The Texas Railroad Commission must tap the brakes on oil and gas production
Texas is now the center of history’s biggest oil and gas boom. This boom, like past booms, is cementing the U.S. as the world’s superpower. But as in those earlier booms, our regulators may need to slow production slightly to preserve our natural resources and the health of our oil industry.
Texas producers are now draining so much oil and natural gas that there aren’t enough purchasers to use all of the gas. Oil and gas often come from the same well. The industry sells the oil but cannot build pipelines fast enough to get all the new gas production to distant gas consumers. As a result, producers are burning off, or flaring, more and more gas — wasting this clean burning gas, which is prized by consumers and industry around the world.
The U.S. Energy Information Administration recently reported that the U.S. is flaring more gas than ever before. Texas alone now flares more gas than many states use. These flares, burning round-the-clock, can be seen from space — nighttime satellite pictures make the Permian Basin look like Texas’s biggest metropolis. This tremendous waste of resources is sparking both public concern and private lawsuits, with regulators, landowners and the industry all pointing fingers at different villains. But for solutions, Texas need only look to its past.
The Railroad Commission of Texas, despite its name, is the world’s premier oil and gas regulator. During the 1930s, Texas dominated oil production to an extent never equaled, pumping as much as a quarter of the world’s oil. During that oil boom, the Railroad Commission learned an important lesson: Sometimes to maximize the value of an oil bonanza, you have to slow it down a little.
Everyone knows that as oil production rises, the price of oil falls. But individual companies can’t do anything about that. Instead, they have to take what they can get for their oil, find ways to produce more for less, and hope for higher prices. But a dominant regulator can help all companies by slowing down all production a bit. As production slows, prices rise, benefiting all companies.
In 1931, the Railroad Commission changed the oil industry forever when it began limiting oil production to ensure higher prices. Companies tried to evade these limits and cheating on the limits became more profitable as prices rose. Texas eventually had to send in the Texas Rangers and the National Guard to enforce the law. But when the limits were enforced, oil companies benefited. They sold slightly less oil, but received substantially higher prices. Ever since, the Railroad Commission’s limits on oil production have been used as a model by dominant commodity producers around the world.
Today, the Railroad Commission has far less influence on Texas oil prices. Our global oil market means that local prices depend on supply and demand around the world. But the commission can shape Texas gas prices. There aren’t enough pipelines and gas export facilities to bring the new flood of gas to market, so local prices are very dependent on local production. Modest reductions in local production can lead to substantial prices increases. Such limits could benefit all producers and preserve Texas’s natural resources until they can be brought to market for their full value.
The Railroad Commission should moderate the pace of the current boom to ensure that Texas gets full value for its gas. It could reject some new flaring permits, although that kind of all-or-nothing regulation might be unfair to the rejected companies. It could also impose modest limits on gas production, forcing all companies to slow their production and also ensuring higher prices for all. The commission is properly cautious about intervening in one of the free market’s biggest energy success stories. But careful regulations can build on the commission’s legacy of using production limits to ensure the long-term health of the oil and gas industry.
Source:https://www.dallasnews.com/opinion/commentary/2020/01/05/the-texas-railroad-commission-must-tap-the-brakes-on-oil-and-gas-production/
Texas to pass Iraq and Iran as world’s No. 3 oil powerhouse
Don’t mess with Texas. It’s a global oil superpower. The shale oil boom has brought a gold rush mentality to the Lone Star State, which is home to not one but two massive oilfields.
Plunging drilling costs have sparked an explosion of production out of the Permian Basin of West Texas. In fact, Texas is pumping so much oil that it will surpass OPEC members Iran and Iraq next year, HSBC predicted in a recent report.If it were a country, Texas would be the world’s No. 3 oil producer, behind only Russia and Saudi Arabia, the investment bank said.”It’s remarkable. The Permian is nothing less than a blessing for the global economy,” said Bob McNally, president of Rapidan Energy Group, a consulting firm. The hyper growth out of Texas is needed because oil prices have risen sharply and major players like Saudi Arabia are quickly maxing out their production.
Much of the excitement in Texas centers around the Permian Basin. Some oil execs believe the amount of oil in the Permian rivals Saudi Arabia’s Ghawar Field, the world’s largest conventional oilfield. Rapid technological advances have dramatically brought down the cost of pumping oil everywhere, especially out of the Permian. Wells there can be profitable below $40 a barrel. “The industry cracked the code on fracking,” said McNally. The rise of Texas, which is also home to the Eagle Ford oilfield in the state’s south, shows how the shale oil revolution has reshaped the global energy landscape. The United States is pumping more oil than ever before, making it less reliant on the turbulent Middle East for imports. “It’s not going to make the world peaceful, but it will make it less volatile,” said McNally, a former White House official.
Scott Sheffield, the chairman of major Permian player Pioneer Natural Resources (PXD), told CNNMoney last month that the United States will become the world’s biggest oil producer by the fall. The combined output of the Permian and Eagle Ford is expected to rise from just 2.5 million barrels per day in 2014 to 5.6 million barrels per day in 2019, according to HSBC. That means Texas will account for more than half of America’s total oil production. By comparison, Iraq’s daily production is seen at about 4.8 million barrels, while Iran is projected to pump 3 million. Oil supplies from Iran are likely to plunge due to tough sanctions from the United States.
However, the boom in Texas has been so rapid that growing pains have emerged. The Permian Basin is quickly running out of pipelines to transport oil out of Texas, forcing companies to explore costly and potentially dangerous alternatives like rail and trucks. More pipelines are getting built, but they won’t be ready in time to fix the bottlenecks that have formed. Fifty-five percent of executives surveyed by the Dallas Federal Reserve expect the lack of crude oil pipeline capacity will slow activity in the Permian. HSBC called the Permian a “victim of its own success” and predicted that logistical constraints will cause production growth will slow in the future. The pipeline shortage is already hurting local prices. The price of oil in West Texas recently traded at a $15 discount to Houston prices. Some oil companies are also tapping the brakes. The number of oil rigs in the Permian dropped by five in June even as the overall US rig count was stable, according to the International Energy Agency. “We’re not in a hurry to grow it fast against a system that’s completely constrained today,” ConocoPhillips (COP) CEO Ryan Lance reportedly said in May.
Another headache: the rush to pump in the Permian is making it more expensive to pay for supplies and services. The cost to service oilfields has spiked by 10% to 15% for some companies in the Permian, HSBC said. At the same time, oil executives are complaining that it’s difficult to find employees. The challenge is magnified by low unemployment in Texas and nationally. “The labor shortage is getting critical,” one exec told the Dallas Fed.
Source: https://money.cnn.com
OPEC Leader Cites ‘New Optimism’ With Oil Prices on the Rise
VIENNA — As officials from some of the world’s biggest oil producers arrive here in Vienna, they have plenty to be cheery about.
Oil prices have risen unexpectedly fast of late, surging 20 percent since the beginning of September, providing much-needed money for the strained budgets of the 14 members of the Organization of the Petroleum Exporting Countries.
That leaves OPEC members with a quandary: Do they again extend production cuts first announced a year ago? What had seemed to analysts to be a foregone conclusion now looks to be more complex.
The group of oil exporters, along with some nonmembers like Russia, agreed to the production cuts to ease a glut in the market and bolster prices. To some extent, that appears to have worked. Brent crude oil, the main international benchmark, is trading at around $64 a barrel, even after falling slightly this week. Some analysts see prices topping $70 next year.
While those figures are well below the heights of more than $100 in 2014, they are more than double the price early last year. In a speech welcoming delegates to Vienna on Monday, the cartel’s secretary general, Mohammad Barkindo, spoke of “a new optimism in the oil market not seen for a very long time.”
According to OPEC figures, the cartel has cut production by about 700,000 barrels a day from a year ago. Russia is holding back another 300,000 barrels a day. That trim, though, amounts to slightly more than 1 percent of global supply.
A bigger influence has been a stronger global economy driving demand for oil. Economists have been upgrading their forecasts for growth worldwide, and that has affected demand, which has risen by nearly five million barrels a day since 2014. That is more than the total daily output of Iraq, OPEC’s second-largest producer.
The twin factors have recently helped make a dent in the substantial inventories of crude that had built up on tank farms, sprawling sites where enormous drums hold excess supplies of oil, around the world.
Other events have played a role. Hurricane Harvey, which swamped oil installations on the gulf coast of the United States in August, caused major disruption and highlighted the dwindling stockpiles.
“All these factors prop up a higher price,” said Sadad I. Al-Husseini, a former executive vice president at Saudi Aramco, Saudi Arabia’s national oil company, who now runs a consulting firm.
Political developments in Saudi Arabia and in other major oil producers like Venezuela are also affecting the market.
In Riyadh, two separate campaigns led by the kingdom’s crown prince, Mohammed bin Salman, are raising questions. For one, a crackdown on corruption led by the prince has swept up at least 11 other senior members of the royal family. Though the effort has not disrupted Saudi oil flows, it has added to the uncertainty facing businesses looking to operate in the kingdom.
Saudi Arabia is also pushing forward on the sale of a stake in Saudi Aramco, set for next year. A return to low prices might put that public offering, which is being spearheaded by the crown prince, at risk, giving Riyadh a major stake in ensuring that production cuts hold.
“I am not saying that Mohammed bin Salman is going to fail or be overthrown or whatever,” said F. Gregory Gause, a Saudi expert and head of international affairs at the Bush School of Government and Public Service at Texas A&M University. “But what I always thought was a very stable system is now embarking on changes on numerous fronts simultaneously.”
Political turmoil in Venezuela, a leading OPEC member, has also raised the specter of a sudden drop in its supply of oil. Production has fallen by 500,000 barrels a day, equivalent to around 20 percent of its output, over the last year. That decline is expected to deepen with the government behind on debt payments and unable to pay service companies crucial to the energy industry.
Elsewhere, production and exports have fallen in Iraq because of tensions in the northern part of the country between Iraqi and Kurdish forces.
While these trends have helped push prices up, potential developments could send them lower again, from the impact of shale oil producers in the United States to a collapse of the agreement on production cuts.
American shale companies, in particular, are seen as the swing producers in the market, able to ramp up output to meet rising demand and take advantage of rising prices. These operators, from small companies to behemoths like Chevron and ConocoPhillips, have streamlined operations and can make money at far lower prices than in previous years. Current prices could lead to a surge in drilling.
Higher prices could also strain an agreement between Saudi Arabia and Russia to hold down production.
Russia has been rapidly drilling recently and could add up to one million barrels to its daily output over the next five years. As Western sanctions — a response to Russia’s military moves in Ukraine and Syria and its meddling in the United States presidential election — begin to bite, Moscow’s calculation could change.
“Russia is the kingpin,” said Bhushan Bahree, an OPEC analyst at IHS Markit. Cooperation between OPEC and non-OPEC producers, he added, “would fall apart without Russian participation.”
Still, most analysts expect OPEC and Russia to extend their production cuts. While OPEC has often moved to stem price declines, it has less of a track record of constraining price increases. Exporters want to make as much revenue as they can, particularly to compensate for recent lean years.
“I don’t think many of the OPEC countries think about the long-term aspects,” said Bill Farren-Price, president of Petroleum Policy Intelligence, a market research firm. “What they think about is how do we fulfill next year’s budget.”
“If we can have a few months of higher prices,” he added, “surely that is a good thing.”
Source: https://www.nytimes.com/2017/11/28/business/energy-environment/opec-oil-prices.html
The Haynesville Shale – An Old Fracking Hot Spot Makes a Comeback
One of the early centers of American shale drilling is roaring back to life, boosted by a building boom of petrochemical plants, fertilizer factories and gas-export terminals along the Gulf Coast.
The Haynesville Shale, a giant natural-gas field in northwest Louisiana, was one of fracking’s hottest spots a decade ago. But it fizzled out about five years ago as gas prices plunged and drillers focused on finding oil next door in Texas. Now, the Haynesville is being reborn as companies with longstanding positions in the area, such as Chesapeake Energy Corp. CHK -0.26% , and newcomers seeking opportunity rush back in and drill again.
Gas production from the Haynesville has risen more than 20% so far this year, to more than 7 billion cubic feet a day from less than 6 billion in January, according to the U.S. Energy Department. The number of rigs active in northern Louisiana parishes and the Texas portion of the field has more than tripled in the past year to 44, according to oil field services company Baker Hughes Inc.
“The Haynesville is where it began,” said Frank Patterson, Chesapeake Energy’s vice president of exploration and production.
The company has been learning how to get more out of the ground by drilling and fracking longer wells, Mr. Patterson told investors earlier this month. Chesapeake, which now produces more than 1.2 billion cubic feet of gas each day in the Haynesville, plans to ramp up efforts to re-frack old wells where production is starting to peter out to squeeze more out of them, using newer technology.
QEP Resources Inc. QEP -2.55% is also re-fracking 30 Haynesville wells this year.
“The payouts on these wells are extremely attractive at $3 gas,” said Charles Stanley , QEP’s chairman and chief executive. Gas this year has averaged roughly $3 per thousand cubic feet at Louisiana’s Henry Hub, a benchmark for U.S. prices.
Comstock Resources Inc. CRK -2.16% sold off some Texas oil properties in 2015 to fund new gas wells in the Haynesville, and it now has three rigs running in the area. The company recently expanded a Haynesville deal with USG Properties and plans to drill another 34 wells as part of that joint venture in East Texas.
A new report by the U.S. Geological Survey estimates the Haynesville and nearby Bossier shales contain more than 300 trillion cubic feet of natural gas, up from roughly 70 trillion cubic feet in its last survey in 2010.
Private companies have piled into the Haynesville over the past 15 to 18 months, thanks to backing from private-equity firms. Dallas-based Covey Park, backed by Denham Capital, and Vine Oil & Gas LP, backed by Blackstone Group BX 0.81% LP, have collectively spent billions buying property in the area from Royal Dutch Shell PLC, Exxon Mobil Corp. and others.
“If you have Haynesville acreage, it’s a good time to drill,” said Clay Lightfoot, an analyst with energy consulting firm Wood Mackenzie.
Driving the trend is a dramatic reduction in costs. Three years ago, the Haynesville had the most expensive well costs in the Lower 48 States, in part because its fuel-bearing rocks are the deepest in the U.S., some more than 15,000 feet underground. But in 2014, when oil prices started to plunge from over $100 to less than $50, some companies refocused on natural gas and began experimenting with technology such as long lateral wells that has helped improve the economics of extraction.
Rising demand for gas has boosted the area’s prospects. The U.S. Energy Department forecasts that between now and 2040, consumption of natural gas will increase more than that of any other fuel source, as demand from big industrial users rises and power plants rapidly replace coal-fired facilities.
Regional producers can now also export their liquefied natural gas. Cheniere Energy Inc . LNG -1.23% ’s Sabine Pass LNG plant, a major exporting facility that opened in Louisiana last year, is sending cargoes of liquefied natural gas to Asia, Europe and South America. A dozen other LNG projects are under construction or are permitted and planned in Texas, Louisiana, Mississippi and Maryland.
That’s a potential drawback for industrial users in the area, such as petrochemical plants, of which there are almost 80 under construction along the Gulf Coast. They fear the price of gas—their main feedstock—could rise as America ships more to foreign buyers.
But the flexibility of domestic as well as foreign customers is making gas production in the area more attractive to investors.
Since 2016, Castleton Commodities International LLC spent more than a $1 billion to buy 160,000 acres of Anadarko Petroleum Corp.’s Haynesville land in East Texas, where it operates nearly 2,000 wells. It recently got an equity investment from Tokyo Gas America Ltd., the biggest utility in Japan and one of the largest LNG players in Asia.
Tellurian Inc., TELL -1.75% whose founder Charif Souki started Cheniere, recently bought Haynesville acreage. The company says the cost of producing gas there and moving it to an export terminal will be $2.25 per million Btu—a big discount to the daily LNG price for the Gulf of Mexico, which was $7.66 per million Btu last week, according to S&P Global Platts.
Albert Huddleston, founder and managing partner of Aethon Energy, a private company based in Dallas, began buying into the Haynesville three years ago, taking over Noble Energy Inc . NBL 0.50% ’s position. Then, he kept buying. It was a contrarian strategy at the time, said Mr. Huddleston.
“I’m a big believer once you find an area that meets your objectives, you continue to buy in that neighborhood,” he said.
Corrections & Amplifications
Natural gas prices so far this year have averaged around $3 per thousand cubic feet. An earlier version of this article incorrectly said that gas prices have averaged $3 per million cubic feet. QEP Resources Inc. is re-fracking 30 Haynesville wells this year. An earlier version of this story incorrectly said the company was re-fracking 30 wells this quarter and planned to drill more in the Bossier shale. (Oct. 17, 2017)
Source: https://www.wsj.com/article_email/an-old-fracking-hot-spot-makes-a-comeback
Natural Gas, LNG Exports And Benefits To The U.S.
The export of U.S. liquefied natural gas (LNG) continues to yield economic and other benefits locally, regionally and to our country as a whole. Two recent news items illustrate – a report detailing the boost LNG exports is giving the Texas economy, and an agreement by Poland to buy American LNG, further expanding opportunities for a valuable U.S. commodity.
A report by North Texans for Natural Gas quantifies the economic benefits of LNG export activity – in direct investment and jobs and generated tax revenue – for the state and the country as well. Expansion of the Freeport LNG export terminal is expected to employ more than 3,500 workers during the four- to five-year construction phase, the report says. It’s estimated the project will generate between $5.1 billion and $7.4 billion in economic benefits per year. That’s just one project. Texas has seven facilities under construction or proposed. At the same time these projects generate tax revenues that help build local infrastructure, support education and emergency services.
Nationally, the report points out, Texas LNG export facilities could create more than 136,000 jobs, with an economic impact of more than $145 billion. All attributable to domestic natural gas output, thanks largely to safe hydraulic fracturing and horizontal drilling. The report:
Just a little over a decade ago, many believed that the United States would need to import increasing amounts of liquefied natural gas (LNG) in order to make up for declining domestic production, from the areas available for exploration and production. Fracking turned this belief on its head, as U.S. production soared in places such as the Barnett Shale in North Texas and the Marcellus Shale in Pennsylvania.
Overseas markets continue to develop for U.S. natural gas. The United States is on track to send its first shale LNG to Poland next month, Bloomberg reports. It’s the first such contract for Central and Eastern Europe and reflects Poland’s effort to diversify its supply of natural gas. Bloomberg:
Poland may offer a new outlet for Cheniere, which said it’s targeting emerging markets as new production facilities from Australia to the U.S. lead to a glut of the fuel. Poland’s Law & Justice government has sought to cut the nation’s dependence on Russia’s Gazprom PJSC for more than two-thirds of gas supplies, stating it has no plan to extend a long-term supply contract beyond 2022 and plans new infrastructure including a pipeline to Norway.
Meanwhile, the U.S. and China have reached an agreement to promote U.S. LNG shipments. U.S. Commerce Secretary Wilbur Ross told reporters at a White House briefing: Bloomberg reports:
“This will let China diversify, somewhat, their sources of supply and will provide a huge export market for American LNG producers.”
Indeed it could. All of the above points to a cycle of benefits for the U.S. from its natural gas wealth. Domestic abundance helps consumers in terms of their heating and electricity costs. Abundance means opportunity to export – trade that brings oversea wealth into this country while stimulating more output here at home. Abundance and exports also provide safe, secure energy to America’s friends abroad.
Call it a win-win-win scenario for American energy.
By Mark Green
https://breakingenergy.com
Saudi Arabia Turns Off the U.S. Oil Tap
At last, Saudi Arabia seems to be doing what it takes to reduce the world’s most visible oil glut: the one in the U.S.Unfortunately, its renewed vigor comes as OPEC’s deal to reduce excess crude stockpiles starts to show signs of unraveling elsewhere, a subject that will be wrestled with by the group’s oil ministers as they and other producer nations meet in St Petersburg on Monday.
Saudi Slump
Weekly U.S. crude oil imports from Saudi Arabia have fallen sharply since early June
Data published last week by the U.S. Energy Information Administration show that imports from Saudi Arabia in the week to July 14 fell to their lowest for seven years: just 524,000 barrels a day. For sure, one week’s number doesn’t mean much on its own, particularly when a single very large crude tanker could raise or lower that figure by half.But this isn’t an isolated figure. The EIA data show a clear drop in deliveries from Saudi Arabia since the start of June. The average rate of U.S. imports from the desert kingdom over the past six weeks has dropped by 450,000 barrels a day, or 34 percent, compared with the first six weeks of the year.
Given that it averages six weeks for a tanker full of crude to travel from the Persian Gulf to the U.S., this drop in imports reflects a slowdown in Saudi shipments that began in mid-April, which shows up in Bloomberg tanker tracking data for the Kingdom. So Saudi Arabia is finally slashing exports to the U.S., even as shipments to other destinations — with less visible inventories — have been maintained, or even risen. This is crucial, because the failure to drain U.S. storage tanks has been a major factor in driving down oil prices. “Exports to the U.S. will drop measurably,” Saudi oil minister Khalid Al-Falih said in May. The kingdom is now making good on that promise.Preliminary tanker data must be treated carefully, though. Several ships show no final destination and could still end up in the U.S. Saudi crude usually moves across oceans in 1 million or 2 million barrel shipments, which means a pickup in flows to the U.S. at the end of July could change the picture dramatically.Anyway, one has to ask whether Riyadh’s new resolve is too late as the OPEC-brokered deal to remove about 1.8 million barrels a day from the world’s supply is looking a little shakier. In June, OPEC members’ compliance with their agreed cuts fell to its lowest level since the deal came into effect (although 95 percent is still pretty good).
Fraying at the Edges
Better non-OPEC compliance in June made up for the worst performance by OPEC members
Ecuador has become the first OPEC country to say openly that it can’t afford to limit production. It may not be the last.Iraq objected to cutting output amid a costly war with fundamentalist insurgents. It was pressured into accepting but has lagged its peers in implementation. In June it made just 28 percent of its agreed cut, according to secondary source data from OPEC.Meanwhile, output has soared from the two OPEC members exempted from the cuts, something I warned about in this column. Libyan production this month will probably exceed 1 million barrels a day, almost twice April’s level. Nigeria is making slower progress, but output there is rising too. Neither will accept a cut, though both might come under pressure to accept a cap slightly above current production levels — similar to Iran’s compromise last year.The Saudis have belatedly woken up to how oil traders react to a U.S. that’s visibly awash with crude. It will amount to very little unless they deal with their Africa problem.
Conoco Phillips Sells San Juan Assets To Hilcorp For $3 Billion
ConocoPhillips (NYSE: COP) agreed April 13 to the sale of its dry gas interests in the San Juan Basin to an affiliate of Hilcorp Energy Co. for up to $3 billion.
The deal comes roughly two weeks after ConocoPhillips’ $13.3 billion sale of Canadian oil sands assets to Cenovus Energy Inc. (NYSE: CVE). In total, ConocoPhillips has announced more than $16 billion of assets sales so far in 2017. Included in its deal price with Hilcorp are incentive payments of about $300 million.
In November, ConocoPhillips said it planned to divest assets of $5 billion to $8 billion to delever and core up its asset base by 2018, analysts said. With its two agreements, the company is on track to double its goal roughly four months into 2017.
The San Juan sell has previously been previously discussed by management said Scott Hanold, an analyst with RBC Capital Markets. The deal price is at the high range of RBC’s estimates.
“COP has now divested over $16 billion is assets this year, well above its three-year goal in under one year,” Hanold said. “We think the company will continue to maintain its priorities of dividend growth, debt reduction, and share repurchases. We expect the stock to react favorably.”
Immediately after ConocoPhillips said it would divest in Canada, for instance, the oil sands sale jumpstarted company stock, lifting it by nearly 9% and increasing the company’s value by roughly $5 billion.
“These transactions will materially reduce our exposure to North American gas and achieve an immediate step change improvement in our balance sheet and cash margins, while accelerating our return of cash to shareholders,” Ryan Lance, ConocoPhillips’ chairman and CEO, said in a statement. “Our company will be more focused, far stronger financially, and well positioned to execute our disciplined, returns-focused value proposition.”
ConocoPhillips’ San Juan Basin assets cover about 1.3 million acres in New Mexico and Colorado. Full-year 2016 production associated with the assets was 124,000 barrels of oil equivalent per day (boe/d), of which about 80% was natural gas. Cash provided by operating activities for 2016 was about $200 million. Year-end 2016 proved reserves were 600 MMboe.
Hilcorp said it estimates 2017 production from the San Juan assets could reach about 115,000 boe/d, consisting of about 80% natural gas and 20% NGL.
“The San Juan Basin acquisition fits the profile of the established, conventional assets [that] Hilcorp typically aims to secure and enhance,” Jason Rebrook, president and chief development officer of Hilcorp, said in a statement. “In the last five years alone, we have invested heavily in our properties, increasing both reserves and production.”
According to ConocoPhillips, the net book value of its San Juan assets was roughly $5.9 billion as of year-end 2016, which includes about $2.8 billion of step-up basis associated with the Burlington acquisition in 2006.
Sale proceeds are comprised of $2.7 billion in cash and contingent payments of up to $300 million spread over six years. The cash portion of the proceeds is subject to customary closing adjustments. The contingent payments are effective Jan. 1, 2018.
ConocoPhillips said it expects the transaction to close in third-quarter 2017, subject to specific conditions precedent being satisfied, including regulatory approval. The company also anticipates recording a non-cash impairment on the assets in the second quarter.
Hilcorp is headquartered in Houston and is one of the largest privately-held independent E&Ps, according to the company press release. Its affiliate, Hilcorp San Juan LP, is a partnership between the company and The Carlyle Group.
Wells Fargo Securities was ConocoPhillips’ exclusive financial advisor on the transaction.
Source: Oilandgasinvestor.com
Now is the time to invest along the Permian Basin in Texas, oil analyst says
A worker prepares to lift drills by pulley to the main floor of a drilling rig in the Permian basin. E&P stocks to buy and sell: Analyst
Friday, 31 Mar 2017 | 2:34 PM ET | 03:02
The saying goes, everything’s bigger in Texas — and this includes opportunities to invest in oil, according to one expert analyst.
Some of the best oil companies to consider investing in are based along the Permian Basin of West Texas, the largest U.S. oil patch, Seaport Global Securities Managing Director Mike Kelly told CNBC on Friday.
“It’s simple economics. … You are spending the least amount of capital [along the Permian], but here you get the most reserves on the ground,” Kelly said on “Power Lunch.” “Lower cost wins.”
Along the Permian alone, the oil and gas industry poured more than $28 billion into land acquisitions in 2016, more than triple what was spent in 2015. These deals are setting the stage for much larger investments that will be needed to extract oil from the ground in coming quarters, many experts agree.
In a Thursday note to clients, Seaport wrote that: “Our oil macro review produced a surprisingly robust outlook. … We think uninspiring [full-year 2017] guidance given on [fourth-quarter] conference calls is a case of massive industry wide sandbagging, which sets up a year of beat opportunities.”
While the near-term environment for many oil names is strong, Kelly has warned investors that he remains relatively cautious with his long-term crude outlook, and says gas is looking “decisively worse.”
Yet Kelly told CNBC on Friday he thinks the wild swing of crude prices lately has actually been “encouraging” for the industry and for many of the companies he follows. “In a $50 world, a lot of these guys make a good living. … You don’t need more than $50 for these things to work.”
Oil prices fell Friday, ending a three-day rally and leading into what could be the oil market’s worst quarter since 2015. Investors are worried that growing U.S. supplies are undermining OPEC-led production cuts. Oil settled the day at $50.60 per barrel, falling 5.8 percent.
For investors looking to put money into the space, Seaport’s Kelly said he would recommend three Texas-based oil stocks: RSP Permian, Ring Energy and Callon Petroleum. Ring is a smaller company but one of the fastest growing small-cap stocks in the sector, Kelly said. And Houston-based Callon is one of the fastest growers overall along the Permian Basin, he added.
“We’re back to backing the Permian wholeheartedly,” Seaport wrote in its Thursday note to investors.
— Reuters contributed to this report.
Source: cnbc.com
Analysts: ‘Rebound’ Coming For Oil And Gas
MIDLAND, Texas—Economic indicators point to a near-term uptick in the oil and gas business after a long and painful downturn, Stratas Advisors researchers told a Midland, Texas, audience March 22.
“We are poised for a rebound,” John Paisie, executive vice president of Hart Energy’s research arm, said in his presentation to the 2017 Permian Basin Outlook Breakfast at the Midland Country Club. There are positive trends, such as Europe’s improving economy and a counterbalance of lingering oversupplies. “We will have a production-demand crossover as the world market rebalances,” Paisie added.
Joining Paisie in the wide-ranging presentation were Greg Haas, Stratas’ director of integrated oil and gas, and Richard Mason, chief technical director for Hart Energy.
Paisie gave a macro view of the industry and how it relates to world and national economies, while Haas focused on midstream and downstream trends—primarily in the Permian. Mason discussed upstream sector trends within the big play, such as drilling, completions and service and supply costs.
Paisie emphasized the importance of viewing the oil and gas business as part of the worldwide economic system. “If you don’t understand the macro factors, then you can’t understand what’s happening in energy,” he said. “That will enable you to maximize the upside and mitigate the downside.”
He discussed Stratas’ methodology and noted that, at a similar breakfast in Houston held in January 2016, he projected crude oil prices would rise to $40 per barrel (bbl) by the end of that year.
Given that the Brent benchmark stood at $26/bbl at the time, “we made a pretty bold prediction,” he added. “But it ended up a good call; our forecast went pretty well.”
At the Midland event, Paisie outlined several reasons for an oil price rebound in the next year, including China’s strong economy and a shift in that nation’s economic emphasis to consumer goods and away from heavy industry. Also, the U.S. economy continues to improve, along with Europe’s, while Iran’s return to the world oil markets brought lower production levels than most economists had projected. OPEC’s production curbs also have helped bring the worldwide crude oversupply into check.
The recent crude price dip is due to lingering oversupply and crude traders moving into long positions. “The sentiment has changed and has become more bearish,” Paisie said, but he projected, despite multiple moving parts of the global economy, better commodity prices are ahead.
Brent prices could move as high at $68/bbl, while the Stratas base case projects Brent at $60/bbl. The U.S. West Texas Intermediate benchmark, in that base case, would likely fall in the $55/bbl to $58/bbl range. Paisie admitted Stratas “is somewhat bullish” in comparison to other current commodity price projections.
Midstream Outlook
Haas opened his presentation by emphasizing just how important the Permian has become in the world’s oil and gas industry.
“The Permian is the driver of liquid supply growth,” he said, adding, “We [U.S. producers] are getting back to where we were, thanks to the Permian Basin.”
The basin’s crude production has climbed by 1 MMbbl/d and continues to rise, he said, with a compound annual growth rate (CAGR) of 8.1%. The midstream is responding to that increase with new pipeline capacity, which Haas projected will have a 9.4% CAGR, “so we will get ahead a little in the game.” The pipelines “will have to run fast to stay in place, so keep putting out those open seasons.”
Turning to his own macro view, Haas noted Permian producers will be competing with the completed Dakota Access Pipeline starting this year, which will be moving Bakken crude to the Midwest and Gulf Coast, while it’s likely the shelved Keystone XL Pipeline will be built to move Canadian crude to the Gulf. Put all of that supply together, plus sales from the federal Strategic Petroleum Reserve, “and we are the United States of excess right now,” Haas added with a chuckle.
Growing exports will have an important role in working off the excess supply, he noted. Exports will help right the growing mismatch between production of light, sweet crudes from the shale plays while much of the nation’s refining capacity has been built to run imported heavy, sour crudes. He noted refiners’ crack spreads are down but remain at a respectable $9/bbl.
Natural gas is another matter for Permian producers, Haas said, because “we still have growing production from the Beast of the East—the Marcellus and Utica—that is really driving natural gas production now.” As with crude, gas exports will be key, he added. Exports to Canada are down because Canadian gas is discounted even more than U.S.-produced gas. However, exports to Mexico and LNG volumes will continue to grow.
U.S. petrochemical plants are strongly favored now due to rising NGL production from the shale plays—as well as discounted gas that can cheaply fuel the nation’s growing cracking capacity.
“U.S. petrochemical producers are sitting in the catbird seat” as a result, he said. NGL exports have been strong and will continue to grow, especially propane, Haas said.
Upstream Trends
Permian producers and service companies have weathered “a downturn like no other,” Mason told the breakfast. Industry observers have questioned whether the turnaround from the downturn that started in late 2014 would be U-shaped or V-shaped. Rather, Mason said “it will be likely the turnaround will be more of a W because of a continued oscillation in the market.”
But regardless of peaks and valleys, he seconded the remarks by Haas and Paisie that “the Permian is leading us off the bottom; this is the most active market on the globe.”
Producers continue to high-grade their acreage, drilling the most prospective locations with longer laterals, more stages and more frack sand. The improving drilling statistics will level off at some point, Mason said, but the Permian energy industry enjoys a substantial technological edge today “and all of that happened with $40 and $50 oil,” noting that “we’re testing the limits of high-intensity completions.”
He discussed separately the various sectors of the Permian’s upstream, calling the workover business “the most challenged sector out there.” Multiple bankruptcies thinned the ranks of workover outfits, “but the equipment is still there and bankruptcies didn’t solve the problem of overcapacity.”
Meanwhile, “high-specification rigs are already in tight supply,” he said, as regional drilling picks up. Large drilling contractors weathered the downturn the best since much of their work is done through long-term contracts. He noted drillers are moving rigs into the Permian from other plays now since it remains the most active region in the country.
“We’re at a critical juncture in the recovery,” Mason said. Prices charged by service and supply companies need to be low enough to attract E&P firms to drill, yet “service providers need to make enough money to be profitable.”
Source: Oilandgasinvestor.com
Trump is about to destroy Obama’s offshore drilling ban with one decisive swoop
President Donald Trump is set to sign an executive order in the very near future that will reverse policies implemented by former President Barack Obama that heavily restricted offshore drilling.
According to Bloomberg, Interior Secretary Ryan Zinke made the announcement Thursday at a closed-door meeting with the National Ocean Industries Association.
More from Bloomberg:
The coming order is set to push the Interior Department to schedule sales of new offshore oil and natural gas rights in U.S. Atlantic and Arctic waters, amending a five-year Obama administration leasing plan that left out auctions there, according to an industry representative who has discussed it with officials.
The order is also expected to begin the process of revoking former President Barack Obama’s decision to indefinitely withdraw most U.S. Arctic waters and some Atlantic Ocean acreage from future leasing. Environmentalists say it would be unprecedented for any president to rescind such a designation, and the reversal would almost certainly be challenged in court.
The action would fulfill campaign promises Trump made last year when he routinely vowed that under a Trump administration, the U.S. would increase domestic energy production, which includes offshore drilling for crude oil and natural gas.
Trump already signed an executive order last week to undo nearly all of Obama’s climate policies. The order also directed the Interior Department and other government agencies to proactively find ways to undo Obama-era climate policy.
However, it will likely take a year or two to completely rid the government of Obama’s drilling lease plan, given its complexity and deep roots. But it will be worth it considering the billions of crude oil reserves that are ripe for harvest.
Source: theblaze.com