Production increased by 5.3 Bcf/d compared with 2024, according to the EIA’s latest Natural Gas Monthly. Three regions — Appalachia, Permian and Haynesville — accounted for 67 per cent of total U.S. marketed gas production and 81 per cent of the growth last year.

Higher natural gas prices helped support drilling activity. The Henry Hub benchmark price rose about 60 per cent in 2025 to US$3.52 per million British thermal units (MMBtu), improving the economics of production across multiple basins.

The Appalachian Basin in the northeastern United States remained the country’s largest natural gas producing region, accounting for 36.6 Bcf/d, or roughly 31 per cent of total U.S. marketed production.

Production growth there has slowed in recent years because of limited pipeline capacity to move gas to markets. However, additional capacity began coming online in 2024 when the Mountain Valley Pipeline was authorized to start operating. Combined with higher gas prices, that helped push Appalachian production up by 1.1 Bcf/d in 2025, compared with only modest growth in 2024.

The Permian Basin in Texas and New Mexico continued to play a major role in U.S. gas growth. Production in the region rose 11 per cent, or 2.7 Bcf/d, reaching an average of 27.7 Bcf/d in 2025.

Much of the natural gas produced in the Permian is associated gas, meaning it is generated as a by-product of oil production. Even though benchmark West Texas Intermediate crude prices declined from US$77 per barrel in 2024 to about US$65 in 2025, prices remained high enough to support oil-directed drilling.

Industry surveys suggest the basin remains economically viable at those levels, with breakeven prices estimated around US$61 per barrel in the Midland Basin and US$62 in the Delaware Basin.

Another factor contributing to higher gas production in the Permian is the region’s rising gas-to-oil ratio, meaning wells are producing more natural gas relative to oil over time.

The Haynesville shale, which spans Louisiana and Texas, also contributed to production growth. Output there averaged 14.9 Bcf/d in 2025, about four per cent higher than in 2024.

Haynesville wells are typically much deeper — between 10,500 and 13,500 feet — than wells in the Appalachian Basin, which generally range from 4,000 to 8,500 feet. The greater depth increases drilling costs, but the basin’s location provides an important advantage.

Haynesville sits close to liquefied natural gas export terminals and large industrial natural gas consumers along the U.S. Gulf Coast, making it an attractive supply source for both domestic and export markets.

The EIA expects U.S. natural gas production to continue growing in the coming years as additional infrastructure and export demand support drilling activity. Expansion of LNG export capacity along the Gulf Coast is expected to play a key role in shaping future natural gas markets.

The United States has been the world’s largest producer of natural gas for more than a decade, largely because of the expansion of shale gas production since the mid-2000s.

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A decade since the start of a shale gas revolution that unlocked new supplies and resulted in a “wholesale turnaround” in U.S. production, the overall size of recoverable gas reserves continues to increase and the pace of production growth is only accelerating, according to IHS Markit.

IHS Markit expects natural gas production to rise by almost 8 billion cubic feet per day (Bcf/d) or more than 10 per cent in 2018 alone. Altogether, U.S. production is expected to grow by another 60 per cent over the next 20 years, the report says.

Additionally, IHS Markit now estimates that approximately 1,250 trillion cubic feet (Tcf) of U.S. supply is economic below $4 per MMBtu Henry Hub price today, up from a previous estimate of 900 Tcf in 2010.

The new report, entitled The Shale Gale Turns 10: A Powerful Wind at America’s Back assesses the impacts of the first 10 years of the unconventional gas revolution—unlocked through the combination of hydraulic fracturing and horizontal drilling technologies—and its future potential.

When the shale revolution began a decade ago, the prevailing assumption was that the U.S. supply base was being exhausted and that the country would have to become a major importer of liquefied natural gas (LNG).

Instead, in what the report describes as a “wholesale turnaround,” U.S. output rose by more than 40 percent in that first decade (2007-2017) and real natural gas prices fell by two thirds during the same period.

In contrast to the assumption a decade ago, the United States is now on track to become one of the world’s major LNG exporters, the report notes. IHS Markit expects U.S. LNG export capacity to more than double in the next five years and rise to at least 10 Bcf/d by 2023.

“To say that the ‘Shale Gale’—as IHS Markit originally coined it in 2010—has been anything but a veritable revolution would be an understatement,” said Daniel Yergin, vice chairman, IHS Markit and co-author of the report.

Yergin continued, “It represents a dramatic and largely unanticipated turnaround that dramatically changed both markets and long-term thinking about energy. The profound and ongoing impacts on the industry, energy markets, the wider economy and the U.S. position in the world continue to unfold.”

The most dramatic effect has been on the U.S. electric power industry, the report says. Where coal and nuclear had previously dominated the growth in share of U.S. electric power generation, natural gas has become a “backbone of electric generation” and regularly competes with coal for the largest share of total electric generation.

By 2040, IHS Markit expects natural gas’ share to grow from almost one-third to nearly half of all electricity generated in the United States.

The report observes that the Shale Gale, has also made a major contribution to reducing U.S. CO₂ emissions. IHS Markit estimates that in 2017, CO₂ emissions from power generation were down 30 percent from 2005. More than half of that emission decline was from gas replacing coal.

In contrast to the assumption a decade ago, the United States is now on track to become one of the world’s major LNG exporters, the report notes. IHS Markit expects U.S. LNG export capacity to more than double in the next five years and rise to at least 10 Bcf/d by 2023.

“To say that the ‘Shale Gale’—as IHS Markit originally coined it in 2010—has been anything but a veritable revolution would be an understatement. It represents a dramatic and largely unanticipated turnaround that dramatically changed both markets and long-term thinking about energy. The profound and ongoing impacts on the industry, energy markets, the wider economy and the U.S. position in the world continue to unfold,” said Daniel Yergin, vice chairman, IHS Markit and co-author of the report. “

The most dramatic effect has been on the U.S. electric power industry, the report says. Where coal and nuclear had previously dominated the growth in share of U.S. electric power generation, natural gas has become a “backbone of electric generation” and regularly competes with coal for the largest share of total electric generation.

By 2040, IHS Markit expects natural gas’ share to grow from almost one-third to nearly half of all electricity generated in the United States.

The report observes that the Shale Gale, has also made a major contribution to reducing U.S. CO₂ emissions. IHS Markit estimates that in 2017, CO₂ emissions from power generation were down 30 percent from 2005. More than half of that emission decline was from gas replacing coal.

What started with natural gas would be extended to oil a few years later, with enormous global impact, the report notes. Between 2008 and 2018, U.S. oil output more than doubled and exceeded the previous height set in 1970.

On a net basis, the United States went from importing 60 per cent of its liquid fuel at the peak to below 16 per cent in 2018—and the share is still falling. The United States is now on track to be the world’s largest oil producer, ahead of Russia and Saudi Arabia, by early next year.

The combined developments of unconventional oil and gas have had far-reaching impacts for the manufacturing sector and the U.S. economy as a whole, the report says.

IHS Markit estimates that more than $120 billion in new capital investments will be spent from 2012-2020 to expand U.S. petrochemical manufacturing capacity—a result of abundant and inexpensive natural gas and natural gas liquids providing advantages in terms of thermal energy, feedstock and electricity costs. “Ancillary” investments could double that number, the report says.

Previous IHS Markit research found that as many as four million jobs (indirect, direct and induced) could be supported by unconventional activity by 2025.

“U.S. power markets and the economy overall would look significantly different had the shale revolution not taken place,” said Sam Andrus, executive director, IHS Markit and co-author of the report. “The new outlook for natural gas cost and availability has created new possibilities for progress toward national goals of energy efficiency, cost efficiency, environmental protection and energy security. In short, the Shale Gale put a powerful new wind at America’s back.”

The Shale Gale Turns 10 will be followed by a series of research papers available to IHS Markit clients, exploring the global implications of the Shale Gale for the energy value chain, economies

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Rise in use of kerosene to offset waxiness in US shale boosting jet fuel prices

Jet fuel prices have hit six-year highs, mostly due to unique properties of US shale that refiners have to deal with when refining the plentiful fossil fuel.

In 2017, the United States produced about 4.7 million barrels per day (b/d) of crude from shale formations.  Refiners have used that crude to manufacture diesel, gasoline and jet fuel.

According to Reuters, shale oil is younger than some other types of crude and it differs somewhat from oil from other formations.  John Jechura, professor of chemical engineering at Colorado School of Mines, told Reuters that shale is a bit “waxier”.

To offset that waxiness when making diesel, refiners can add kerosene and other components found in jet fuel to make the fuel useable for truck and car engines, market sources told Reuters.

Using these components cuts the available pool of jet fuel at a time when economic growth in the US has helped increase air travel.  As well, not all refiners can make jet fuel.  And, those that do manufacture jet fuel also make diesel, which is also in high demand now.

“Some jet fuel has been diverted to the diesel pool because diesel demand is quite strong this year in the U.S., particularly on the East Coast,” Amrit Naresh, global distillate analyst at ESAI Energy told Reuters.

In April, jet fuel prices rose substantially, and, on April 20 were 4.50 cents/gallon above the ultra-low sulphur diesel futures benchmark on the New York Mercantile Exchange.  This is the highest since December 2014, excluding a spike last year after Hurricane Harvey.

Traders tell Reuters jet fuel last traded at 0.75 cents above futures and prices have not been this high in June since 2012.  Diesel futures are trading at about $2.15/gallon while jet fuel is at $2.16/gallon.

The rise in prices comes at a time when US airlines report they expect 3.7 per cent more passengers than last year, according to Airlines for America, an industry group.

Despite more customers, the rising cost of jet fuel is squeezing airline profits.  On Monday, the International Air Transport Association forecast airlines’ combined profits will be 12 per cent less than was forecast in December.  This is mostly due to the rising price of jet fuel.

In March 2018, US production of kerosene-type jet fuel hit almost 1.78 million b/d, according to US Energy Information Administration data.  However, jet fuel imports fell in the first quarter of this year and unplanned shutdowns at East Coast refineries also helped boost jet fuel costs in 2018.

Refiners have found it more profitable to make diesel fuel now because regulatory costs tied to diesel have dropped, according to Neil Earnest, president of consulting company Muse, Stancil & Co. in Dallas.

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Shale gas in China has seen significant progress over the last decade, growing to nearly 600 wells and 9 Bcm (billion cubic metres) of production last year. In its latest analysis, Wood Mackenzie projects Chinese shale gas production to almost double to 17 Bcm in 2020.

Currently in production are Sinopec’s Fuling, and PetroChina’s Changning-Weiyuan and Zhaotong projects which sit in the mountainous terrain of the Sichuan Basin. Nearly 700 new wells will come onstream between 2018 and 2020 from the three projects combined, with a total capital investment of US$5.5 billion.

Despite commendable achievements in domestic shale, China will still miss its 2020 30-bcm production target announced in its 13^th energy sector five-year plan by a considerable margin.

“China is eager to materialise its shale gas potential to fuel its massive gasification initiative and support rising demand growth,” explained Dr. Tingyun Yang, consultant, Wood Mackenzie.

“In order to meet the government’s 30-bcm target, up to 725 additional wells are needed by 2020 on top of the nearly 700 new wells. This will double the amount of investment needed in the base-case drilling plan. The required well number could be larger if well productivity degrades. This is a mammoth task for the Chinese NOCs (national oil companies).”

“The speed of shale development will impact global gas markets. Considering the impact of shale gas production on domestic demand, the 2020 13-bcm ‘gap’ will have to be filled by imports, in particular LNG,” added Lynn-Yuqian Lin, consultant, Wood Mackenzie.

“We have already witnessed how China was able to leverage on flexible LNG to cope with record-high demand this recent winter season.”

“The good news for Chinese shale gas is well costs have gone down considerably – 40% for exploration wells compared to 2010 levels, and 25% for commercial wells compared to 2014. Chinese NOCs are starting to get their shale game plan together,” said Dr. Yang.

The US took more than three decades to finally realise its shale boom. Success was built on a combination of underlying factors, including competitive and open markets, active small players, developed infrastructure and easily available expertise. None of these hold true for China.

A comparison of plays and rocks reveals China’s uniqueness. Shale formations tend to be deeper, more tectonically fractured and often less-pressured than US plays. Greater depth requires deeper wells, leading to higher cost and more challenges in maintaining well integrity while drilling.

Above ground, most of China’s shale gas plays are located in mountainous terrain. Selecting viable well sites is not as straightforward as in Texas, where the topography is far flatter.

In China, operators have to first remove mountainous land to host well sites, build their own infrastructure, and transport drilling crews and equipment across vast distances to the well sites. High population density also makes drilling and hydraulic fracturing harder.

Looking at shale players, the Majors took a run at China’s vast shale resources during the first few years of the decade, but all exited after lacklustre results. Only BP now remains with two undeveloped shale production sharing contracts.

The Chinese NOCs, however, have overcome these challenges by developing their own understanding of the unique geology, relying on their own service arms to get more experience and, most importantly, progress in completion techniques and technology.

They have adopted a pad-based drilling, fracturing and production process, which reduces the footprint of the well sites on the mountains. This practice, combined with more indigenous technology and drilling and completion techniques – fracturing trucks, drillable bridge plugs, and drilling trajectory control know-how for example – have helped to save drilling time and reduce costs, while wells are becoming larger.

While Chinese shale well costs are still much higher compared to the US, (even 20% higher compared to a deeper and larger well in the Haynesville) a recent turnkey contract for drilling, cementing and completion of four Sichuan wells won by domestic oil services company Honghua Group, could perhaps hint at a new chapter in Chinese shale.

The contract would imply an all-in cost at US$7-7.5 million per well, a further 20% drop in well cost compared to 2017, once pad construction, infrastructure and facilities costs are included.

“While we do not expect a Chinese shale gas boom anytime soon, the NOCs will no doubt continue to push on and innovate, driven by the need to secure and develop energy resources for strategic reasons,” concluded Dr. Yang.

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US shale firms have used profits to boost output

According to a report by Reuters, nearly one-third of the top 25 US shale oil companies have paid or are planning to pay dividends this year.  If the companies follow through on their pledges, this would be the largest number of companies offering returns since the shale boom began about 10 years ago.

Over the past year, oil prices have gone up about one third.  This boost will allow many US shale companies to increase their revenue and respond to investors’ calls for better shareholder returns.

So far, despite booming production, investors in shale have seen thin returns because companies have plowed their profits back into production to raise output instead of offering returns to shareholders.

Reuters reports that financial disclosures from seven US shale producers, including Anadarko and ConocoPhillips, show the companies have increased their quarterly dividends this year.  Just two years ago, eight of the 25 largest shale firms cut their payouts as oil prices tanked.

“Investors are using a large megaphone as they talk to the industry about returns, and it’s on the minds of a lot of CEOs,” Travis Stice, chief executive of shale producer Diamondback Energy Inc, told Reuters.

Diamondback became the first US shale oil company to start a payout since oil prices began falling in 2014.  The company announced a 12.5 per cent quarterly dividend last month, according to S&P Global Market Intelligence.

Since the move, shares in the Permian basin-based company have gone up by about 11 per cent.

“You’re going to see more shale producers focus on dividends,” Leigh Goehring of G&R Associates told Reuters. “Shareholders are demanding it and a trend is forming.”

Since the beginning of the year, 11 US shale producers have announced plans to spend a total of $3.5 billion on stock buybacks.

This week, oil producers are meeting investors at an industry conference in New Orleans.  The annual gathering is used by energy companies to outline their yearly production goals and shape investor expectations for first-quarter results.

According to Reuters, more companies will be pressured to offer payouts through dividends or share repurchases.  Investors will be looking to discuss production gains and how companies are handling the rising costs of services.

“There does seem to be increasing evidence of financial prudence in the industry,” Andy McConn of oil consultancy Wood Mackenzie told Reuters.

Still, 12 of the 25 major shale firms will not be offering quarterly payouts.  The companies are reinvesting their cash into drilling and projects.  Reuters reports Parsley Energy and Continental Resources are two companies that say they are focused on driving growth.

However, that could change as more of their rivals focus on payouts to investors.

“Investors are looking for improving results, better returns and operational performance,” Maynard Holt, chief executive of energy investment bank Tudor, Pickering, Holt & Co told Reuters.

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Rising US shale production helped boost overall US output to over 10 million b/d

Reuters reports the secretary general of OPEC along with other cartel officials will meet with US shale firms in Houston next Monday to discuss ways to reduce the global glut of crude oil.

According to the report, OPEC Secretary General Mohammad Barkindo will be at the meeting along with chief executives from a number of US shale companies.

The meeting will be held on the first day of the CERAWeek energy conference in Houston, a yearly international gathering of energy industry leaders.

At this time last year, OPEC held unprecedented talks with fund executives and shale companies at the sidelines of conference.

“Shale has dramatically changed the world’s perception of fossil fuels,” the chief executive of one shale company told Reuters. The official, who declined to be identified by name, added “We now have a seat at the table on pricing.”

The United States oil industry is not participating in the OPEC supply cut agreement because the US private producers could be sued for collusion if they join the pact.

OPEC’s agreement has cut production by participants overall by 1.8 million barrels per day (b/d).  While the cartel and its non-member partners have cut their output, US production has risen to over 10 million b/d and the International Energy Agency forecasts the US will overtake Russia as the world’s biggest oil producer next year at the latest.

Despite the rising US output, OPEC officials say they are not concerned about the surge in US shale production kneecapping its efforts.  But, the cartel is urging shale producers to help reduce the global oversupply.

“It’s normal for shale oil, tight oil to increase in 2018 and whenever oil prices support it,” Reuters reports Iraq’s national representative to OPEC, Ali Nazar, said at an event in Berlin on Tuesday.

“But we all should look with responsibility to the market in order to keep the balance in the market as much as we can so as not to harm investors.”

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2017 should see more stable prices, beginning of US shale revival

As a year draws to its close, journalists like to look back and talk about what they got right, skip over what they got wrong, and blather about what they think will happen in the coming 12 months.

I’m no different. Especially since my 2016 prognostication record isn’t too bad, with the exception of several spectacular misses – taking a curve too fast, hurtling over the mountainside, and crashing in a ball of fire, kind of misses.

#1 on the hit parade: Let’s start with my biggest miss, the election of Donald Trump as president. 

I’m not alone on this one. I remember late in the campaign when Fox News’ Megyn Kelly interviewed Newt Gingrich, who was arrogantly predicting a Trump win based on internal polling. What I want to know is, who the hell is the GOP pollster? Everyone else was predicting a Hillary Clinton win with a 90-plus percentage certainty, including me.

Here’s why Trump is my pick as the most important energy story of 2016.

The New York billionaire promised to give the American energy industry everything in its letter to Santa Claus: rollback of the Obama Administration’s many regulations, speedier LNG approvals, opening up of federal lands for increased drilling, a revival of the coal industry, and the biggest one of all, the banning of OPEC crude oil from American markets.

Not an economist I have interviewed or a pundit I have read gives Trump a snowball’s chance in Hades of making that ban fly. Either the new President will discover he doesn’t have the power to do it, the geopolitical problems it would create are just too enormous, or the skittish Republican-dominated Congress won’t let him.

But if he does follow through with his pledge – first announced in his May 26 energy speech in Bismarck, North Dakota and repeated on the campaign trail – the ban will effectively create a North American oil market and profoundly change the American industry, which will enjoy stable domestic prices and still be able to take advantage of export opportunities.

Likelihood of Trump banning OPEC (and oil from “other nations hostile to our interest”)? Less than 50%, in my estimation. Not great odds, but better than he was given to win the Nov. 8 election. Stay tuned.

#2 – American shale producers’ reduction in costs, boost in productivity.

I called this one. Back in early 2015, when it became clear the Saudis were going to use OPEC to drive US shale companies out of market, I argued that American ingenuity, innovation, and management expertise would triumph in the end.

And that’s exactly what happened. Skeptics will argue that producers leaned on service companies for the entire cost reduction, and while that certainly is partly the case (and service producers will be looking to recoup some of their losses in 2017) that is hardly all of it.

Senior IHS Markit analyst Pete Stark told me in an interview that in the Permian Basin, for instance, the amount of oil that could be produced with $1 million of capital had doubled in the past two years. He attributed that spectacular productivity increase to drilling efficiencies, greater automation, and a range of capital and management efficiencies no one worried about when oil was over $100.

Outgoing Pioneer Natural Resources CEO Scott Sheffield told reporters during a quarterly conference call that his company’s costs were so low they were in line with the Saudis’, in some cases under $10.

In 2017, look for American ingenuity to continue. Manhattan Institute fellow Mark Mills says there are more cost reductions to come in what he calls Shale 2.0 – the application of Big Data and analytics to the optimization of shale wells.

#3 – Oil prices and the OPEC production cuts deal

Everyone remembers when WTI prices hit $23 last Jan. Now they’re hovering around $53. A more than 100 per cent increase in one year is a big story, but we’ll be watching prices with keen interest in 2017 to see if OPEC members and Russia follow through with their promises.

Sarp Ozkan, economist with DrillingInfo and author of the crude oil price forecast Supply for Every Demand, said in an interview that 2017 oil prices will be decided by the success of the OPEC-led agreement. If it fails, Ozkan predicts prices will hover in the $52 WTI range. But if it succeeds, prices could rise as high as $67 and American oil output could rise by as much as 750,000 b/d, a significant increase from the current level of 8.5 million b/d.

Energy economist Craig Pirrong at the C.T. Bauer School of Business, University of Houston, isn’t quite as bullish. When I interviewed him for an Energy News Webinar, he was skeptical OPEC members wouldn’t cheat, and forecast a high of $57 for the coming year.

The consensus among economists I’ve interviewed seems to be a range in the mid-$50s. At that price, many American shale producers will still be ramping up production.

At least they will be in the Permian Basin, where 2016 saw a land rush that drove acreage prices as high as $60,000 and saw companies flooding into West Texas to take advantage of the multiple formations and well developed infrastructure, much of it based in the Midland area.

The best news as we get set to ring in the New Year is that the worst seems to be over for the American oil patch. Prices are settling at a sustainable level, capital expenditures are stabilizing and may begin to rise, service companies are hiring and ramping up after two very difficult years.

From our news team at the North American Energy News, we wish you and yours a Very Happy New Year and all the best in your business and employment endeavors.

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Even if OPEC, Russia deal works as hoped, uptick in US shale production could keep prices depressed

Crude oil prices rose Friday on news that OPEC agreed to stabilize global markets. Somewhere in Riydah, Deputy Crown Prince Mohammed bin Salman is desperately hoping he can finesse prices high enough to cut Saudi Arabia’s burgeoning deficits but not high enough to fire up the mighty US shale production, which fell by a million b/d over the past two years of low prices.

At a meeting in Algiers, OPEC members “took into account current market conditions and immediate prospects and concluded that it is not advisable to ignore the potential risk that the present stock overhang may continue to weigh negatively well into the future, with a worsening impact on producers, consumers and the industry,” the cartel said in a press release.

This is a reversal for the Saudis, the most powerful OPEC player, which said only this spring that they didn’t care if prices were $30 or $70, they were no longer ceding market share to balance global oil markets.

Well, the Prince has had a change of heart. Low prices did not reduce production as much as the Saudis expected. Even though consumption grew rapidly, a huge glut of crude oil in inventory continued to depress prices, largely because OPEC members actually increased production by several million b/d and Russia also maximized output. Daily oversupply is thought to about 1 to 1.5 million b/d, according to analysts.

The impact of the new strategy will depend upon how OPEC ministers decide to slice and dice production numbers. Output will be limited to between 32.5 and 33.0 million b/d, down from the current 33.6 million b/d. At best, this is probably a freeze, not a cut, according to Reuters market analyst John Kemp.

Khalid al-Falih, the Saudi oil minister, says the deal will involve “gentle adjustments and reassurances to the market” but “it will be called a freeze but involve individual cuts,” according to the Petroleum Economist newsletter.

With oil prices hovering in the high $40 range on Friday, they seem poised to bump over the psychologically important $50 threshold in the near future. OPEC minister hope to keep it below $60, which University of Houston energy economist Ed Hirs says is the price the most efficient shale producers need to start up again.

“To get back into the flush of shale drilling activity at 2013-14 levels we will need sustained prices of $80/bbl at WTI [West Texas Intermediate].  Certainly many will come back at $60, but when we look at averages, half of the industry has been made noneconomic,” he said in an interview.

Hirs notes that many shale drillers have large inventories of DUCs (drilled uncompleted wells). The US Energy Information Administration estimates there are 4,117 in the four oil-dominant shale basins (Bakken, Eagle Ford, Niobrara, Permian).

Hirs says that with the many oil company bankruptcies and reorganizations that have occurred, the drilling costs for those wells have been written off.

“Many analysts think that these DUCs will be completed profitably at $50/b at the wellhead,” which are less than the commonly quoted Brent and WTI, he said.

In other words, OPEC’s new strategy is likely to have a minor impact on American shale production, but not enough to significantly affect output.

Assuming, of course, that OPEC members stick to the new ceiling. Hirs is skeptical they will.

“I doubt that the agreement will hold.  They all cheat on their quotas and underreport their production,” he said.

“The illustration of that point is the ‘addition’ of Iranian oil had a very small impact on the market. Why? It was already in the market, just at half-price or so.  Now that Iran can get $40-plus a barrel, they feel like they have a windfall.”

Russia has agreed to withhold additional production in the short-term if the Saudis follow through with their commitment, but “who among OPEC will enforce a quota agreement against Russia?” Hirs asks.

Bottom line, American and Canadian oil producers should be cautiously optimistic about the short-term impact of the OPEC and Russian new direction, if for no other reason than it signals a change of thinking among the Saudis, who have driven the price rout that began in late 2014.

Now that they’s shifted strategy, they may do so again in 2017 if the current agreement, expected to be implemented in Nov., doesn’t achieve the desired results.

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Not many American oil producers are competitive at low prices, but EOG Resources has the technical knowhow and execution to pull it off, says energy economist Ed Hirs.

EOG announced in its last operational update that “premium inventory” (defined as direct after-tax rate of return hurdle rate of at least 30% at $40 prices) had increased from 2.0 to 3.5 billion BOE, and net premium drilling locations had risen from 3,200 to 4,300. According to the update, EOG produced US crude oil volumes of 265,400 b/d in Q2, beating the “midpoint of the company’s guidance by 2 per cent.”

What’s EOG’s secret?

Hirs says the company excels in all the key facets of operating an oil and gas company. EOG buys the best resource, gets in early, and sells the not so great rock at a profit. The company is known for having a first rate science and technical team. And they’re very good at execution in the field.

“They’re extremely sharp. Certainly, I would say, the finest in the oil patch right now,” Hirs said in an interview.

Like other producers, EOG has worked hard to reduced its costs of doing business. The operations update lists exploration and development expenditures (excluding property acquisitions) down 49 per cent.

“The benefits of EOG’s premium drilling strategy are beginning to show in our operating performance,” said CEO Bill Thomas.

“We are committed to focusing capital on our premium assets, which we are confident will increasingly lead to break-out performance as prices improve.”

South Texas Eagle Ford

The Eagle Ford is EOG’s largest high-return play, according to the update.  In Q2, the company increased its Eagle Ford premium inventory by 390 net drilling locations to almost 2,000 total, which could be expanded “significantly” if more cost reductions or well productivity improvements are achieved.

For example, EOG estimates that a 10 per cent reduction in completed well costs or a 10 per cent improvement in estimated recoverable reserves per well would more than double EOG’s premium inventory in the Eagle Ford.

During Q2 EOG completed 60 wells in the Eagle Ford with an average treated lateral length of 4,800 feet per well and an average 30-day initial production rate per well of 1,705 boed, 175 b/d of natural gas liquids (NGLs) and 1.1 MMcfd of natural gas.

Delaware Basin

In Q2 EOG expanded its premium inventory in all three of its major formations – the Wolfcamp, the Second Bone Spring, and the Leonard, adding more than 500 net premium drilling locations, and continuing to improve the economics through advances in well and completion designs, including recent breakthroughs that enable higher productivity with longer laterals.

“EOG is well positioned for years of high-return growth in this world-class basin,” according to the update.

The company completed 16 wells during Q2 with an average treated lateral length of 6,500 feet per well, a 44 per cent increase in lateral length from Q1.

The average 30-day initial production rate per well was 2,410 boed, 340 b/d of NGLs, and 2.8 MMcfd of natural gas.  In the Second Bone Spring, nine wells were completed with an average treated lateral length of 4,500 feet per well and an average 30-day initial production rate per well of 1,500 boed, 155 b/d of NGLs, and 1.4 MMcfd of natural gas.

Rockies and the Bakken

EOG says it continued to optimize its core Rockies and Bakken plays, adding 200 additional net premium drilling locations to its inventory in the DJ Basin Codell in Wyoming.  The Codell is a liquids-rich sandstone formation that now has significant premium potential due to cost reductions and efficiencies.

EOG reported a Q2 net loss of $292.6 million, or $0.53 per share, compared to Q2 2015 net income of $5.3 million, or $0.01 per share, which the company blamed on low oil and natural gas prices.

“A lot of 2012 data pointed to average marginal costs of $50/b [or higher] in fields like the Niobrara. There are lots of companies higher and only a few companies lower,” says Hirs.

“Not surprising that EOG is one of the few that is lower. These guys are a crack technical team.”

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Peak tight gas production in Barnett Shale is 5 Bcf/d, down to 4.5 Bcf under current conditions

Global shale natural gas production will rise by 400 per cent over the next 25 years, but that’s little consolation for Barnett Shale producers, who are just doing their best to weather the price rout that began in 2008.

The Barnett Shale is a geological formation located in the Bend Arch-Fort Worth Basin that covers 5,000 square miles of north Texas, including the metroplex of Dallas-Fort Worth and at least 17 counties. The formation is tight gas and requires hydraulic fracturing and horizontal wells to produce cost-effectively. Some oil is found in the Barnett, but no liquids-rich natural gas.

I recently interviewed Ed Ireland, executive director of the Barnett Shale Energy Education Council and economics professor at Texas Christian University, about the current situation in the Barnett. This interview has been lightly edited.

Markham: Why don’t you give me the state of the union in the Barnett?

EI: Sure. The current state is that there are no drilling rigs running basically and this has been true now for many months. I think there’s been a rig here or there but certainly no consistent drilling program here. One well was fracked last week in the Barnett Shale – it was drilled earlier.

Other than that as far as activity or new well activity, there’s basically none. But the Barnett Shale continues to be a fairly significant producing natural gas field – it’s over somewhere around 4.5 billion cubic feet a day, which still puts the Barnett as a significant producing natural gas field in the US.

But drilling activity really started declining in 2008 and there’s been an amazing resilience of the level of production in the Barnett Shale in line of that decline. It’s starting to take its toll and the existing wells are starting to show very steep declines and it’s all related of course to the price.

Basically, no company in the United States is knowingly drilling for dry natural gas, they’re going for, if they’re drilling at all, they’re going for crude oil or liquids of some sort. So we’re in a production mode and we’ll be there until the natural gas price recovers from its current levels.

Markham: Are the Barnett producers shifting to a more natural gas liquids weighted strategy? Is that likely to be the go-forward?

EI: Well, they would if they could. The problem is with a large portion of the Barnett Shale is dry natural gas – there aren’t any liquids. And in the major part of the Barnett Shale, in Montague County, there is some crude oil production and in some other parts of the Barnett Shale there is some natural gas liquids production but a lot of the Barnett Shale is dry natural gas and that’s just not economical at this stage.

Markham: We ran a column a couple of weeks ago from a columnist who said that the investment in drilling for gas had dropped significantly and, unless it picked up, gas prices were going to start to rise pretty soon. Is that your take on things?

EI: Yes, I would agree with that. The lack of drilling for natural gas in the Barnett Shale is not unique, it’s true pretty much everywhere. Unless there’s a significant liquids component, dry natural gas wells have not been drilled for some time and it is starting to take its toll I think to the extent that other natural gas fields in the United Started are showing the kind of decline rates that we’re seeing in the Barnett Shale. There’s no question that that’s going to have an impact on natural gas supply and therefore on prices.

Markham: We’ve heard reports from other fields, in particular the Permian, that producers have been working hard to get their decline rates down. Are we seeing the same kind of thing in the Barnett – new technologies, new techniques, refracking, that sort of thing?

EI: Yes, absolutely. A number of producers here have been refracking wells. At this point in time, I would say it has been more of an experimental or an investigative type of approach. Devon Energy has reported that they had, I believe a 30 well program where Devon went in and refracked the wells and they haven’t, as far as I’m aware, released the information regarding the success of those refracks other than just saying that they were very successful.

I’d say that that is a practice that’s been underway here because refracking a horizontal well has had its challenges and is certainly something that, at least in the Barnett Shale, is not something that’s been done on a large scale basis. I think that’s what will happen; I think that as the price starts the recover, I personally think that the first move we’ll see will be refracking the wells before any new ones are drilled.

The conversations that I’ve had with producers is that they’re getting tremendous results with these refracks, with bringing wells back up to their initial rates of production if not higher. I think that is the first round of activity that we’ll see as prices start to recover.

Markham: Is that kind of change in strategy going to have a big impact on that service industry based in the Barnett?

EI: Yes, for sure. Of course, all of that is being done by the service companies and I think there’s been a lot to learn about the most efficient ways to refrack these horizontal wells. Of course, the whole hydraulic fracturing technology and the number of frack stages involved has changed significantly from when these Barnett Shale wells were initially drilled starting back in 2002, really the prime time– large number of wells that were drilled in the Barnett was between about 2002 and 2008 so some of these wells have some age on them now and we’ll realize old technology back to today’s standards.

So I think for the service companies to be able to bring these wells up to date is going to have a major impact and I could really see the Barnett Shale recovering to more than its 5 billion cubic feet of production that we reached just from refracking wells. Then the next stage would be drilling new wells.

The University of Texas published a study it seems a year or two ago about the Barnett Shale capability and they said that there’s two to three times as much gas remaining in the Barnett Shale as already been extracted. So there’s a lot of gas here and it just takes the right price to go get it.

Markham: It sounds like some service companies like the fracking companies – the big guys like Halliburton and so on – will do well under the new strategy but others like drillers, for instance, may not.

EI: Well, I think it’s technology – that’s the key to it. It’s going to be the service companies that are currently investing their time, efforts and money into the technology that’s required to bring these wells back up to where they were or higher levels. So yes, I think that the companies that have been investing in not only technologies but investing in reducing the cost of applying those technologies, those are the companies that are going to be the big winners.

Markham: Ed, is there anything that we should’ve talked about that we didn’t?

EI: I mentioned that there has been, even the last few days, continues to be a lot of changing hands, ownership of the assets. As an economist, those kinds of transactions are exactly what you’d expect to see in a free market and that is many of the players – oil and gas companies that initially developed the Barnett Shale – some of those are choosing to move on and they’re selling their assets here and could be concentrating their efforts in other areas.

To me that doesn’t indicate that the future of the Barnett is somehow clouded. In fact, in my eyes those kinds of moves are exactly what is needed to ensure the future redevelopment, continued development of the Barnett Shale because different types of companies – different types of expertise – are now coming in.

The companies that are going out were perfectly suited and did a great job at getting the Barnett to where it is now and as these assets change hands, in my mind, that’s a positive thing that happens and it’s happened continuously in the oil and gas business. That’s just how it works and that’s what makes markets efficient.

So I think all of this, while it’s disruptive to employees and others in this area and in other areas where it’s happening, in the long run it’s all a positive move and I think it sets up, specifically the Barnett Shale, to move in to the next stage of being redeveloped.

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