Oil prices rose almost 2 percent on Monday, after Venezuela said OPEC and non-OPEC producers were close to reaching an output stabilizing deal and as clashes in Libya raised concerns that efforts to restart crude exports could be disrupted.

Venezuelan President Nicolas Maduro has said that a deal could be announced this month to stabilize oil markets, which have come under pressure due to a persistent glut and a price collapse over the past two years.

Brent crude futures were at $46.59 per barrel at 0301 GMT (11:01 p.m. EDT), up 82 cents, or 1.8 percent, from their previous settlement. U.S. crude was up 88 cents, or about 2 percent, at $43.91 a barrel.

The rise in oil prices is a reaction to Venezuelan comments about producers reaching a possible output agreement, said Ric Spooner, CMC Markets' chief market analyst. Loading disruptions in Libya were also underpinning the market, Spooner added.

"(Libya) unable to get their first ship loaded is a reminder that it may be difficult for Libya to increase production."

Clashes in Libya have halted the loading of the first oil cargo from the port of Ras Lanuf in close to two years, while also raising fears of a new conflict over Libya's oil resources.

Brent and WTI prices had been dragged to multi-week lows on Friday amid worries returning supplies from Libya would add to the global supply glut.

Concerns over rising supplies remain a bugbear on sentiment.

Crude exports from No.3 OPEC producer Iran in August jumped 15 percent from a month ago to more than 2 million barrels per day, according to a source with knowledge of its tanker loading schedule, closing in on Tehran's pre-sanctions shipment levels of five years ago.

In the United States, drillers have added oil rigs for 11 out of the past 12 weeks. Drillers added two oil rigs in the week to Sept. 16, bringing the total rig count up to 416, the most since February.

http://www.reuters.com/article/global-oil-idUSL3N1BV0I3

Iran's August crude oil exports jumped 15 percent from July to more than 2 million barrels per day (bpd), according to a source with knowledge of its tanker loading schedule, closing in on Tehran's pre-sanctions shipment levels of five years ago.

The No. 3 OPEC producer has more than doubled its crude exports, excluding the ultra light oil condensate, since December. Economic sanctions targeting Iran's disputed nuclear program were lifted in January, and it has been battling since then to regain market share lost to other Middle East producers over the previous four years.

The strong demand for Iran's crude in Asia and Europe has enabled it to raise its oil output to just over 3.8 million bpd as of this month, still shy of the 4 million bpd level Tehran says is a precondition for discussing output limits with Saudi Arabia and Russia.

Members of the Organization of the Petroleum Exporting Countries (OPEC) and Russia are expected to meet during the International Energy Forum in Algeria over Sept. 26-28 to discuss a possible output freeze to stabilize oil prices LCOc1 CLc1 that are still down around 60 percent since mid-2014.

"The only way for producers to maximize their revenues in a low oil price environment to meet budget requirements is to raise production," said Victor Shum, an oil analyst at consultancy IHS. "So there is unlikely to be any supply deal ... in late September," he said.

"We can expect Iran to continue to raise production."

August crude exports from Iran excluding condensate roughly doubled from a year ago to 2.11 million bpd, the source said, based on data compiled from tanker loading schedules.

The crude exports have climbed from 1.9 million bpd in June and 1.83 million bpd in July, the schedules showed.

Iran's August exports are the highest since January 2012, boosted by record purchases from the world's third-largest oil importer India and a 48 percent jump that brought European sales to 630,000 bpd, tanker loadings for last month also showed.

Other sources who track Iran's shipping data or who are familiar with its tanker loadings have slightly different figures for Iran's crude exports in August, but still show a near doubling since January.

For countries like Iran that do not report official trade data, counting tankers is the primary means of estimating their oil trade, although counts may vary from tracker to tracker.

Details on condensate loadings for August remain unclear. But if shipments of the ultra light oil were steady with this year's average of nearly 310,000 bpd, the total crude and condensate exports last month would be this year's highest at 2.41 million bpd, still short of average pre-sanctions exports of 2.5 million to 2.6 million bpd in 2011, according to figures from the U.S. Energy Information Administration.

Iran's crude exports excluding condensate to Asia in August were 1.48 million bpd, up from 1.40 million bpd in July and roughly steady to this year's previous peak in April.

Loadings headed for India reached a likely record of nearly 600,000 bpd last month, according to data stretching back at least 15 years, up 150,000 bpd from July, and topping 564,000 bpd loaded for China.

Japanese loadings were nearly 230,000 bpd, compared with about 92,000 bpd for South Korea.

Iranian oil was also loaded for Turkey, Greece, and Spain, and exports to Italy more than doubled from the previous month to 87,000 bpd, according to the schedules.

To further boost its exports, Iran expects to complete the building of a terminal by year-end for a new grade.

http://www.reuters.com/article/us-iran-oil-exports-idUSKCN11M0XL

Libya halted loading what would be the first overseas crude shipment from the port of Ras Lanuf since 2014 as rival armed forces fought for control of the facility, complicating efforts to end a five-year conflict that has slashed oil exports from the OPEC country.

Forces loyal to eastern-based military commander Khalifa Haftar repulsed a local Petroleum Facilities Guard unit that tried on Sunday to seize control of Ras Lanuf and the country’s largest oil port of Es Sider in east Libya, Mohammad Al-Azoumi, spokesman for a battalion under Haftar’s command, said by phone. Five petroleum guards were killed during the clashes, he said.

The fighting forced the tanker Seadelta to suspend the loading of 781,000 barrels of oil for shipment to Italy, Nasser Delaab, petroleum operations inspector at Harouge Oil Operations, said by phone. The tanker, which began loading earlier Sunday, sailed away from Ras Lanuf and may return to the port to finish taking on oil on Monday, he said. Another tanker, the Syra, will arrive soon in Ras Lanuf to ship 600,000 barrels of crude to Italy, he said.

Output Slashed

Libya is seeking to boost crude exports after fighting among rival militias slashed oil production following the 2011 ouster of former dictator Moammar Al Qaddafi. The conflict halted exports from the nation’s main oil ports of Es Sider, Zueitina and Ras Lanuf as the country struggled to form a unified national government. The National Oil Corp. planned to resume exports from the ports after reaching an accord with Haftar, who seized control of the facilities last week.

Brent crude gained as much as 1.9 percent to $46.62 a barrel and traded at $46.52 as of 9:08 a.m. in Dubai on Monday. Haftar took Ras Lanuf and Es Sider from Ibrahim Jadran, leader of local Petroleum Facilities Guard units, giving the eastern region’s powerful military chief control of both shipping terminals and oil fields in Libya’s main producing areas.

The Seadelta had been loading crude from onshore storage tanks before being interrupted, said Delaab, who helps organize oil movements at Ras Lanuf, Libya’s third-largest oil port. The vessel arrived there early Sunday from Trieste, Italy, according to tanker tracking data compiled by Bloomberg. Both the Seadelta and Syra were navigating off the Libyan coast as of Sunday evening local time, according to the tracking data.

Libya, if it succeeds in shipping the Seadelta cargo from Ras Lanuf, will be selling into an oversupplied market in which crude is trading at about half its 2014 levels. The country holds Africa’s largest oil reserves and pumped 1.6 million barrels of crude a day before Qaddafi’s ouster. Production has tumbled since then to 260,000 barrels a day in August, according to data compiled by Bloomberg, and Libya now ranks as the second-smallest producer in the Organization of Petroleum Exporting Countries, after Gabon.

Harouge Oil pumped about 100,000 barrels a day through the end of 2014 but halted operations due to fighting in the country, Delaab said. The company has production rights to at least five oil fields around Ras Lanuf, according to its website.

http://www.bloomberg.com/news/articles/2016-09-18/libya-clashes-halt-first-oil-cargo-from-ras-lanuf-since-2014

Nigeria must get out of paying so-called cash calls to joint ventures with oil and gas companies to stand a chance of pulling its ailing economy out of recession, Finance Minister Kemi Adeosun said on Friday.

The minister said the Nigerian National Petroleum Corporation (NNPC) had spent 110 billion naira ($360 million) on cash calls this month, which dwarfed the country's 41 billion naira income from oil production over the same period.

NNPC also owes several billion in back debt to oil companies from unpaid cash calls, which oil worker unions say is stalling the creation of jobs and investment.

"We are already working to see how we can get out of the cash calls. And that is very fundamental to the economy," Adeosun told a press conference.

"We are working with the Ministry of Petroleum Resources and NNPC ... that's a long-term plan: To allow those joint ventures to borrow money that they need rather than taking money out of the federation account."

Sub-Saharan Africa's largest economy is trying to boost tax revenues and the non-oil income to fund a record $30 billion 2016 budget aimed at reviving the West African country that has been hit by lower oil prices.

Adeosun told Reuters in April the government was thinking of forcing the cash calls, which are for international and local joint venture partners, out of budget funding and into so-called modified carrier arrangements.

Modified carry agreements are loans provided by large international oil companies to the NNPC for investing in oil exploration and production projects.

http://www.reuters.com/article/nigeria-oil-idUSL8N1BS1U5

New York Attorney General Eric Schneiderman is investigating why Exxon Mobil Corp. hasn’t written down the value of its assets, two years into a pronounced crash in oil prices.

Mr. Schneiderman’s office, which has been probing Exxon’s past knowledge of the impact of climate change and how it could affect its future business, is also examining the company’s accounting practices, according to people familiar with the matter.

An Exxon spokesman declined to comment about the investigation by the Democratic attorney general but said Exxon follows all rules and regulations.

Since 2014, oil producers world-wide have been forced to recognize that wells they plan to drill in the future are worth $200 billion less than they once thought, according to consultancy Rystad Energy. Because the fall in prices means billions of barrels cannot be economically tapped, such revisions have become a staple of oil-patch earnings, helping to push losses to record levels in recent years.

Exxon hasn’t taken any write-downs—the only major oil producer not to do so—which has led some analysts to question its accounting practices.

The company has played down the criticism, saying it is extremely conservative in booking the value of new potential fields and wells. That reduces its exposure to write-downs if the assets later prove to be worth less than expected, it says.

Exxon’s ability to avoid write-downs—and potential losses that come with them—has been among the factors helping the company outperform rivals since prices began falling in mid-2014. Exxon shares have fallen by about half of the average of top peers  Chevron Corp., Royal Dutch Shell PLC, Total SA andBP PLC. Since 2014, those companies have booked more than $50 billion overall in write-downs and impairments.

Yet Exxon has lost money for six straight quarters in its U.S. drilling business. The company had to remove the equivalent of more than 900 million barrels of U.S. natural gas reserves from its books in 2015, an acknowledgment that wells on those properties cannot currently be economically drilled. When it agreed to purchase shale explorer XTO Energy Inc. in 2009 for $31 billion, natural gas sold for almost double what it does now.

For many producers, such losses in net income and reserves would make write-downs inevitable, but Exxon didn’t write down the overall value of its reserves. The lack of such a step at Exxon “raises serious questions of financial stewardship,” Paul Sankey, an oil analyst at Wolfe Research, wrote last month.

“It is impossible to believe that no assets have been impaired,” he said.

The process for booking oil and gas reserves, and recognizing when they fall, is separate from accounting for how the value of those reserves changes over time on a company balance sheet.

John Herrlin, an analyst at Société Générale, came to a different conclusion in an investor note last month, writing that about three fourths of Exxon’s reserves are from areas with producing wells, a factor that makes impairments less likely than in undeveloped areas.

Exxon Chief Executive Rex Tillerson told trade publication Energy Intelligence last year that the company has been able to avoid write-downs because it places a high burden on executives to ensure that projects can work at lower prices, and holds them accountable.

“We don’t do write-downs,” Mr. Tillerson told the publication. “We are not going to bail you out by writing it down. That is the message to our organization.”

Out of the 40 biggest publicly traded oil companies in the world, Exxon is the only one that hasn’t booked any impairments in the last 10 years, according to S&P Global Market Intelligence.

In 2013, the U.S. Securities and Exchange Commission asked Exxon why it hadn’t booked any impairments in the previous year, citing a speech Mr. Tillerson gave in June 2012 in which he said the company was making “no money” due to declining natural-gas prices.

Exxon’s response then mirrors its position now: That short-term price fluctuations aren’t enough to render worthless wells that would potentially be drilled over decades. Another key to the company’s assessment is the view that its assets will hold value when prices eventually rebound.

Natural gas rose substantially in 2013 after the SEC’s inquiry, but many oil executives and forecasters have said they expect prices to remain low for some time.

Last year, Exxon scrutinized its assets most at risk for impairment and found that future cash flows anticipated from its fields were “substantially” higher than the book value of the asset. Exxon “does not view temporarily low prices or margins as a trigger event for conducting impairment tests,” according to a company filing.

The company is known for its conservatism in recognizing the value of reserves, a practice that results in lower write-downs, said Sean Heinroth, a principal in the energy practice at management consultancy A.T. Kearney. Exxon is also known for rigidly interpreting regulations and sometimes pushing back against regulators if company leaders feel their practices follow the law, he said.

“I would have expected some write-downs, even to avoid being called out on it, on being the last company not to have write-downs,” he said.

Exxon has previously faced a lawsuit over its impairment practices. Plaintiffs including the Ohio state pension system alleged in a 2004 class-action suit that the company’s failure to impair its properties undercut shareholders of Mobil Corp. in the 1999 deal that combined the companies.

The suit alleged that Exxon should have seen write-downs of between $3 billion to $7 billion in the late 1990s, another period of historically low prices. It included an allegation from a former Exxon insider that the company “operated under an order” by former Chief Executive Lee Raymond that “no impairment would be recorded.”

Exxon denied the allegations. The lawsuit was dismissed because the statute of limitations on such claims had passed.

http://www.wsj.com/articles/exxons-accounting-practices-are-investigated-1474018381/

Oil producers in the North Sea were supposed to be among the first victims of OPEC’s battle for market share. Instead their high-cost, decades-old facilities are proving surprisingly resilient to the price slump.

Crude oil and condensate output is likely to continue rising in the U.K. North Sea until 2018 as projects that were sanctioned before crude’s plunge four years ago start up, according to estimates by industry consultant Wood Mackenzie Ltd. Even though production dips after that, output by the end of the decade will still be roughly equal to the 2015 level.

Since 2014, the Organization of Petroleum Exporting Countries has pumped without limits and allowed prices to plunge to 12-year lows to squeeze higher-cost rivals. While the strategy is expected to reduce non-OPEC output by 840,000 barrels a day this year, the battle is far from over. The unexpected stamina of areas like the North Sea, where operators have proved adept at keeping the taps open to keep cash flowing, is adding to the global glut and keeping prices lower for longer.

“Production has stayed resilient,” said Ian Thom, an Edinburgh-based senior research manager for U.K. upstream at Wood Mackenzie. “We saw a record number of dollars invested in the high-oil price environment,” and that is still delivering new production.

OPEC and the International Energy Agency have said they expect production from some countries to increase, deferring a return to balance in the market. OPEC, responsible for more than 40 percent of the world’s oil, said Sept. 12 it expectsproduction from outside the group will grow by 200,000 barrels a day next year, raising it from an earlier projection of a drop of 150,000 a day.

A day later, the IEA said it estimates supplies outside OPEC will rise by 380,000 barrels a day, rebounding from a sharp decline this year. Coupled with slowing demand, increasing output will delay the rebalancing of the market until the second half of next year, the Paris-based agency said. Only last month it predicted a return to equilibrium this year.

“There are pockets of resilience across the world,” IEA’s Executive Director Fatih Birol said in an interview in London. “Some companies were able to bring costs down substantially and this provides some resilience.”

Production of crude and condensate, a type of light oil, will top 1 million barrels a day in the U.K. North Sea this year, about 8 percent higher than last year, according to Wood Mackenzie. Output will reach 1.07 million barrels a day in 2017 and 1.11 million the next year before falling to about 956,000 barrels at the end of the decade.

Post-Soviet High

When oil prices started their decline in the middle of 2014, some countries found it easier and cheaper to keep the fields running instead of shutting them now and starting again later. In Russia, production has been running at a post-Soviet high all year, Energy Ministry data show. The plunge in the ruble has reduced costs, offsetting the decline in oil prices.

In Norway, companies have brought down costs and become more efficient. Output in Western Europe’s biggest producer has exceeded 2015 levels in six of this year’s first seven months, according to the Norwegian Petroleum Directorate. Efficiency gains and new field start-ups have helped the country beat the government’s own forecasts.

In the U.S. Gulf of Mexico, output is projected to reach a record high in 2017, according to the Energy Information Administration. However, narrowing profit margins have forced many operators to pull back on future exploration spending, and they are putting fewer rigs to use, according to the agency.

Losing Steam

With oil’s downturn now running into its third year, companies’ and producing countries around the world are seeing their balance sheets getting weaker. Drillers have been cutting investments in exploration, contributing to a drop in discoveries to the lowest in seven decades. This will affect supply at some point in the future and, potentially, prices.

If oil prices continue to be low “the general trend is high-cost areas will lose steam sooner or later,” Birol said.

For now, operators in the U.K.’s North Sea are seeking to weather the price slump by cutting costs and even collaborating in ways they never thought possible. Earlier this year, some including Royal Dutch Shell Plc started pooling spare parts and tools, and are even sharing plans on how to drill wells so they can work faster and cheaper.

Companies are “working on cost efficiency reductions which seems to be going fairly well” in the North Sea, said Philipp Chladek, a senior industry analyst for Bloomberg Intelligence in London. “But without new investments in exploration, you will see the effects on production levels in three to five years.”

http://www.bloomberg.com/news/articles/2016-09-16/against-all-odds-north-sea-proves-resilient-to-oil-price-slump

Ukraine has changed the charter of Naftogaz in violation of a deal with foreign creditors, in a move that could hold up a $500 million loan for vital gas purchases from Europe, the state-run energy firm said on Friday.

"These funds are essential for gas purchases that will allow Ukraine to get through the winter season in a stable manner," Naftogaz said in emailed comments.

The European Bank for Reconstruction and Development (EBRD) expressed concern on Friday after Naftogaz said the economy ministry transferred control of the company's gas transport arm last week, in violation of corporate governance principles.

The ministry did not immediately respond to a request for comment.

Last October, the government approved a plan to reform the corporate governance of Naftogaz in exchange for loans worth $800 million from the World Bank and the EBRD to buy gas from Europe for the winter.

Naftogaz said on Friday that the charter change imposed by the ministry violated the terms of the energy firm's loan agreement with the EBRD and could lead to a default on the debt.

The EBRD, which along with Ukraine's other Western backers has urged the authorities to prioritise the restructuring of the graft-ridden energy sector, said Naftogaz must stick to the terms of the deal.

"The EBRD is looking into this, if the development is confirmed, this is a very serious matter. We do expect that our partners (Naftogaz Ukraine) will honour their commitments and continue building Naftogaz into an example of corporate governance reform," an EBRD spokesman said.

Naftogaz, Ukraine's largest energy company, operates in every part of the gas sector, from production to transport to sales.

Since last December, Ukraine has not bought any gas from traditional supplier Russia, instead importing gas from Europe. Last year, Ukraine produced 19.9 billion cubic metres of gas and imported 16.5 bcm, including 10.3 bcm from Europe.

Naftogaz says charter change threatens gas purchases from Europe

Ukraine has changed the charter of Naftogaz in violation of a deal with foreign creditors, in a move that could hold up a $500 million loan for vital gas purchases from Europe, the state-run energy firm said on Friday.

"These funds are essential for gas purchases that will allow Ukraine to get through the winter season in a stable manner," Naftogaz said in emailed comments.

The European Bank for Reconstruction and Development (EBRD) expressed concern on Friday after Naftogaz said the economy ministry transferred control of the company's gas transport arm last week, in violation of corporate governance principles.

The ministry did not immediately respond to a request for comment.

Last October, the government approved a plan to reform the corporate governance of Naftogaz in exchange for loans worth $800 million from the World Bank and the EBRD to buy gas from Europe for the winter.

Naftogaz said on Friday that the charter change imposed by the ministry violated the terms of the energy firm's loan agreement with the EBRD and could lead to a default on the debt.

The EBRD, which along with Ukraine's other Western backers has urged the authorities to prioritise the restructuring of the graft-ridden energy sector, said Naftogaz must stick to the terms of the deal.

Naftogaz, Ukraine's largest energy company, operates in every part of the gas sector, from production to transport to sales.

Since last December, Ukraine has not bought any gas from traditional supplier Russia, instead importing gas from Europe. Last year, Ukraine produced 19.9 billion cubic metres of gas and imported 16.5 bcm, including 10.3 bcm from Europe.

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Attached Files

Russian gas exports via pipeline to Europe and Turkey in the year to date are up by 9.4%, or 10.3 Bcm, compared with the same period last year, state-controlled gas giant Gazprom said Friday, pointing to continued strong flows so far in September.

After a slump in exports in July, Gazprom's supplies to Europe and Turkey -- but not including the former Soviet Union countries -- recovered in August.

Supplies in the first eight months of 2016 were 10 Bcm higher than in the same period last year.

That implies year-on-year growth in the first half of September of 0.3 Bcm.

Gazprom's gas exports in the first six months of 2016 were up 10.6 Bcm year on year, so exports in the second half are still down year on year.

Gazprom's most recently stated target of total exports to Europe and Turkey in 2016 is 166-170 Bcm, though Miller, speaking in Moscow on June 30, said Gazprom's gas sales in Europe could even exceed that amount if the upcoming winter was cold and the sales dynamics seen earlier in the year persisted.

Gazprom -- while not giving absolute volumes -- broke out the year-on-year supply growth for some of its European customers.

Russian gas supplies to Germany rose by almost 28% year on year from January 1 to September 15, while exports to Austria were up 40% and to Denmark by a huge 222%.

"We continue to record strong demand for Russian gas in the countries along the route of the planned Nord Stream 2," Miller said.

"Nord Stream 2 is being developed in line with the schedule," he added.

Russian gas exports to the UK rose by 55%, to France by 27%, to Poland by 20%, to the Netherlands by nearly 92%, to Greece by 59% and to Macedonia by 20%.

Exports to the countries of the former Soviet Union are also up by 9.4% in the year to date compared with the same period of 2015.

TURKSTREAM, ITGI POSEIDON

With Europe remaining Gazprom's absolute key focus -- especially given the prospect of a large wave of US LNG headed for the continent -- Gazprom is also working quickly to realize new gas pipeline projects.

As well as Nord Stream 2, which still faces intense political opposition, Gazprom is making quick progress on the planned TurkStream line to Turkey.

This week, it was granted by Ankara the first permits for the offshore section of the pipeline in Turkish waters.

It followed the first permits earlier this month, which came just one week after a meeting between Miller and Turkish energy minister Berat Albayrak in Istanbul.

Gazprom has also now opted to build the TurkStream line -- which is expected to have two strings of 15.75 Bcm/year capacity -- right up to the Greek border.

From there it can link in with the once defunct, but now revived, ITGI Poseidon project to pipe Russian gas onward to Greece and Italy. Gazprom in February signed a memorandum of understanding in Rome with Edison and Greece's DEPA outlining the interest of the three parties in the route to Greece and Italy.

On Wednesday, Miller met with EDF CEO Jean-Bernard Levy in Paris where they discussed the creation of new routes for Russian gas exports to Europe "in light of the resumed TurkStream project."

Miller also met with Engie Chairman Gerard Mestrallet to discuss "ongoing and future cooperation", including joint efforts within the Nord Stream 2 project.

Engie was a member of the Nord Stream 2 operating consortium along with four other European partners until August when the companies dropped out of the JV because of Polish competition objections.

http://www.platts.com/latest-news/natural-gas/london/gazprom-export-volume-data-points-to-strong-natural-26547121

ConocoPhillips finds buyer for offshore block in Indonesia

Indonesian energy company Medco is reportedly on the verge of acquiring ConocoPhillips’ stake in the Natuna Sea offshore block in Indonesia.

ConocoPhillips operates the offshore South Natuna Sea Block B with a 40 percent stake. The area has three producing oil fields and 16 natural gas fields in various stages of development.

Reuters based its story on accounts of three people familiar to the matter, who did not wish to be identified. They reportedly said that Medco would announce the deal soon. No financial details were given.

When asked for a comment by Offshore Energy Today, a ConocoPhillips’ spokesperson said: “Unless formally announced by our company, ConocoPhillips does not comment on ongoing business development or commercial activities.”
To remind, ConocoPhillips has been working on asset sales, primarily deepwater fields in the U.S. Gulf of Mexico, but it also mentioned Indonesia in one of its previous quarterly reports.

The company is working to achieve a goal of $1 billion of proceeds from asset sales in 2016, aiming to use the obtained cash to service debt.

ConocoPhillips CEO has previously said the company’s aim is to reduce debt as it matures, adding that debt payment could be accelerated as assets sales progress.

As for the soon to be sold offshore block in Indonesia, natural gas production from it is sold under international sales agreements to Malaysia and Singapore, and liquefied petroleum gas is sold locally for domestic consumption.

http://www.offshoreenergytoday.com/report-conocophillips-finds-buyer-for-offshore-block-in-indonesia/

Recent development in the LNG market is expected to have a significant impact on both the construction of LNG carriers and the primary LNG trading routes, according to Douglas-Westwood (DW).

The LNG carrier market currently faces over-supply and a combination of low commodity prices and a reduction in imports from key consumers such as Japan (following the re-start of its nuclear power stations), has resulted in a substantial decline in charter rates for LNG carriers.

Rates have been pushed down to approximately US$25,000 a day, considerably below typical breakeven costs of $40,000, as DW notes that 36 carriers were delivered in 2015, and only four newbuilds having been ordered in 2016 so far.

However, this trend is expected to change over the 2017-2021 period, due predominantly to liquefaction projects expected onstream in Australasia and North America. The USA is forecast to increase its LNG export capacity from 11 mmtpa in 2016 to 77 mmtpa by 2021. In the World LNG Market Forecast Report 2017-2021, DW forecasts the delivery of over 150 units yet to be ordered over the 2017-2021 period, in addition to the current order book, in order to satisfy this additional supply.

DW forecasts the delivery of over 150 units yet to be ordered over the 2017-2021 period, in addition to the current order book, in order to satisfy this additional supply.

With the increase in U.S. LNG exports, DW expects the diversification of the primary trade routes for LNG transportation. The recent expansion of the Panama Canal also provides a means for vessels travelling to Asia and South America from the Gulf Coast to reduce their voyage times. This is ultimately expected to introduce greater competition to LNG trading routes, DW says.

http://www.lngworldnews.com/dw-new-developments-to-shake-up-lng-market/

The activity in U.S. oilfields inched up  with the number of drilling rigs looking for oil increasing by two in the last week. Those gains though were more than offset by the amount of natural gas-seeking rigs shrinking by three.

The oil rig count gains primarily came in Oklahoma. Texas’s Permian Basin saw two rigs added, but North Texas’ Barnett Shale losing two rigs negated those gains for the state, according to weekly data collected by the Baker Hughes oilfield services firm.

The total count of 506 rigs is up from an all-time low of 404 in May, according to Baker Hughes. Of the total, 416 of them are primarily drilling for oil. But the oil rig count is down 74 percent from its peak of 1,609 in October 2014, before oil prices began plummeting.

http://fuelfix.com/blog/2016/09/16/oil-rig-count-ticks-up-slightly/

Gasoline prices are set to jump across the eastern U.S. after a spill from the country’s largest fuel pipeline choked off supplies.

A leak in Alabama Sept. 9 shut the main gasoline pipeline delivering fuel from refineries along the Gulf Coast to 50 million Americans in states from Mississippi to New Jersey. Colonial Pipeline Co. said on Thursday it pushed back the estimate for a complete startup of its Line 1 to next week from this weekend, citing adverse weather conditions overnight that slowed the cleanup and repair.

Suppliers are moving gasoline and diesel by sea and sending trucks to distant terminals to bring fuel to consumers, but it won’t come close to the 1.3 million barrels a day that the shuttered line normally carries.

“The thing is that there is a time pressure. No one is exactly sure when the pipeline will be completely fixed,” Patricia Hemsworth, senior vice president at Paragon Global Markets in New York, said by message.

Colonial is delivering some gasoline through a pipe that typically carries jet fuel and diesel, though the company hasn’t said how much. The U.S. Environmental Protection Agency temporarily lifted requirements on fuel quality amid what it described as “extreme and unusual fuel supply circumstance,” and Georgia, Alabama and North Carolina governors lifted rules that limit how many hours fuel truckers can work.

Red Alert

North American fuel distributor Mansfield Oil Co. on Thursday urged its customers to take fuel-saving measures over the next week and place orders early as its supply distribution network was impacted from Mississippi to Maryland.

“Mansfield’s Supply and Logistics Teams are meeting daily and treating this situation with the same importance and urgency as a natural disaster and moving to Red Alert,” the company said in its online daily newsletter to customers.

Prices may rise as much as 15 cents a gallon over the next week in parts of the eastern U.S. due to the shutdown, Patrick DeHaan, an analyst with GasBuddy, said in a tweet.

“It’s likely to get worse before it gets any better,” he said by phone. “It’s really a race against the clock — will there be gasoline available to replenish those terminals before they draw down?”

Retailers in Nashville and Atlanta were required to sell summer-grade gasoline, which carries a lower vapor pressure than fuels used in the winter, through Thursday. The EPA is waiving the federal mandates to distribute the fuel with low volatility amid the regional shortages.

Gasoline futures jumped 6.87 cents a gallon Thursday and the premium of October contracts over November widened on concern that prompt supply at the delivery point for the New York Mercantile Exchange will become scarce. The eastern U.S. relies on imports, primarily from refineries in Texas and Louisiana, eastern Canada and Europe, to help meet demand.

“What is truly extraordinary and really the main barometer of this Colonial Pipeline disaster is the spread action,” Hemsworth said. “Right now logistics are limiting the supply at the futures contracts’ deliverable point. You realize how dependent we are on our infrastructure.”

https://www.energyvoice.com/oilandgas/119493/leak-biggest-us-gasoline-pipe-sparks-supplier-red-alert/

 Enbridge Inc. announced its purchase of Spectra Energy Corp. Enbridge currently operates 1,800 miles of large-diameter (24 inches or greater) natural gas pipelines in the United States. Before its acquisition of Spectra Energy, Enbridge was the 15th-largest holder of large-diameter U.S. natural gas pipeline miles (including co-owned pipeline), and Spectra ranked fourth in the nation with nearly 9,800 miles. Their newly combined pipeline holdings are still the fourth-largest overall.

Nearly 82% of large-diameter pipeline miles and 62% of all pipeline miles in the United States are owned by 10 companies. Kinder Morgan Inc., with 32,000 miles of large-diameter pipeline, has more than double the mileage of TransCanada Corporation, which acquired Columbia Pipeline Group in July 2015. The merger of Energy Transfer Equity LP (third-largest holder) and Williams Companies, Inc. (fifth-largest holder) that was recently canceled would have resulted in a large natural gas pipeline conglomerate ranked second to Kinder Morgan, which owns about 19% of all U.S. pipeline.

Most of the top-10 companies, which includes some large regional players, are common carrier pipelines regulated by the Federal Energy Regulatory Commission (FERC). The top five companies have national or international scale operations.

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