SPECIAL FOCUS: NORTH AMERICAN OUTLOOK

North American drilling:
Growing, but at a slowing rate

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

US DRILLING
The Boom continues

A couple of years ago, we thought that the price-led expansion would be constrained, either by lack of personnel, lack of rigs or rig components, lack of prospects, or lack of some critical well construction element, such as pipe. We were wrong. The resolve to find ways around these obstacles prevailed. But, there are clear signs that the rate of well drilling is slowing. There is talk of stacked rigs-normally a sure sign of trouble. But the Baker Hughes rig count keeps climbing. The explanation for these two seemingly incongruous facts is that newbuilds have been added at a faster rate than the rise in the rig count. This increase has been a modest 5.6% the first seven months of the year, which is about a third of the rig count increase in 2006.

Since this is a mid-course correction of our February forecast, we see that we were a bit too optimistic at that time, when we forecasted 52,208 wells. Based on operator surveys, state data, well permits, rig counts and other sources, we now forecast that 2007 will see 49,215 wells drilled-a spare 0.6% increase over 2006’s 48,929 wells.

Operator surveys. This update of World Oil’s survey includes 18 major US drillers (integrated companies and independents with large drilling programs) and 132 independents. The optimism expressed in February continues, but has tempered the total number of wells planned for 2007.

Midyear revision, 2007 US drilling forecast

What 18 US major drillers1 plan for 2007-Midyear update Click table to enlarge.

Major downward revisions from our February survey occurred in California (520 wells), Colorado (865 wells), Kentucky (1,252 wells-possibly a reporting error) and Wyoming (641 wells). Upward revisions were modest and not sufficient to overcome the general pullback. Some of the stronger upward revisions were in Arkansas (204 wells), Pennsylvania (50 wells), Tennessee (37 wells) and Texas (169 wells). Even though this survey is not collected scientifically, the responses gathered represent a very large sample of major drillers’ plans.

Rigs. Counts often show large differences among the rig-counting services (such as Baker Hughes, Smith International and RigData), which is something that we see routinely, given the different methodologies. We see similar differences between the rig counts and the state agencies’ well data. Sometimes, even when all rig counts go in the same general direction and magnitude, the well-count data show the opposite trend. This is usually due to rigs too small to be counted by most surveys, especially when drilling coalbed methane. Alternatively, when an area is experiencing a rapid change in drilling activity, the reporting agencies become swamped and lag in their ability to gather and report well data.

Newbuilds have strongly entered the market and in some cases have had a downward effect on rig efficiency (wells/rig)-seasoning crews takes time. There are some areas that could use more rigs, but the dayrates being charged are pulling rigs to the most prospective regions, leaving some operators and trends waiting for a softening rig market before continuing development plans.

As of mid-July, the Baker Hughes’ and Smith International’s working rig counts have increased about 6%, adding some 100 rigs to around 1,730 rigs. There appear to be enough rigs to sustain present drilling levels.

Prices. The general picture, as far as gas prices go, is that demand is soft, supply is easily adequate and storage levels remain stubbornly high. The situation is identical to last year, when traders were hoping for either a very hot summer or an active hurricane season to reduce storage levels.

What 132 US independents1 plan for 2007-Midyear update Click table to enlarge.

Adding to supply, the 1-Bcfd-capacity Independence Hub saw first gas in late July. It will begin a ramp-up process as it brings on 14 wells over the coming months, each capable of producing in the 50-MMcfd range. If there is a low-price scare and it results in significantly reduced drilling, such a downturn would be short lived, because unconventional wells are a growing portion of supply (40%) and storage levels would quickly be reduced. In the Rocky Mountain region, a price scare has already occurred with wellhead prices dropping as low as $1.87/MMBtu in selected markets, but averaging $4.25/MMBtu year-to-date, according to the Energy Information Agency’s Natural Gas Weekly Update.

According to Citigroup’s E&P Spending Survey: 2007 Midyear Update, the industry is using planning prices of $57.05/bbl for WTI crude and $7.08/Mcf for natural gas. Compared to last year, these expectations are up $3.52/bbl for oil and down $0.25 for natural gas. Overall, their survey reveals that global industry spending is advancing at a 7% rate; however, US spending is up 5.7% while Canadian spending is down 6.6%. It is noteworthy that much of this increase goes into higher spread rates, not just more boreholes.

Area highlights. Drilling is up overall from last year, but down from our forecasted numbers presented in February’s issue. On land, the drilling market has separated into two distinct segments, conventional and unconventional drilling (see page 67). Conventional drilling fluctuates with the seasons and/or commodity price, while unconventional activity seems unaffected by either at this time. Most unconventional drilling is horizontal, seeking coal bed methane or shale gas.

The big theme this year is that coalbed methane drilling is down from 2006, particularly in Kansas (off 641 wells) and Wyoming (off 605 wells). The reasons vary (see page 91). In Kansas, CBM drilling soared to 1,828 wells in 2006, and this year the frenzy is pulling back to a projected 570 wells. In Wyoming, environmental problems with dewatering threaten to increase costs by requiring more reuse, treatment, reinjection, or some combination of these. Add to this the fact that the Rocky Mountain area is overproducing relative to its infrastructure. Local storage levels are very high, and pipeline capacity is not sufficient for exporting to big, gas-thirsty markets. The Rockies Express (REX) pipeline is partly complete, from Meker, Colorado, through the Cheyenne hub and into Missouri at this time. But the full length won’t be finished all the way to Clarington, Ohio, until June 2009, according to the schedule.

What 19 Canadian drillers plan for 2007-Midyear update1 Click table to enlarge.

Canadian drilling, 2007 provincial forecasts- Midyear update1

The pullback in CBM is matched by increases in unconventional shale gas drilling in the Barnett Shale in North Texas and the Fayetteville Shale in Arkansas (see page 23). The Fayetteville trend has been very active this year and one operator, Southwestern Energy, has drilled 68 wells thus far in 2007, keeping 20 rigs drilling in the play.

In the Gulf of Mexico, operators are on a pace to drill 799 new wells, down slightly from our February estimate of 804 wells and from the 2006 total of 813 wells. GOM rig count continues to drop (see page 59) as rigs leave the Gulf for better contracts elsewhere. But footage estimates are increasing, as operators drill deeper wells on the shelf and in new deepwater trends.

Most of Texas’ drilling will take place in Districts 5, 6, 7B, 7C, 8 and 9 in the Barnett Shale play. According to the Texas Alliance of Energy Producers, the Texas PetroIndex has reached the highest level ever at 227.6, up significantly from 100, its 1995 base-year value. The monthly index uses 25 metrics including prices, rigs, completions, volume, value and employment, among others. In comments at a recent press conference, economist Karr Ingham noted the strong rise in the index over the past few years capped by a leveling off over the past few months. He found the leveling significant, since in earlier booms the activity dropoff occurred suddenly and down substantially over one or two months. The Alliance thus confirms independently what World Oil has found in its survey. The industry appears to be reaching a sustainable high drilling level.

In Ohio, a significant legislative change occurred that has opened new acreage for development. In September 2004, a law was passed that normalized the distance-from-housing drilling regulations across the state. Cities had widely varying distance regulations that were hampering drilling. Now, operators can drill closer to existing structures uniformly across the state. According to state officials, 25% of the state’s new drilling is in these newly opened “urbanized” drilling areas. The Clinton sandstone, Knox formation and Trenton-Black River trends will see the most action. World Oil forecasts a 12.5% increase in drilling to over 1,000 wells.

One of two oil gatherers is having problems and may go out of business in Tennessee. Other oil gatherers are stepping in to help, but transport distances are driving up costs and reducing potential profits for producers. This has dampened drilling activity and reduced anticipated drilling by 47 wells to 395 wells for 2007.

Oklahoma will see a nearly 12% increase in drilling led by the deeper western basins. Most rigs are under contract and locked up, leaving few available for small operators to use on one- or two-well prospects. Rigs are also being drawn out of state south to the Barnett Shale play. The state increased permit costs, making it a bit more expensive to drill, and large operators have leased major prospective acreage blocks, which is squeezing out the smaller players. Even with these constraints, the state will see over 3,000 wells drilled.

Rig counts are stable in Utah at 37-40 rigs. These rigs are mostly drilling development wells, but permits are down slightly. According to state officials, the Ferron CBM play in Carbon and Emery counties is drilled out. Still, the state will see a 16% increase in wells drilled.

Drilling in Colorado has shifted between the various basins over time. At one time, the D-J basin was the hot spot; now the Piceance basin is the operator’s choice. They are seeking the Williams Fork and Mesa Verde formations as preferred targets. Well reports are down according to state officials, likely due to lags in reporting CBM drilling. The San Juan and Raton basins still have solid CBM activity. But, World Oil anticipates a slowing in activity, dropping almost 900 wells from our February estimate. The state will still see over 4,000 wells drilled in 2007.

Coalbed methane drilling has been a mainstay of Wyoming’s activity. This year will see a significant slowing. While we had anticipated a 4% increase in our February forecast, drilling has slowed markedly and we have reduced our forecast almost 13%, dropping 487 wells from the 2006 figure. The state will see almost 3,300 wells drilled.

Much of this retrenchment is driven by a drop in wellhead gas price. Early in the CBM play, gas was selling for $7.60/Mcf, but now it has dropped to as low as $2.40/Mcf in some places, greatly reducing the economic incentive to drill. Pipeline capacity is the constraint and that won’t be eased until after the REX pipeline is fully up and running in two years.

Another issue is the disposal of produced waters. Many of Wyoming’s rivers flow into Montana and the differing state environmental limits are creating cross-border problems. The states must come to some agreement and producers must take more care with their water disposal, but it has not yet caused a significant drilling constraint.

About these statistics. World Oil’s tables are produced aided by data from a variety of sources, including the American Petroleum Institute, ODS-Petrodata Group, the Texas Railroad Commission and most other state regulatory agencies. In addition, 150 operating companies with drilling programs responded to this year’s survey. Our survey is not scientifically randomized and new environmental and political challenges may emerge at any time. Please note credits and explanations in table footnotes.

World Oil editors try to be as objective as possible in this estimating process to present what they believe is the most current data available. It is realized that sound forecasting can only be as reliable as the base data. It should be noted that well counting is a dynamic process and most historical data will be updated over a period of several years before the “books are closed” on any given year.

CANADA

It had to happen. When the oil patch starts surging, there are always people who predict that the inevitable downturn in activity is imminent. But after four years of unprecedented growth, the downturn still came as a bit of a shock.

Economics. The culprit was a prolonged spate of soft natural gas prices. Also, the Canadian dollar, surging to levels not seen in three decades, is virtually at par with the American greenback, substantially decreasing the value of Canadian exports. The shortage of skilled workers continues to be a source of concern. And there are a couple of political concerns: proposed federal and provincial environmental controls and Alberta’s review of its royalty structure.

The increasing and unanticipated strength of the Canadian dollar is proving troublesome for producers. Despite a surge in stock values on the Toronto Stock Exchange this year, profits are expected to drop for the majority of producers. They rely on the premium gained by exporting their products for American dollars. Some industry experts maintain that every 1% increase in Canadian Loonie value costs producers $1.3 billion annually.

An ongoing source of concern remains the lack of skilled workers. Alberta Employment recently released data that indicate a shortfall of 40,000 oil workers in the province within eight years.

And yet many of the fundamentals driving the upsurge over the past several years remain firmly in place. Canadian producers recorded first-quarter 2007 cash flows just slightly lower than the first quarter of 2006. Surging world demand has sustained remarkably bullish oil prices. Concurrently, declining North American supplies of conventional crude have convinced producers that the multi-billion-dollar investments necessary to recover a portion of Alberta’s massive oil sands developments are worthwhile.

Politics. The belief in the worthiness of developing oil sands remains despite Alberta’s ongoing royalty review, which was launched by the new provincial administration after increasing public and political pressure. Since the review’s inception, the industry has mounted an extremely well-organized, public campaign to convince Albertans-and Canadians in general-that the current royalty structure is not only fair, but in fact benefits the province and the country through encouraging development that boosts the economy.

Skeptics have criticized the review as little more than a political maneuver from a government that can’t afford to risk the revenue streams generated by an industry with record activity.

Industry associations, including the Canadian Association of Petroleum Producers (CAPP) and the Small Explorers and Producers Association of Canada (SEPAC), have both argued that spiraling costs paid by producers have to be considered when assessing the royalty regime. Others, like the Petroleum Services Association of Canada (PSAC), have said that the recent downturn in activity proves that changes are not required.

In response, Alberta Premier Ed Stelmach said that his government will take into account factors like higher costs, the Canadian dollar, and the unique characteristics of unconventional resources.

On the environmental front, a change appears to be underway regarding public opinion. Very few Canadians seem prepared to give up gas-guzzling SUVs or embrace a less energy-intensive lifestyle. Nevertheless, there is a growing sentiment that “something” must be done about the environment and, in particular, Canada’s status as one of the planet’s highest consumers of energy per capita.

Although the federal government has resisted following through on Canada’s Kyoto Accord obligations, it has introduced the Regulatory Framework for Air Emissions, a made-in-Canada solution. It will reduce greenhouse gas emissions 20% by 2020, and 65% by 2050. Not surprisingly, environmentalists are outraged that the government is not introducing stricter requirements, while some industry groups are complaining that the goals will cause them (and the country) economic hardship.

Canadian conventional oil production, symbolized by this Shiningbank Energy Income Fund (now PrimeWest Energy Trust) well along Alberta provincial highway 22 near Cremona, remains in a slow decline, offset by gains in oil sands output. Photo by Kurt Abraham, Managing/International Editor.

A report recently released by Environment Canada also states that unless Ottawa follows with taxes on emissions, Canada will never hit its targets. Ironically, Canadian Prime Minister Stephen Harper’s minority government is also under fire for not adhering to a bill drafted by the opposition Liberals (and passed by the other opposition parties) that requires his administration to adhere to Kyoto. The irony, of course, is that the Liberals originally signed Kyoto, and then did nothing to follow through while they were in power. The Tories are not expected to comply, as disregarding the bill would not trigger an election.

So, at the half-way point of 2007, the Canadian industry faces more uncertainty than it has for many years. Given the nature of the concerns, the industry now must address challenges that fall within its influence.

The dichotomy of the price environment has accelerated an ongoing trend that Alberta has experienced for many years-the shift to an industry dominated not just by oil, but by the oil sands. On the flip side, natural gas development has slowed significantly, as the first-half slump in gas prices has dramatically affected drilling plans for the remainder of 2007. Additionally, plans to develop gas supplies that are still characterized as unconventional in Canada, most typically coalbed methane, have predominantly been shelved until gas prices climb out of their current slump.

In fact, the value of oil exports exceeded that of gas for the first time in many years, according to the National Energy Board. Net revenue for crude oil exports was about C$25 billion in 2006, compared to $17 billion in 2005 (up 47%); net natural gas revenues were $24 billion, versus $32 billion the year before (down 25%). Overall, net export revenues were flat in 2006.

However, over the long term, it seems unlikely that North America’s seemingly insatiable demand for gas will abate at any point in the foreseeable future. But a different long-term concern has been raised in some quarters about Canada’s gas productive capacity, and its obligations under the North American Free Trade Agreement.

To date, NAFTA has been upheld by the federal government and the National Energy Board. However, if supply continues to fall as predicted, there may be a point in the future when domestic requirements compete with US demand. It is uncertain how Canada will manage the needs of its citizens, given the NAFTA requirements.

In this bearish gas-price environment, a substantial amount of gas drilling has been delayed, but producers seem optimistic that the trend will reverse itself sooner rather than later. A hot summer in the US may be all that’s required to snap prices out of their slump.

Regardless, it is widely accepted that Canada’s future as an oil producer is heavily tied to the continuing development of Alberta’s massive oil sands deposits, claimed as the second-largest oil reserves in the world.

Even with global crude prices remaining strong, there are some concerns about the increasing costs associated with the incredible activity levels and growth in Alberta’s Athabasca oil sands region. Recently, China National Petroleum Corp. (CNPC) announced that it was reducing its investments in Alberta’s oil sands, preferring to invest in Venezuela. Apparently, CNPC was not prepared to wait the necessary time required in Alberta to develop oil sands holdings, opting for the more business-friendly Venezuela.

Many other firms are pushing ahead with their plans, including Houston’s Marathon Oil, which has expressed interest in pursuing oil sands opportunities.

Among those companies committed to long-term oil sands investment are Petro-Canada and its partners (UTS Energy Corp. and Teck Cominco Limited), which have taken the next step in developing its C$14-billion Fort Hills oil sands mining project, having made the decision to proceed with project engineering. Once the year-long phase is complete, the partners will make the final decision on whether or not to proceed with the project, which will produce 140,000 bpd of synthetic crude in Phase One, scheduled to be online in 2012. Phase Two would then ramp production up to 280,000 bpd of synthetic crude by 2014.

As it stands right now, there is still more than C$100 billion committed to oil sands development over the next decade, despite the present uncertainty in the Canadian market.

Drilling. On the drilling front, operators punched down 9,913 wells during first-half 2007 according to the Daily Oil Bulletin. That figure is down just under 11% from the 11,135 wells drilled in the first six months of 2006. At this pace, drilling would fall below the 20,000-well mark for the first time since 2003.

World Oil’s six-month survey of Canadian drillers seems to uphold that forecast, with most operators indicating they will drill about the same number of wells in the second half of the year. Natural gas remains the primary target, with 76% of the planned wells to drill for gas.

Total second-half drilling is expected to decline by less than 1%, with the largest decrease in British Columbia (down 55%). Activity in Alberta will increase slightly in the second half (up 3%), while drilling in Saskatchewan is expected to increase by 35%.

Rig activity saw an average of 359 units working through the first six months of 2007, out of a total of 857 rigs available through June, according to the Canadian Association of Oilwell Drilling Contractors (CAODC). This is the lowest average number of rigs working since 2002, and a 31% decrease from 2006. CAODC has also adjusted its 2007 forecast downward dramatically to 16,339 wells drilled, versus the 19,023 it predicted last fall. Lower gas prices and very low first-quarter drilling totals are the main reasons.

Meanwhile, PSAC is less bearish, predicting 19,200 wells will be drilled in 2007.

Reserves. Daily Oil Bulletin records indicate that the Canadian industry replaced natural gas production in 2006, the first year since 2003 that the replacement ratio did not exceed 20%. Proved reserves replacement was essentially flat, at 4.53 Tcf, just shy of last year’s production of 4.55 Tcf. In total, Canadian proved reserves stood at 38.7 Tcf.

M&A activity. One of the offshoots of turbulence in this industry is an upswing in merger and acquisition activity, and 2007 is no different. Highlights in the first half of the year include a late-June C$3.5 billion deal to take private the CCS Income Trust, a Calgary-based service company. The deal was secured by an investor group led by the company’s president and CEO.

In late May, Pogo Producing Company approved the sale of wholly owned Northrock Resources Ltd. to Abu Dhabi National Energy Company PJSC in a cash deal worth US$2 billion. Pogo originally acquired Calgary-based Northrock for US$1.7 billion in late 2005.

In early May, Calgary’s Husky Energy Inc. acquired Valero Energy Corp.’s Lima Ohio refinery for US$1.9 billion, subject to regulatory approval. The refinery’s throughput capacity is 165,000 b/d of light crude.

Also in May, PrimeWest Energy Trust and Shiningbank Energy Income Fund agreed to merge in a C$1.25 billion deal that will create Canada’s fifth-largest energy trust. The combined entity will have daily production of 59,000 boed.

Looking ahead, one of the best signals of industry’s intentions remains land sales. Bonuses paid by producers through first-half 2007 were substantially lower than those paid in 2006. However, 2006 was a record year, and it is worth noting that 2007 levels are closer to what would otherwise be considered normal by Canadian standards. In fact, the amounts collected still represent the fourth-highest total in Canadian history. In total, producers paid $983 million through the first half for mineral rights, down 63% from last year’s $2.66 billion.

MEXICO

After eight consecutive years of financial losses, state oil firm Pemex finally reported a net surplus of close to $4 billion during 2006. This is significant, given that the annual average loss from 1998 to 2005 was around $3.2 billion. As recently as 2005, the company reported a net loss of more than $7 billion. Furthermore, during the same year, the growing debt that the company accumulated during the mid-1990s outgrew the value of Pemex’s assets. Yet, last year’s financial result has allowed the company to rebound to a positive equity value, proving that there is life after death.

One of the main reasons for this remarkable recovery is the fiscal framework applied to Pemex during 2006. This structure originated from the new Federal Rights Law approved by the congress in 2005. Nevertheless, the company’s financial future still looks extremely complicated. Officials have reported that beginning in 2008, and continuing into the following decade, Pemex will need around $22 billion of yearly investment. This figure is astonishingly high compared to the $2.9 billion annual average recorded from 1983 to 2000, or even against the more adequate average of $10.7 billion achieved from 2001 to 2007. To reach this level of via the “Pidiregas” financing (debt) mechanism is highly improbable, because the company’s debt is already around $110 billion.

In this context, the ideological discussion over Pemex’s role as a public monopoly maximizing the value of the country’s resources, against the apparent need to open the sector to private capital, will dominate the political debate in the months to come. The solution to the company’s financial dilemma is not trivial, and it will require brilliant proposals and a national compromise that takes into consideration Pemex’s circumstances. It must also consider the government’s oil income dependency and the federal state’s economic welfare before either passing a new fiscal reform to provide the company with more resources, or making the necessary changes in the constitution to allow the involvement of private capital in E&P activities.

Exploration/drilling. The 656 wells drilled in the country in 2006 was a hefty number by Mexican standards, but it was 11.5% less than the total wells drilled the previous year. In addition, the 69 exploration wells drilled represented a 22% drop from the 2003-2005 average. Furthermore, the relatively high 55% success ratio of that period dropped to 46% in 2006, meaning that both the total number and success ratio of exploration wells fell in 2006, not good news when one notices that the country is in a seven-year-long slide of oil and gas proved reserves. The optimistic note, however, is that the government forecasts a 13% increase in exploration drilling and a 22% increase in total wells drilled for the current year.

At the beginning of 2007, proved oil and gas reserves stood at 15.5 billion boe, which yields just around 9.5 years in the reserves/production ratio. This is the first time since the oil boom of the 1970s that the ratio has been reported as less than 10 years. Despite the 6.5% decline in proved reserves from 2005 to 2006, it is interesting to note that the reserve replacement rate of 41% was the highest reported since 1998, the initial year of external reserves certification.

Development/production. The average daily Mexican production peeked at a historic level of 3.38 million bbl in 2004. Ever since, it has steadily dropped every year, up to a 7% rate by first-half 2007. This behavior coincides with the start of the decline in Cantarell field, which represents more than half of the county’s oil production. The decline is projected to continue at a 14% rate for the next 10 years. This means an annual production loss of about 150,000 bopd. How and when Pemex will be able to cope with Cantarell’s decline is yet to be seen, because an important alternative may be to incorporate production from the Chicontepec region, as well as the GOM’s deepwater potential. However, the company will require considerable investment to face the technical challenges of developing such reserves, which, as noted above, are not an easy alternative to undertake within the financial situation.

It must be noted that despite the decrease in oil production since 2004, the light oil output, mainly from the Southwest Marine Region of the GOM, has increased 12%, improving the quality of the Mexican oil mix from a heavy/light proportion of 73%, down to 67% in 2007. A similar trend can be observed for natural gas production. It has not only increased a whopping 33% from 2002 to 2007, but it has also changed its origin from 30% to 44% non-associated, due to investments in non-associated gas development in the Northern Region. This development extends from the GOM coastal plain, in the north-central portion of Veracuz, to Tamaulipas and Coahuila states south of the border with the US.