Libya's Sharara oil field, the country's largest, resumed production on Sunday after a week-long disruption and state-owned NOC lifted force majeure on loadings of Sharara crude on Monday, sources told Reuters.

The field was producing around 80,000 barrels per day (bpd) on Sunday and about 220,000 bpd prior to the March 27 shutdown.

"The main development over the weekend is the restart of Sharara," managing director of PetroMatrix Olivier Jakob said.

Uncertainty about how Libyan output would fare in the months ahead added short-term volatility to oil prices, he said. "(It) is a swing factor that can make it move both ways if one looks at the balances for the second half of the year." he added.

http://www.reuters.com/article/us-global-oil-idUSKBN17501U

During the oil price rout, islands in the Caribbean were exhibit A for the longest-lasting glut in three decades, with millions of barrels stored there. Now, that oil is flowing again, a sign the market is rebalancing.

Since mid-February, between 10 million and 20 million barrels have left the Caribbean, according to estimates from traders who asked not to be named because their data is proprietary. The draw, hardly noticed by most in the market, reflects the impact of the output cuts orchestrated by OPEC and Russia.

Low taxes and the Caribbean’s proximity to U.S. and Latin America oil centers have made it into one of the world’s largest oil storage centers, holding as much as 140 million barrels. While a lack of official data can make the area invisible to some, the information is key in framing a full picture of global supply and demand at a time of market uncertainty.

"Caribbean and other storage has drawn down rapidly over the past weeks," said Amrita Sen, chief oil analyst at Energy Aspects Ltd., in a note to clients. "The first indications that the rebalancing has begun are here."

On Sunday, Mohammad Barkindo, OPEC’s Secretary-General, said he remained "cautiously optimistic” the gap between supply and demand was starting to tighten. The Organization of Petroleum Exporting Countries and the 11 countries that agreed to trim production in the first half of the year are now weighing whether to extend the cutbacks to the end of 2017.

West Texas Intermediate oil fell 0.7 percent to $50.24 a barrel in New York on Monday. Oil prices have fallen about 10 percent this year as crude stockpiles in the U.S. have since December grown by almost 55 million barrels to 534 million barrels, the highest since 1929.

Grand Bahama, Aruba, Bonaire, Curaçao, St. Eustatius and St. Lucia, mostly known for the beaches that draw sun-chasing visitors from around the world, all have significant depots to store crude and refined products.

Chinese oil companies, which lease millions of barrels of storage in the southern Caribbean sea, are leading the stock-draw from those islands, the traders said. PetroChina Co. used the super-tanker Nectar last month to remove stored crude from Aruba and Curaçao, according to ship-tracking data compiled by Bloomberg. It also loaded the Maxim, another very-large crude carrier (VLCC), with crude from storage in the Caribbean Sea.

Indian oil refiners are also taking crude out. In a rare shipment, Reliance Industries Ltd. received Ecuadorian crude stored in the island of Grand Bahama in the DHT Condor super-tanker. More recently, another giant tanker, the Amphitrite, took Venezuelan crude from a terminal in St. Eustatius, also for Reliance.

"Globally, crude stocks are coming down," said Mike Loya, the Houston-based top executive at Vitol Group BV, the world’s largest independent oil trader.

The Caribbean outflows also reflect a change in the relationship between spot and forward oil prices. For much of 2015 and 2016, the shape of the oil curve showed spot prices below forward prices. In a contango market, traders can buy barrels, place them on storage and lock in a profit by selling them forward in the futures market.

The price difference between Brent crude oil for immediate delivery and the one-year forward, a key contango yardstick, reached more than $11 a barrel in January 2015. But after OPEC and Russia announced their output cuts in late last year, the contango has all but dissipated, with the one-year Brent price spread at just about 80 cents a barrel on Monday.

"Less visible inventories have been drawing," Martijn Rats, oil analyst at Morgan Stanley in London, said in a note to clients.

https://www.bloomberg.com/news/articles/2017-04-03/oil-traders-said-to-drain-caribbean-hoards-as-opec-impact-hits

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Qatar has lifted a self-imposed moratorium on development of the world's biggest natural gas field, the chief executive of Qatar Petroleum said on Monday, as the world's top LNG exporter looks to see off an expected rise in competition.

Qatar declared a moratorium in 2005 on the development of the North Field, which it shares with Iran, to give Doha time to study the impact on the reservoir from a rapid rise in output.

The vast offshore gas field, which Doha calls the North Field and Iran calls South Pars, accounts for nearly all of Qatar's gas production and around 60 percent of its export revenue.

"We have completed most of our projects and now is a good time to lift the moratorium," QP Chief Executive Saad al-Kaabi told reporters in Doha.

The new development will increase production of the North Field by about 10 percent, adding about 400,000 barrels per day of oil equivalent to Qatar's output, he said.

LNG GLUT

Qatar is expected to lose its top exporter position this year to Australia, where new production is due to come on line.

The LNG market is undergoing huge changes as the biggest ever flood of new supply is hitting the market, with volumes coming mainly from the United States and Australia.

President Vladimir Putin said on Thursday Russia aimed to become the world's largest LNG producer.

The flurry of LNG production has resulted in global installed LNG capacity of over 300 million tonnes a year, while only around 268 million tonnes of LNG were traded in 2016, Thomson Reuters data shows.

That has helped pull down Asian spot LNG prices by more than 70 percent from their 2014 peaks to $5.65 per million British thermal units (mmBtu).

Qatar's decision to lift the moratorium on new gas development now could help the Gulf monarchy maintain a competitive edge after 2020, when the global LNG market is expected to tighten.

"With global activity levels and costs low, now is a good time to add new capacity, even if the LNG market does presently look over supplied," said Giles Farrer, research director of Global LNG at Wood Mackenzie.

"It's a signal that Qatar intends to increase its market share, which has been falling as other regions have built new capacity."

An energy advisor to the Qatar government said he saw it as a preemptive step to warn competitors who are considering LNG investments that Qatar would remain an aggressive seller.

"It will certainly give rivals something to chew on. It's like when Saudi develops future oil capacity even when there is a glut - it shows you mean business," he said, declining to be named as he was not authorized to speak publicly.

The announcement coincides with the start of a major LNG industry conference this week in Japan, attended by many of its competitors and potential new customers.

Kaabi said low prices would not pressure Qatar.

"By the time this project comes online in five years or so it should be a good market for gas," he said. "We don't see that the pricing pressure has affected us as much as some."

IRAN NO ENEMY

Iran, which suffers severe domestic gas shortages, has made a rapid increase in production from South Pars a top priority and signed a preliminary deal with France's Total in November to develop its South Pars II project.

Total was the first Western energy company to sign a major deal with Tehran since the lifting of international sanctions.

Kaabi said the decision to lift the moratorium was not prompted by Iran's plan to develop its part of the shared field.

"What we are doing today is something completely new and we will in future of course ... share all this with them (Iran)."

The economy of Qatar, a future World Cup host with a population of 2.6 million, has been pressured by the global oil slump and in 2015 QP dismissed thousands of workers and has earmarked a number of assets for divestment.

QP is merging two LNG divisions, Qatargas and RasGas, to save hundreds of millions of dollars.

In February, Kaabi said Qatar would focus on seeking international opportunities by exploring for oil and gas in Cyprus and Morocco.

But the current low LNG price environment may deter investment in new supply projects, bringing tighter supplies and price spikes in the future.

New production from Qatar's North field is seen starting within 5-7 years, targeting gas exports of 2 billion standard cubic feet per day, Kaabi said.

http://www.reuters.com/article/us-qatar-gas-idUSKBN175181

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The world’s gas industry is descending on Tokyo this week with something other than cherry blossoms on its mind: a trio of Asian LNG buyers testing their collective muscle in a push for more flexible long-term contracts for the fuel.

Korea Gas Corp (KOGAS), Japan’s JERA and China National Offshore Oil Corp (CNOOC) – whose joint liquefied natural gas volumes account for a third of global LNG trade – are attempting to cement a shift in power from producers to importers amid a supply glut that is expected to persist into the early-2020s.

Developing responses from LNG producers to the group’s alliance may also soon start to give clues as to who will win advantage as the fuel surplus puts pressure on suppliers to give buyers greater contractual freedom than they have had since the industry first began to ramp up in the 1970s.

“Destination clauses will probably die soon under the pressure of buyers and the growing needs for flexibility,” said Anne-Sophie Corbeau, a research fellow at the King Abdullah Petroleum Studies and Research Centre (KAPSARC) in Saudi Arabia.

No meetings between the three buyers and major producers such as Royal Dutch Shell, Chevron and Qatargas have yet been confirmed at the Gastech biannual industry gathering, but representatives of all are certain to be in attendance, and other delegates are sure to be watching to see what happens when their paths cross.

North Asian LNG buyers – including those agreeing last month to explore joint purchases of supplies – have for decades relied on rigid long-term contracts that prevent cargo resales because the main priority was security of supply as energy demand soared amid double-digit economic growth.

But a slowdown in Asian growth over the past few years, especially in top two buyers Japan and South Korea, and impending liberalisation of gas and power markets mean dominant utilities are now often stuck with surplus cargoes they cannot resell amid stagnant or shrinking demand at home.

Last year for instance, global installed LNG capacity was over 300 million tonnes a year, while only about 268 million tonnes of LNG were traded, according to Thomson Reuters data.

JERA and KOGAS have both indicated they aim to ink only future contracts that have more flexible terms, but it remains unclear if they or other Asian buyers plan to force existing contracts into arbitration.

Many LNG producers have so far declined to comment on the rising threat from more aggressive buyers, although Australia’s Woodside Petroleum; suggested last week that flexibility in long-term contracts would eventually lead to a more liquid market.

DISRUPTION

Another disrupting force in the LNG market could be the emergence of importers like Pakistan that utilise floating storage and regasification units, who would also be small-scale buyers seeking shorter-term contracts.

“There are more new types of players coming into the market so it’s no longer the long-term bilateral type of dedicated deals between utilities and exporters, but we’re seeing a more flexible and liquid market developing,” Keisuke Sadamori, director of energy markets and security for the International Energy Agency, told Reuters.

Asia, which accounts for about 70 percent of the world’s LNG demand, is poised as well to benefit from rising U.S. exports that are on track to make the United States the third-largest exporter of LNG next year.

U.S. LNG is attractive to Asian buyers as cargoes have no destination restrictions that prevent them from being resold when domestic power demand is weak.

“This growth (in spot and short-term contracts) is driven by several factors including … the Japanese gas and power sector deregulations, (and the) uncertainty of LNG demand in Japan and Korea given potential nuclear power plant re-starts,” said Marc Howson, LNG Senior Managing Editor at Global Platts.

The emergence of price-sensitive buyers in India and China is also driving the market towards more spot trade, Howson said.

India does not rule out the possibility of joining the China, Japan and Korea grouping to jointly buy LNG to extract better deals, the country’s Oil Minister Dharmendra Pradhan said last month, adding that the market was gradually becoming more consumer-centric.

http://www.lngworldnews.com/talk-of-tokyo-lng-trio-to-test-leverage-in-push-to-free-up-purchases/

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Royal Dutch Shell's integrated gas and new energies director, Maarten Wetselaar, said on Tuesday that destination clauses in long-term liquefied natural gas (LNG) supply contracts that have linked suppliers and customers for decades are "not really crucial".

"They're not really crucial in contracts anyway, once you've delivered LNG into a tank, it is quite expensive to get it out again and ship it to someone else," Wetselaar said, speaking on the sidelines of a gas conference in Chiba, Japan.

The Shell executive was responding to questions on efforts made by the world's biggest buyers of the fuel to club together last month to push for more flexible supply contracts that drop cargo destination clauses.

http://www.reuters.com/article/japan-gastech-shell-idUSL3N1HC0L1

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New, standardized solutions will drive down production costs and accelerate delivery

AG&P’s scalable LNG platforms have a flexible design. The 4,000 m3 to 8,000 m3 vessel is designed for shallow water delivery and the 6,000 m3 to 16,500 m3 platform has scalable capacity which is suitable for open water delivery cost-efficiencies and uptake. (Graphic: Business Wire)



 
AG&P (Atlantic, Gulf and Pacific Company), the global leader of infrastructure solutions, today announced two standardized modular products for the LNG supply network that will drive down costs, accelerate schedule and enable last-mile delivery to LNG demand centers scattered across Southeast Asia, South Asia and the Caribbean.

“While there is increasing preference for small-scale and mid-scale LNG solutions in emerging economies like Indonesia and India, uptake remains slow with few projects underway. Standardization and modular solutions will be the circuit-breaker that will bring projects online, enabling the switch to LNG as a clean and affordable energy source”

Speaking at Gastech 2017, the company presented designs incorporating standardized equipment to deliver a scalable LNG delivery platform and a fit-for-purpose, onshore modular regasification unit. These ‘plug and play’ packages, based on standard solutions, are built in AG&P’s dedicated, state-of-the-art, 150-hectare modularization facilities, which helps speed delivery times and significantly reduces the cost of customized engineering and project man-hours while increasing productivity and quality. Cost-effective and built for transportation across the world, AG&P believes these off-the-shelf products have the potential to bolster the small and mid-scale LNG market.



http://www.businesswire.com/news/home/20170403006713/en/AGP-Announces-Integrated-Plug-and-Play-Solutions-LNG-Supply/?feedref=JjAwJuNHiystnCoBq_hl-YKT6SDyMw5Lye4ovXwHmkqD8R-QU5o2AvY8bhI9uvWSD8DYIYv4TIC1g1u0AKcacnnViVjtb72bOP4-4nHK5idAXrgr_e1ZUbxvK6BY66Xm&utm_source=dlvr.it&utm_medium=twitter

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European and Israeli governments gave their support on Monday to moving forward with a Mediterranean pipeline project to carry natural gas from Israel to Europe, setting a target date of 2025 for completion.

The planned 2,000 km (1,248 mile) pipeline aims to link gas fields off the coasts of Israel and Cyprus with Greece and possibly Italy, at a cost of up to 6 billion euros ($6.4 billion).

"This is an ambitious project, which as the Commission, we clearly support, as it will have a high value in terms of security of supply and diversification targets," said European Climate and Energy Commissioner Miguel Arias Canete.

Israel has discovered more than 900 billion cubic metres (bcm) of gas offshore, with some studies pointing to another 2,200 bcm waiting to be tapped. Along with the European market, it is exploring options to export to Turkey, Egypt and Jordan.

Cyprus' Aphrodite natural gas field holds an additional 128 bcm, and Cypriot waters are expected to hold more reserves.

After a meeting in Tel Aviv between energy ministers from Israel, Cyprus, Greece and Italy, Canete told reporters he believed the project would "meet all relevant requirements" to make financial commitment possible.

Israeli Energy Minister Yuval Steinitz said the pipeline could be completed in 2025. "But we will try to speed up and to shorten the timetable," he said.

A feasibility study has been completed and the next few years would focus on "proper development activities", with a final investment decision expected by 2020, said Elio Ruggeri, chief executive of IGI Poseidon, the project owners.

IGI Poseidon is a joint venture between Greece's DEPA and Italian energy group Edison.

"Our estimate today is for the pipeline to cost 5 billion euros to (reach) the Greek system and 6 billion euros to (reach)the Italian system," Ruggeri told Reuters.

The energy ministers said they would next meet in Cyprus in six months to further advance the project.

http://www.reuters.com/article/energy-natgas-israel-idUSL5N1HB1V8

World's largest independent energy trader Vitol's profit rose 25 percent last year, the Financial Times reported on Monday, citing people familiar with the matter.

The Swiss-based company had a net income of $2 billion in 2016, up from just over $1.6 billion in 2015.

The 2016 net income included $500 million of gains from asset sales and a $100 million tax bill, the newspaper reported.

The results are unaudited and subject to revision, according to the FT.

Vitol said last month that annual traded volumes rose 16 percent in 2016 to a new record as it sold more gasoline and diesel in markets such as the U.S. and Australia.

Vitol's turnover, however, fell to $152 billion in 2016 from $168 billion in 2015 as a result of lower energy prices.

http://www.reuters.com/article/vitol-results-idUSL3N1HB31W

Brazil's black market pipeline: Gangs hijack Petrobras' oil, fuel

In September, police investigating a wave of killings in the northern Rio de Janeiro suburbs followed a tip to the isolated scrubland near the massive Duque de Caxias oil refinery.

Police presumed the killings were linked to turf battles between criminal gangs in the run-up to municipal elections the following month.

They found a different explanation buried beneath the grass: a system of tubes to siphon fuel from underground pipelines leading from the refinery, owned by state-run oil company Petrobras.

Some of the killings, police said, were part of a power struggle between rival gangs earnings millions of dollars a year from stealing crude oil, diesel and gasoline and selling it on a thriving black market.

The discovery highlighted a fast-growing criminal enterprise in Brazil's oil heartland, between Rio de Janeiro and Sao Paulo. From just one recorded incident in 2014, the number of thefts and attempted thefts from Petrobras rose to 14 in 2015 - before jumping five-fold to 73 last year, the company told Reuters.

The racket is part of a larger crime wave in Brazil, and especially Rio, amid the country's worst recession on record.

Investigators believe the oil and fuel thefts were masterminded by the city's powerful militias - often made up of retired or off-duty cops - as they seek to move away from terror and violence to lower-profile crimes following a crackdown by authorities in recent years.

The thieves' methods range from hijacking tanker trucks to tapping the company's more than 11,000 kilometers of pipelines - and processing stolen crude at their own secret refineries.

"Not even Petrobras knows exactly how much is being stolen," said Giniton Lages, the Rio police chief who led the investigation at Duque de Caxias. "It's a huge business, moving millions of reais."

INSIDE JOB

While oil theft - often with environmental damage from the accompanying spills - is commonplace in regions like the Niger Delta of Nigeria, it has not traditionally been a problem in Brazil.

The thefts add to the steep challenges facing Petroleo Brasileiro SA, as the Rio-based firm is formally known. Amid weak oil prices, the company is scaling back under new CEO Pedro Parente and trying to emerge from a $100 million pile of debt.

For the past three years, the state-run company has been hit by a sprawling investigation into corruption and political kickbacks in its dealings with construction firms.

Police suspect corruption in the oil thefts as well. The taps and pipes near the Duque de Caxias refinery were so precisely engineered that investigators concluded the thieves must have had help from inside Petrobras.

"They knew what type of fuel was inside each pipe and what was the ideal point to place a tap without the change of pressure in the tube raising the attention of the company's security system," Lages said.

Petrobras, whose production of about 2.8 million barrels a day makes it one of the world's top 10 oil companies, said it was working with police to identify any employees or ex-employees that may have been involved in the crimes.

"In 2016, there was a startling increase in theft from our pipelines," said Rodrigo Spagnolo, head of pipeline maintenance at Transpetro, Petrobras' transport subsidiary.

The company, however, said the robberies had no material impact on its earnings. Petrobras reported revenues of $81 billion last year.

http://www.reuters.com/article/us-brazil-petrobras-theft-idUSKBN1760C7

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Genscape Cushing: +762,000bbls in last week

@zerohedge  

It may be more than a year before US Gulf of Mexico oil exploration begins to ramp up in any noticeable way, but several new deepwater fields are adding to production and there seems to be sparks of interest in developing recent offshore finds.

Platts Analytics Bentek Energy is forecasting a rise in US offshore production to 1.868 million b/d by year-end and to 2.296 million b/d by end-2022 from 1.669 million b/d at end-December 2016.

The reason? Several new fields are slated to come online this year, including Barataria and South Santa Cruz, operated by small privately held Deep Gulf Energy, and Crown and Anchor by LLOG Exploration. Those will bring a combined 15,000 b/d of oil equivalent production.

But the Tornado Field, at around 9,000 boe/d, came onstream in November and other large fields that came on in 2016 such as Anadarko Petroleum's Heidelberg, Shell's Stones, ExxonMobil's Julia and Noble Energy's Gunflint, are still ramping up, sources said. Also, new wells are expected this year from Anadarko's Lucius Field (online since early 2015), and Hess' Tubular Bells (online since late 2014).

Even though sanctioning of large projects are few in number these days, some are still being advanced. For instance, Chevron's long-awaited Big Foot development will come online in late 2018. And Shell's Appomattox field is set to come online in 2020. Shell's Kaikias Field, to be tied back to its Ursa production hub, comes on in 2019.

"I've said for the past few years that things should be more active [in the Gulf] in 2018 and 2019, and I'm still hopeful that's the case," Trevor Crone, analyst for Platts unit RigData, said. "We should see a modest but steady increase in drilling in 2019."

RigData shows just six semisubmersible rigs and 22 drill ships under contract in the US Gulf of Mexico as of the end of March, down from 10 and 29, respectively, year on year.

"It won't go gangbusters anytime soon. I think there will be gradual improvement from here on out," Crone said.

GULF SALE 'EARLY SIGN' OF COMEBACK

As for new exploration, last month's Central Gulf of Mexico lease sale, which captured nearly $275 million in total high bids -- up from the $156 million seen in last year's comparable sale -- "is an early sign that offshore exploration and production spend is likely to come back," UBS analyst Amy Wong said in a post-sale investor note.

Mexico also held its first deepwater auction on its side of the Gulf in December 2016, where eight of 10 blocks received bids and Australia's BHP won a separate bidding to develop the Trion deepwater find jointly with state company Pemex.

But most of these are long-lead exploratory projects that could take up to a decade to produce -- and that's after a discovery is made, which could take several years as seismic is analyzed, drilling locations selected and other prepatory work is done.

Terms for US Gulf deepwater tracts are seven to 10 years, meaning operators have until 2024 (for tracts in 2,600-5,250 foot water depths) or 2027 (for blocks in water depths greater than 5,250 feet) to drill them.

Analysts have said $60/b is roughly the oil price operators likely want to see before embarking on wildcat exploration. With many deepwater wells costing well over $100 million each in remote locations 150-200 miles offshore and at total depths 30,000 feet and greater, operators have shied away from the risk -- especially when shale wells onshore yield more immediate benefits.

"Broadly speaking, our view is that we're not going to see any kind of full-scale return to exploration until oil prices go back up," Gordon Loy, Gulf of Mexico upstream oil and gas analyst for energy consultants Wood Mackenzie, told S&P Global Platts.

Still, Loy said breakeven oil prices for many Gulf of Mexico deepwater projects are "sub-$50" per barrel now, down from the $60s/b and $70s/b a few years ago.

In a report last week, Wood Mac said investment decisions on global deepwater oil and gas projects will likely see a recovery this year as drilling costs in the sector have fallen to a level making them more competitive with US shale plays.

DEEPWATER COSTS COULD FALL MORE

Noting that cost inflation in the US tight oil industry was back "with a vengeance," the report estimated that, in contrast, deepwater costs could fall further, helped by leaner development principles and improved well designs.

"A lot of projects we classify as probable [for development] are undergoing a rescrubbing," Loy said. "They are being optimized, and operators are right-sizing facilities to be able to produce from a field they have now, not over-designing and not building in extra capacity [for the] future."

On the other hand, "we're still seeing appraisal activity at some high-profile discoveries" in the Gulf of Mexico, including Chevron's 2015 Anchor discovery (not related to a similar-named LLOG field), Anadarko Petroleum's Shenandoah and Cobalt's North Platte, he said.

"Those will still move forward. But a majority of Gulf of Mexico exploration will focus on lower-risk subsea tiebacks for the near future," Loy said.

Subsea tiebacks connect fields relatively near a production hub to the facility. They allow operators to capture value from smaller discoveries that may not be economic enough to warrant stand-alone production hubs.

In addition, top energy officials such as Saudi's oil minister Khalid Al-Falih and even Chevron CEO John Watson recently said shale alone will not be enough to fill a needed crude supply gap into the 2020s.

Speaking at the Howard Weil conference in New Orleans last week, Paal Kibsgaard, CEO of oil services provider Schlumberger, said production is holding up well despite under-investment despite a global industry downturn now into its third year.

Even so, "the current situation is not sustainable," Kibsgaard added.

http://www.platts.com/latest-news/oil/houston/feature-new-us-gulf-fields-add-to-oil-production-21339393

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NAmerico Partners LP is proposing a multibillion-dollar pipeline to ferry natural gas from fast-growing fields in West Texas to the Gulf Coast, the company said on Monday, angling to match plans by rivals such as Kinder Morgan Inc (KMI.N).

The pipeline, one of at least three being considered to ease a looming gas glut in the Permian producing region, would link to existing lines, including those that export gas to Mexico and to a Cheniere Energy Inc (LNG.A) liquefied natural gas export facility under construction.

The pipeline would be the first major project by NAmerico Partners, founded two years ago in Houston. The company is backed by private equity fund Cresta Energy LP, whose management includes former executives from Regency Energy Partners LP, a large energy infrastructure company that was bought by Energy Transfer Partners (ETP.N) in 2015.

NAmerico Managing Partner Jeff Welch told Reuters in an interview this week that discussions with prospective shippers were at an advanced stage, and the pipeline would begin operations in 2019 if enough of them committed to supplying gas.

He declined to identify the shippers but said the company was confident the project would proceed.

NAmerico's 468-mile (753-km) pipeline, named the Pecos Trail Pipeline, would transport some 1.85 billion cubic feet per day of natural gas to the major Gulf Coast refining and petrochemical hub in Corpus Christi.

Last month, Kinder Morgan, which operates the largest natural gas pipeline network in North America, outlined a plan to build a 430-mile (692-kilometer) pipe traveling a similar route. It would be able to move 1.7 bcf per day of gas.

Enterprise Products Partners (EPD.N), another large pipeline operator, has said it may build a gas line to Corpus Christi, Texas, from the Permian.

"We've got this gigantic gas supply in West Texas, and big exports southbound and eastbound," Rick Smead, managing director of advisory services for consultancy RBN Energy, said in a telephone interview.

Kinder Morgan has also said its pipeline would begin operations in 2019 if enough shippers commit.

Analysts said the potential for new supplies could allow multiple projects to proceed.

The projects are being planned as big producers including Exxon Mobil, Apache Corp, and Chevron Corp are expected to pour billions of dollars into drilling in the Permian, a vast shale play in West Texas known for its low production costs and massive reserves.

Demand for natural gas in south Texas and the Corpus Christi area is expected to soar in the coming years. Cheniere Energy has said it has customers for 8.42 million metric tons a year of LNG from its site, which is expected to begin operations around 2018.

Exxon and Saudi Basic Industries Corp 2010.SE, an arm of Saudi Aramco, the state-owned energy company, also have proposed building a multibillion-dollar chemical and plastics plant outside of Corpus Christi. That plant would use natural gas as a raw material.

Natural gas production in West Texas is expected to more than quadruple by the middle of the next decade, Scott Sheffield, chief executive of Pioneer Natural Resources Co (PXD.N), a large Permian producer, said last month.

Gas production in the Permian is projected to reach 7.9 Bcf/d in April, up from 5.4 bcf/d the same month in 2014, according to the U.S. Energy Information Administration.

The number of drilling rigs operating in the region has more than doubled in the last year to 319 as of March 31, according to energy services provider Baker Hughes (BHI.N).

While companies are primarily drilling in the Permian for crude, natural gas comes up along with it. The EIA estimates each new rig in March added in the Permian increases the field's gas production by 1.1 million cubic feet a day.

http://www.reuters.com/article/us-namerico-partners-pipeline-idUSKBN1750CW

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