22 – $28) before rising at year-end.

Gas prices are more problematic. Spot wellhead prices have generally held above $3.00/Mcf since mid-March, despite a volatile market in which spot prices bounced up or down daily by as much as $0.25/Mcf. Just about any market information, such as weather or storage reports, has had an exaggerated effect on spot prices. Gas in underground storage has remained unusually high for the past several months. By the end of June, storage was about 19% above the previous 5-year average for that month. By the end of summer, the winter storage outlook will be much clearer.

The third disconnect emerged from two operator surveys. When asked for planned wells the second half, operators responded with enthusiasm. But when queried about capital spending, they were more reserved. However, keep in mind that the drilling survey compares first and second-half plans, whereas the spending survey primarily compares year-to-year plans. Thus, although spending for 2002 is indicated to be down, this does not imply that second-half spending will be lower than during the first six months.

The 19 companies with major drilling programs and 176 independents responding to World Oil’s survey said they would raise overall drilling levels by 20% in the last half. Operators continue to focus on development, which will account for 88% of second-half wells.

While planning to increase drilling by 15%, majors see more emphasis on exploration, and say wildcat drilling will more than double. Independents are more bullish overall, with plans to raise drilling by 51%. They also will be exploration focused the second half, and plan nearly double the exploration wells drilled the first half.

In its midyear survey of operators’ E&P expenditures, Salomon Smith Barney indicates U.S. oil companies will reduce spending by 15.5% this year, compared to 2001. This decline is only slightly deeper than reductions indicated last December. Independents, who are historically quicker to modify their plans, will tighten spending 23.5%, compared to a 19% cut projected six months earlier. The 159 independents responding plan to spend $16.5 billion in 2002, compared to $21.5 billion spent in 2001. The ten major oil companies surveyed say their 2002 expenditures will fall 3.2% to $13.4 billion.

On a more optimistic note, Salomon Smith Barney also asked operators whether they plan to maintain, increase or reduce second-half spending. Fifty-six percent of independents said they would raise spending, while 13% noted reductions. Major operators were more reserved, with 40% indicating spending increases and 20% planning cuts.

Canada. There are signs that more optimism may be returning to industry boardrooms. Oil prices are about where they were a year ago, providing a semblance of stability. Gas prices are currently about 30% lower than they were a year ago, but the combination of high North American decline rates, reduced drilling and rising U.S. demand is expected to drive prices upward in 2002 and into 2003.

M&A activity slowed this year compared to recent historical levels. However, there have been two notable deals: in early April, the US$19-billion merger of PanCanadian Energy and Alberta Energy to form EnCana Corp.; and in May, Canadian Natural Resources’ $1.5-billion takeover of Rio Alto Exploration, which had been rumored since last year.

EnCana, now North America’s largest independent oil and gas company, put a stamp on its new identity with a $300-million acquisition of Colorado gas properties from El Paso Corp. The properties include 38 MMcfd of gas production, 500 Bcfg reserves, a gas plant and gas gathering system.

Despite long-term export prospects, gas exports to the U.S. are slightly behind the pace set in 2001 for volume, while revenues have fallen substantially. In February, export revenues from natural gas fell to $70.6 billion from $1.96 billion in 2001. Meanwhile, if numerous oil sands developments proceed to the operation phase, many speculate that Canada may emerge as the top crude supplier to the U.S.

   Land Sales. Mirroring this year’s activity, land sales revenues are almost 60% below record 2001 levels, although per-hectare prices are 45% lower, possibly indicating a recovery may occur in the second half of 2002. First-half land-sale revenues for western Canadian provincial authorities were valued at $255.7 million, compared to $619.7 million in the same period last year.

Alberta collected the highest amount through June, $158.0 million, down more than 60% from 2001, followed by British Columbia at $81.7 million, Saskatchewan at $15.9 million and Manitoba virtually dormant, at $5,167. The average price per hectare in Alberta was $112, compared to $224 in the first half of 2001. In British Columbia, the average was $269 per hectare, vs. $374 last year.

   Drilling. Through the first half of 2002, drilling levels fell significantly compared to 2001. Of course, much of this is attributable to the usual retreat due to the spring meltwater. According to the Daily Oil Bulletin records, there were 7,028 wells drilled through June, 29.7% less than last year’s record six-month total of 9,998. Although below last year’s levels, 2002 should still rank among the top five drilling years in Canadian history by year-end.

Overall, the outlook has improved as 2002 progresses. The latest drilling forecast from the Canadian Association of Oilwell Drilling Contractors calls for 14,323 wells to be drilled in 2002, up 5% from the 13,600 wells projected last September. Rig utilization is expected to average 50% for the year, with an average of 315 rigs working out of the total fleet of 657. In 2001, the fleet averaged 63% utilization. The nominal break-even point for average activity cited by the drillers is 55% utilization. In May, Petroleum Services Association of Canada (PSAC) also revised its forecast upward to 14,000 wells for the year, after originally projecting a total of 13,386 in January. Of that total, 8,614, or 62% will be gas wells, says PSAC.

Rig 60 is the first of four new rigs being utilized in Canada’s MacKenzie Delta by Akita Equatak, a joint venture between Akita Drilling Ltd. and Inuvialuit Development Corp. These new rigs are under long-term contracts, reflecting the faith held by these firms and their oil company customers in the long-term future of Canada’s northern territories. (Photo courtesy of David Watt Photography)

   Production. Canada’s oil and gas industry reached a crossroads in early 2002. For the first time, bitumen production exceeded conventional crude in Alberta. Oil sands developments have taken center stage, drawing capital away from conventional exploration and other development projects.

Total crude production and equivalent, including bitumen, synthetic and natural gas liquids, was 2.93 million bpd through June, up 3.5% from 2001. Conventional light and medium crude production was up 1.4% to 824,000 bpd, compared to last year. Bitumen and heavy oil production was up 1.3%, to 902,000 bpd through June for the comparable prior-year period. Synthetic production is on its way to another record this year, with output from the Syncrude and Suncor mines increasing dramatically to 425,000 bpd, up 21.4% from 2001. The huge increase is largely due to Suncor’s Millennium Project, which is now onstream.

Oil sands development is expected to surge further over the next 10 years, as there are now several projects planned, which represent more than $32 billion in spending. As oil sands increase their role, the Alberta government has been pushing for recognition of the size of the reserves, which rival those of Saudi Arabia. The IEA and IPA, for example, previously only listed reserves that were booked through producing leases – about 7 billion bbl. But the province says that 177 billions bbl of these tar-like deposits are recoverable reserves using existing technology, with about 315 billion bbl ultimately recoverable.

As for conventional oil, Husky Oil Operations Ltd. and Petro-Canada will proceed with perhaps the $1.52-billion White Rose development, which is scheduled online by late 2005. The companies plan to build an FPSO with a storage capacity of 940,000 bbl and peak production of 92,000 bpd. Husky’s Terra Nova project began production in January, adding to an overall offshore production increase of 20% in the first half, to 169,000 bpd. Terra Nova will add to higher production figures for this year. Meanwhile, resolution of a dispute between Newfoundland and Nova Scotia over provincial boundaries is positive for those areas.

On the down side was Chevron Canada Resources’ decision to put aside its Hebron project, citing a lack of technology to make project development economical. Hebron comprises perhaps 325 MMbbl in heavy oil reserves and is sited in a complex geological structure.

As for natural gas, production dropped to 17.2 Bcfd, down 2.8% from 2001. Canada’s East Coast has been getting some mixed reviews lately. Shell Canada Ltd. recently drilled one of the most expensive dry holes in Canadian history – a $90-million duster – not far from the Sable Island gas play. This was Shell’s fifth consecutive dry hole in the area. Additionally, in early July, a survey by Deloitte & Touche LLP indicated that Canadian oil executives believe Canada’s north holds far more promise for new natural gas discoveries than the East Coast.

   Mexico. An increasingly important player in world oil markets, Mexico ranks fifth in oil production and eighth in proven oil reserves. A quasi-OPEC nation relative to production quotas, Mexico’s oil exports averaged 1.61 MMbpd in the first quarter 2002 – slightly above its 1.56-MMbpd OPEC quota – and are currently inching higher.

Gas production, which averaged 4.51 Bcfd in 2001, falls shy of demand, requiring the import of 300 MMcfd in 2001. Skyrocketing demand may cause that number to double during the next 12 months.

A bright spot in the gas-supply picture are four consortia with plans to build LNG regasification terminals on the California Baja coast. Shell Gas & Power, Phillips, Sempra Energy and Marathon, respectively, lead the four consortia. These could be online within the next three to four years. More than a dozen other LNG terminals are under review. Although it is envisioned that most of the gas would be U.S. bound, Mexican demand may play a role.

Another positive development is the discovery of three, potentially giant, dry-gas fields that could boost current gas reserves by 25%, according to Pemex general director Raul Munoz Leos. The three discoveries are: Lankahuasa field, located onshore Veracruz state; Playuela field, offshore Veracruz; and Hap field in the Bay of Campeche. Munoz Leos characterized the discoveries as "happening once every 15 to 20 years."

Congress approved over $14 billion for E&P projects for 2002 – nearly doubling the past four years’ average. Three areas will receive the lion’s share of the budget: Cantarell oilfield complex in the Bay of Campeche, Burgos basin in the northeast Grijalva River Delta in the southeast.

Pemex continues to try and make inroads in privatization. However, it is unlikely that the constitution would be changed to allow subsurface asset sharing by private and foreign firms. Current participation is limited to certain infrastructure development and services.

Pemex has proposed a way around these constitutional restrictions. It involves bundling various upstream service contracts and granting a degree of autonomy over a given region. Further, such contracts would be dependent on unit prices, avoiding any element – or at least the appearance – of production sharing or profit sharing, both of which are constitutionally forbidden. The best place to apply the new scheme would be in the gas-rich Burgos basin, since it appears that the country could have a gas-supply shortfall of 1 to 2 Bcfd within the next eight years. A model contract should be ready to submit to Congress early this fall. Complicating the matter is a $170 million "Who stole the money?" scandal involving Pemex, politics and the labor union.

The Cantarell nitrogen-injection project was completed by year-end 2001. Production continues to ramp up, and could rise as much as 60% from pre-project levels. Appraisal work continues on Sihil field, a new discovery that may hold well over a billion bbl of oil in reserves.

Others. The considerable increase in oil production in recent years continues in Cuba, averaging 52,000 bpd last year. The past year saw new development in Yumuri, Canasi and Seboruco fields, as well as in workover efforts in mature, heavy oil fields onshore.

   Greenland. Just one bid was received "from a major" in a licensing round that closed in July 2002. A decision as to the awarding of the western offshore acreage should come this fall. Statoil and Phillips relinquished the last two remaining licenses in the west (Fylla West and Sisimiut, respectively).

   Nicaragua has at least four oil companies that are qualified to bid on blocks located on both Pacific and Caribbean coasts, as well as inland. Awards will be decided in 2003.

In a related matter, Guatemala is saber-rattling over a maritime border dispute regarding Nicaragua’s offshore leasing plans. It has asked the International Court in the Hague to rule on the matter. Guatemalan President Portillo recently canceled a production sharing contract with tiny Compania Petrolera del Alantico SA. The PSC, which covered an inland lake, was strongly protested by environmental groups.

	Table:Midyear revision, 2002 U.S. drilling forecast
	Table: What 35 Canadian drillers plan for 2002 – midyear update