North American
Outlook

It’s time to use the “B” word

Oil and gas demand is remarkably resilient to high prices. Books and pundits are saying that high prices are here to stay. Optimism abounds. We might as well face the facts: We’re in a boom.

United States by World Oil staff; Canada by Robert Curran, Calgary, Canada; Mexico by Sergio M. Galina Hidalgo, Mexico City

UNITED STATES

Most oil companies are flush with cash. If you’re one of the majors, you’ve probably been buying back some of your stock or raising dividends. You’ve also been buying just about anything else in the way of assets. And the money just keeps on pouring in. You don’t want to create a boom, because a boom creates high demand for rigs with the attendant high day rates. And you also know what usually follows a boom. So you set your budget low and let the money pass through more slowly. But those pesky independents have a mind of their own, and they’re drilling. For folks like us at World Oil, it’s about taking pulses and counting: operators, rigs and wells.

We have revised our overall US well drilling forecast for 2005 upward, by 3.9%. The resulting 41,517 wells would still be 8.7% above the actual 2004 count, as reported by state governmental agencies and other sources. This is the direction that our data took us, working from a state-by-state, district-by-district basis.

Some areas, such as Oklahoma, seem to be rig-constrained, and in addition, are drilling deeper and spending more time on location per well. Yet, other areas, especially Texas, have been steadily moving in rigs for the third year in a row, making it difficult to believe that growth of more than 20% and, in some cases, 30%, is possible from a first half-year to second half basis. Thus, even our upward revision will likely prove too conservative for 2005 as a whole.

The Reed Hycalog rig census of October 2004 would seem to indicate that the 1,736 land rig inventory means that there are plenty of rigs available, particularly using the Baker Hughes Inc. (BHI) rig count. That is not the case. BHI only counts rigs that are “significant consumers of oilfield services and supply” and actively drilling, i.e., “turning to the right.” This means that working rigs that are in transit, rigging up/ down, or on location but well testing, are not counted. Also, to some extent, rigs tend to stay in the states and regions that are their “homes,” not traveling cross-county often.

BHI says that there were 1,306 rigs working on land and along inland waters as of mid-July, compared to 1,114 at this time last year. Combined with Reed’s census, this would yield a utilization rate of 77%. However, RigData counts rigs differently, showing an upward trend of 1,333 (2003), 1,556 (2004) and 1,702 (2005). The latter number would yield a land rig efficiency of 98%. While there have probably been some additions to the rig fleet, there must also be some “flux,” that is, a few percent that are down for maintenance or repairs or between contracts. Our conclusion is that utilization rates are nearing their maximum, and further increases in US well drilling will be rig-constrained in 2006.

If we were to base our forecast on just the survey data provided by the majors, we would have to say that drilling will be up nearly 20% this year over last. Furthermore, second-half 2005 wells would be up 23% over the first half. While not a scientific survey, it does include nearly all of the major operators in the US, and that increase is fairly close to the BHI rig count’s gain.

The 120 independents, however, while also not a scientific survey, are wildly optimistic, stating plans, as a group, that would translate to an increase of 40% or more over last year’s activity. The difference between this group’s second-half and first-half 2005 drilling would be 26%, with some independents planning increases of 40% to 70%. The obvious question is where are all the rigs going to come from to sustain such levels?

In the Gulf of Mexico, the picture is quite motley. Most indicators that deal with rigs are up at least modestly. For example, as of mid-July, ODS-Petrodata tells us that there were 11 more rigs actively working in the Gulf than there were at the same time last year (122 vs. 111). They also say that the number of slack days between wells is down, due primarily to longer contract lengths. However, if we average the year-to-date BHI offshore rig counts for first-half 2004 and first-half 2005, we find that, so far, they are unchanged – up by only one rig. Another upside indicator shows that there was a slight increase in the number of exploration wells being drilled from a year-to-year perspective.

Everything else in the Gulf points down modestly. Our combined MMS and state offshore data show a decreased forecast for 2005, down 24 wells from 2004, to 939 wells. Permits show a drop from this time last year, from 535 in 2004, to 528 in 2005. Development drilling shows a decline from 169 in 2004, to 149 in 2005, as does the number of plans to drill, falling from 656 wells at this time last year, to 584 wells in mid-July this year. Possible reasons for the disparate data are mere hunches at this point. Well depths, which averaged 12,275 ft on the OCS last year, could be getting a little deeper, and time on location could be getting longer, especially, with the small uptick in exploration drilling. However, this conflicts with less slack time between wells.

Whatever the reason for the disparate data, we can safely say that the outcome going forward will be relatively stable in the Gulf, with no large surprises in either direction. In addition, the second half of the year will be up from the first half, as it was last year, although not likely as great of an increase as shown in the table. Of course, there must be some slight lowering of the first-half numbers, due to disruptions from tropical storms Arlene and Cindy, and Hurricane Dennis. Hurricane Emily threatened southern Texas but did most of its damage in northern Mexico. Impact on offshore US facilities was minimal, other than temporary personnel evacuations. In addition, MMS recently made some changes to its reporting system, which resulted in an underreporting of first-half wells.

So, in summary, absent a collapse in prices, well-drilling activity will be robust throughout 2005 and show good gains on a year-to-year and first-to-second-half basis. But without a flurry of newbuilds, 2006 will not see the same strong gains as the previous two years, due to lack of rig availability. It’s worth remembering that the BHI rig count is now over 1,400 rigs – nearly triple what it was just six years ago in April 1999.

	What 15 US major drillers plan for 2005 – Midyear update
	What 125 US independents plan for 2005 – Midyear update

CANADA

Buoyed by strong commodity prices and continued growth in world energy demand, Canada’s oil and natural gas industry is on a roll that approaches three years. With no end in sight, most companies’ balance sheets are firmly in the black, multiple prospects are on the go, and a bullish attitude exists about the future.

Concerns about long-term sustainability of conventional development remain, but high prices have turned previously marginal properties into certain money-makers. Yes, gas production has declined, overall, in Western Canada over the last several years, along with output of conventional light and medium crude blends. However, investment in, and production of, heavy oil and oil sands has increased.

Replacing reserves remains a concern for producers. High prices have led to development of properties with quick turnaround times but shorter reserve lives, particularly for gas. The mid-to-long-term outlook is less certain, but unconventional sources, such as coalbed methane, may have a future.

Doubts also remain about the alliance struck between the federal New Democratic Party (NDP) and the Liberal Party to preserve the Liberals’ minority government, and how that may impact E&P. The NDP and Liberals both support the Kyoto Accords, but how that might manifest itself is unknown. Critics have said that implementing Kyoto could cost industry C$40 billion.

Asset sales. With so many companies in strong financial positions, a number of big-ticket takeovers and asset sales have highlighted first-half 2005. In June, Calgary-based Precision Drilling Corp. announced the sale of its energy services and international contract drilling divisions for US$2.28 billion (about C$2.9 billion) to Houston’s Weatherford International Ltd., including US$900 million in cash and 26 million Weatherford shares.

In July, Houston-based Pogo Producing Co. paid C$2.2 billion (about US$1.8 billion) to acquire Calgary’s Northrock Resources Ltd., the Canadian subsidiary of Unocal Corp. Northrock has net production of 16,000 bpd of liquids and 85 MMcfgd. Also in July, Calgary-based Nexen Inc. said it was finalizing several deals to dispose of oil and gas properties across Western Canada for about $946 million. Combined output of the properties is about 55,000 boed, weighted 60% toward oil.

EnCana Corp. closed its previously announced C$400-million (US$320 million) sale of conventional oil and gas assets (about 6,400 boed) to StarPoint Energy Trust in July. Roughly 85% of these assets’ output is oil and liquids. In addition, EnCana has been reviewing bids for its assets in Ecuador, which may be worth about US$1.3 billion. The company also announced plans to sell its gas storage assets in early 2006.

In May, Enterra Energy Trust acquired High Point Resources Inc. in a C$250-million deal composed of a share swap and assumption of $67 million in debt. High Point’s production is about 3,800 boed. Finally, Devon Canada Corp. paid US$200 million (about C$160 million) in July for heavy oil, and conventional oil and gas leases from ExxonMobil Canada Energy. Output from the largely undeveloped lands is about 3,000 bopd.

Prolonged, high commodity prices have also heightened interest in higher-cost projects. The far north (Mackenzie Delta) remains a prospect, provided the entities involved can resolve disputes over issues associated with shipping gas southward. Some parties have threatened to walk away from negotiations over the contentious pipeline if certain demands remain on the table.

On Canada’s East Coast, Newfoundland’s government continues to seek a bigger piece of the revenue pie that has grown with continued high prices. After winning royalty concessions from the federal government, Newfoundland Premier Danny Williams has hinted that he might also consider tinkering with the existing royalty structure in an effort to further increase its share.

Meanwhile, in an effort to encourage more development, the Canada-Newfoundland Offshore Petroleum Board said it would allow offshore jackup rigs in certain areas of the Grand Banks on a seasonal basis. Previously, only semisubmersibles had been allowed, due to concerns about the jackup mobility in areas that often experience pack ice and icebergs. Husky Energy has expressed interest in using a jackup in the South Whale zone of the Grand Banks this summer.

In Nova Scotia, Anadarko Petroleum announced plans to build the US$650-million (C$810-million) Bear Head LNG regasification plant by 2008. Facility construction was set to begin this summer, including 7.6 Bcf of gas storage.

Oil sands. In Alberta’s oil sands, production has taken a massive hit through first-half 2005, as the big fire early this year at Suncor Energy’s plant has halved production at the site from 260,000 bpd to 130,000 bpd. Repairs will not be complete until September. A small fire at the Athabasca Oil Sands Project also lowered production slightly in the first quarter, although majority owner Shell Canada Ltd recently announced that the project had reached the 100-million-bbl mark in just over two years of production.

The production drop will also be felt by Alberta’s government, which is projecting oil sands royalty revenues to fall more than 70% in the current fiscal year. However, those numbers are expected to recover as production rebuilds and surpasses previous highs.

Canadian conventional oil output, like this Devon-operated site west of Rocky Mountain House, Alberta, continues to decline, having lost 4% last year. Photo by Kurt Abraham, Managing/ International Editor.

Despite the setbacks earlier this year, oil sands output and bitumen production should resume their growing dominance in the overall Canadian oil production landscape in 2006 and beyond. In fact, industry has more than C$60 billion of oil sands investment on the books, slated for expenditure between now and 2015.

Most recently, Imperial Oil filed regulatory applications to construct and operate its Kearl oil sands mining project, at a cost between C$4.5 billion and C$6.5 billion. Construction should begin in 2007, with 100,000-bopd production commencing in 2010. By 2018, capacity could reach 300,000 bopd. Imperial holds 70% of the project, with the rest held by sister company ExxonMobil Canada. Kearl Lake is about 45 mi north of Fort McMurray.

Another 20 mi to the north, the Chinese have a 40% stake in the Northern Lights oil sands mining project (via state-owned Sinopec Group), which was picked up in May for C$105 million (US$84 million). The C$4.5-billion project includes an upgrader and is set to begin output of 100,000 bopd in 2009 or 2010. Northern Lights is also mulling the use of coal at the mining site to fuel its plant operations.

And in April, China’s CNOOC Ltd., a major offshore oil producer, paid US$122 million (C$153 million) for a 16.69% stake in privately held MEG Energy Corp. MEG hopes to begin construction on a 3,000-bpd, steam-assisted gravity drainage (SAGD) pilot in the Christina Lake area this year. The pilot could lead to a 22,000-bpd commercial project in the same area.

The Chinese government’s interest in Alberta’s oil sands mirrors that of the US. After touring an oil sands mine near Fort McMurray in early July, US Treasury Secretary John Snow expressed appreciation for the energy security that the oil sands represent in North America. The Chinese have recently made other business overtures in Canada, including a deal to help bankroll Enbridge’s proposed $C2.5-billion pipeline to the West Coast, which could ship crude to Asia.

Meanwhile, North American Oil Sands Corp. and Paramount Resources Ltd. have acquired 160,000 acres as they gear up to file applications for an in situ oil sands project with regulators as early as the end of 2005. This is pending their stakeholder consultation process. The project’s size will be determined by further delineation drilling.

UTS Energy and Petro-Canada have closed the deal they struck last year in which Petro-Canada pays $900 million of the Fort Hills oil sands project’s next $1 billion in development costs, to earn a 60% stake in the 100,000-bpd site. This may include an integrated upgrader, for which a decision will be announced by mid-2006.

One of the biggest challenges facing oil sands development is the increasing demand for skilled labor, which has created an economic boom in the Fort McMurray area. Massive work camps are required to meet current labor demands, and this will only grow as construction begins on other projects. Local politicians and health officials are concerned that the city will soon be overwhelmed with increasing needs for infrastructure and health care, as Fort McMurray continues to grow at an accelerated rate.

Not far south, Imperial is taking steps to continue production at its 150,000-bpd Cold Lake thermal heavy oil project, with plans to drill at least 200 wells a year for the next 15 years. Imperial has recovered more than 750 million bbl from the in situ project since the first pilot in the mid-1960s.

Land sales. Matching the pace of activity across Canada in 2005, land sale bonuses set a first-half record, topping out at C$1.1 billion (US$880 million). The previous six-month high was $957 million (US$765 million), set in 1997.

Alberta once again led the pack, with a record C$758 million in bonus bids (up 40%), followed by British Columbia at $252 million (up 110%), and Saskatchewan at $69 million (up 86%). The Northwest Territories also received work commitment bids of $58 million. Last year, Alberta collected C$540 million, B.C. received C$120 million, and Saskatchewan took in C$37 million.

Drilling. Through the first half of 2005, drilling activity remained strong, but fell behind 2004’s record pace. The Daily Oil Bulletin reported 9,277 completions, 8.5% lower than the six-month total of 10,129 through June of last year. The drop in activity is due primarily to the extremely wet weather across much of Western Canada in May, and particularly June. The heavy rainfall caused severe flooding and prevented drillers from accessing leases.

Producers continue to target gas about 70% of the time. Exploration activity has increased about 11% over last year, driven almost solely by Alberta activity.

Rig activity is also up through the first half of 2005, with an average 598 rigs working out of 723 available in the first quarter, and 280 rigs working out of 735 in the second quarter, according to the Canadian Association of Oilwell Drilling Contractors (CAODC).

CAODC has also adjusted its 2005 forecast downward slightly, to 24,099 wells drilled, from the 24,205 it predicted last October. The lower total reflects inclement weather in June, as well as more drilling time per well than originally projected. The association predicts an average 484 rigs working in 2005, out of a fleet of 742, for 65% average utilization. Meanwhile, the Petroleum Services Association of Canada also adjusted its numbers down slightly, to 23,825 wells for 2005.

World Oil’s six-month survey of Canadian drillers demonstrates a continued focus on gas, with 81% of all wells drilled targeting gas. Last year, producers said they would target gas 65% of the time. Activity looks to increase among survey participants, supporting the predominantly bullish outlook in Canada. The World Oil survey group represents an impressive 55% sample of all Canadian drilling.

Total second-half drilling should increase by almost 28% from the first half, indicating a final 2005 well count of 23,750. The largest percentage increase is expected in Saskatchewan (up 187%), followed by Alberta (up 32%). Drilling in British Columbia is projected to decrease by 42%.

Production. Output levels continue to decline in Canada for crude oil, although gas production is up slightly at mid-2005. On the oil side, the shift from light and medium blends to heavy, bitumen and synthetic crudes continues, although the significant decrease at Suncor’s oil sands plant has reversed that trend this year. Overall liquids production stood at 2.4 million bpd, down 8% from 2.6 million bpd through first-half 2004. Gas output was 17.4 Bcfd, compared to 17.1 Bcfd last year, a modest 1.8% increase.

On the East Coast, Husky is on track to see first oil from its C$2.35-billion (US$1.9-billion) development of Newfoundland’s White Rose field offshore before the end of 2005. The FPSO vessel is scheduled to move to the field in August, about 220 mi east of St. Johns. White Rose has estimated recoverable reserves of 250 million bbl.

(Mr. Curran is a Calgary-based freelance writer.)

MEXICO

During most of 2005, the main issue of concern for Mexico’s oil industry and national oil company, Pemex (which holds a monopoly over all upstream activities), has been the legal initiative regarding a new fiscal framework. This initiative could make more resources available for Pemex’s operation and investments.

Political/ regulatory situation. After intensive lobbying and negotiation of a political compromise between the three major parties – not an easy task considering the impasse experienced by the Mexican Congress for the past three years – the new law was passed by the Senate in April and ratified by the Congress in late June 2005. Essentially, it will lower the tax rate that Pemex has to pay to the government for extracting oil and gas. Among other things, it will also allow the company to deduct exploration investments, thus generating a much needed fiscal break for such activity.

Under the new tax framework, moderate estimates of projected additional resources for the company could be up to $2.5 billion for 2006. However, it could be much more than that, taking into account current high prices of the oil and gas produced. The real trick to maximizing the benefit for the company is to maintain its recent year’s budget levels allocated by the federal government.

For instance, during most of the 2000 decade, Pemex has been enjoying historically high investment budgets. Yet, because most of these investments have been financed through PIDIREGAS, a financing (debt) mechanism, the company already has to direct important amounts of its yearly budget to pay for accumulated debt. Therefore, in light of this new law, the federal government may be tempted to decrease the allowed debt level for Pemex or its operational budget. This would dramatically affect the company’s investment plan continuity. In summary, a probable downward adjustment to the budget could very easily erode all potential gains to PEMEX from the new tax regime.

Mexican drilling increased 20% last year, and is expected to gain another 9% during 2005. Photo courtesy of Pemex.

Exploration/ drilling. In 2004, the PEMEX exploration and production subsidiary’s (PEP) investment budget was more than $12 billion. This year, it is expected to be about $13 billion. Both figures are record highs. The amounts invested allowed PEP to drill 103 exploration wells and 624 development wells during 2004, for a record total of 727 wells. That figure is 20% larger than the total for 2003. The drilling success ratio for the 103 exploration wells was 41%, since 11 wells turned out to be oil producers, and 31 wells produced gas and condensate. The upward trend in drilling wells will continue in 2005, as PEP plans to drill 790 exploration and development wells.

In addition, 27 new producing fields, mostly gas fields, were discovered in 2004. The new discoveries accounted for 920 million barrels of oil, equal to 57% of last year’s total production. This oil reserve replacement ratio compares most favorably to the 26% average of the past 10 years.

Development/ production. Last year, in an effort to further tap offshore oil and non-associated gas reserves, and boost production, PEMEX directed about 70% of its investment to the following areas:

• Cantarell heavy oil complex and the Ku-Maloob-Zaap basin in the Bay of Campeche
• The Northern Burgos gas basin
• A set of 18 E&P gas projects known as the Strategic Gas Program.

In 2005, Pemex’s production goals are set at 3.44 million bopd and 4.86 Bcfgd, a 2% and 6% increase over last year’s production levels, respectively. However, most of the oil produced will continue to be heavy. This is a negative trend that has seen Mexico’s oil mix change from 47% heavy oil in 1995 to 73% in 2004.

In contrast, the non-associated natural gas production has grown from 16% to 39% of the total gas produced over the same period. These data show that while the efforts of PEMEX to produce more oil have been successful, the lack of new discoveries and development of light crude is evident. On the other hand, although the company has to import larger volumes of gas every year, it has been capable of increasing the development of non-associated natural gas. This will help to cope with the 6% average annual growth in national demand during the past decade.

This last point is a particularly important achievement in the context of the legal uncertainty that has cast a shadow of doubt over the final contribution of multiple service contracts (MSCs) awarded to private companies in 2003. These MSCs’ purpose was to develop and produce non-associated gas. As of the end of last year, they had resulted in the drilling of 22 wells that had begun to produce about 0.1 Bcfgd, still far away from the 0.43 Bcfgd goal expected by 2006. Unfortunately for PEMEX and its plans, many analysts believe that these contracts will eventually be canceled after undergoing further legal scrutiny. 

What 30 Canadian drillers plan for 2005 – Midyear update