ConocoPhillips trims capex after posting quarterly loss

JULY 27, 2017 / 6:19 AM / AN HOUR AGO

ConocoPhillips Chairman and Chief Executive Officer Ryan M. Lance (C) rings the closing bell at the New York Stock Exchange (NYSE), February 27, 2013.Brendan McDermid/File Photo

(Reuters) – ConocoPhillips (COP.N) slashed its 2017 capital spending by 4 percent on Thursday, the latest U.S. oil and natural gas producer to do so in reaction to depressed crude prices CLc1.

Conoco and peers had mapped out ambitious capital spending programs for 2017 early in the year, expecting oil prices to be higher than where they are today, just under $50 per barrel.

But Conoco becomes the latest this week to cut its spending plans, after Hess Corp (HES.N), Anadarko Petroleum Corp (APC.N) and others.

“This is the right approach for value creation in the upstream sector, especially at a time of uncertainty in the commodity markets,” Conoco Chief Executive Ryan Lance said in a statement.

Conoco now plans to spend $4.8 billion this year, down from a prior estimate of $5 billion. The cut came after Conoco’s quarterly loss more than tripled despite recent asset sales.

Shares of the Houston-based company rose 0.2 percent to $43.79 in premarket trading.

The company posted a net loss of $3.4 billion, or $2.78 per share, compared to a net loss of $1.1 billion, or 78 cents per share, in the year-ago quarter.

Excluding one-time items, the company earned 14 cents per share. By that measure, analysts expected a loss of 2 cents per share, according to Thomson Reuters I/B/E/S.

Production fell 8 percent to 1.4 million barrels of oil equivalent per day.

Conoco sold its assets in the Barnett shale of Texas last month for about $305 million, part of a plan to shed its exposure to natural gas.

Conoco also sold its Canadian oil sands and natural gas assets in March to Cenovus Energy Inc (CVE.TO), in a cash-and-stock deal with about $13.3 billion. The price was widely seen as high, a boon for Conoco.

Conoco is the latest international oil major to pull back from northern Alberta’s oil sands, which is among the most costly locations in the world to develop.

Reporting by Ernest Scheyder; Editing by Nick Zieminski

Why oil prices scored their biggest one-day rally of 2017

Why oil prices scored their biggest one-day rally of 2017

Published: July 25, 2017 3:05 p.m. ET

WTI oil settle 3.3% higher Tuesday

Getty Images


OPEC members can’t take all the credit for oil’s rally Tuesday surge, which saw prices score their biggest single-session gain of the year.

News of cuts to oil-and-gas exploration spending and signs of a potential slowdown in U.S. output also played roles in the bullish shift in sentiment.

On Tuesday, September West Texas Intermediate crude CLU7, +3.24%  rallied by $1.55, or 3.3%, to settle at $47.89 a barrel on the New York Mercantile Exchange, marking the strongest single-day climb since late last year, according to FactSet data.

Saudi Arabia said at a meeting in Russia Monday that it would cut August exports to 6.6 million barrels a day—a million barrels less than a year earlier. Separately, Nigeria, which isn’t part of the production-cut agreement led by the Organization of the Petroleum Exporting Countries, also promised to limit its daily production to 1.8 million barrels.

Traders have taken these developments as bullish for prices, though many do point out that the Saudis normally lower exports at this time of year because of stronger domestic demand for oil, and Nigeria’s output would still have to rise from it’s current level of just over 1.6 million barrels a day before the West African nation would cap its output.

Still, at the meeting Monday, which include some major non-OPEC nations such as Russia, oil producers were upbeat.

“OPEC and Non-OPEC members displayed optimism over the current production cut deal and seemed confident that the path they were treading would eventually rebalance the markets,” said Lukman Otunuga, research analyst at FXTM, in an note Tuesday.

Saudi energy minister Khalid al-Falih said Monday the coalition’s compliance with the production deal was strong, while OPEC secretary-general Mohammad Barkindo said the rebalancing of oil-market supply and demand is “bound to accelerate in the second half,” according to The Wall Street Journal.

Adding further support to oil prices, James Williams, energy economist at WTRG Economics, pointed to “Halliburton’s expectation of a flat rig count” as well as “Anadarko Petroleum Corp.’s losses and plans to reduce exploration.”

After posting a larger-than-expected second-quarter loss, oil-and-gas exploration and production company Anadarko Petroleum Corp. APC, +3.47% cut its investment guidance by $300 million for the full year. Al Walker, the company’s chief executive officer, cited “current market conditions [that] require lower capital intensity given the volatility of margins realized in this operating environment.”

Year to date, oil prices, in particular, have dropped by around 11%, while natural-gas prices NGU17, +1.56%  have lost nearly 20%.

Meanwhile, David Lesar, Halliburton Co.’s HAL, +1.52% chief executive officer and president, said in an earnings call that “rig count growth is showing signs of plateauing and customers are tapping the brakes.”

That implies a potential slowdown in oil production, market participants said.

And nearer term, traders are looking ahead to a weekly report that is expected to reveal a fourth-straight weekly decline in U.S. crude inventories. Analysts polled by S&P Global Platts expect the Energy Information Administration to report on Wednesday a decline of 2.5 million barrels for crude stockpiles in the week ended July 21.

“U.S. oil stocks, while still higher than we need, are down 45 million barrels from the end of March,” said Williams.

Allegro and Indra Announce Global Strategic Partnership Servicing the Commodities Trading and Risk Management Market

Both companies will collaborate globally in the implementation of Allegro Horizon, Allegro’s leading commodities trading solution that can increase performance, reduce costs and provide greater agility to operations.

Allegro Development Corp., a leading provider of commodity management software, announced today that it has expanded its partnership with Indra, one of the main global consulting and technology companies, to provide a range of services to firms involved in commodity trading and risk management (CTRM).

Allegro and Indra first signed an agreement nearly a decade ago. During this time, the companies have worked together to serve customers the world over, including in the Americas, Europe and the Asia-Pacific region. Now, the strategic partnership has been enhanced so that Indra will implement and support Allegro Horizon, a commodity trading and risk management software system for mid- and large-size companies across the commodity landscape globally.

Customers of both companies will gain important benefits in their operations. Allegro’s CTRM software can improve business visibility and margins, while reducing the costs of commodity trading and risk management software ownership.

Indra has a presence in more than 140 countries, and, with Allegro’s growing international presence, the two companies will be more prepared than at any prior point in their relationship to manage CTRM rollouts around the globe. A highlight of the partnership is the fact that it takes full advantage of the partners’ local knowledge and expertise. Because of the partnership’s geographic reach, Indra and Allegro will be better suited to oversee extension development, reporting, interfacing and end-to-end implementations, as well as to provide maintenance and support after projects go live.

Jonathan English, Senior Vice President, Global Sales, Allegro:

“We simply couldn’t ask for a better partner than Indra. Clearly, they have the world’s regions covered with their technology professionals. But that’s only scratching the surface of what Indra provides. They are experts with the Allegro solution. They understand what customers need, and they bring deep, broad experience to every project. They also know the challenges that must be overcome to succeed in today’s ever-changing commodity business. All of us at Allegro are very excited about this new chapter in our partnership.”

Leonardo Benitez, Director of Utilities, Indra:

“Having worked with Allegro since 2008, we fully understand the capabilities of its CTRM platform and how it can benefit customers. The entire Indra team is extraordinarily excited to continue this relationship, but the true beneficiaries will be the commodity buyers, sellers, producers and consumers who need an industry-leading solution to enhance their businesses.”

About Allegro

Allegro is a global leader in commodity trading and risk management software for power and gas utilities, refiners, producers, traders and commodity consumers, providing position visibility, risk management, comprehensive controls and regulatory compliance. With more than three decades of industry experience, Allegro’s enterprise platform drives profitability and efficiency across front, middle and back offices, while managing the complex logistics associated with physical commodities. Headquartered in Dallas, Allegro has offices in London, Singapore, Calgary, Dubai, Houston, Jakarta and Zurich, along with a global network of partners. For more information, visit

About Indra

Indra is one of the main global consulting and technology companies and the technology partner for core business operations of its clients’ businesses throughout the world. It offers a comprehensive range of proprietary solutions and cutting edge services with a high added value in technology, which adds to a unique culture that is reliable, flexible and adaptable to its clients’ needs. Indra is a world leader in the development of comprehensive technological solutions in fields such as Defense & Security, Transport & Traffic, Energy & Industry, Telecommunications & Media, Financial Services and Public Administrations & Healthcare. Through its Minsait unit, it provides a response to the challenges of digital transformation. In 2016, it reported revenues of €2,709m, had a workforce of 34,000 professionals, a local presence in 46 countries, and sales operations in more than 140 countries. To learn more, visit

BHP Billiton to step up U.S. shale production

BHP Billiton to step up U.S. shale production

Published: July 18, 2017 11:21 p.m. ET

MELBOURNE, Australia–BHP Billiton Ltd. (BHP.AU) said Wednesday it plans to step up activity in the U.S. oil-and-gas shale fields that activist shareholders are agitating for the resources company to offload.

The move is expected to revive flagging onshore production volumes even as BHP continues to invest in conventional energy operations and exploration in the Gulf of Mexico and other basins while seeking to sell some unwanted U.S. shale acreage.

BHP has been forced to defend its strategy after New York hedge fund Elliott Management Corp. led a series of attacks in recent months, calling for a sweeping overhaul of the world’s largest-listed mining company and criticizing the billions of dollars spent on acquisitions and mistimed share buybacks. The push by Elliott and other shareholders has drawn BHP’s petroleum division into the spotlight and revived questions about the billions of dollars spent picking on onshore U.S. assets at the height of the natural-gas boom.

BHP on Wednesday forecast a rise in overall production across its operations over the 2018 financial year, as steady growth in iron-ore output and a rebound in commodities including copper offset a further drop in petroleum volumes in the 12 months through June.

The company expects to have up 10 rigs operating in its U.S. shale fields in the coming year, double the number currently drilling for oil and gas after it added two more in the recent quarter, Chief Executive Andrew Mackenzie said.

That will see it spending about US$1.2 billion onshore U.S., the bulk of its US$2 billion petroleum expenditure budget for fiscal 2018, which is expected to deliver a 35% increase in shale production the following year after an expected decline in the current period, the company said.

After months of discussions with BHP and its directors, Elliott in April went public with its calls for the company to spin off its U.S. petroleum business and to rid itself of its dual-listed structure in favor of a main listing in London. In May, it refined its attack, urging BHP to launch an independent review of all its oil-and-gas assets globally and to collapse its listed structure around the Australian shares to unlock shareholder value and halt an underperformance in the shares.

A spokesman for Elliott declined to comment Wednesday on BHP’s quarterly production update or plans.

Other investors have entered the fray, including Australian fund manager Tribeca Investment Partners, which has called for BHP to divest its U.S. onshore oil-and-gas assets. AMP Capital, one of BHP’s largest shareholders, has said BHP now needs to prove the worth of its U.S. onshore business and why it is compatible with the broader portfolio.

BHP has rejected the criticism, arguing that ending its U.K.-Australia structure would be too costly and that there was a beneficial fit between its mining and petroleum operations, although Mr. Mackenzie earlier this year conceded BHP had mistimed the shale acquisitions and had more recently pivoted its focus toward conventional assets.

In the production report, Mr. Mackenzie said the company was pushing ahead with an exit from noncore U.S. acreage, and a sale of the southern Hawkville assets in Texas was expected by September. It also doesn’t plan further development of its operations in the gas-rich Fayetteville in Arkansas and is considering sale of these assets.

Elsewhere in the portfolio, Mr. Mackenzie said drilling of the Wildling-2 appraisal well in the Gulf of Mexico will continue and results were expected this quarter, while the recently approved second phase of the Mad Dog project in the deepwater Gulf of Mexico would expand oil volumes as supply tightens.

In the last financial year, BHP’s petroleum production fell 13% to 208 million barrels of oil equivalent due to the deferral of activity onshore U.S. and natural field decline in the conventional assets. It forecast output would fall 9%-13% in the year ahead.

Production of iron ore, the biggest driver of BHP’s earnings in the previous fiscal year rose 4% to 231 million metric tons in the just-ended fiscal year as prices rebounded, with record volumes at BHP’s mines in Western Australia. BHP said it expected output to grow by between 3% and 5% this year.

Production of coking coal, used alongside iron ore to producer steel, fell 6% to 40 million tons in fiscal 2017, in line with a target that was cut in April due to damage to the rail network caused by a cyclone in Australia’s east coast. BHP said production was expected to climb 10%-15% this year.

Thermal coal, which is used by power stations, was 7% higher at 29 million tons and is forecast to be steady to 3% higher this year. And copper production is expected to jump by 25%-35% this year after falling 16% in fiscal 2017 to 1.33 million tons–the lower end of revised guidance after output was held back by a 44-day strike at the Escondida mine in Chile as well as disruptions at its Olympic Dam mine in South Australia due to maintenance and after a state-wide power outage.

Write to Robb M. Stewart at

U.S. shale output expected to rise by 113,000 barrels a day in August: EIA

U.S. shale oil output expected to rise by 113,000 barrels a day in August: EIA

Published: July 17, 2017 2:10 p.m. ET

Shale crude-oil production from seven major U.S. oil plays is expected to climb in August, according to monthly report from the Energy Information Administration released Monday. Shale output is seen rising by 113,000 barrels a day to 5.585 million barrels a day in August from July, the EIA said. Oil output from the Permian Basin, which covers parts of western Texas and southeastern New Mexico, is expected to see the largest climb among the big shale plays, with an increase of 64,000 barrels a day. August West Texas Intermediate oil CLQ7, +1.39% continued to trade lower, losing 42 cents, or 0.9%, to $46.12 a barrel, less than a half hour before the settlement on the New York Mercantile Exchange.

Read the full story: Oil settles lower as report renews U.S. shale-output worries

U.S. shale oil investment surges more than 50% in 2017, IEA says

U.S. shale oil investment surges more than 50% in 2017, IEA says

Published: July 12, 2017 5:27 a.m. ET

Costs for U.S. shale also seen as rising this year

Getty Images

Workers with Raven Drilling line up pipe while drilling for oil in the Bakken shale formation

After two years of significant declines in upstream oil investments, the sector is finally facing a rebound in 2017 and it all comes down to one thing: a sharp jump in money flowing into U.S. shale oil projects.

The International Energy Agency, in a report out on Tuesday, predicts a 53% upswing in shale investments this year, even as oil prices are struggling to make a sustainable push above $50 a barrel.

“The largest planned increase in upstream spending in 2017 in percentage terms is in the United States, in particular in shale assets that have benefited from a reduction in breakeven prices as a result of a combination of improvement in costs and efficiency gains,” the IEA said.

The big rise in U.S. activities is expected to give global upstream — or exploration and production — investments a 6% bump in 2017, following a 44% plunge between 2014 and 2016. Russia and the Middle East are also seen ramping up spending on upstream projects, albeit at a slower pace, as the chart below shows.

International Energy Agency


Investment in the oil industry started to significantly decline two years ago, when oil prices plunged from above $100 a barrel as a global supply glut destabilized the market. That immediately slowed U.S. shale production, as their oil at the time was more expensive to extract than in many OPEC countries, for example.

But as prices stayed persistently lower, the shale industry adapted and has been able to increase production. U.S. producers have also benefited from the OPEC-led production cuts that have left room and incentivized other producers to take market share. The U.S. Energy Information Administration in May lifted its 2017 U.S. output forecast to an average of 9.31 million barrels per day and again in June raised its 2018 production forecast.

The latest Baker Hughes rig count also showed that the number of active U.S. rigs drilling for oil rose by seven to 763 last week.

“U.S. shale industry operates in a highly dynamic and competitive environment with a very flexible and well-developed service sector, which tends to adapt to market conditions very quickly,” the IEA said in its report.

“There are already signs that the sector is experiencing some renewed cost inflation — a trend that might accelerate in the second half of 2017 — should oil prices remain at current levels (around $50 per barrel) or rise. We estimate that average costs for U.S. shale activities will increase on average by 16% in 2017,” they added.

Crude oil CLQ7, +1.02%  is trading close to $46 a barrel at the moment, while Brent LCOU7, +0.53%  trades at $48.

More broadly, and not just looking at upstream spending, total energy investments worldwide fell 12% in 2016 to around $1.7 trillion, the IEA said. While that has not yet raised near-term concerns over energy security, the Paris-based agency said the low activity in oil and gas exploration could lead to potential risks in coming years.

“The recent slowdown in the sanctioning of conventional oil fields to its lowest level in more than 70 years may lead to tighter supply in the near future,” the IEA said in the report.

“Given depletion of existing fields, the pace of investment in conventional fields will need to rise to avoid a supply squeeze, even on optimistic assumptions about technology and the impact of climate policies on oil demand.”

Oil rises slightly, but growing global supply a worry

Oil rises slightly, but growing global supply a worry

By Julia Simon | NEW YORK

Oil prices rose modestly on Monday, but increased drilling activity in the United States and uncertainty over Libyan and Nigerian production cuts clouded the future supply outlook.

U.S. crude futures settled up 17 cents or 0.4 percent to $44.40 a barrel, while Brent crude futures also rose 17 cents or 0.36 percent to $46.88 a barrel.

Despite the modest rally on the day, Brent crude prices were 17 percent below their 2017 opening level.

With lingering questions surrounding production cuts, the market is “iffy on what OPEC is going to do,” said James Williams, president of energy consultant WTRG Economics in London, Arkansas.

The Organization of the Petroleum Exporting Countries and some non-OPEC members agreed in May to curtail production until March 2018, but the move has failed to eliminate a global glut of crude.

Several key OPEC ministers will meet non-OPEC country Russia on July 24 in St Petersburg, Russia, to discuss oil markets.

Kuwait said on Sunday that Nigeria and Libya had been invited to the meeting and their production could be capped earlier than November, when OPEC is scheduled to hold formal talks, according to Bloomberg.

However, Nigeria’s oil minister was unable to attend the OPEC meeting because of a previous commitment, the Kuwait Oil Minister Essam al-Marzouq told reporters on Monday.

Libya said on Monday it was ready for talks but added that its political, economic and humanitarian situation should be taken into account in talks on caps.

Meanwhile on Monday the CEO of Saudi Aramco Amin Nasser told a conference in Istanbul he thought the world was headed for a global supply shortage.

“The volume of conventional oil discovered around the world over the past four years has more than halved compared with the previous four,” Nasser said.

Yet U.S. oil production continues to grow, rising more than 10 percent since mid-2016.

U.S. energy firms added seven oil drilling rigs last week, marking a 24th week of increases out of the last 25 and bringing the count to 763, the most since April 2015, energy services company Baker Hughes said.

BNP Paribas joined a growing list of investment banks and analysts that have cut their crude oil price forecasts for the coming year.

“We thus have made deep cuts to our crude oil price forecasts. We now see the price of WTI averaging $49/bbl in 2017 (-$8/bbl revision) and that of Brent $51/bbl (-$9/bbl revision),” the bank said in a note.

(To view a graphic on OPEC crude oil exports, click

(Additional reporting by Dmitri Zhdannikov and Amanda Cooper in London, Henning Gloystein in Singapore; Editing by Bernadette Baum and Andrew Hay)

U.S. gas market rebalances as power producers return to coal: Kemp

U.S. gas market rebalances as power producers return to coal: Kemp

By John Kemp | LONDON

The U.S. natural gas market has rebalanced with higher prices steadying production while reducing demand from electricity generators and making room for increased exports.

Higher prices have averted the stock crunch many analysts feared in 2017 as a result of rising exports and the start up of a large number of new gas-fired combined cycle power plants.

During the first six months of 2017, prices for next-month delivery at Henry Hub were almost $1 per million British thermal units or 46 percent higher than in the first half of 2016.

Gas prices paid by electricity producers were up $1 per million British thermal units or 39 percent in the first four months of the year, according to the U.S. Energy Information Administration.

Power producers generated 349 Terawatt-hours of electricity from natural gas between January and April and used 2,611 billion cubic feet of gas in the process (“Electric Power Monthly”, EIA, June 2017).

But gas-fired generation was down 15 percent compared with the same period in 2016 while the volume of gas consumed fell by 14 percent (

By contrast, total electricity generation from all sources was down by less than 2 percent compared with the prior year.

Coal-fired power plants were the main beneficiaries from higher gas prices, increasing their electricity generation by almost 7 percent.

Coal-fired plants operated at an average of 49 percent of their maximum output between January and April compared with 44 percent in the same period in 2016.

By contrast, gas-fired combined-cycle units operated at 48 percent of their maximum output, down from 53 percent in 2016.


Higher gas prices seem to have arrested the slide in gas production, with output down by 4 percent compared with the previous year but showing signs of stabilizing.

The ramp up in oil drilling since May 2016 in response to higher oil prices has also boosted associated gas output.

Stabilizing gas output and reduced consumption by electricity generators has freed up gas for export while leaving inventories at comfortable levels.

U.S. gas exports increased nearly 50 percent to 1,045 billion cubic feet in the first four months, while gas imports were up just 6 percent to 1,063 billion cubic feet.

As a result, net imports shrank from 303 billion cubic feet in January-April 2016 to just 18 billion cubic feet in January-April 2017.

Working gas stocks in underground storage stood at 2,816 billion cubic feet on June 23, which was 313 billion below 2016 but 183 billion above the five-year seasonal average.

Storage injections have been broadly tracking the normal seasonal trajectory, especially once adjusted for the slightly warmer-than-average start to the cooling season.

Weekly builds have been running a little below the five-year average but are higher than in 2016 once adjusted for airconditioning demand.

For the time being, the market appears fairly balanced, with stocks neither excessive nor tight, and with front-month futures prices around $3 per million British thermal units.

(Editing by Edmund Blair)

Natural-gas prices turn higher as EIA reports smaller-than-expected rise in U.S. supplies

Natural-gas prices turn higher as EIA reports smaller-than-expected rise in U.S. supplies

Published: June 29, 2017 10:35 a.m. ET

Data from the U.S. Energy Information Administration Thursday showed that domestic supplies of natural gas rose by 46 billion cubic feet for the week ended June 23. Analysts surveyed by S&P Global Platts forecast a larger build of 52 billion cubic feet. Total stocks now stand at 2.816 trillion cubic feet, down 319 billion cubic feet from a year ago, but 181 billion cubic feet above the five-year average, the government said. August natural gas NGQ17, -0.19% rose 2.3 cents, or 0.7%, from Wednesday’s settlement to $3.117 per million British thermal units. It traded at $3.077 before the data.

Read the full story: Crude-oil recovery stretches to sixth day

Clogged oil arteries slow U.S. shale rush to record output

Clogged oil arteries slow U.S. shale rush to record output

A pumping station owned by Tallgrass Energy is pictured in Guernsey, Wyoming, U.S. on January 17, 2017. REUTERS/David Gaffen

A gallon of gasoline that allows a driver on the U.S. East Coast to travel about 25 miles has already navigated thousands of miles from an oil field to one of the world’s largest fuel markets.

If its last stop is one of the region’s struggling refineries – an increasingly unlikely prospect – the crude used to produce the gas would have probably arrived by tanker from West Africa. That’s because the region’s five plants have no pipeline access to U.S. shale fields or Canada’s oil sands.

Or the journey to an East Coast gas pump might start instead in North Dakota’s Bakken shale fields – which means it could take up to three months, including a stop at a Gulf Coast refinery. The same trip would have been even longer a month ago, before the opening of the controversial Dakota Access Pipeline.

That line was nearly derailed last year by protesters. Its arduous path to approval provides one case study in the oil industry’s struggle to open up a bottleneck holding back resurgent domestic oil production – an outmoded U.S. distribution system.

The equally divisive Keystone XL pipeline provides a more poignant example: First proposed in 2008 to connect Canada’s oil sands to Gulf Coast refineries, the line may now never get built – despite the enthusiastic backing of U.S. President Donald Trump.

As permitting dragged on for years, oil prices crashed, dimming the prospects for investment in the oil sands. Top firms have since written down or sold off billions of dollars in Canadian production assets and decamped for U.S. shale fields.

Pipeline construction often lags production booms by years – if proposed lines are built at all – because of opposition from environmentalists and landowners, topographic obstacles, and permitting and construction challenges. That forces drillers to limit output or ship oil domestically, usually by rail – which is more costly and arguably less safe.

The crimped production, in turn, costs the economy jobs, keeps prices higher for consumers and stymies the nation’s long-held geopolitical goal of reducing dependence on foreign oil.

Obstacles to pipeline construction are coming into sharp focus as resurgent shale firms, after a two-year downturn, are now on pace to take domestic crude oil output to a record in 2018, surpassing 10 million barrels per day (bpd), according to the U.S. Energy Department.

That would top the previous peak in the early 1970s and challenge Russia and Saudi Arabia for the title of top global producer.



To transport all that oil from central shale regions such as Texas and North Dakota to the East Coast, the U.S. relies largely on pipelines built decades ago. The industry has retooled many old oil arteries, and the resulting patchwork often offers a convoluted route.

“It’s a hodge-podge way of doing it,” said Tricia Curtis, oil analyst at Petronerds, a consultancy based in Denver.

U.S. Interior Minister Ryan Zinke wants the nation to become the dominant global energy player, and is considering opening more federal lands – such as national parks and Native American reservations – to fossil fuel development. He also aims to lift restrictions on offshore drilling.

That’s a new twist on achieving “energy independence,” an elusive, almost mythical goal that’s been a standby of U.S. political dialogue over the half century since Richard Nixon was president.

Surging shale has reduced import dependence, but achieving anything approaching “independence” would require an overhaul of the nation’s pipeline network – including construction of the kind of projects that face bleak prospects because of political opposition and geographic realities.

About half of U.S. petroleum consumption is on the East and West Coasts, while the large expanse in the middle of the country accounts for 93 percent of crude output in the lower 48 states.

The challenges to building new pipelines are likely to keep the East and West Coast markets – where most Americans live – dependent on imported oil, said Doug Johnson, vice president at Tallgrass Energy Partners (TEP.N), which operates pipelines and storage facilities in the central and western United States.

The Rocky Mountains makes construction to much of the West Coast impossible, as does difficult topography and dense population on the East Coast.

“Moving new pipelines through those areas is very, very challenging,” Johnson said.

Tallgrass’s Pony Express line kicks off in Guernsey, Wyoming, a small town of 1,000 near the historic Oregon Trail Ruts. It’s one small example of the industry’s history of repurposing old lines. Originally built as a crude line in 1954, it was converted to a natural gas line in 1997, then changed back into a crude line in 2014.

“This thing is like the cat with nine lives,” Johnson said.



Building pipelines from faraway oil fields such as the Bakken directly to the densely populated East Coast would be a boon to energy firms and consumers. But it won’t happen, said Sandy Fielden, an analyst at Morningstar.

“That flies in the face of NIMBY,” he said, referring to the ‘not in my backyard’ political resistance to construction. “Pipelines being built across New Jersey is not considered to be a practical proposition.”

Resistance to new pipelines in the Northeast has led firms to battle for control of existing lines.

Midwest refiners are clashing with East Coast refiners over a proposal to reverse the flow of fuels on a Pennsylvania pipeline that transports refined products from east to west. Midwest refiners – who can access Dakota and Canada crudes, unlike their East Coast competitors – want that flow reversed to give them access to gasoline markets further east.

In at least one case, pipeline protesters are demanding the removal of an existing line. A 60-year-old Enbridge Line in Wisconsin and Michigan, an essential artery of oil from Canada, has come under fire from opponents of varying political stripes.

Environmentalists call the current pipeline network strong enough. They argue the country needs to look toward renewable energy sources rather than expanding climate-damaging oil-and-gas development.

Another environmental threat comes from an irony of the patchwork of U.S. pipelines – that the network is both over-subscribed and yet, in places, underused. Because many arteries travel similar routes, they duplicate one another and often can’t operate at full capacity.

That raises the prospect of damaging leaks that go unnoticed by automated detection systems that require highly pressurized lines to function, said Anthony Swift, a director at the National Resources Defense Council.

One bright spot for firms that already own pipelines: It’s far easier, politically and logistically, to expand a line than to build a new one – making existing lines increasingly valuable.

But in the long term, the U.S. will struggle to boost production without new pipelines that serve key consumer markets, said Tad True, president and CEO of Casper, Wyoming-based True Companies, a private pipeline owner.

“One of the successes of this country was based on access to cheap energy,” he said. “The continued success of the United States depends on continued access to cheap energy.”


(Editing by Simon Webb and Brian Thevenot)