Newswell

Utica shale is in 'same league' as Eagle Ford

The results of Chesapeake Energy Corp.’s four best horizontal wells in the Utica shale suggest these wildcats could rival—if not surpass—production from some of the best Eagle Ford wells. This is according to a report by Irene Haas, an analyst with Wunderlich Securities Inc.

Three of the wells are in Ohio and one is in Beaver County, Pennsylvania. The Utica play, which primarily lies beneath the Marcellus shale, has been a recent target of land acquisitions. Chesapeake announced its results from its four wells in late September.

“We find it very interesting that the best well is located in Harrison County (Ohio) with some very strong wells in Carroll County (Ohio) as well,” says Haas. “Based on the early IP (initial production) rates ranging from 1,530 barrels of oil equivalent (BOE) per day to 3,010 BOE per day, with high liquid content, these wells are indeed in the same league as some of the best Eagle Ford wells, if not better. The Beaver County well also helps establish the dry-gas belt.”

To date, Chesapeake has drilled 12 horizontal wells in the Utica, reporting strong production from both the wet-gas and dry-gas portions of the play. According to the report, the company is mostly focused on the wet-gas window, which is shallower than the dry-gas portion and offers better returns than the oily belt. However, it is beginning to work in the oily portion as well. Chesapeake has five oil rigs running and is expecting to have 10 working in the shale by year-end 2011, 20 by year-end 2012 and 40 by year-end 2014.

“This is more aggressive than the previous count from Chesapeake,” Haas says.

Joining Chesapeake, which has 1.25 million acres in the Utica, are major players Consol Energy, 400,000 acres; EV Energy Partners, 159,000 acres; Gulfport Energy Corp., 30,000 acres; PDC Energy, 30,000 acres; and Magnum Hunter Resources, 20,000 acres.

By mapping the overlap between areas with high total organic carbon content and proper thermal maturity, and considering the presence of the Point Pleasant formation, “We can narrow the Utica sweet spot in Ohio into a list of counties,” Haas said. Those counties are Noble, Monroe, Guernsey, Belmont, Jefferson, Harrison, Tuscarawas, Carroll, Stark, Columbiana, Mahoning, Portage and Trumbull.

The wet-gas window for the Utica, according to the report, could extend into the western Pennsylvania counties of Beaver, Lawrence, Mercer and Crawford.

“We expect a ramp-up in drilling and testing this year, and we should see a more accurate map defining the exact boundary of the wet-gas belt. Our ‘best zip codes’ list could shift with new data,” Haas says.

A successful Utica could generate as many natural gas liquids (NGLs) as the neighboring Marcellus, and perhaps more, the report notes. Chesapeake projects that maximum ethane recovery will be needed to achieve optimal results.

“While Chesapeake is processing the wet gas in three processing plants nearby, recovery of ethane has been small due to market limitations. Chesapeake is working on de-bottlenecking the NGLs,” says Haas.

“We do not have detailed information about the mineralogy, porosity, permeability and presence of natural fractures. Is the Point Pleasant formation the only sweet zone within the Utica? How geographically extensive are these sweet spots? What will be required to complete these wells optimally?

“There is insufficient production history from the few horizontal wells drilled thus far to define a decline curve or per-well reserves, and the economics are not well understood,” the analyst notes. “We do not know the product mix between dry gas, wet gas, and condensate. Are we looking at the oily portion of the Utica play? Does it work?”

These and many more questions will be answered as Utica exploration continues.

—Mike Madere

For more on the Utica shale, see UGcenter.com ? and OilandGasInvestor.com.

Tertzakian: Bakken, other new oil changing ‘oil world order’

“Who would have said two years ago that North Dakota would be an energy superpower?” asked Peter Tertzakian, speaking at The Oil Council’s annual Americas Assembly held in New York in late September. Tertzakian is chief energy economist and managing director for Calgary-based, energy private-equity firm ARC Financial Corp., and author of A Thousand Barrels a Second and The End of Energy Obesity.

“A new world order” in oil dynamics is under way, and North American production is prominently in the fray, he said.

North Dakota’s new Bakken oil play, dubbed a shale-oil play but actually producing from rock that sits between two shales, is making 400,000 barrels a day already, he said. This is while U.S. producers have been intently at work on it in just the past four years and only particularly aggressively in just the past two years.

Also, Canadian oil production is growing, he notes. For example, TransCanada’s proposed Keystone XL pipeline that is to take crude from Alberta’s oil sands to refiners on the U.S. Gulf Coast will have an initial capacity of a half-million barrels a day.

The assumptions of the old world order have been that society is addicted to oil; consumption will keep growing; we are near peak production; and there are no energy alternatives to oil. Additionally, the old outlook presumes that environmental concerns trump additions; OPEC will keep prices high; and geopolitics are an antagonist to supply and therefore, prices will continue to rise.

The new world order is being driven by rising fuel prices, environmental and security issues, government policy, and societal and technological changes, Tertzakian said.

Under the new paradigm, oil will be a vital fuel for a long time yet; structural influences will be more dominant than cyclical ones; and oil consumption will grow but not as fast as one might think. Additionally, in the new order, prices can’t be assumed to keep rising unless geopolitical issues become very heated; high-cost producers of oil are very vulnerable; and producers that hold onto oil world-order assumptions and don’t innovate and adapt may go out of business.

“But if you do innovate and adapt, you will make a fortune. You will make a fortune! Is the barrel half full or half empty? The barrel is half full. That is the new world order,” he said.

How high is “high cost” for those producers that are vulnerable? “If you can’t make your business go on $65…, I’m loathe to say I’m excited about that company.”

—Nissa Darbonne

KKR’s Bookout: The profit-potential story from unconventionals

It’s still early days in the Lower 48 unconventional-resource play, says John Bookout, Houston- based managing director for multi-industry, global private-equity firm KKR. That’s despite that the horizontal shale revolution is already more than 10 years old now, dating back to Mitchell Energy & Development Corp.’s success into the late 1990s in the Barnett shale.

“We are only just beginning to understand the true extent of this disruptive technology (of horizontal drilling and multistage lateral fracturing) and what it can do…in shale basins—and conventional basins,” Bookout told attendees at The Oil Council’s annual Americas meeting in New York.

He expects horizontally produced resources will be “extraordinarily important for many, many years to come…There are literally hundreds of thousands of locations that can produce meaningful oil and gas reserves at a low cost.”

One example of the significance of these reserves? BHP Billiton Ltd. recently paid $15.1 billion for Petrohawk Energy Corp., a 69% premium to Petrohawk’s pre-announcement closing price. Bookout notes, “There is a difference in what Wall Street saw and what BHP saw in Petrohawk.”

It could be merely that the Street is basing E&P values on strip commodity prices, while bringing Petrohawk into the BHP portfolio gave it a meaningful entry into U.S. shales—plus thousands of experienced employees too.

But, overall, the Street appears to under-appreciate the value of these stories, Bookout says. “I can’t explain to you how and why the values of many of the independents are what they are today. This is the early stage of the investment window. We think it is a tremendous investment.”

On the horizon are improved returns. Drastic reductions in unconventional-resource well-completion costs are coming in the next few years, Bookout says.

“What the industry hasn’t done (during most of the run on shales) is focus on completion technology in terms of overall cost.”

Bookout notes that two-thirds of unconventional-resource well costs are completion oriented. Industry, particularly while defining the point of diminishing returns on number of frac stages and lateral length, has employed a tack of “pump more fluid, pump more proppant, pump all you can.”

Findings now indicate that 70% of frac fluid is not penetrating the target—“70% of it is simply waste. The ‘more is better’ (thinking) caused us to frac the productive parts but we did a lot more (than that).”

Bookout thinks sliding-sleeve technology will contribute to reduced completion costs. Also, Schlumberger Ltd.’s new HiWAY frac technology, successfully piloted in Petrohawk Energy Corp. wells in the Eagle Ford late last year and into this year, is “simply a better way of doing more with less.”

As completions become more efficient, oilfield-service costs will begin to soften in 2013 on the completion side. He forecasts that, “four or five years out, completion costs will be half of what they are today.”

Bookout and the KKR energy-investment team have invested in and monetized two unconventional-resource E&Ps in just the past two and a half years. It invested in Appalachia-focused East Resources Inc. in 2009 for an undisclosed amount; East was sold in mid-2010 to supermajor Royal Dutch Shell for $4.7 billion after it proved its acreage prospective for Marcellus shale gas.

Also, it invested $600 million in privately held Hilcorp Co.’s $400 million of South Texas properties in 2010 and sold the $1-billion venture this year to Marathon Oil Corp. for some $3.5 billion.

KKR developed a strategy for investing in unconventional resources during a study that began in late 2008. The compressed time frame that is involved in developing these shale plays is remarkable, Bookout says.

Today, acreage costs are jumping in a matter of months from $1,000 or $3,000 to, in the case of the Eagle Ford lately, as much as $30,000, in some hot spots.

And, the Utica is already taking off. “What has happened in the Utica is nothing short of breathtaking.” Leasehold that was $100 an acre a year ago is being bid at $8,000 an acre today with practically no well data released. Chesapeake Energy Corp. just released its data on its first four horizontal Utica wells, and the acreage cost is destined to rise further, he said.

“Deciding where and how to invest is much more complicated today than three years ago, when we started.”

—Nissa Darbonne

Interest in Michigan shales continues to heat up

Michigan is commanding a closer look from the oil and gas industry. The Collingwood and Utica shales, along with the A-1 Carbonate, have become important zones of interest in the Michigan Basin and are attracting new players to the state, according to two geologists participating in a recent Hart Energy webinar.

William B. Harrison III, director of the Michigan Geological Repository for Research and Education at Western Michigan University, and Tim Gognat, managing member of Global GeoData LLC, provided an overview of the shales, including an update on recent activity.

“There appear to be some great opportunities for oil and gas here in Michigan,” said Harrison, professor emeritus and director of the Michigan Basin Core Research Laboratory, part of the Michigan Geological Repository for Research and Education.

Michigan began attracting attention following completion of the Petoskey Exploration LLC-St. Pioneer #1-3 well in Missaukee County in early January 2010. It reached a measured depth of 15,001 feet and a true vertical depth of 9,477 feet.

“This includes about 5,500 feet horizontally in the Upper Trenton/Collingwood formation,” Harrison said.

Tests this past spring indicated that the maximum gas-production rate at the Petoskey well was a little more than 3,000 cubic feet per day. Fewer than 20 barrels of oil were being produced daily.

“The Collingwood is a separate stratographic unit that is more related to the Trenton shale than the Utica,” Harrison said. The organic content of the Collingwood is two- to four times that of the Utica. But overall, he said, “The potential of the Utica is largely unknown because of a lack of data.”

Potential development in the Collingwood is well-defined by existing wireline log data. In addition, the exploration depth for the Collingwood is from 7,000 to 10,000 feet in the gas window. The oil window is in shallower areas, as confirmed by the St. Koehler and Kendall #1-27 well in Cheboygan County.

Gognat pointed out that in the A-1 Carbonate, recent activity has been driven by Devon Energy Corp. “About a month ago Devon announced its first well that will penetrate the A-1 Carbonate in Gladwin County. It appears they have a fair amount of confidence in the play.”

In late September, according to a report in the Michigan Oil & Gas News, Devon filed permit applications for a second Gladwin County well.

“My interpretation is that they are pursuing the A-1 Carbonate in an area that has a variety of structural complexities involved,” said Gognat, adding that Devon is keying off a significant well that the old Gulf Oil Co. drilled in the late 1930s.

Log analysis of the A-1 can be difficult, Gognat said. In addition, A-1 Carbonate oil and gas production records are generally incomplete and difficult to acquire.

—Mike Madere

John B. Hess: An energy crisis is on the way, unless U.S. acts

Are energy and climate change the greatest challenges facing man in the 21st century? “I would agree with that,” said John B. Hess, Hess Corp. chairman of the board and CEO, during a keynote speech at the recent IHS Herold Pacesetters conference held in Stamford, Connecticut.

“We can no longer pursue narrow, short-term political agendas; we all must collaborate—Democrats and Republicans, government and industry, the U.S.—with the rest of the world, for the common good. We need to put energy policy at the top of the U.S. political agenda and at the top of the G-20 agenda.”

Hess laid out a plan for the U.S. that would lower oil demand, encourage more drilling, emphasize natural gas for electric generation, invest in research for all forms of energy, and set realistic targets for reductions in carbon emissions.

“If we do all these things… we’ll conserve 3 million barrels per day, save more than $100 billion a year and reduce our carbon footprint and our nation’s financial deficit,” he said. “But to do so will require leadership from government and industry.”

Hess emphasized the need for a long-term strategy, rather than quick fixes, to solve the world’s energy problems. The long lead times to bring oil and gas fields online, build electric plants, and solve transmission issues necessitate this approach.

Some 85% of the world’s energy is comprised of hydrocarbons, and as the world population grows from 6.9 billion today to more than 9 billion by 2050, hydrocarbons will continue to play a lead role, the CEO said. “Sometimes I alarm people when I say this, but I say it to make people be pragmatic: An energy crisis is on the way, likely triggered by the need for oil.

“Even assuring negative growth in oil demand in Europe, and flat-to-negative growth in the U.S., it’s not unrealistic to look for demand growth in coming years of 800,000 to 1 million barrels of oil per day,” he said.

This growth is driven by developing economies, and largely by growth of transportation demand. “We’re projected to go from 1 billion cars today to 2 billion by 2050,” Hess said. “We’re not running out of oil—we’ve already produced 1 trillion barrels, and 2 trillion barrels remain. But we’re not investing enough to grow our production capacity to keep up with demand….

“The world surplus oil-production capacity, with the problems in Libya right now, is 2 million barrels per day—not much of a cushion. As demand growth continues, we won’t have enough capacity to meet demand. We need to act now.”

In this scenario, Hess said, supply will lag demand, prices will skyrocket and the world economy will be “brought to its knees.” The $140-per-barrel oil peak of recent years was not an aberration, it was a warning, he said. Avoiding this crisis will require leadership from both the business and political sectors.

Domestically, the energy policy for oil requires moderating demand and increasing supply, Hess said. “It’s not complicated.” Measures should involve raising the mileage performance standard to 50 miles per gallon. “I give President Obama credit for pushing it to 56 (miles per gallon),” Hess said. “But I would go faster, in terms of ramping up the work to do this.

“We need much higher fuel efficiency than the current standards of 25 to 27 miles per gallon. A lot of this technology is available.” Reaching these goals requires a combination of vehicle mix, engine downsizing, advances in combustion technology and hybrids, he said.

“Hybrids are the real solution here. The Chevy Volt and Toyota Prius, if introduced more to replace the bigger CUVs or SUVs, could go a long way to get to 20% to 30% efficiency improvements.

“If it takes 15 years to replace the vehicle fleet, with 230 million cars and light-duty trucks, the U.S. could save more than 3 million barrels of oil per day. At today’s price of $100 (Brent), we would save $100 billion in reduced energy costs. This is a worthy prize, and within reach.”

Electric cars are too limited by range and cost to play a major role in the U.S. highway system, Hess said.

The U.S. must encourage drilling to enhance energy security and secure supply, while helping the economy, Hess said. “I hope all of you start to inform the public and the political leadership that intangible drilling costs are not a tax break or subsidy. If they are made up for grabs it will have an adverse effect on our energy security.”

The U.S. also needs to get the offshore industry back to business, he said. Before the moratorium in the Gulf of Mexico, the average number of permits granted per month was 12. Recently it has been about eight per month, “but it is still moving too slowly....We need to put the industry back to work.”

And the U.S. must do all it can to help increase supply in the countries that have hydrocarbons. Much of that future supply lies in Saudi Arabia and Iraq, and Hess praised Saudi Arabia for its efforts to maintain supply stability.

As for natural gas’ future in the U.S., Hess said the fuel has evolved from a bridge to a baseload fuel. The priority use is for electric generation, where the fuel offers lower costs and higher efficiencies. “This is a game-changer and we should be incentivizing to push a gas wave of electric generation,” to improve economics and help reduce the carbon footprint.

For coal, Hess noted that “Al Gore’s words ring true: ‘clean coal is like a healthy cigarette—at present it doesn’t exist.’”

As for climate-change efforts, the U.S. and the world must adopt realistic targets for carbon emission reductions, Hess said. “There’s a balance needed there. Unless we’re realistic, we could put the economy in more reversal.”

And, the U.S. can’t meet the challenge of emission reductions alone, he said, noting that China, with just 10% of the world’s GDP, has already surpassed the U.S.’ CO2 emissions.

—Susan Klann

Industry revenue model implies lower field activity in early 2012

Hart Energy’s Domestic Oil and Gas Revenue Model topped $28.3 billion for the month of July, the latest period for which official U.S. Department of Energy production and wellhead pricing figures are available. But applying current oil, gas and natural gas liquids (NGLs) pricing to July production implies a 14% reduction in overall domestic revenue at this time, suggesting rig count will head lower in the first half of 2012.

The revenue model is a useful tool for tracking the changing flow of domestic revenue from U.S. oil and gas production. Revenue flow generated from oil and gas production provides capital that is reinvested back into fieldwork for the industry. When the trend line for monthly revenues rises, so do field expenditures—and vice versa.

Of note, the July figures marked the sixth time in 2011 that monthly revenue flow for oil and gas activity exceeded $25 billion with February (and its short 28-day period) the only exception. Hart’s domestic oil and gas revenue model peaked at $29.8 billion in May 2011 as average monthly oil prices at the wellhead averaged $108.81.

The accompanying graph shows monthly revenue flow in billions of dollars for domestic natural gas, oil, and NGL production from January 2006 to July 2011, the last month for which data is available. The black line in the center of the chart adjusts revenue flow for $85 oil, which would reduce industry revenues on July’s production levels to $25 billion monthly. A further reduction to sub-$80 oil would result in monthly revenues similar to 2006-07 and 2010, suggesting rig count and field activity would pull back.

Hart Energy’s model serves as an informal predictor of future activity. Rig count direction follows the trend in revenue flow with a 90-day lag.

That rule of thumb is worth remembering with oil prices suffering from an onslaught of bad global economic news. July revenue flow reflects monthly average wellhead prices of $97.30 per barrel. However, adjusting the monthly revenue model to accommodate $85 prices at the wellhead reduces domestic revenues by $2.5 billion, to $25.8 billion monthly. Substituting the $77.50 close on October 3 further reduces revenue flow to $23.8 billion—assuming oil, gas and NGL production remains unchanged from that reported in July.

Thus, a sustained period of wellhead oil prices in the sub-$85 range would suggest a drop in rig count during the first quarter 2012.

For comparison, $85 oil reduces industry revenues to levels last seen in the fourth quarter of 2011.

A further drop to sub-$80 oil reduces industry revenue flow to the low $20-billion level monthly, or revenue reflective of volumes during the first nine months of 2010. Revenue flow at that level is also similar to industry conditions in 2007 before the climb began to the 2008 peak. However, field costs are higher now, with the post-2008 transition to unconventional plays and their attendant demand for greater service intensity, suggesting a margin squeeze on operators would be greater now than in prior years.

Operator interest in liquids beginning in the spring of 2010 is reflected in gradually rising volumes of both domestic oil production, which reversed a multi-decade decline at the end of 2008 (and which has grown approximately 12% to 5.6 million barrels of oil per day in July 2011), and NGL production.

While rising liquids production is an important factor, the real stimulus comes from higher oil prices. The general rise in oil prices over the past few years boosted domestic NGL revenues from less than $1 billion monthly in early 2009 to $3.3 billion in July 2011.

July’s revenue total was the fourth-highest monthly figure for NGLs in the last decade and within shouting distance of the $3.8-billion peak in July 2008.

Meanwhile, monthly natural gas revenues have oscillated between $7- and $8 billion since January 2010, but reached $8.3 billion in July 2011 on the basis of higher production.

—Richard Mason How to do business in Asia’ s energy giant—think ‘China Inc.’

In the post-recessionary U.S. economy, all eyes have increasingly turned toward Asia and its rapidly developing economies. The region saw its share of the world’s economic growth increase to about 40% from 2000-2005 and nearly 50% from 2005-2010, according to Ernst & Young Oil & Gas data. In the Far East, one major emerging market is taking a more globalized and strategic approach to amassing long-term energy resources.

How to do business in Asia's energy giant - think "China Inc."

In 2010, China trumped the U.S. to become the world’s biggest energy consumer in total coal, oil, natural gas, nuclear power, and renewable energy usage. For now, however, the energy behemoth lags behind the U.S. as the second-largest oil consumer. But as industry and increased investment continue to shape the world’s most populous country, China will likely double its oil consumption to more than 19 million barrels per day by 2035, according to the IMF World Economic Outlook database. China also is poised to outshine the U.S. as an economic superpower in the next two decades, alone accounting for nearly 30% of the world’s growth during the next five years.

While this ramp-up in activity could be a harbinger of new ventures and opportunities in China, oil and gas companies looking to do business in China also face the unique challenge of understanding the country’s political and cultural goals, what international corporate strategist and investment banker Dr. Robert Kuhn referred to as China’s “politico-strategic framework,” in a keynote presentation at the Ernst & Young Energy Executive Insight Session in Houston in late September. In gaining this critical understanding, companies willing to form mutually beneficial relationships with China “will have an enormous impact,” he said.

“To understand China, the first thing to really get your mind around is that the policies of the nation are completely determined by the personalities of the leaders,” Kuhn said. “This is the case in no other developed nation as strong as it is in China.” And understanding the nation’s politics and leadership are imperative components when integrating business strategies.

“Every company virtually in the world has a China strategy, whether they know it or not,” Kuhn said. Part of the underlying challenge is to be aware of the China strategy so the company can react to it.

“Working with China in any capacity with the attitude, ‘we are going to continue doing what we do best’ (instead of integrating new strategies) will only sub-optimize that company’s business,” placing it at a competitive disadvantage, Kuhn said.

Any company that believes it can work in China using only a government relations department to handle activity is misled. “Government relations is (only) a part of it,” Kuhn said, explaining that the country functions and strategizes like a corporate entity rather than as a state. “If you begin to think of China as a company, then you begin to start to understand how best to do business with China. The best way I have found to describe it is that you’re dealing with ‘China Inc.,’” he said.

When advising on company strategies, Kuhn said he categorizes the companies he works in two general ways: companies that have an opportunity to work in China and alongside Chinese companies, and companies China will invest in and forge partnerships with for resources and technology sharing.

Contrary to Western opinion, China does not want to take over the world, Kuhn said, explaining that China is more interested in partnering with and forming relationships with other economic powerhouses to learn from and exchange commodities.

—Nancy Agin

Argentina’s shale-gas plays lure the majors back for another look

With an estimated shale-gas resource of 774 trillion cubic feet (Tcf), Argentina ranks third in the world in terms of technically recoverable shale-gas resources. The country also has an estimated 11 Tcf of tight-sands gas resources.

That potential is attracting major oil companies such as ExxonMobil, Total, Chevron and large independents such as Apache Corp. Foreign investment in E&P in the South American country is starting to pick up again after a hiatus brought on by a government-regulated gas price that is now $2 to $2.50 per thousand cubic feet (Mcf) of gas, significantly below the breakeven price required to make shale-gas plays work.

“One of the key impediments is the gas and oil pricing regime,” said Anish Kapadia, senior research analyst, Tudor Pickering Holt & Co., during a Hart Energy webinar, “Argentina’s Neuquen Basin: A World Hotspot for Unconventional Resources.” He added, “The regime that is in place in Argentina will change.”

The government began that change in 2008 with the Gas Plus Program, designed to attract investment in unconventional resources. The program allows producers to supply gas to customers willing to pay more than the government-regulated price.

“The gas price is determined by the government based on a ‘reasonable’ rate of return,” explained Laura Atkins, director of petroleum research, Hart Energy. “Recent prices for tight gas have been $4 to $7 per million Btu (MMBtu). Oil prices are controlled by an export tax and are currently around $60 per barrel.”

The price for natural gas is still well below the cost of imported gas. The blended mix of pipeline gas from Bolivia and liquefied natural gas is around $9.50 per Mcf, Kapadia noted.

“With significant shale-gas and tight-gas potential, there’s a clear rationale for the government to allow a higher price, say $6 to $7 per Mcf to domestic producers. It will save the government $2 to $3 per Mcf plus encourage investment and get tax revenues,” he explained.

And, the industry is responding. In August, Halliburton announced it had completed the first horizon- tal, multistage-hydraulic-fracture, shale-gas completion in Argentina’s Neuquen Basin for Apache Corp.

Apache Energia Argentina is in a joint venture with Madalena Ventures Inc. on the Cortadera Block in the Neuquen Basin. The joint venture drilled the CorS X-1 well to a total depth of 14,760 feet. A full suite of electric logs was run on both conventional and unconventional formations. The Vaca Muerta shale was found to be 708 meters (2,024 feet) in gross thickness. Cores were also taken in the conventional Quintuco and Mulichinco formations.

At the end of August, Exxon-Mobil Exploration Argentina and Americas Petrogas agreed to explore and possibly exploit Americas’ four Los Toldos blocks totaling 163,500 acres in the Neuquen Basin. The four blocks are along the Chihuidos high in a favorable location relative to other recent discoveries of shale oil and gas in the Vaca Muerta shale. The company expects to spud the first well on the blocks in the fourth quarter.

ExxonMobil will earn a 45% interest in the farm-in while Americas will retain 45%. The remaining 10% is held by Gas y Petroleo del Neuquen. Exxon-Mobil will provide technical assistance.

The U.S. Energy Information Administration has cited a risked, recoverable resource of 240 Tcf of gas in the Vaca Muerta shale in the basin.

Vaca Muerta, or “dead cow,” is the odd name for the shale that could be very similar to the Eagle Ford in the U.S., said Kapadia. It has dry-gas, wet-gas and oil corridors. The Neuquen Basin has been producing for more than 100 years and there are thousands of wells that have been drilled through the shales.

“The data from the wells shows the key characteristics of the rock are in line with or better than shale plays in the U.S.,” he noted. “The 30-day, initial production rates for the first five wells ranged from 200 to 560 barrels per day.”

YPF has the largest acreage position in the Neuquen Basin with about 3 million net acres. Apache, Total and Chevron have all increased acreage positions recently. New entrants include ExxonMobil, GTE and EOG. Pure-plays on Argentina include Petrobras Argentina, Madalena, Crown Point, Americas, APCO, ArPetrol and Azabache.

“Most of the acreage has been bought up,” Kapadia said. “To get more acreage, you will see merger and acquisition deals and farm-ins as other companies see the potential of this play.”

YPF plans to drill about 30 appraisal and development wells this year plus 13 exploratory wells. Apache (51%), Americas (19.5%), Energicon (19.5%) and Gas y Petroleo de Neuquen (10%) are testing the Vaca Muerta shale on the Huacalera Block.

—Scott Weeden

IEA: Unconventional gas production to post significant rise

Unconventional oil and natural gas liquids will account for 9.2 million barrels per day or 35% of the total increase in liquids production in the reference case by 2035, according to the U.S. Energy Information Administration’s (EIA) “International Energy Outlook 2011,” released in mid-September. Unconventional natural gas production is predicted to rise from 14 trillion cubic feet (Tcf) in 2008 to 43 Tcf in 2035.

“High oil prices, improvements in exploration and extraction technologies, emphasis on recovery efficiency, and the emergence and continued growth of unconventional resource production are the primary factors supporting the growth of non-OPEC liquids production in the reference case,” according to the report.

Natural gas is expected to have the fastest growth rate among fossil fuels over the projection period. Unconventional natural gas supplies are expected to increase substantially, especially from the U.S., China and Canada.

Other areas, such as Europe, will continue to see declines in gas production at a rate of about 0.9% per year through 2035, due to declining conventional North Sea production, primarily. Unconventional production will slow the rate of overall decline.

Growth in Australian gas production is expected from 1.7 Tcf in 2008 to 5.7 Tcf in 2035. The Australia/New Zealand region shows the strongest growth in gas production among OECD regions—4.5% per year.

“With more than 40% of the world’s proved natural gas reserves, the Middle East accounts for the largest increase in regional natural gas production from 2008 to 2035 and for 26% of the total increment in world natural gas production in the reference case,” the outlook notes.

About 17% of the global increase in gas production will come from non-OECD Europe and Eurasia, which includes Russia, Central Asia and non-OECD Europe.

“If Russia is to increase exports to Asia while at least maintaining exports to Europe, it must invest in new fields. Moreover, it will require such investment simply to maintain current production levels because production is in decline at its three largest gas fields (Yam-burg, Urengoy and Medvezh’ye).”

Natural gas production from Africa is expected to nearly double from 7.5 Tcf in 2008 to 14.1 Tcf in 2035. “Remaining resources are more promising in West Africa than in North Africa, which has been producing large volumes of natural gas over a much longer period,” the report notes.

The fastest growth for natural gas production in Latin America is forecast for Brazil, averaging 6.9% per year. “Recent discoveries of oil and natural gas in the subsalt Santos Basin are expected to increase the country’s gas production,” according to the outlook.

On the oil side, non-OPEC production is being boosted by the return to sustained high oil prices, which has encouraged investment in conventional liquids production, enhanced oil recovery projects and unconventional liquids production. Non-OPEC production should rise from 50 million barrels per day in 2008 to 65.3 million in 2035.

“The overall increase results primarily from higher production in four countries: Brazil; Russia; Kazakhstan; and the U.S. Among non-OPEC producers, the near absence of prospects for new, large, conventional petroleum liquids projects, along with declines in production from existing conventional fields, results in heavy investment in the development of smaller fields,” says the report.

The major areas of decline are in Mexico and the North Sea, while the most significant decline in non-OPEC liquids production is projected for Europe. A decrease from 5.1 million barrels daily in 2008 to 3.0 million in 2035 is expected.

“Although the shortage of investment in Mexico is expected to lead to a mid-term decline, Mexico has potential resources to support a long-term recovery in total production, primarily in the Gulf of Mexico,” the report noted.

“The extent and timing of a recovery will depend in part on the level of economic access granted to foreign investors and operators. Pemex currently does not have the technical capability or financial means to develop potential deepwater projects in the Gulf of Mexico.”

For OPEC producers, Saudi Arabia will maintain its lead in liquids production. Iraq’ s production could increase by 3.7% per year, assuming “that political, legislative, logistical, investment and security uncertainties will be resolved in the long term, and that OPEC constraints and resource availability will be the factors with the strongest influence on Iraq’s willingness and ability to increase production,” the outlook stated.

Unconventional liquids production in OPEC depends primarily on projects in Venezuela’s Orinoco region and Qatar’s gas-to-liquids plant.

“Outside OPEC, unconventional liquids production comes from a much more diverse group of countries and resource types,” the report notes. “As a whole, non-OPEC unconventional liquids production in the reference case increases by 8.2 million barrels per day. By volume, the countries making the largest contributions to the increase in non-OPEC unconventional liquids are Canada (3.3 million barrels daily), the U.S. (2.3 million), Brazil (1.2 million) and China (900,000 barrels per day).”

—Scott Weeden

Poland expects shale-gas production to surface by 2014

With a drilling rig in the background, Polish Prime Minister Donald Tusk recently touted the benefits of shale-gas production. Visiting a shale-gas drilling rig in Lubocino in Pomerania, the prime minister stated, “After many years of gas and energy dependence from our large neighbor, it is safe to say that my generation will live to see the moment when we will be self-dependent as far as gas is concerned.

“We claim, with moderate optimism, that 2014 will be the beginning of commercial exploitation. We have worked out a prospect until 2035, and this is the moment when we will be able to say that we will be dependent mainly on our own gas.”

More than 100 concessions for shale-gas exploration were granted to foreign and domestic companies, noted Tusk.

According to estimates, there may be up to 5.3 trillion cubic meters (187 trillion cubic feet) of recoverable shale-gas reserves in Poland.

Poland does face some political opposition to the shale-gas development. The European Union is said to be considering anti-shale-gas regulations. Polish officials have said they will veto any edict from the EU that would interfere with the development of the country’s resources.

Poland is leading the shale-gas revolution in Europe and is by far the most active country in terms of leasing and drilling activity.

And, the government wants to keep as much money in the country as possible. Government officials are working with Norwegian and Canadian exports to devise legal provisions that will guarantee profit to Poland from shale-gas development.

The prime minister was at the Lubocino-1 well, which was drilled by Polskie Górnictwo Naftowe i Gazownictwo (PGNIG). Gas production began following hydraulic fracturing of the shale formation. Drilling of production wells is expected to begin in the middle of 2012 with trial exploitation in 2013.

PGNIG has received 15 concessions that allow exploration for unconventional deposits.

Another company operating in Poland is 3Legs Resources Plc. The company has completed testing of one horizontal well—Lebien LE-2H—and is drilling a second vertical pilot well, the Warblino LE-1H.

ConocoPhillips is farming in on the 3Legs’ Baltic concessions. It is providing funding for seismic surveys and the drilling of three wells in return for the right to acquire a 70% interest in the concessions. ConocoPhillips has until March 2012 to give notice within 180 days to exercise the right.

ExxonMobil is preparing to frac its second test well near the eastern town of Siennica. The company has six licenses to explore for shale gas in Poland.

In the Lublin Basin, Exxon (51%) is operating in partnership with Total (49%). In the Podlasie Basin, Exxon has partnered with Hutton Energy. o Wntt— S eeced

For more on shale gas in Poland, see

OilandGasInvestor.com ? and the July 2011 cover story.

NPC study: North America oil is an abundant resource

Contrary to conventional wisdom, the North American oil resource base could provide substantial supply for decades ahead, according to a major new report by the National Petroleum Council (NPC) titled Prudent Development: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources.

Released in mid-September, the 18-month study cited four major conclusions. One of those is that the North American oil resource base offers substantial supply for decades ahead and could help the U.S. reduce, but not eliminate, its requirements and costs for oil imported from outside North America.

“This landmark study represents a comprehensive and candid view of our nation’s energy future that we hope will serve as an important tool in creating an informed energy policy for America,” said Jim Hackett, chairman and chief executive officer, Anadarko Petroleum Corp., and chairman of the NPC’s Resource Development Committee, which conducted the study at the request of U.S. Secretary of Energy, Steven Chu.

“Prudent development of our domestic energy resources, particularly natural gas and oil, drives economic development, creates jobs, and enhances our nation’s energy security, and this report recognizes those opportunities, as well as candidly addresses the challenges and potential solutions. It also suggests that natural gas is a good near-term answer for reducing America’s carbon footprint.”

Not surprisingly, the study concluded that the potential supply of natural gas is far greater than was estimated even a few years ago. In 2007, it looked as though a shortage of natural gas would lead to higher imports of liquefied natural gas (LNG). However, with LNG imports hitting the lowest levels in years, that has not occurred because of the domestic gas resources and the technology to develop those resources.

As noted, “These resources have the potential to meet even the highest projections of demand reviewed by this study.”

And, given the success in tapping unconventional oil and gas resources, there are significant, new opportunities for global technological leadership and an expanded global role for U.S. oil and gas companies, stated the study.

The third conclusion was that North America would still need the oil and gas resources along with strides in energy efficiency and alternative energy.

“Americans will need natural gas and oil for much of their energy requirements for the foreseeable future. Moreover, the natural gas and oil industry is vital to the U.S. economy, generating millions of high-paying jobs and providing tax revenues to federal, state, and local governments,” the report stated.

Finally, the study emphasized that the benefits of gas and oil would result from working in an environmentally responsible way.

“The critical path to sustained and expanded resource development in North America includes effective regulation and a commitment of industry and regulators to continuous improvement in practices to eliminate or minimize environmental risk. These steps are necessary for public trust,” according to the study.

Without the industry improving its environmental, safety and health practices, access to available resources could be undermined. For greater access for the industry, consumers, and all other stakeholders, industry participants must continually improve their environmental, safety, and health practices to preserve the benefits for all.

For the study, the NPC examined a broad range of energy supply, demand, environmental, and technology outlooks through 2050, including issues related to public health, safety, environmental risks associated with production and delivery practices, and opportunities for natural gas to reduce emissions from energy use.

The NPC proposed five core strategies. The first is to support prudent development and regulation of natural gas and oil resources. Those measures could include councils of excellence covering environmental, safety, and health practices. Corporate and regulatory commitment to advancing environmental performance is needed. Affected communities must be engaged. Policies must also be structured to support prudent development of and access to resources.

Second, there must be a mechanism to put a price on greenhouse gas (GHG) emissions that is economy-wide, market-based, predictable, transparent and part of a global framework. It will be difficult for the U.S. to reduce GHG emissions without that mechanism . Options must be kept open for carbon capture and sequestration, full fuel cycle and technology choices, and developing methodologies to minimize environmental footprints.

A focus on energy efficiency is the third strategy. Policies are needed that support continued progress to adopt cost-effective efficiency standards for buildings and appliances. Disincentives for utilities to deploy efficiency measures should be removed. Barriers to combined heat and power as a way to increase the efficiency of electricity production should be removed.

Fourth, the function of energy markets should be enhanced with policies and regulations that improve mechanisms for utilities to manage the impacts of price volatility, harmonize market rules and service arrangements between the wholesale natural gas and electric markets. Environmental regulatory certainty affecting investments and fuel choices in the power sector must be increased.

Finally, a skilled workforce must be developed through increased public and private financial support for educational and training activities.

—Scott Weeden

Macondo blowout report generates a mixed response

While the U.S. government’s final report on the Deepwater Horizon blowout was not officially an agenda item at the American Association of Mineral Owners’ 12th annual conference in Houston in mid-September, it was the topic de rigueur.

David Pursell, managing director and head of securities for Tudor, Pickering, Holt & Co. Securities Inc., was critical of the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) report that spread the blame to companies other than BP, the operator of the faulty well.

Meanwhile, for Jacqueline Lang Weaver, a professor at the University of Houston Law Center, the blowout and ensuing report prompted déjà vu.

Pursell compared the April 20, 2010, explosion at the Macondo prospect with the space shuttle Challenger disaster, which claimed the lives of seven astronauts when the spacecraft broke apart 73 seconds into its flight.

By the time the market closed on the day of the Challenger tragedy, only one of the companies that had potential liability, Morton Thiokol, was down significantly (12%), Pursell said.

“Within a couple of hours Wall Street figured out very quickly and efficiently that maybe it wasn’t just an O-ring failure. They figured out what company’s products were ultimately responsible,” he said.

Following the BP Macondo disaster, however, the market’s reaction was very different, Pursell pointed out. One month later, the stocks of all five key companies involved in the Macondo project—BP, Anadarko, Halliburton, Transocean and Cameron—were down the same percentage.

“But 10 weeks after the disaster, the market figured out that Halliburton and Cameron had little or no liability,” he said, adding that Anadarko, BP and Cameron shares were down the same percentage at that point.

Shortly afterward, Anadarko’s stock rose slightly because, Pursell said, “the market had figured out that maybe their liability was not as much.

“The point is, to the stock market, the oil and gas business is a hell of a lot more complicated than rocket science,” he quipped.

“I encourage everyone to read the report. It is an indictment of BOEMRE. Everyone in this room who is an oil and gas guy knows it is BP’s rig and it’s BP’s fault.”

Pursell’s statement was a retort to the report’s claims that errors in judgment by BP, Halliburton and Transocean played major roles in the disaster.

“These errors, mistakes and management failures were not the product of a single rogue company, but instead revealed both failures and inadequate safety procedures by three industry players that have a large presence in offshore oil and gas drilling throughout the world,” the report claimed.

While the report contends that offshore drilling can be done safely, it proposed major changes in governmental regulations and industry practices.

Weaver, the UH law professor, sees similarities in the Macondo explosion and the 1989 Exxon

Valdez oil spill that soiled the waters of Prince William Sound and blackened more than 1,000 miles of coastline.

In reading the reports of the two incidents, Weaver said that “you can substitute Exxon Valdez for Deepwater Horizon” in many references. In making this comparison, Weaver referred to what she called “the spirit of Ronald Reagan, which is really anti-big government and pro-deregulation.

“The ideology plays a very real role in the Exxon Valdez spill, as it has in the financial crisis and the BP Deepwater Horizon,” Weaver said, as she made a pitch for the industry to become the pace-setter in developing higher standards “in a deepwater, high-pressure, high-temperature” environment.

In further comparison of the Alaska oil spill and the Gulf of Mexico explosion, Weaver noted a major difference. Congress, which moved quickly on approving legislation resulting from the Exxon Valdez spill, has yet to act on Deepwater Horizon.

“After Exxon Valdez, Congress immediately passed the Oil Pollution Act of 1990,” she said. The legislation established provisions that expanded the federal government’s capacity to respond to oil spills and provide money and resources for cleanup.

“Congress also put in a requirement that tankers have double hulls, so even if an alcoholic captain of a large tanker crashed into a reef the double-hull tanker will help prevent a disaster from man-made errors.”

After Deepwater Horizon, the prevailing question is, “What is the equivalent of the double-hull tanker that will prevent disasters from inevitable human error?” Weaver noted.

The answer, she said, may be the Marine Well Containment Co.’s stacking cap, which is designed to be put on top of a well and—when working in conjunction with floating barges—captures oil fairly quickly.

“Yes, it will take a couple of days to clear the debris, but you wouldn’t have weeks and weeks of a massive oil spill,” Weaver said, adding that industry task forces helped devise the idea of the marine well containment cap.

For Gulf Coast producers, the timing of the Macondo explosion could not have been worse, Weaver said. “President Obama had finally, after 20 years, (approved) a new leasing program and announced it in March. Three weeks later, here comes the Macondo well, which basically shuts down the Gulf and delays lease sales.”

The bottom line, Weaver said, is that a priority on safety, better blowout preventers and other equipment, and a knowledgeable, well-funded regulatory agency is the formula for the “Holy Grail” for the industry.

Weaver talked about the approach of executives such as former Apache Corp. co-chief operating officer John Crum and Exxon Mobil Corp. chairman and chief executive Rex Tillerson, who think that companies have an obligation to internalize a “safety cause” system such as the one used in the North Sea, which puts the burden on the operator to assess and mitigate all risks.

“It makes it harder on the well operator. But it makes you plan and makes you look at every aspect of what can happen out there, and I think that provides a better chance of protecting the environment,” Weaver said in summing up Crum’s philosophy.

Tillerson and other executives, according to Weaver, “have testified that they would not have drilled the way BP did. That’s not to say as a whole that the industry does not have problems. But if you look at the testimony Tiller-son presented and the way Exxon works, they basically perform a (well operations) audit with cold eyes” anywhere in the world.

“Being wise in advance is difficult, but you have to collect the company’s collective knowledge to pool ideas about accident scenarios. And, you should never stop being afraid. If you forget the hazards in your work, you won’t be thinking about what might go wrong. You will experience vulnerable arrogance, which is basically complacency,” she said.

“Industry seems to be willing to say it was complacent but not willing to say it was negligent. But if you ask me, complacency is negligence in a high-temperature, high-pressure environment.”

According to the University of California, Berkeley, Center for Catastrophic Risk Management, 50,000 wells have been drilled in the Gulf. However, only 43 were considered high-risk, as was the Macondo.

Weaver responded to the statistic with a compelling question: “So is the risk of failure 1 in 50,000, or 1 in 43?”

—Mike Madere

For more analysis of the Gulf of Mexico post-Macondo, see OilandGasInvestor.com.