North American drilling: We wuz wrong (sort of)

United States by World Oil Staff; Canada by Robert Curran, Calgary, Canada; Mexico by Dr. Daniel Romo Rico, Mexico City 

UNITED STATES

Most of you will recognize the famous title from The Economist, when it confessed that its forecast of impending doom in oil supply “wuz wrong.” This midyear update of World Oil’s January forecast (published in the February issue) would seem to indicate that we were way too optimistic then, when we called for a 20% drop in US drilling, to 43,926 wells. Rigs were in freefall at the time, so we had to guess at where the bottom lay. We believe that we’ve now seen the worse. If this revised forecast holds, then US drilling will fall off to 37,966 wells, about 30% down from 2008. And even this may be too optimistic, as it is predicated on the bottom of a V-shaped recovery having already occurred and rig counts improving in the second half. Indeed, this revised forecast calls for the second half having 15% more wells drilled than the first half—which is entirely dependent on oil prices stabilizing at July’s levels, and gas prices gaining ground.

To the extent that there was a turnaround in some areas, it was mostly due to the rebound in oil prices.  The trough came in May, June or July, depending on where you were located. And in a few, mostly gas-rich states, it has yet to fully bottom out.

Rig counts. The rig counts bear this out. We used Smith International, Baker Hughes, Schlumberger and RigData rig-counting services. Sometimes they were not in agreement as to when the bottom—when there was one—occurred, but there was nearly always general agreement. The Baker Hughes aggregate gas/oil split tells the story. For about a decade, the number of rigs drilling for gas vs. the number of rigs drilling for oil has hovered around 80/20 in favor of gas. Coinciding with high gas prices, the ratio hit 85% of rigs drilling for gas in February 2007. With the collapse of prices in fall 2008, the ratio stood at 78% by the beginning of this year. As of July 10, “only” 73% are now drilling for gas, but the number is clearly dropping and will likely drop further in the short term. Thus, a redirect toward oil is what’s turning the rig counts up a little.

Midyear revision, 2009 US drilling forecast

The Texas PetroIndex tracks Texas E&P activity, and is published in cooperation with the Texas Alliance of Energy Producers. The Index, created by economist Karr Ingham, has continuously expanded since August 2002, and peaked in October 2008 at 144% above the 2002 level. At the end of June, it was down 20% from its 2008 peak, its lowest level in 2 years. It will likely fall further when the July and August numbers are crunched.

Natural gas. Gas prices seem bleak at the moment. The problem is two-fold and nearly equally split between crummy demand and oversupply. Of the four components of gas demand, it is industrial that is responsible for most of the demand deficit, with residential contributing a little (commercial and electrical are holding).  Consumption is forecast to be down 2.3% this year.  However, for context, consumption has been down 4.4%, 3.2% and 1.5% in 2001, 2003 and 2006, respectively.

The other side of the coin, supply, or in this case, oversupply, is causing storage levels to be 19% above of their 5-year average. But this has been seen before too, most recently in the summer of 2006. And storage levels are easily within 10-year norms. So it’s a mixed bag on where gas prices are heading, with great uncertainty in all predictions, made worse by a clouded LNG picture. One thing is certain: The shale gas plays, which account for about 10% of US gas production, are at best thinly economic, and probably uneconomic at today’s $4/Mcf-and-lower prices. The gas-directed rig count is off 56%. The other thing that is certain is that natural gas production decline is 30% per year overall. So long term, it would seem that prices would have to firm up just to keep supply flat.

One final note on prices. Historically, the relationship between gas and oil prices has varied wildly, but nevertheless their ratio has been between about 6 and 12 over 90% of the time during the last 20 years. Once, briefly, it hit 21 (when the first Gulf War began in 1991). In mid-July, the ratio stood at 19.3, which means that, if history is any measure, either oil prices have a long way to come down, gas prices will come up, or some combination of the two will occur. 

Surveys. This year, we foolishly asked the question at the bottom of our survey, “If there has been/will be a large change in drilling activity, please indicate why.” Unsurprisingly, the universal answer was “prices.” Perhaps the most succinct comment—and this deserves some sort of award for effective communication—is the one by the company who wrote, “Natural gas prices suck.” (We assume he means that in the vein of Webster’s third definition, “are of poor quality.”)

A few folks added in “politics” or “political uncertainty,” which was presumably the uncertainty of the proposed elimination of the tax deduction for Intangible Drilling Costs (IDC), which, by the way, are quite tangible.

The most affected would be small independents, the “mom & pops” if you will, which operate at marginal profitability. On the federal side, the reason to eliminate the IDC and generally raise taxes on the oil industry is to raise money for a government that is, and has been by all accounts, broke. The fact that the IDC has been around for  90 years indicates that it will most likely be used as a bargaining chip and survive.

Area highlights. The shine has definitely come off not only the shale gas plays, but also the coalbed methane plays (see p. 71). The CBM slowdown isn’t as much dramatic as it is steadily eroding, even during 2007 and 2008. The US gets about 10% of production from these low-rate producers, and while we forecast that 2,796 CBM wells will get drilled this year, that’s off by 46% compared to 2008—a bit less than other gas drilling. The CBM core areas are Wyoming (Green River Basin), Colorado (Piceance Basin), New Mexico (San Juan Basin) and Alabama (Black Warrior).

Predominantly oily states, such as Illinois, Indiana, Ohio and Pennsylvania, are faring better than their gassy neighbors. Most of the Illinois wells are shallow, being in the 2,000–3,000-ft range. Pennsylvania is oil rich too, but in addition, that state’s Marcellus Shale gas play is in the early stages of exploitation, and it has the potential to become another Barnett Shale in scope. Parts of the Marcellus extend well into New York and West Virginia, although it is not developed outside of Pennsylvania.  

Much of Texas is both gas and oil rich, but those areas that are mostly oil or still have shallow oil to drill saw a move away from natural gas toward drilling that oil. Districts 1, 7C, 8 and 8A all fall into that category; and all saw a “V” in rig activity in mid-spring.

Louisiana is following the rest of the country, except for those involved with the Haynesville Shale play. Operators there and in some of the other shale plays have little choice but to drill and produce gas, despite $3−$4 prices. Most of those very expensive leases, some of which cost upwards of $30,000/acre, are short lived, being in the 2−5-year range. So operators who still have cash to invest have to drill it or lose it. Still, drilling there is helping to slow the pace of the downturn.

 In the Gulf of Mexico, prior commitments to projects are resulting in several platforms coming onstream. However, drilling in the shelf (i.e., jackups), has fallen steeply (see p. 51), while deepwater drilling is holding for now.  

North Dakota’s Bakken Shale play—which is not really a gas shale play at all—is still drilling some long horizontals in the dolomite member of the Bakken to produce oil. It remains the largest, newest “field”—actually, a continuous resource—in the US, having a technically recoverable potential of 3.0−4.3 billion bbl (see World Oil, June 2008, p. 83).

Missouri made it out of the “Others” category again. It has a Canadian oil sands-style thermal (steam) play by Calgary-based MegaWest that has resulted in hundreds of shallow wells being drilled. The company has fallen on shaky times, but still has hopes of continuing projects in Missouri, Kentucky and elsewhere.

About these statistics. World Oil’s tables are produced with the aid of data from a variety of sources, including the American Petroleum Insititute, Groppe, Long & Littell, ODS-Petrodata Group, IHS Energy, the Texas Railroad Commission, other state and federal regulatory agencies, as well as international agencies. Most importantly, operating companies with drilling programs responded to this year’s survey. Please note credits and explanations in the table footnotes. We thank all contributors for their time and effort in providing data and analysis for this report.

World Oil editors try to be as objective as possible in the 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. In this respect, it should be noted that well counting is a dynamic process and most historical data will be continually updated over a period of several years before “the books are closed” on any given year.

CANADA

The last 12 months are testament to the mercurial nature of the oil and gas sector. The uncertain outlook a year ago is gone, but the certainty of 2009 is that of an industry mired in a protracted slump. Activity has dropped to levels not seen in more than a decade, and even the most optimistic prognosticators are looking to 2010 or beyond for the next turnaround.

While some experts argue that oil prices have settled to a more reasonable level since they hit record highs in 2008, it is rock-bottom gas prices that have played the biggest role in this year’s drop in activity. High storage levels, the massive volumes of shale gas coming into production, sluggish demand from continued weakness of the global economy, and increasing LNG availability have more than offset any upward pressure created by producers shutting in more and more gas production.

The downturn has reversed last year’s frantic search for workers—layoffs have been seen across virtually every industry in Canada. Government revenues from oil and gas activity have plummeted, both in royalties and in land sale bonuses. One positive aspects of the lower activity is the associated drop in finding, development and acquisition costs in 2009.

Not surprisingly, the difficult economic conditions have prompted governments across Canada to examine what they can do to improve their individual situations. Federally, the Conservative administration of Prime Minister Stephen Harper continues to move forward with the implementation of a national carbon trading market. Like the US, Canada has abandoned the notion that the targets set by the Kyoto Accord are achievable. Instead, the new program will cap greenhouse gas emissions and reduce them 20% from 2006 levels by 2020, and 65% by 2050.

Meanwhile, Canadian producers are concerned that new low-carbon rules enacted in California unfairly discriminate against production from Alberta’s massive oil sands deposits and are concerned that other US jurisdictions may be contemplating similar legislation. The concern is understandable, since Canada remains the No. 1 crude oil supplier to its southern neighbor.

The export factor is a big one for Canadian producers. In 2008, oil and gas exports represented a record C$93 billion, or about 28% of Canada’s entire export revenues, according to the National Energy Board. Producers that export to the US have been given something of a buffer in 2009 with the Canadian dollar tracking down compared to 2008 levels, even though recent market activity has seen the Loonie move about the 90-cent mark vs. the US dollar. Over the past several years, the Canadian dollar has hovered somewhere in the 80-cent range.

In Alberta, Premier Ed Stelmach announced that his government would institute a competitiveness review. Since the midpoint of 2008, Alberta has lagged its Western Canadian counterparts in most categories, and is facing a budget deficit for the first time in 15 years. Earlier this year, Stelmach’s beleaguered administration announced drilling incentives including a one-year royalty credit and maximum 5% royalty for new wells, plus a $200-per-meter-drilled royalty credit applied on a sliding scale depending on companies’ 2008 production. The incentives were set to expire in March 2010, but in June, the program was extended for another year.

The Alberta government had been under fire since announcing in 2007 plans to implement a new royalty structure that went into effect this year. Producers strongly voiced their dislike for the new system, and some have responded by taking their capital programs outside Alberta’s borders and diverting land acquisitions to Alberta’s neighboring provinces, British Columbia and Saskatchewan.

Also, recently both the Canadian Association of Petroleum Producers and the Small Explorers and Producers Association of Canada have spoken positively of the measures implemented by the Stelmach government in response to the current slump in activity.

Alberta is also going ahead with plans to collect royalties from bitumen production as actual barrels rather than cash to ensure that upgraders and/or refineries in Alberta will be guaranteed a supply of feedstock. With the necessary legislation now in place, the next step is to issue a request for proposals from private firms for the contract to market the province’s bitumen. As it stands now, Alberta would start collecting its barrels in January 2012.

On the environmental front, Alberta is advancing its C$2 billion Carbon Capture and Sequestration (CCS) incentive program, having shortlisted three applicants: the Alberta Carbon Trunk Line-Northwest Upgrader (Enhance Energy Inc. and Northwest Upgrading), the Quest CCS project (Shell Canada Energy, Chevron Canada Ltd. and Marathon Oil Sands LP), and the Genesee integrated gasification combined-cycle CCS power generation plant (EPCOR Utilities Inc. and Enbridge Inc.).

Meanwhile, neighboring Saskatchewan continues to enjoy continued steady activity despite the overall downturn, a trend some attribute to Premier Brad Wall’s pledge not to increase royalties and to review the province’s regulatory regime to ensure it remains competitive. In fact, Saskatchewan is on track to record a modest budget surplus in the current fiscal year, making it the only province not projected to record a deficit.

In British Columbia, Liberal Premier Gordon Campbell’s administration has also announced it will implement a stimulus package targeting gas production—the bulk of the province’s reserves are natural gas. Industry has been very supportive of Campbell’s efforts to offer a competitive royalty and regulatory regime. But despite all these efforts, spending remains well behind 2008 levels as producers continue to minimize activity.

Records compiled by the Daily Oil Bulletin indicate that plans for capital expenditures have decreased by more than $20 billion, including an $8 billion drop in spending on oil sands projects. Among those companies that have announced spending cuts are: Canadian Natural Resources Limited, down C$4 billion; Suncor Energy Inc., down $3 billion; Petro-Canada, down $1.9 billion; Talisman Energy Inc., down $1.8 billion; Husky Energy Inc., down $1.3 billion; and EnCana Corporation, down $1.3 billion. Suncor also put the brakes on its $20.6 billion Voyageur oil sands expansion—where construction was already underway—citing low oil prices and the global credit crisis.

There are some bright spots, however, as a number of firms have actually increased spending plans for 2009. Not surprisingly, most of them are focused on oil developments. They include Imperial Oil, up almost C$1 billion, and Canadian Oil Sands Trust, up $160 million.

Given Canada’s dwindling conventional gas supplies, producers here will eventually have to turn more and more to unconventional sources, much the way their counterparts in the US have already done. In the near future, though, gas production is likely to continue to drop until prices make a sustained recovery. And so, the future of the Canadian industry remains firmly centered on the development of oil sands reserves, which contain enough oil to supply Canada for almost four centuries using currently available technology.

The sheer scope of the oil sands developments makes them an easy target for environmentalists, and it appears some people are listening to them. The concerns include California’s new low-carbon law and the possibility that other states might follow its lead, the Waxman-Markey bill currently before the US Congress, and the prospect that the Environmental Protection Agency could step in at any point, regardless, and implement climate change rules on its own. Now Norway has even waded into the fray. In May, the country’s center-left government ended up delaying a parliamentary vote on whether it should withdraw from a $2 billion oil sands project entered into by StatoilHydro, of which the government owns two-thirds.

In response, producers and government officials seem to agree that they need to do a better job providing a positive counterpoint to the green activists’ emotional campaign against oil sands development, which produces high levels of greenhouse gases.

According to a recent study released by the Canadian Energy Research Institute, it would be possible to reduce emissions from oil sands productions to levels equal to or less than those of conventional oil by 2026, provided industry and governments aggressively implemented carbon capture and storage facilities.

For the time being, oil sands production continues to increase on an annual basis and is expected to continue to grow in the foreseeable future. The Canadian Association of Petroleum Producers is projecting average daily production of 3.3 million bbl by 2025, and 2.2 million bbl per day by 2015.

Imperial Oil has been very active, approving the first phase of its C$8 billion Kearl oil sands mining project, which is scheduled to begin production by late 2012, averaging 110,000 bopd in phase one, eventually ramping up to peak production of 345,000 bpd. To the south, the company is also preparing to expand its Cold Lake operation by 30,000 bpd with the proposed Nabiye cyclic steam stimulation project.

Royal Dutch Shell remains on track to complete the expansion of its Athabasca Oil Sands Project, which calls for the construction of another mine and an upgrader that would add 100,000 bpd in late 2010 or early 2011. The site could ultimately produce up to 470,000 bpd of bitumen.

Meanwhile, CNRL is publicly debating the merits of proceeding with the development of the third and fourth tranches of its Horizon Oil Sands Mining Project due to continued market and price instability. Horizon produced first oil this year, and is currently approaching first-phase capacity of 110,000 bpd.

At Devon Energy’s Jackfish SAGD project, all well pairs are now operational and the company expects to reach productive capacity of 35,000 bopd sometime in the next few months. Work continues at Jackfish 2, which is expected to be operational by 2011, bringing on another 35,000 bpd of production.

The downturn has been positive for Husky and 50% partner BP, which originally pegged the cost of their Sunrise SAGD project at C$4.5 billion. But with steel, labor and other costs dropping, Husky now says Sunrise will cost $2.5 billion for the first phase of the 60,000-bpd development. A decision about when to proceed is expected soon.

There has not been a lot of M&A activity so far in 2009, other than the mega-merger between Suncor and Petro-Canada in June. Shareholders of both companies endorsed the deal, which will create a fully integrated, C$22 billion company. The merger is of particular significance because Petro-Canada was Canada’s first and only national oil company.

Canadian crude production is expected to increase slightly in 2009. Oil and liquids production increased to just under 2.8 million bpd through the first half and should continue to climb through the remainder of the year.

Natural gas production continued its downward trend at the halfway point of 2009, and is now expected to hit just 15.7 Tcf for the year, compared to a high of 17.3 Tcf in 2006.

Land sale results provide more food for the bears, as bonus revenues have plummeted across Western Canada. Leases and licenses acquired in these sales form the basis for drilling plans and are viewed as an indicator of future activity.

In 2008, Alberta dropped to second place behind British Columbia in land-sale revenues for the first time. Historically, Alberta has pulled in about 80% of the dollars spent acquiring Crown lands. But at the midway point of 2009, Alberta’s receipts were down 77% from last year’s $450 million, and off more than 95% from the $2.2 billion collected through six months in 2006. To the west, British Columbia pulled in $246 million, down 74% from last year’s halfway mark of $960 million. And Saskatchewan drew $36 million, well behind the $600 million it collected a year ago.

Drilling also fell substantially from 2008 levels through six months. According to Daily Oil Bulletin records, 5,947 wells were drilled through the first half, down 27% from 8,126 last year. At the current pace, drilling may fall to levels not seen since the mid-1990s.

Reflecting the general pessimism in Canada about the remainder of 2009, both the Canadian Association of Oilwell Drilling Contractors (CADOC) and Petroleum Services Association of Canada (PSAC) have revised their drilling forecasts downward for the year. CAODC now predicts drilling will hit 8,787 wells, compared to its original forecast of 14,325. PSAC is more optimistic, forecasting 10,000 wells drilled, vs. its original forecast of 16,750.

MEXICO

Mexico’s national oil company, Pemex, showed a contrasting performance in upstream activities during 2008, in spite of the highest Capex in the company’s history.

Exploration and drilling. Last year, oil and gas activity was carried out mainly in the deep basins of the Gulf of Mexico, while inshore activities were mainly developed in the southeast basins.

Total oil and gas proved reserves reached 14.3 billion boe, 2.8% below the 2007 level. So it continued its consecutive decline since 1998, when the company started to count its reserves under the new classification required by the US Securities and Exchange Commission (SEC). The positive note, though, is that the rate of replacement of proved reserves over production stood at 71.8%, which compares favorably against 50.7% of the previous year.

Hydrocarbon proved reserves comprise 72.7% crude oil, 17.1% dry gas, and the rest are other liquids and condensates. Of the total oil reserves, 41.4% are located in the Northeast Marine Region of Campeche Bay, in Cantarell and Ku-Maloob-Zaap Fields. The gas reserves were located primarily inland in the Burgos, Samaria-Luna and Bellota-Jujo Basins. Overall, total hydrocarbon proved reserves are located 69% offshore and 31% onshore. The volume of proved reserves at current production implies production for 9.9 years.

In 2008, 65 exploration wells were completed, 32.7% more than in 2007, yet exploratory wells had a 42% success ratio, the lowest level since 2004. They were located, by and large, in the Burgos and Veracruz areas, where non-associated gas fields are most common.

Development and production. The company completed 664 development wells (604 onshore and 60 offshore), 8.9% more than the previous year. Most of them were located in the Poza Rica-Altamira, Burgos, Cinco Presidentes, Samaria-Luna and Bellota-Jujo Basins.

Crude oil production in Mexico has continued to decline from the 2004 peak. Average crude oil production during 2008 was 2.79 million bpd, representing a decrease of 9.2% over the previous year and 17.5% from the peak.

The downward trend of Cantarell Field, from 1.47 million bpd in 2007 to 1.01 million bpd in 2008, was the main factor in the decline of Mexican crude oil production. Ku-Maloob-Zaap production helped offset the Cantarell decline. Nevertheless, Pemex continues to face important technical challenges to produce in mature fields.

Gas production rose 14.2% in 2008, reaching a historic level of 6.92 Tcfd, which represented a major achievement for the Pemex production strategy. The main explanation for the increase is the dynamic extraction of associated gas, particularly in Cantarell Field, where Pemex produced 1.63 Tcfd, 72.3% more than the previous year. Non-associated gas production decreased by the decline in Burgos, reversing the upward trend registered since 2001.

Pemex spent in Capex $18 billion last year, the highest level in the company history. In upstream activities the company invested $15.9 billion. In 2009, Pemex plans to invest around $19 billion, with 87% of that directed upstream.

Political context. Politics in 2008 was historic regarding public opinion and media coverage of the energy sector. The result of many months of negotiation in the Congress was the so-called energy reform that will allow Pemex to have greater flexibility to decide how to organize itself in its role as national oil company. Four professional counselors, appointed by President Calderon and ratified by the Senate, were incorporated into the board of directors. Through seven specialized committees, the counselors will promote transparency and accountability, R&D activities, improve the investment strategy and strengthen environmental and security policies.

In addition, the Ministry of Energy and the Energy Regulatory Commission were reinforced in their responsibility for defining the energy policy. The National Hydrocarbons Commission was established to regulate and supervise the upstream activities under mid- and long-term considerations, and the National Energy Commission was integrated to coordinate national energy policy. In addition, Pemex will operate under a new fiscal regime.

Many critics say the reform is insufficient to improve the company’s efficiency or cope with structural problems, such as an accumulated backlog of investments; technological dependence; the strong perception of corruption; the high level of bureaucracy; and the obstacles imposed by the workers’ union.

Finally, the results of the July elections shifted control of the Congress to the former ruling party, PRI, which may be tempted to propose changes to the constitution to allow more private investment in the sector. However, it is difficult to believe that the PRI would pay the political cost of opening the sector without the support of other parties, since oil nationalism is still very important in this country.