SAUDI SAID READY TO CUT OUTPUT IF IRAN AGREES TO FREEZE

Reuters Saudi-Iran sources: "three unidentified people familiar with the discussions"

Saudi Arabia and Iran Said to Have Ended Oil Talks in Vienna

@zerohedge

Maintenance at Algeria's Skikda LNG export facility has now been completed, with the first cargoes shipped out in the past week.

The two-month shutdown was partly to blame for a slump in exports of LNG to Spain in August, while Spanish gas demand was also lower.

The 4.7 million mt/year Skikda plant was closed for planned maintenance in mid-July, according to industry sources, with the final cargo before the shutdown loaded on July 11, data from Platts Analytics' Eclipse Energy showed.

The first LNG cargo to leave Skikda after the restart was aboard the Cheikh Bouamama, which took 45 million cu m of gas equivalent to the Fos Cavaou LNG import plant in southern France last weekend.

A second cargo loaded from Skikda aboard the Cheikh el Mokrani is taking 45 million cu m of gas equivalent to the Sagunto terminal in Spain and is expected to arrive Friday, according to Platts Analytics.

Skikda has been a steady supplier of LNG to Spain over the past 12 months, supplying close to 2 Bcm of gas equivalent to the Spanish market since September 1, 2015, according to Platts Analytics data.

That equates to around 15% of Spain's total LNG imports of 13.3 Bcm over the past year.

Algeria's other LNG export facility at Arzew supplied some 1.4 Bcm of gas equivalent to Spain in the period.

Although Algeria's LNG exports dipped in August due to the Skikda outage, they had been running at five-year highs in the month before the shutdown and exports so far in 2016 are on a level with volumes sold in 2015.

http://www.platts.com/latest-news/natural-gas/london/algerias-skikda-resumes-lng-exports-after-two-26552025

The oil industry may be ready to open its wallet after two years of slashing investments.

Companies will spend 2.5 percent more on capital expenditure next year than they did this year, the first yearly growth in such spending since 2014, BMI Research said in a Sept. 22 report. Spending will increase by another 7 percent to 14 percent in 2018. It will remain well below spending in 2014, before the worst oil crash in a generation caused firms to cut back on drilling and exploration to conserve cash, the researcher said.

BMI oil spending by region

North American independent producers, Asian state-run oil companies and Russian firms are prepared to boost investments next year, outweighing continued cuts from global oil majors such as Exxon Mobil Corp. and Total SA, BMI said, based on company guidance and its own estimates. Spending will increase to a total of $455 billion next year from $444 billion this year, BMI said.

“We expect global spending in the oil and gas sector will reach its nadir in 2016 , returning to growth in 2017,” Christopher Haines, BMI’s head of oil and gas research, said in the report. “For now, we see stronger growth in capital expenditure in 2018 , as better forecast oil prices are building confidence behind spending outlooks.”

BMI’s outlook is more optimistic than groups like the International Energy Agency, which said last week that the industry might cut spending in 2017 for a third year in a row as companies continue to grapple with weaker finances. Oil prices still hover around $50 a barrel, less then half the level of the summer of 2014.

http://www.bloomberg.com/news/articles/2016-09-23/oil-firms-seen-spending-more-next-year-for-first-time-since-2014

Canada is sending a record amount of oil to the U.S., filling pipelines to capacity and threatening to push more crude into rail cars.

U.S. imports from its northern neighbor jumped 17 percent to 3.46 million barrels a day last week, the U.S. Energy Information Administration said Wednesday in a preliminary report. That’s the most since the agency began collecting such data in 2010. Exports have surged as Alberta recovers from wildfires that disrupted supplies earlier this year.

Supplies from the oil sands are piling up as producers bring back output and projects that had been delayed by the fires come online. The glut highlights Canada’s dependence on the U.S. market after TransCanada Corp.’s seven-year struggle to get approval for the Keystone XL link to the Gulf of Mexico failed while its proposed Energy East line to the Atlantic Coast faces mounting opposition in Canada. The stress on existing lines means more crude will be hauled by rail at higher costs and the discount on Canadian crude will likely widen.

“As volumes continue to build, so will the pressure on the constrained pipelines system,” Kevin Birn, a director at IHS Energy in Calgary, said by e-mail Wednesday. “At some point in the coming months those volumes could very well overtake available capacity and increased movements of rail should be expected.”

Pipeline Capacity

Enbridge Inc.’s mainline system, the most important conduit for shipping Canadian crude into the U.S., has been running above its 2.4 million-barrel-a-day capacity and was full in August, according to Genscape Inc. analyst Ryan Saxton. Other lines including Spectra Energy’s Express and TransCanada’s Keystone were about 89 percent full last month.

Western Canadian Select heavy crude is trading at a discount of $14.30 a barrel to West Texas Intermediate, according to data compiled by Bloomberg. WTI for November delivery advanced 98 cents to settle at $46.32 a barrel on the New York Mercantile Exchange on Thursday. The U.S. benchmark is down almost 60 percent from its 2014 peak.

The discount on Canadian crude could expand to a one-year high of $16 a barrel by year end as a bigger price spread will be needed to encourage the use of rail, a more expensive method of shipment, said Eric Peterson, research chief at Denver-based ARB Midstream LLC, an oil transport investor.

Crude by Rail

Canadian crude-by-rail exports rose to a six-month high of 109,000 barrels a day in April before declining after wildfires took about 1 million barrels a day of production off the market, National Energy Board data show.

While Canada’s conventional oil production is declining, oil-sands output continues to grow as projects initiated before the 2014 oil rout are completed. Companies including Cenovus Energy Inc. and Canadian Natural Resources Ltd. are set to add about 390,000 barrels a day of capacity by the end of next year, according to company statements and JuneWarren-Nickle’s Energy Group’s Summer 2016 Oil Sands Quarterly.

Crude output is expected to rise about 5 percent to more than 4 million barrels a day in 2017, above the country’s pipeline export capacity, according to the Canadian Association of Petroleum Producers.

As getting approval for pipelines at home has become increasingly difficult, Enbridge and TransCanada have sought deals south of the border to expand. Enbridge agreed to pay $28 billion for Houston-based Spectra Energy Corp. and TransCanada is buying Columbia Pipeline Group Inc., also based in Houston, for $10.2 billion.

“Canada is stuck with its main outlet being the U.S.,” Bloomberg Intelligence Analyst Gurpal Dosanjh said in a phone interview in New York. “This will stay in the considerable future while Canadian production grows.”

http://www.bloomberg.com/news/articles/2016-09-22/heavy-canadian-crude-set-to-weaken-as-supply-exceeds-pipe-space

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Aboriginal tribes from Canada and the northern United States signed a treaty on Thursday to jointly fight proposals to build more pipelines to carry crude from Alberta's oil sands, saying further development would damage the environment.

The move came as Native American tribes on Thursday took their fight to Washington to stop development of the $3.7 billion Dakota Access oil pipeline, which would cross federally managed and private lands in North Dakota, South Dakota, Iowa and Illinois.

Last week the U.S. Justice Department intervened to delay construction of the pipeline in North Dakota.

The Treaty Alliance Against Tar Sands Expansion was signed by 50 aboriginal groups in North America, who also plan to oppose tanker and rail projects in both countries, they said in a statement.

Targets include projects proposed by Kinder Morgan Inc, TransCanada Corp and Enbridge Inc.

While aboriginal groups have long opposed oil sands development, the treaty signals a more coordinated approach to fight proposals.

Among the treaty's signatories is the Standing Rock Sioux tribe who opposes the Dakota pipeline.

"What this treaty means is that from Quebec, we will work with allies in (British Columbia) to make sure that the Kinder Morgan pipeline does not pass," Kanesatake Grand Chief Serge Simon said in the statement.

"And we will also work with our tribal allies in Minnesota as they take on Enbridge's Line 3 expansion, and we know they'll help us do the same against Energy East," he said, referring to TransCanada's plan to carry 1.1 million barrels of crude per day from Alberta to Canada's East Coast.

The statement did not specify what actions the groups would take to stop development.

The Canadian Energy Pipeline Association, whose members include the targeted companies, said in a statement that the industry would listen to aboriginal concerns.

"The fact remains there is a critical need for pipelines in Canada," the association said, noting that they are the safest and most environmentally friendly way to move oil and gas.

Canada is assessing oil pipeline proposals as the country's energy-rich province Alberta reels from a crash in prices, partly due to insufficient means of moving oil to lucrative international markets.

http://www.reuters.com/article/us-canada-pipeline-aboriginal-idUSKCN11S2HS

Mexico's state-owned Pemex should delay the December 5 auction for its deepwater Trion block because the current terms could deter interest from any potential farm-in partners, a former US State Department energy adviser said Thursday.

David Goldwyn, president of Goldwyn Global Strategies and former special envoy for energy under President Barack Obama, said Pemex's proposed Trion terms put too much risk on the private partners.

"It's better to have a delay than a failure," Goldwyn said. "It's a disappointment, but it's an example of where pushing Pemex and bringing them into the reform full speed is really going to be critical."

Goldwyn made the comments during the Wilson Center's North American Energy Forum in Washington.

"Trion is an appetizing field, but I think it's the terms that are not right," he said. "The culture of trusting the private market, the culture of opening up and operating like a real company has not yet set in at Pemex." The Trion block in the Perdido Fold Belt sits close to the maritime border with the US in the Gulf of Mexico and has certified proven, probable and possible reserves of 480 million barrels of light crude, with water depths of 2,200-2,500 meters (7,200-8,200 feet), according to Pemex.

Under the farm-in terms, Pemex will receive $450 million for work it has already done in exploration, plus up to a 45% share in the project.

Ten companies have applied to bid, but some watchers have doubts about how many of them will actually submit bids.

There was no talk of delaying the Trion auction when Mexico's National Hydrocarbons Commission met Thursday. The regulators gave Pemex an additional week to respond to 100 questions submitted by prospective partners.

Apart from the Trion terms, Goldwyn praised Mexico's energy reforms and said he expects success when it auctions 10 deepwater blocks in the Gulf of Mexico, also set for December 5.

"I really want the farm-outs to go well because the success of the reform will largely be judged by whether Mexico can reverse declines, produce more and generate revenues," Goldwyn said. "To some extent, the near-term opportunity is all in the farm-outs."

http://www.platts.com/latest-news/oil/washington/mexicos-pemex-urged-to-delay-trion-auction-to-27674136?hootpostid=f55248b3ab0686f987853d630f87edd2

Sinoenergy has committed to spend another C$500 million ($380 million) to support operations of Alberta-based light oil, natural gas and NGLs producer Long Run Exploration, the Canadian government said Thursday.

The investment will be spread over the next two years and came after an early September visit to China by Canadian Prime Minister Justin Trudeau, the statement said.

Four commercial deals were signed in Ottawa Thursday as a follow-up to the visit, it added, with Sinoenergy and Long Run being one of them. The other three deals relate to non-hydrocarbon industries.

Sinoenergy's commitment to inject fresh capital into Long Run comes on the back of a C$780 million offer it made in February to acquire 100% interest in Long Run.

The deal, which closed on June 29, was driven primarily by Long Run's inability to generate sufficient cash flow and develop its assets given the low oil price environment, Long Run said then.

With a land position of over 600,000 net acres at Peace River, Redwater and Deep Basin in Western Canada, Long Run's light oil, NGL and natural gas production in first-quarter 2016 was 27,775 b/d of oil equivalent, compared with 35,602 boe/d in the same quarter the prior year, information posted on the company website said.

A Long Run official declined to comment on Thursday's announcement, but said that production is still underway at its assets.

"Given the continuing low oil prices, shrinking netbacks and limited pipeline access, the future of several Canadian juniors including Long Run is at risk," said Paul Pasco, an independent analyst and until recently an upstream analyst with Wood Mackenzie.

"Although this may not be the best time for international companies to invest in debt-laden Canadian producers, the Sinoenergy deal looks like an exception. Long Run has some good assets that will need capital to be monetized."

In their efforts to shed debt and emerge as a leaner producer with low operating costs, the way forward for smaller Canadian producers will be mergers, Pasco said.

"We have seen several transactions this year related to the sale of midstream assets by juniors and that will likely increase further. But it will be a challenge to sell upstream oil sands assets as there is still a mismatch between the buyer and seller expectations," Pasco said.

Sinoenergy would have carried out its due diligence before committing those dollars, said Gary Leach, president of the Explorers and Producers Association of Canada.

"A WTI $45/b oil price could trigger investment in Western Canada's light oil plays," Leach said.

http://www.platts.com/latest-news/natural-gas/calgary/chinas-sinoenergy-to-invest-c500-mil-in-canadas-27674130?hootpostid=6b3e01e90eef8093941213822607fbbd

Canacol Energy Ltd is pleased to provide a revised capital plan for 2016. The new capital plan accelerates the Corporation's natural gas opportunities in Colombia with three new gas wells. In addition, one new oil well will be drilled over the remainder of 2016. The revised 2016 capital plan has increased by $34 million, from $58 million to $92 million. In August, Canacol raised $35 million from long term strategic investors including follow-on investment from the Corporation's largest shareholder, Cavengas Holdings S.R.L. to accelerate gas drilling.

Despite significant volatility in global oil prices, the Corporation anticipates near record EBITDAX of approximately $135 million for 2016. Canacol forecasts average realized gas sales pricing of $5.60 per thousand standard cubic feet ('mscf') with a netback of $4.56/mcf, representing an estimated 81% netback margin. The Corporation's fixed price gas contracts mitigate impact from oil volatility with approximately 86% of 2016 corporate production insensitive to world oil prices. The Corporation continues to reduce costs with an estimated 40% reduction in general & administrative expenses for the year. Canacol estimates oil and gas sales before royalty between 16,000 to 17,000 barrels of oil equivalent per day ('boepd') for 2016 and third quarter oil and gas sales before royalty of approximately 18,200 boepd.

Over the past three years, the Corporation has made four gas discoveries and added 302 BCF in 2P reserves on the Esperanza and VIM 5 E&P blocks located in the Lower Magdalena Basin, Colombia. Canacol recently added a second rig to the two blocks. The objectives of the expanded gas drilling program are to 1) target management's estimate of more than 100 billion cubic feet ('BCF') of new potential recoverable resource in 2016 to secure new gas sales contracts, and 2) increase the productive capacity of the Corporation's gas assets to more than 190 million cubic feet per day ('MMcf/d') in anticipation of new sales contracts. Canacol has a large inventory of prospects and leads targeting 2.4 - 2.8 trillion cubic feet ('TCF') of unrisked mean estimate resource potential. The Corporation's gas resource capture strategy remains balanced for the remainder of 2016 with two gas exploration wells and two gas development wells.Trombon-1 gas exploration well: Esperanza E&P contract - Lower Magdalena Basin, Colombia, 100% working interest

Offset to the Nispero-1 gas discovery, the Corporation spud Trombon-1 on September 13, 2016. Canacol anticipates the well will take five to six weeks to drill and flow test. In late August 2016, Nispero-1 exploration well tested 28 MMcf/d of dry gas with no water. The well encountered 79 feet measured depth (55 feet true vertical depth) of net gas pay with average porosity of 17% within the primary Cienaga de Oro ('CDO') reservoir sandstones. With success at Nispero, the Corporation spud Trombon-1 from Nispero's drilling platform. Trombon-1 exploration well is targeting the same CDO reservoir interval tested in the offsetting Nispero-1 well, but in a distinct and isolated fault block located approximately 2 kilometers south of the Nispero discovery. Management estimates Trombon-1 may contain 40 BCF of potential recoverable resource.

Nelson-6 gas exploration well: Esperanza E&P contract - Lower Magdalena Basin, Colombia, 100% working interest

The Corporation plans to spud Nelson-6 in October 2016. The well may provide the potential to book reserves against by-passed pay within the shallow Porquero sandstone reservoirs in the Nelson gas field. As of December 31, 2015, Nelson gas field had 2P reserves of 209 BCF associated with the CDO reservoir with four straight successful wells drilled into the field. Management estimates Nelson-6 may contain 31 BCF of potential recoverable resource.

Nelson-8 gas development well: Esperanza E&P contract - Lower Magdalena Basin, Colombia, 100% working interest

The Corporation plans to spud Nelson-8 in November 2016. The well offers the opportunity to reclassify reserves and an additional 8 - 12 MMcf/d of productive capacity. The well is targeting the CDO reservoir sandstones in the Nelson gas field.

Starting in late September 2016, the Corporation plans to workover four Nelson gas wells. The objective is to extend each well's productive life and optimize reserve recovery. The Corporation also plans to upgrade the Jobo facility and Nispero-Jobo flow line.

Clarinete-3 gas development well: VIM-5 E&P contract - Lower Magdalena Basin, Colombia, 100% working interest

The Corporation plans to spud Clarinete-3 in the fourth quarter of 2016. The well may provide the potential to reclassify reserves and additional 10 - 12 MMcf/d of productive capacity. Clarinete-3 well is targeting the CDO reservoir sandstones which is productive in both the Clarinete and Nelson gas fields. As of December 31, 2015, Clarinete had 2P reserves of 163 BCF with two straight successful wells drilled into the field.

Mono Capuchino-1 oil exploration well: VMM-2 E&P contract - Middle Magdalena Basin, Colombia, 67% working interest

Offset to the Mono Arana-1 oil discovery, the Corporation plans to spud Mono Capuchino-1 in October 2016. In January 2013, Mono Arana-1 exploration well tested approximately 600 barrels of oil per day ('bopd') from a 335 foot perforated interval in the La Luna Formation. With Mono Capuchino-1, the Corporation plans to further investigate the potential for this established play. Management estimates the Mono Capuchino-1 prospect may contain 9 million barrels ('MMbls') of potential recoverable resource.

http://www.oilvoice.com/n/Canacol-Energy-doubles-natural-gas-drilling-activity-in-Colombia/558c66f0c554.aspx?utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+OilvoiceHeadlines+%28OilVoice+Headlines%29

The biggest player in the Permian Basin, America's most coveted oil field, thinks rig counts in region are poised for explosive growth.

In an interview with Bloomberg, Pioneer Natural Resources Co. Chief Executive Scott Sheffield predicted that 100 oil rigs will be added in the area considered to be U.S. shale drillers' version of prime real estate over the next year. Bloomberg Intelligence Analysts Vincent Piazza and Daniel Krauser note that Pioneer has the highest gross production of any driller in the Spraberry and Wolfcamp formations in the Texan oil field.

The shale revolution sparked a frenzied rise in U.S. crude production that eventually drove oil prices to their lowest level in more than a decade earlier this year. While prices have since recovered, they've failed to sustainably hold above $50 per barrel — and any advances may continue to be capped if drillers boost activity in the productive Permian Basin.

Rig count data from Baker Hughes shows the number of all types of active rigs in the Permian Basin — which spans from West Texas into a portion of New Mexico — stands at 202 as of Sept. 16, with 416 active oil rigs across the U.S.

Adding a rig in the Permian, he warned, results in an outsized boost to U.S. oil production four to six months down the road — meaning headline rig count figures wouldn't necessarily tell the full story on where aggregate production is heading.

At a conference on Wednesday, Sheffield said he sees output in the region "really taking off" in the first half of next year, with aggregate U.S. production beginning to grow again around the end of 2017 or the following year.

The Permian region can grow production by 300,000 barrels per day, per year, according to Sheffield.

The decline in rig counts has been the biggest contributor to the weakness in U.S. business investment since crude prices began to collapse in the middle of 2014. During Wednesday's press conference following the Federal Reserve's announcement, Chair Janet Yellen said drilling was "now showing signs of stabilizing."

http://www.bloomberg.com/news/articles/2016-09-22/the-top-permian-oil-producer-says-rig-counts-in-the-region-are-going-to-soar

A.P. Moller-Maersk (MAERSKb.CO) is in talks to buy a portfolio of North Sea assets from Royal Dutch Shell as the Danish group considers adding scale to its oil and gas business ahead of a planned spin off, banking sources said.

Maersk announced on Thursday a major overhaul that will see it focus on its core transport and logistics businesses, while looking at options for its energy division within 24 months that could include a joint venture, merger or listing.

Maersk has said over the past year that it planned to invest several billions of dollars to expand its oil operations, although it is now likely to face bigger financial pressures given a rout in earnings from shipping, weak oil prices and the loss of a major oil contract in Qatar.

Maersk Oil has held talks in recent weeks about buying a large part of the North Sea portfolio that Shell is seeking to sell as part of a three-year, $30 billion divestment plan following its purchase of BG Group earlier this year, banking sources involved in the talks told Reuters.

The assets under discussion are valued at around $2 billion, they added.

Shell and Maersk Oil declined to comment.

Although the aging UK North Sea is considered a relatively costly oil region, Maersk - which already has assets there - believes it can reduce the costs of running Shell's fields as well as the costs of dismantling and cleaning up assets nearing the end of their production lives, the sources said.

Explaining Maersk's options for its energy business, one source with knowledge of the process said: "They could look to bulk it up potentially with merger combinations before an exit – the key is to make it attractive to get the value they want."

Maersk Oil is currently developing the Culzean gas field which is expected to start production in 2019 and which could supply up to 5 percent of Britain's gas demand.

The division produces around 500,000 barrels per day of oil and gas equivalent around the world, according to its website. Barclays analysts estimate Maersk Oil would currently have a market value of around $4.7 billion as a standalone business.

Maersk Oil has suffered a series of setbacks, first and foremost when Qatar chose not to extend its 25-year license to operate the giant Al Shaheen field. Its plans to develop a huge offshore field in Angola also stalled as it struggled to reduce costs.

In February, Maersk tumbled to a loss after writing down Maersk Oil's assets by $2.6 billion.

Still, many of the division's assets are considered attractive, including its stake in Norway's giant Johan Sverdrup oil field development.

"The energy-division is sort of cut off with a 'For sale' sign in the window," Sydbank analyst Morten Imsgard said.

"Maersk Oil is a small player in a larger context, so there are many players big enough to take in Maersk Oil. Drilling is relatively large, but its competitors are under extreme financial pressure, so Maersk is less likely to find a sell-off opportunity there."

http://www.reuters.com/article/us-maersk-restructuring-oil-idUSKCN11S1L9

Indian energy group Bharat Petroleum Corp Ltd is looking at buying more stakes in oil and gas assets that are already producing to speed up investment returns, the managing director of the company's exploration business told Reuters.

The state-run refiner had previously focused mainly on exploration assets overseas, where it has invested just over $1.5 billion.

But the company now also looks at fields that are already producing. In March, it bought a stake in Russian oilfields that are in production via its upstream subsidiary Bharat Petro Resources Ltd.

"That is why we looked at Russia," BPRL's managing director D. Rajkumar told Reuters in the sidelines of a news conference on Wednesday.

"That will ensure we have a balanced portfolio of assets from exploration, development to producing. So with all this, we will be in a self-sustaining place soon."

Pressure on oil companies to get a quick return on their investment has increased because of lower oil prices which have also hit the industry's capital spending plans.

Bharat Petroleum was the first Indian state refiner to venture into the upstream oil business when it bought minority stakes in Brazilian blocks in 2007.

In 2008, Bharat Petroleum invested in a gas block in Mozambique but the production has now been delayed to 2020-21 after liquefied natural gas (LNG) prices slumped.

The purchase of the Russian assets gives Bharat Petroleum a potential for immediate revenues and bridges the gap till 2021-22 when Mozambique gas production starts, Rajkumar said.

The company's chairman S. Varadarajan said it would also continue to look for exploration opportunities.

"There is a strategy to look at different markets and projects which are at different phases (of exploration and production) and that is why we did the Russian acquisition," Varadarajan said.

BPCL plans to invest 150 to 200 billion rupees ($2.25 billion to $3.00 billion) over the next five years in developing existing blocks, the company has said.

http://www.reuters.com/article/us-bpcl-oil-strategy-idUSKCN11S1CM

Gazprom said on Thursday it had discovered a new gas deposit during exploration at the Kirinskoye field in the Sea of Okhotsk near Russia's Sakhalin island.

The field is crucial for Gazprom's plans to raise liquefied gas production at its Sakhalin-2 plant on the island. It has not disclosed the reserves of the newly discovered deposit.

Shell, which also has a stake in the LNG plant, may also get a share in the Kirinskoye field as part of an asset swap deal with Gazprom, though the prospects for this are uncertain because of international sanctions for Russia's role in the Ukraine crisis. These bar Western companies from development of deep-sea gas deposits in Russia and from some oil fields as well.

In 2015, the United States restricted exports, re-exports and transfers of technology and equipment to the Yuzhno-Kirinskoye field, part of the wider Kirinskoye deposit.

Gazprom Deputy CEO Alexander Medvedev told the Reuters Russia Investment Summit last week that Gazprom had not yet chosen which assets it wanted to swap under its deal with Shell.

The Sakhalin-2 plant, which currently produces 10 million tonnes of LNG per year, is due to add another 5 million tonnes of LNG to allow Russia to come closer to its target of 5 percent of the global LNG market.

http://www.reuters.com/article/russia-gazprom-deposit-idUSL8N1BY2JX

Landowners in the Marcellus Shale drilling region are lobbying daily at the state Capitol in hopes of winning last-minute passage of a bill to prevent some gas drillers from reducing royalty payments through deductions.

They set up a table in the Rotunda within sight of the House Republican caucus meeting room to urge support for a bill that restricts what companies can deduct in post-production costs for compressing and transporting gas from the well to market.

The measure, supported by several Northeast region lawmakers, would buttress a 1979 state law that guarantees leaseholders receive at least 12.5 percent of the value of gas extracted.

The lobbying effort follows several years of complaints by landowners in Bradford, Susquehanna, Wyoming and Lycoming counties about the business practices of Chesapeake Energy LLC in using deductions to cut royalty payments.

“I am really concerned about a major injustice to the landowners of Pennsylvania,” Joe Moore, a Wyalusing landowner, said Tuesday.

He said his mother signed gas leases to allow drilling on 90 acres of property she owns but has not received royalty payments in some months recently because of the extent of company deductions.

Mr. Moore spoke of other landowners who report receiving no royalties and even notices saying they owe money to drilling companies.

He said state government is losing money, too, from reduced royalty payments for drilling on state forest land and gamelands.

County commissioners from the drilling region are expected to lobby on the bill next week. The National Association of Royalty Owners Pennsylvania Chapter is coordinating the lobbying.

Supporters face a challenge in making headway with a bill that has drawn opposition from the gas industry and lawmakers in drilling regions in western Pennsylvania. Supporters face the hurdle of winning passage of the bill in the House and Senate with limited days left in the 2015-16 legislative session.

“I’m hoping there will be a vote in the House,” said Rep. Sandra Majors, R-111, Bridgewater Twp., a bill co-sponsor.

The House Environmental Resources and Energy Committee voted in June to approve the royalty bill in recognition of the issues facing landowners, said Steven Miskin, spokesman for House Majority Leader Dave Reed, R-62, Indiana. However, many lawmakers have concerns about the bill’s impact on contract language, he said.

A royalty bill reached the House floor in the previous legislative session only to get bogged down with inconclusive debate over an amendment by a western Pennsylvania lawmaker to give landowners some remedies to pursue complaints about royalties.

http://thetimes-tribune.com/news/property-owners-lobby-for-royalty-bill-1.2093498

The Eagle Ford shale oil patch has seen brighter days. New well permits are down, production is low (down from its 2015 peak of 1.7 million b/d, to around 980,000 b/d this year) and producers are pulling out of the region to focus their efforts elsewhere.

Symbolic of the mood in the field, things were a little more subdued at the recent Hart Energy DUG Eagle Ford conference in San Antonio.

Many attendees were quick to notice the smaller scale of the conference this year.  Lower oil and gas prices meant a lighter presence and scaled-back events surrounding the conference, which was held in conjunction with the Midstream Texas conference. Major players and past year exhibitors like Baker Hughes and Halliburton were obviously missing from the smaller-than-usual exhibition space and at least one attendee compared this year to past years by lamenting the absence of magicians and open bar at an after-hours mixer.

Attendance this year was healthy, but still was a telling reminder of the current state of the Eagle Ford. Around 1,500 people were at the conference, a more than 45% decrease from last year.

“While that’s smaller than during the ‘boom,’ it’s not down as much as the decline in crude oil price from the top to the bottom, or the fall in the US rig count, so we’re feeling pretty good about it with the current market conditions,” said Greg Salerno, vice president of marketing for conference presenter Hart Energy.

Finding the bright spots in the darkness seemed to be a theme at this year’s conference.

Major operators focused their presentations on their cost-cutting prowess and efficiency milestones that they’ve achieved recently (including Chesapeake Energy’s recent record of drilling a well in eight days).

“Records today are the normal for the future,” said Jason Pigott, executive vice president of Chesapeake.

Christopher Heinson, the COO of Sanchez Energy, said the company has focused on optimizing returns in the Eagle Ford. He said the company has managed to cut per-well drilling costs from around $4.5 million to $3.5 million. They achieved this by “debundling” services and sourcing directly from providers.

All Eagle Ford operators who spoke mentioned technological advancements that have helped improve efficiencies such as automation, data management, longer horizontal reaches and other strategies that have allowed them to drill fewer wells, cheaply.

“Prices have made us work harder,” Heinson said. “It’s impressive given the environment.”

Despite the lower production numbers and languishing oil prices there is plenty of potential for the Eagle Ford basin and producers to remain optimistic.

“I’d like to think there are a few more Champagne bottles with corks ready to pop,” said Dale Kokoski, regional vice president at Marathon Oil.

He said that Marathon continues to work in the Eagle Ford but has shifted from “high-growth mode” to “mid-cycle focused.”

Eagle Ford’s proximity to ports in Houston and Corpus Christi make the potential for cost-effective exports of both crude and natural gas an appealing possibility.

And there is still plenty of oil in the ground to get.

The University of Texas at Austin’s Bureau of Economic Geology released new, unpublished research on the field at the conference.

Scott Tinker, bureau director, and Svetlana Ikonnikova, an energy economist there, said the Eagle Ford holds an estimated 230 billion barrels of oil, though just 10 billion is recoverable. The researchers estimate that there also is 462 trillion cubic feet of natural gas, with 34 trillion cubic feet recoverable in the Eagle Ford.

Merger and acquisition opportunities also are attracting investments to the Eagle Ford as operators refocus on other basins, prune their portfolios or sell non-operating positions.

“These times won’t last,” said Mark Sooby, managing director of Bank of America Merrill Lynch. “If you are going to make a transaction, you want to make it in the down cycle and the down cycle is almost over.”

http://blogs.platts.com/2016/09/22/dont-be-fooled-numbers-eagle-ford-sleeping-giant/

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Attached Files

Acting through Alaska Gasline Development Corp. (AGDC), the State of Alaska, US, has signed a memorandum of understanding (MoU) with ConocoPhillips Alaska Inc. to create a joint venture (JV) company. The JV would market LNG from the Alaska LNG project to global LNG markets. It would also acquire North Slope gas, with the aim of bringing both LNG buyers and wellhead sellers together. In addition to this, AGDC and ConocoPhillips are planning to support other large North Slope producers in the JV’s formation.

AGDC claims that the MoU is part of the company’s broader plan to prepare the Alaska LNG project for a front end engineering development (FEED) decision. This plan includes the following elements:

-Structuring for federal and state tax efficiencies, including seeking a federal ruling on tax-exempt status.
-Advancing low cost financing and investor options.
-Engaging engineering, procurement and contracting (EPC) companies with the ability to shoulder a significant part of the construction risk.
-Bringing major North Slope producers on board to commit their gas to the planned JV, or tolling arrangements with the project.
-Positioning a JV to engage the LNG market to measure the extent and timing of demand.

AGDC claims that once the JV has been formed, sales and negotiations with global purchasers could start immediately.

The Chairman of AGDC, Dave Cruz, said: “The AGDC board welcomes the commercial progress made by AGDC under the leadership of President Meyer as evidenced by this agreement.”

The President of AGDC, Keith Meyer, said: “We are pleased to be working with ConocoPhillips, the leader in Alaskan LNG, in this important phase of Alaska’s major infrastructure project.”

Once established, it is also expected that the JV would initially focus on gathering LNG market information in support of its pursuit of gas and LNG sales as the project proceeds. The JV would also look to set out terms for the reliable and sufficient supply of gas to the project, resolving longstanding project gas supply assurance issues. The MoU expects that third parties or other producers could also join the JV, make gas available through wellhead sales, or even commit to tolling arrangements with the Alaska LNG project.

http://www.lngindustry.com/liquefaction/22092016/AGDC-and-ConocoPhillips-sign-MoU-to-create-LNG-joint-venture-3086/

Crude export payments have been halted to Gulf Keystone Petroleum and apparently other producers in Iraqi Kurdistan following a dispute between the regional and federal governments over exports.

http://www.upstreamonline.com/live/1444800/kurdistan-payments-in-abeyance?utm_source=twitterfeed&utm_medium=twitter

OPEC members Saudi Arabia and Iran, whose rivalry derailed an oil supply accord earlier this year, met in Vienna a week before the organization holds talks in Algeria.

The two oil producers, along with fellow OPEC member Qatar, met at the headquarters of the Organization of Petroleum Exporting Countries in Vienna, according to three people familiar with the matter. They were making preparations for informal discussions between energy ministers from OPEC and Russia in Algiers next week, the people said, asking not to be identified because the talks were private.

The face-to-face talks between Saudi Arabia and Iran, OPEC’s two leading members and fierce regional rivals, show diplomatic efforts to secure a meaningful deal in Algiers are still under way despite market skepticism. Prices have retreated this month amid concern there will be no serious commitment to constrain supply and all but two of 23 analysts surveyed by Bloomberg this week predict there will be no agreement next week.

"We may be starting see a change of attitude in Riyadh," said Michael Lynch, president of Strategic Energy & Economic Research in Winchester, Massachusetts. "A positive result to the talks in Algiers is looking more likely."

Doha Failure

OPEC’s last attempt to reach a deal, which also involved Russia, the largest non-OPEC producer, fell apart in Doha in mid-April when Saudi Arabia insisted at the last minute that Iran also had to freeze production. Iran had refused because it was just starting to revive exports following the end of international sanctions.

The discussions on Wednesday in Vienna marked the latest step in a flurry of shuttle diplomacy that has seen OPEC officials meet from Paris to Moscow and the Middle East. OPEC Secretary-General Mohammed Barkindo visited Qatar and Iran earlier this month to build consensus before the Algiers conference. President Vladimir Putin said on Sept. 2 that the producers can overcome their divisions to reach a deal.

With Iran having restored lost output since international sanctions were lifted in January, the chances of a deal now are higher than at any time since OPEC launched its strategy two years ago, according to Jamie Webster, a fellow at the Center on Global Energy Policy at Columbia University in New York.

Remaining Obstacles

The growing pressure from low oil prices may also give Saudi Arabia, which has depleted its cash reserves to cover a budget deficit, an incentive to compromise, according to Abhishek Deshpande, chief energy analyst at Natixis SA in London. Still, a number of obstacles to securing an agreement remain, including tensions between Saudi Arabia and Iran as they continue to clash in proxy conflicts around the region from Syria to Yemen.

OPEC also remains locked in a contest for market share, both between members and with competitors outside the group like U.S. shale drillers, making a deal difficult. Some OPEC members such as Iran and Iraq aim to boost capacity, while de facto group leader Saudi Arabia is pumping at record levels to maintain its sales volumes.

The group is also reluctant to enter into a pact with Russia, which it doubts would deliver on any pledge to curb supply, according to Citigroup Inc.

http://www.bloomberg.com/news/articles/2016-09-21/saudi-arabia-said-to-meet-with-iran-for-oil-talks-before-algiers-itd76sc2

Argentina’s biggest oil company sees the government removing production subsidies by the end of 2017, a step that may help lure investment as President Mauricio Macri tries to sell his vision of a more competitive economy.

The reforms, including talks with unions and contractors to help reduce costs, may attract some $5 billion to $10 billion in additional investments into the country’s oil and gas industry through the end of next year, YPF SA Chairman Miguel Angel Gutierrez said in an interview Wednesday at Bloomberg headquarters in New York. YPF has also had conversations with “middle-market" energy producers and equity firms as it seeks to pull in even more money, the chairman said.

“We need to demonstrate to the world that we are able to reduce costs." Gutierrez said. “With the right set of conditions, I think the investment will come."

While support for natural gas production should remain in place for another three years after it expires next year, the direction is clear, he said. “We are moving toward a market economy, no doubt. Our industry is not an exception."

Since taking office in December, Macri has devalued the national currency, ended foreign exchange restrictions and cut fuel subsidies, as he tries to revive Argentina’s moribund economy. State-owned YPF, meanwhile, is courting international corporations from Exxon Mobil Corp. to France’s Total SA, as it seeks help to develop the world’s second biggest shale oil and gas reserves.

Bowing to public opinion, YPF will “no doubt" remain controlled by the government, Gutierrez said. Nonetheless, market reforms are making the company and country more competitive, helping to attract investments from major energy companies, private equity firms and other backers, the chairman said.

Contract Negotiations

YPF is negotiating with unions and contractors to lower costs and the national and local governments have spent billions on new roads and other infrastructure in Vaca Muerta, the country’s vast, mostly untapped shale fields, Gutierrez said. The Buenos Aires-based company expects to lower drilling costs below $10 million a well by the end of this year, he said.

Macri ended a 15-year fight with bondholders, who had frozen the nation out of debt markets and trimmed a budget deficit that ballooned under past presidents. He also replaced YPF’s leadership this year, appointing Gutierrez, a former Telefonica SA and JPMorgan Chase & Co. executive, as chairman and Ricardo Darre as chief executive officer.

Vaca Muerta, Spanish for dead cow, has major deposits of both oil and gas. Covering an area the size of Belgium, it has become one of the world’s top shale plays and is considered key to restoring energy self-sufficiency in Argentina. Exxon has designated the formation as one of nine “key activity” areas in the Western Hemisphere.

YPF and Chevron Corp. are jointly developing shale there as well and BP Plc Chief Executive Officer Bob Dudley said on Sept. 14 that the U.K. producer sees “enormous potential" in the South American country.

Domestic Focus

While Vaca Muerta could eventually make Argentina a force on the global natural gas market, YPF’s focus for now remains on domestic use as well as sales to neighboring Bolivia and Chile, Gutierrez said. The country will likely remain a net importer of gas for at least the next five years.

Financial index provider MSCI Inc. said in June it would review Argentina, South America’s second-largest economy, for a possible upgrade to emerging market status. Argentina has been classified in the frontier category for the last seven years.

http://www.bloomberg.com/news/articles/2016-09-21/ypf-sees-argentina-reforms-drawing-billions-in-shale-investments

The Woodlands-based Smart Sand has filed paperwork with the Securities and Exchange Commission to go public. The company deals in sand for hydraulic fracturing, similar to what is pictured here in this AP file photo taken in the Marcellus Shale drilling region in July 2011.

Smart Sand, The Woodlands-based company that produces sand for hydraulic fracturing, plans to go public.

The company on Friday filed a registration statement with the Securities and Exchange Commission for an initial public offering, documents show.

Smart Sand operates two white sand processing sites in Wisconsin with a combined 344 million tons of "proven recoverable" sand reserves. In its SEC filing, the company said the two sites give it a large reserve base of sand with good access to Class I railroads.

Company officials also stated they could likely expand capacity of their larger processing facility to meet increased demand, citing projections that demand for frac sand will grow 23 percent per year through 2020.

In hydraulic fracturing, drillers shoot millions of gallons of water into horizontal wells to fracture the rock and free the hydrocarbons. To keep those fractures open, they add "proppant" — sand.

The company plans to raise up to $100 million during its IPO, according to Renaissance Capital.

http://www.chron.com/business/bizfeed/article/Texas-frac-sand-company-files-for-IPO-9234112.php

Russian oil output rose to a record ahead of talks on supply with Saudi Arabia and other members of the Organization of Petroleum Exporting Countries next week.

Output in September has been about 11.09 million barrels a day, the highest monthly average since the Soviet era, and reached about 11.18 million on Tuesday, Energy Ministry data show. Maintenance at Sakhalin Island in August capped output that month at just over 10.7 million barrels a day.

Russia will meet fellow oil producers in Algiers on Sept. 28 to discuss the market as the global crude surplus keeps prices below $50 a barrel. President Vladimir Putin said Sept. 1 he’s confident producers can overcome differences that derailed a proposal to freeze supply in April. Yet the start of new Russian fields shows the country is keen to squeeze as much revenue from its oil resources while it can.

“Russia keeps posting new record highs because neither Russia nor OPEC managed to agree upon freezing,” said Alexander Kornilov, an oil analyst at Aton LLC. “Production is profitable.”

The April agreement collapsed when Saudi Arabia insisted on the participation of Iran, which refused to join as it ramped up output following the removal of international sanctions. Putin has said he’d like Russia and OPEC to reach an accord on freezing supply while exempting Iran until it restores production to pre-sanctions levels.

Russia would be ready to cap output at the level of any month in the second half of this year, Energy Minister Alexander Novak said two weeks ago in China.

Russian oil producers have been able to weather the commodities rout as a weaker ruble reduced costs and taxes eased with lower crude prices. That has helped support output at existing projects as new fields come on line.

Putin on Wednesday oversaw the start of Siberia’s East Messoyakha oil field, run by Rosneft PJSC and Gazprom Neft PJSC. The deposit is expected to produce 577,000 tons of oil this year and reach a peak of 5.6 million tons, or 112,000 barrels a day, at the end of the decade, according to the Kremlin.

Rosneft, Russia’s largest oil producer, also plans to start its Siberian Suzun field in a month’s time, Chief Executive Officer Igor Sechin said Wednesday. The company expects output from the deposit to peak at 4.5 million tons of oil, or 90,000 barrels a day, in 2017, according to a presentation last month.

Russia’s second-largest producer, Lukoil PJSC, started test production at the Caspian Sea’s Filanovsky field at the beginning of August, pumping 20,000 barrels a day, it said Aug. 30. The company’s press service didn’t immediately comment on Filanovsky’s current output when contacted on Wednesday.

https://www.energyvoice.com/marketinfo/119936/russian-oil-output-surges-opec-talks-loom/

India’s imports of liquefied natural gas rose 34.6 percent in August as compared to the same month a year ago, according to the data from oil ministry’s Petroleum Planning and Analysis Cell (PPAC).

India imported 2,144 million metric standard cubic metres (mmscm) of LNG in August compared with 1,593 mmscm in the same month last year, PPAC said.

The country imported 10,348 mmscm of LNG in April-August, up by 25.7 percent as compared with the corresponding period of the previous year.

India’s LNG imports have been rising steadily this year boosted by low prices of the chilled fuel with the exception of July when the country’s LNG imports marked the first monthly decline as gas consumption remained flat and domestic gas production rose.

Costs of importing LNG into India have dropped sharply in 2016 after India’s largest LNG importer, Petronet signed a revised long-term contract with RasGas of Qatar.

The country’s prime minister Narendra Modi said last month that the world’s fourth-largest importer of the chilled fuel could save up to US$3 billion due to the renegotiated import deal.

India imports LNG via Petronet’s Dahej and Kochi LNG terminals, Shell’s Hazira plant, and the Dabhol terminal operated by Ratnagiri Gas and Power.

http://www.lngworldnews.com/india-boosts-lng-imports-in-august/

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U.S. crude oil refinery inputs averaged 16.6 million barrels per day during the week ending September 16, 2016, 143,000 barrels per day less than the previous week’s average. Refineries operated at 92.0% of their operable capacity last week. Gasoline production increased last week, averaging 10.1 million barrels per day. Distillate fuel production increased last week, averaging about 5.0 million barrels per day.

U.S. crude oil imports averaged 8.3 million barrels per day last week, up by 247,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged 8.1 million barrels per day, 9.0% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 569,000 barrels per day. Distillate fuel imports averaged 76,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 6.2 million barrels from the previous week. At 504.6 million barrels, U.S. crude oil inventories are at historically high levels for this time of year. Total motor gasoline inventories decreased by 3.2 million barrels last week, but are well above the upper limit of the average range. Both finished gasoline inventories and blending components inventories decreased last week. Distillate fuel inventories increased by 2.2 million barrels last week and are well above the upper limit of the average range for this time of year. Propane/propylene inventories rose 0.7 million barrels last week and are above the upper limit of the average range. Total commercial petroleum inventories decreased by 6.0 million barrels last week.

Total products supplied over the last four-week period averaged 20.3 million barrels per day, up by 3.0% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged over 9.5 million barrels per day, up by 4.1% from the same period last year. Distillate fuel product supplied averaged about 3.6 million barrels per day over the last four weeks, down by 5.9% from the same period last year. Jet fuel product supplied is up 8.1% compared to the same four-week period last year.

Cushing up 500,000 bbl

http://ir.eia.gov/wpsr/wpsrsummary.pdf

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                                                                       Last Week    Week before      Last year

Domestic Production '000................. 8,512                8,493              9,136
Alaska ............................................    464                   458                  488
Lower 48 ........................................ 8,048               8,035              8,648
Exports ...........................................     588                  418                 477

http://ir.eia.gov/wpsr/overview.pdf

Saudi Aramco plans to shut two refineries towards the end of this year for scheduled maintenance, four sources close to the matter said, which could free up more of the state oil company’s crude for export.

Saudi Aramco has scheduled maintenance at its refinery in Yanbu and its largest refinery in Ras Tanura in November and December, the sources said.

Each shutdown could add 4 million to 8 million barrels of crude into global markets, depending on the extent of the shutdowns and their duration, according to Reuters’ calculations.

A rise in Saudi crude exports on top of a recovery in Nigerian production would add to global supply which is likely to weigh on oil prices and push a potential market rebalancing further out into 2017.

“It’s bullish for refining margins but very bearish for crude,” said an oil analyst who declined to be named due to company policy.

“Saudi crude exports will climb.” Saudi Arabia’s fuel output will also fall during the maintenance, in particular middle distillates such as diesel and jet fuel, helping to tighten the market during peak winter demand in the northern hemisphere.

Yanbu Aramco Sinopec Refining Co (Yasref), owned 62.5 per cent by Aramco and the rest by China’s Sinopec, is expected to shut its 400,000 barrel-per-day refinery complex for maintenance in November, the sources said.

This could last for 10-15 days, one of the sources said.

Separately, Saudi Aramco plans to carry out maintenance at the Ras Tanura refinery in December for 20-25 days, which may involve only the 325,000-bpd crude distillation unit (CDU), the sources added.

Saudi Aramco and Sinopec do not comment on refinery operations.

Saudi Aramco could export more Arab Light and Arab Heavy crude during the refinery shutdowns, trade sources said, although the producer also has the option to move excess barrels into storage if supply exceeds demand.

http://gulfnews.com/business/sectors/markets/saudi-aramco-plans-maintenance-at-two-refineries-in-nov-dec-1.1898791

Venezuela's state oil company PDVSA has awarded $3.2 billion in contracts to drill wells in the Orinoco Belt with the aim of increasing production by 250,000 barrels per day in the next 30 months, the Caracas-based company said in a statement on Wednesday.

Schlumberger NV, Oklahoma-based contractor Horizontal Well Drillers and Venezuelan contractor Y&V won contracts to service three joint ventures between PDVSA [PDVSA.UL] and foreign partners.

http://www.reuters.com/article/us-venezuela-pdvsa-contract-idUSKCN11R1NY

TransCanada Corp. and Alberta natural gas producers agree they need a new pipeline deal to fend off rival U.S. supplies. The challenge is to agree on how long it should last.

The pipeline operator is striving to get commitments for decade-long contracts to ship fuel east to Central Canada in exchange for lower tolls. The idea is to help Canadian supplies remain competitive even as two rival pipelines are set to link giant shale plays in the eastern U.S. to markets in Ontario and Quebec. But the length of the contracts is becoming a point of contention.

“What’s really got some of these guys concerned is how long you have to commit to,” Jeff Tonken, chief executive officer of gas producer Birchcliff Energy Ltd., said in a phone interview. While TransCanada aims to start a formal bidding process in October to sign up producers, Tonken said it may take until the end of the year before there’s enough support to move ahead.

Holding on to clients in Canada’s two most populous provinces is becoming critical for western gas producers as the U.S. meets more of its own demand, while projects to liquefy and export gas from the Pacific Coast struggle for approval. Competition is set to become tighter with the proposed Rover and Nexus pipelines from the Marcellus and Utica shales.

Long Discussions

The mainline ships a significant amount of Canada’s gas to market. The country produced about 15 billion cubic feet a day last year, and the mainline carried about 3 billion of that -- or one-fifth -- from the West. It was the largest single source of adjusted earnings in TransCanada’s gas pipelines business in the second quarter. The company’s stock has gained 37 percent this year and is hovering near a record high after it made a big bet on gas with the purchase of Columbia Pipeline Group Inc. for $10.2 billion, which closed in July.

TransCanada has proposed tolls 40 to 50 percent cheaper than the current rates for new firm, 10-year contracts, to as low as 82 cents a gigajoule if it can secure 2 billion cubic feet a day of commitments to ship from Empress, Alberta, to the Dawn hub in Ontario.

Currently, local distribution companies in Ontario and Quebec and gas marketers hold contracts to move gas east from Western Canada, many of which expire in 2022. Those distributors are increasingly looking to buy gas at the Dawn hub near Sarnia, Ontario, and elsewhere in the province, as more supply options emerge.

Currency Risk

The requirement to sign up for a decade means producers would need to line up buyers for the fuel and would face fluctuating currency exchange rates affecting the viability of the tolls, said Tonken. Tonken is on a sub-committee of the Canadian Association of Petroleum Producers in talks with TransCanada.

TransCanada is optimistic it can overcome the producers’ concerns in time to start a so-called open season for the tolls next month, said Steve Clark, the company’s senior vice-president of Canadian & Eastern U.S. Pipelines. That timeline is necessary for regulators to approve the tolls so they can take effect in November, 2017, in line with the shipping calendar, he said. Competitors of the Canadian producers are prepared to sign up for terms exceeding 10 years on other pipelines, he said.

“That’s the nature of the pipeline business these days,” Clark said.

There’s the added question of whether the 82-cent rate will be low enough to hold onto Central Canada.

Price Clarity

“It’s also not clear how much U.S. Northeast producers would be prepared to undercut Canadian producers to capture the market,” said Randy Ollenberger, an analyst at BMO Capital Markets in Calgary.

Gas producer Peyto Exploration & Development Corp. has also raised the issue of a spate of outages over the last year-and-a-half on TransCanada’s Alberta system while the operator was conducting maintenance. The work hindered shipments and cost producers about C$25 million for firm transportation service they weren’t able to access, according to an estimate from Peyto. Darren Gee, Peyto’s chief executive officer, said that type of “unpredictable risk” is preventing him from signing up for a long-term mainline contract.

TransCanada’s Clark said the Alberta system work is wrapping up and the company is confident it will be able to make the necessary firm transportation service available. He declined to comment on Peyto’s estimate on the cost to producers for the work.

Consultants hired by TransCanada have shown that the 82-cent rate would allow Canadian gas producers to compete with U.S. rivals, he said.

“Given we don’t have to build anything here, we just have to get a rate approved, we think we have a timing advantage,” Clark said. “But we can’t wait forever. We need to move quickly.”

http://www.bloomberg.com/news/articles/2016-09-21/transcanada-plan-to-vie-with-u-s-gas-stirs-fear-of-10-year-toll

LNG powerhouse Qatar is pushing its massive export facilities at beyond capacity production levels as it moves to protect market share from Australia and other upstarts amid low prices, in a move analysts have described as similar to Saudi Arabia’s tactics in oil.

The increased output comes as Qatar, the world’s biggest LNG producer, revealed it would pursue a strategy to maintain its share of global production amid low prices. Last year, it renegotiated a key Indian contract that had left the buyer severely out of the money.

Analysts say the moves could further hit prices and Australian LNG projects struggling to ramp up in the low-priced environment, which recently caused Santos to announce it would hold back production from its Gladstone plant.

Qatar’s mantle as the world’s biggest LNG producer is under threat from $200 billion of new Australian projects approved over the past decade.

The investment is bringing on a wave of supply that has overtaken demand growth and is hitting prices that are already much lower than expected when the projects were committed to.

But instead of easing off production of uncontracted LNG, Qatar appears to be following a similar strategy to that of Saudi Arabia in oil by running full tilt.

Credit Suisse analysts say Qatar has the lowest cash costs in the world.

“Qatar again ran at over 100 per cent capacity in 2015, and has been talking in 2016 about considering ‘innovative marketing strategies to protect its market share’,” Credit Suisse co-head of global oil and gas research, David Hewitt, told The Australian.

“If that were to translate to lower prices to secure volume in the spot market, it would put additional pressure on other suppliers, including Australian projects, into the already fragile spot market.”

In the sheikdom’s latest economic outlook, released in June, Qatar revealed concerns about new LNG market entrants that was not visible in its previous reports.

“In a context of surplus shipping capacity and a looming glut in global LNG supplies, Qatar intends to consider and follow innovative marketing policies to protect its market share,” the country’s Ministry of Development Planning and Statistics said.

Neither the Ministry nor Qatar gas responded to requests from The Australian for more details on the policies.

Last year, Qatar exported a ­record 106.4 billion cubic metres of gas as LNG (77.1 million tonnes), stretching production beyond its capacity of 77 million tonnes.

According to the Platts news service, Qatar’s 2016 first-half ­production for this year was 3 per cent higher than for the same ­period last year, indicating this year could see another record.

Credit Suisse, citing industry sources, says only about 60 million tonnes of Qatar’s annual exports are contracted.

“It could clear the potential excess from 2018 onwards on its own,” the bank says of the coming global oversupply.

“That, however, looks unlikely, as Qatar has the lowest cash costs and could pursue the more recent policy of Saudi Arabia for oil.”

On top of producing flat out, Qatar’s state-owned RasGas last year agreed to cut the price of a contract with India’s Petronet LNG to $US6 to $US7 per MMBtu, up to 50 per cent lower than the $US12 to $US13 agreed earlier, according to Reuters news agency. Qatar also waived a $US1.5bn penalty for taking less LNG than agreed.

Wood Mackenzie analyst Saul Kavonic said the Petronet deal highlighted the risk that LNG contracts would need to be renegotiated, especially if oil prices (which LNG contracts are linked to) rose while spot LNG stayed low.

“If you see it with India, that’s one thing, but if you start to see it with the more traditional buyers, like Japan, South Korea, or even China, that could be more meaningful,” Mr Kavonic said.

“It’s a big risk out there in the market that is keeping some of the big LNG players awake at night.”

Australia produced about 25 million tonnes of LNG last year but is forecast to increase production to 85 million tonnes by the end of the decade as projects approved during the boom continue to ramp up.

While the returns will be low after development cost blowouts and lower-than-expected prices, most should generate cash at current spot prices of $US5 per MMBtu because of low operating costs.

The Santos-run Gladstone LNG project and Shell’s Queensland Curtis LNG projects are two of the higher-cost plants, with Credit Suisse-estimated cash costs of $US7.50 to $US8 per MMBtu.

http://www.theaustralian.com.au/business/mining-energy/lng-players-under-pump-as-qatar-goes-all-out-to-lift-output/news-story/da0b8054299532c0a0f89ad9c80765f9

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We’ve just hit a milestone worth mentioning. The price of natural gas as traded at the benchmark Henry Hub delivery point (in southern Louisiana) closed at over $3 per thousand cubic feet (Mcf) for two days.

It’s an important psychological barrier that gives traders (and drillers) hope for higher prices. However, before we begin popping the champagne corks here in the Marcellus/Utica, you should understand that there is no “the price” in natural gas.

Gas is traded at hundreds of locations along major gas pipelines. The venerable Henry Hub is important because it is the benchmark, setting prices that many gas contracts are tied to.

But the reality of natural gas prices for the Marcellus and Utica is one of low prices due to lack of pipeline capacity to move our oversupply to other markets. So while the price of gas trading at the Henry Hub yesterday closed at $3.08/Mcf (according to price experts Natural Gas Intelligence), the price of gas trading at the Tennessee Gas Pipeline Zone 5 300L in northeastern PA closed yesterday at $1.26/Mcf (NGI).

http://marcellusdrilling.com/2016/09/natgas-trades-above-3mcf-1st-time-in-1-yr-still-low-in-m-u/

Over 300 oil service workers in Norway went on a strike on Wednesday morning after mediation between the Norwegian Oil and Gas Association and the Norwegian Union of Industri Energi failed.

To remind, mediation over the collective oil service agreement between the employers’ organization in Norway and the workers’ union took place on Tuesday. The negotiations ended almost four hours past the original, midnight deadline but the agreement has not been reached.

The strike affects the following companies, Schlumberger Norge, Baker Hughes Norge, Halliburton Norge, Oceaneering, and Oceaneering Asset Integrity.

The walkout primarily affects environmental treatment of drilling waste, and could call a halt to some drilling operations, but it does not immediately affect oil and gas production on the NCS.

Industri Energi’s negotiator Ommund Stokka said the employers’ association did not show any willingness to meet the union’s demands. The union believes that by accepting the employers’ proposal, the gap between the operator / drilling / catering and oil service staff would increase dramatically.

The employers’ organization, on the other hand, said the union’s demands were unreasonably high. Karl Eirik Schjøtt-Pedersen, CEO of Norwegian Oil and Gas Association, said it was irresponsible to strike for a wage increase in a year when 40,000 people lost their jobs in the oil industry and while companies are still considering further downsizing.

The union secretary Einar Johannessen stated that at the beginning only a limited number of workers will participate but, if necessary, the strike will escalate unless the deal is reached.

Jan Hodneland, a chief negotiator at the Norwegian Oil and Gas Association, noted the strike is not showing solidarity to those who have lost their jobs.

http://www.offshoreenergytoday.com/oil-service-workers-go-on-strike-in-norway/

A new $24 billion Chinese refinery that’ll use as much crude oil as some of Asia’s biggest plants is set to take on rivals by helping make plastic bottles rather than fuel for cars.

Rongsheng Petrochemical Co. has cleared more than 10,000 acres of land in Zhoushan island to build a 400,000 barrel-per-day facility by 2018, and will double that capacity by 2020, said Shou Bochun, a general manager at the trading arm of the privately owned company. Once the plant in eastern China reaches it expanded size by the end of the decade, it would rank among the top refineries in Asia, rivaling those of India’s Reliance Industries Ltd. and South Korea’s SK Innovation Co.

Hangzhou-based Rongsheng plans to consume all of the plant’s output of naphtha, a key ingredient in the manufacture of petrochemicals, while minimizing production of diesel and fuels, Shou said. At maximum capacity, the refinery will be able to produce 10.4 million metric tons a year of aromatics including paraxylene and 2.8 million tons of ethylene, both of which are used to make plastics, according to a proposal posted on the website of the Zhoushan government.

The company’s ambition underlines China’s increasing appetite for petrochemicals, used to make everything from sportwear to soda bottles. That will also help drive oil demand in the world’s second-biggest consumer amid a global glut and weak prices. Chinese petrochemical makers will need 90 percent more crude oil in 2030 than last year, while diesel demand growth is entering “a 10-year plateau”, according to Li Zhenguang, a senior analyst at China Petroleum & Chemical Corp., known as Sinopec.

“It is chemicals really that is driving China’s oil-demand growth,” said Gordon Kwan, head of Asia oil and gas research at Nomura Holdings Inc. in Hong Kong. “Going forward, gasoline and chemicals will be very important when it comes to driving crude oil demand in China.”

The nation’s oil consumption will rise to 700 million tons in 2030, or 14 million barrels a day, from 540 million tons in 2015, according to Li at Sinopec, which is China’s biggest refiner. He estimated the petrochemical sector will account for 19 percent of the country’s crude demand by the end of the next decade from 13 percent last year, which suggests consumption by the industry will almost double to 133 million tons.

China imported 11.6 million tons of paraxylene last year from countries including South Korea, Japan, Taiwan and India, up 17 percent from a year earlier and compared with 3.5 million in 2010, customs data show. That’s about half of its requirements for the product, according to Shou.

Polyester T-shirts

The Zhoushan project by Rongsheng, a polyester fabric producer, may add a blow to other Asian refiners competing for the fast-growing Chinese petrochemical market amid a supply glut in the region. The Asian nation’s factories are forecast to make about 25 million tons of synthetic fibers this year, according to Salmon Aidan Lee, a Singapore-based consultant at Wood Mackenzie Ltd. That’s enough to produce 208 billion T-shirts.

“Not only will this private petrochemical plant take market share away from PetroChina and Sinopec, but it will also take away market share from South Korean refiners and other regional competition,” said Nomura’s Kwan.

Apart from Rongsheng’s 51 percent, privately owned Tongkun Group Co. and state-owned Juhua Group each control 20 percent of the project. Zhoushan Marine Comprehensive Development and Investment holds the remainder. The companies will fund the plant, estimated to cost about 160 billion yuan ($24 billion), by raising debt and selling equity, said Shou.

http://www.bloomberg.com/news/articles/2016-09-20/a-24-billion-china-refinery-bets-on-a-great-future-in-plastics

China's imports of liquefied natural gas grew 60.1 percent in August over the same month last year to 2.26 million tonnes, data from Chinese customs showed on Wednesday.

August imports of kerosene gained 21.3 percent on year to 320,000 tonnes, the data showed.

http://www.reuters.com/article/china-economy-trade-lng-idUSB9N1BO007

China's diesel exports rose 47.6 percent in August over the same year-ago level to 1.07 million tonnes, data from the Chinese customs showed on Wednesday.

Gasoline exports were up 44 percent on year to 670,000 tonnes while kerosene exports rose 16.8 percent to 1.13 million tonnes, the data showed.

http://www.reuters.com/article/china-diesel-exports-idUSB9N1BO008

Algeria is on track for more than 9 billion cubic meters a year additional gas output next year when three delayed projects in its south west come online, a source at state energy company Sonatrach said.

The third largest gas supplier to the Europe Union, Algeria has struggled in recent years to increase production of crude and natural gas because of low foreign investment to boost output at maturing fields and work new production.

For a year, European Union officials and energy firms have been pushing Algeria to adapt to more competitive markets, especially with the fall in crude prices, to attract the investment needed to pump more gas north again.

Three projects

Among the projects are Touat Gas set for February 2017 with an estimated output of 12.8 million cubic meters per day, Timimoun in March 2017 with 4.6 million cubic meters per day, and Reggane will provide 8 million cubic meters per day in June.

“The three projects will come online on time, the outcome will reinforce our position as a reliable gas exporter to Europe. No delays, the projects will be delivered in 2017,” the Sonatrach source told Reuters.

“Further in the south, we have found a huge potential of gas around the fields of Akabli and Tidikelt, in addition to Alrar’s project in the east that will deliver gas and oil,” the source said.

Dent in exports

A drop in European gas demand dented Algerian exports that were squeezed by slowing production at mature fields, low investment and s rapidly increasing domestic need for gas to generate power.

Still, Sonatrach has invested to stabilize and increase production at its large, mature fields and expects to bring five new gas fields online in the south of the country despite delays from state bureaucracy.

Gas output is expected to reach 141.3 bcm in 2017, 143.9 bcm in 2018, 150 bcm in 2019 and 165 bcm in 2020, according to a Sonatrach document.

In another advance, Algeria’s Tiguentourine gas plant resumed full production for the first time since a militant attack in 2013, after its third train came back online. The plant, operated with BP and Statoil with a full capacity of 9 billion cubic meters a year.

At its huge, mature Hassi R'mel field, Sonatrach has engaged in boosting operations to help bolster production.

Sonatrach is also due to recuperate by the end of 2017 important volumes of gas that have been injected in the past decades in Hassi Messaoud and its region.

Algeria is expected to export 50 billion cubic meters in 2016 to Europe, an increase of 15 per cent in comparison with 2015, according to Sonatrach.

Algeria is seen as a natural partner for the European Union as it looks to diversify energy supplies after the Ukraine conflict exposed the risks of relying too much on the bloc’s top gas supplier, Russia.

http://english.alarabiya.net/en/business/energy/2016/09/20/New-fields-to-boost-Algerian-gas-output-in-2017.html

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The American Petroleum Institute reported a 7.5 million barrel draw in U.S. crude oil supplies on Tuesday, instead of the build that many expected.

American crude inventories were slated to increase by 2.3 million barrels over the past week, according to a survey by Reuters, and 2.8 million barrels were expected to be added according to S&P Global Platts. Zero Hedge’s sources had anticipated an even bigger 3.25 million barrel build.

Gasoline supplies declined by 2.5 million barrels, surpassing forecasts of a 1.4 million barrel draw. Zero Hedge attributed the draw to the250,000-gallon leak in Helena, Alabama, which caused severe gasoline supply shortages along the East Coast. The pipeline’s holding company completed construction on a bypass line on Tuesday and told shippers to expect supplies starting tomorrow.

Distillate inventories rose by 1.4 million barrels, marking six weeks of consecutive increases.

Last week, EIA reported that U.S. crude oil inventories fell 600,000 barrels, after the biggest inventory draw of the century in the week prior, which was a 14.5 million barrel draw.

Tuesday’s API report will either be validated or discredited by the U.S. Energy Information Administration's official crude supplies report Wednesday morning.

Brent futures were down 0.30 percent or 14 cents at $45.80 a barrel one hour before the API report was released. Similarly, West Texas Intermediate futures were down by half a percent or 23 cents at $45.63 a barrel. Nearly 50 minutes after reporting, WTI was trading up 1.3% at $44.43 and Brent up 0.39% at $46.13. Gasoline was down 2.96% at 1.3788.

Zero Hedge noted that barrel prices are expected to remain “rangebound” until the Organization of Petroleum Exporting Countries’ unofficial meeting in Algiers next week, which many are hoping will end with some sort of agreement to curb OPEC’s crude oil production.

http://oilprice.com/Latest-Energy-News/World-News/Crude-Spikes-After-API-Reports-Massive-Crude-Draw.html

Painted Pony Petroleum Ltd. is pleased to announce 180 MMcfe/d (30,000 boe/d) of production volumes were averaged over the previous five days, based on field estimates. The Corporation's production increase represents both absolute and per share production growth of greater than 80% over second quarter 2016 average daily production volumes of 99.8 MMcfe/d (16,634 boe/d).

Painted Pony's production volumes at the Townsend Facilty averaged in excess of 100 MMcfe/d (16,670 boe/d) based on field estimates over the previous five days.

As per previous guidance, Painted Pony anticipates increasing production volumes by an incremental 50 MMcfe/d (8,330 boe/d) to the Townsend Facility in early October 2016. Painted Pony expects total daily production volumes for the third quarter of 2016 to average approximately 138 MMcfe/d (23,000 boe/d) and 2016 exit production volumes to be approximately 240 MMcfe/d (40,000 boe/d).

The recent increase in production volumes is consistent with Painted Pony's strategic 5-year plan and represents a significant milestone in the growth of the Corporation. Painted Pony continues to focus on growing production per share while working to lower capital and operating costs.

Asset Swap Update

Painted Pony anticipates closing the previously announced (press release dated July 27, 2016) asset swap with an industry partner on or about September 26, 2016.

http://www.oilvoice.com/n/Painted-Pony-Petroleum-announces-30000-boed-production-milestone/74a864033069.aspx

Encana Corp., the Canadian oil and natural gas producer, is selling about $1 billion of shares to fund drilling in Texas next year and repay debt.

The company agreed to sell 107 million shares at $9.35 apiece through underwriters led by units of Credit Suisse Group AG and JPMorgan Chase & Co., Calgary-based Encana said in a statement on Monday after the close of regular trading on North American markets. An additional 16.05 million shares can also be purchased, as part of the deal.

Encana joins producers including Crescent Point Energy Corp. in selling shares in recent weeks to fund drilling as U.S. crude is up 65 percent from its February low. Most of the company’s investment next year will be targeted toward increasing output in the Permian Basin in West Texas, the largest U.S. oil field.

One of Canada’s largest gas producers, Encana has increasingly focused its attention on boosting oil and petroleum liquids production from shales including the Permian, where it established a position with the 2014 purchase of Athlon Energy for $7.1 billion. The company said it aims to double the number of wells on stream in the Permian in 2017, compared to this year.

Shares of the producer, which were halted in Toronto after the announcement, are up 85 percent this year. Encana’s U.S.-listed stock dropped in after-hours trading and was down 4.8 percent to $9.39 as of 7:59 p.m. in New York.

http://www.bloomberg.com/news/articles/2016-09-19/encana-selling-107-million-shares-to-fund-drilling-repay-debt

Gas deliveries from Cheniere Energy, the operator of the Sabine Pass LNG export terminal, dropped on Monday and Tuesday, signaling they may now be shutting down for repairs to fix gas flares that had not performed as expected, according to reports.

Cheniere had said earlier this month that the planned shutdown would begin “later this month” and would last four weeks, but no specific date had been given.

Even while the repairs are going on, LNG from the terminal could continue being shipped to various export destinations, Argus Media notes, because it also includes a number of storage tanks capable of holding a combined 17 billion cu ft of gas, and according to Argus, they are full to capacity at the moment. These 17 bcf of gas can be divided into four or five export cargos, with the typical average load of an LNG tanker ranging between 3 and 3.5 bcf.

The terminal received a daily average of 1.18 bcf in the first two weeks of September, but on Monday it only received 20.8 million cubic feet, and the same amount was scheduled for delivery on Tuesday. This indicates that the two operating liquefaction trains at Sabine Pass have been shut down in preparation for the repairs. The terminal is planned to have a total of five trains, each with a daily capacity of 694 million cubic feet of LNG.

At the end of last month, the first cargo of LNG from Sabine Pass reached China, media reported at the time. This was the first cargo of U.S. LNG to be exported to Asia. The continent is the most attractive market for LNG producers worldwide because of ample demand. This demand, however, has slackened recently, as more and more LNG projects came on stream, pushing prices down.

The Sabine Pass project is worth US$20 billion and is one of several such projects being built around the U.S. in a bid to make better use of the abundance of natural gas extracted across the country’s shale plays. So far, however, U.S. LNG has faced stiff competition abroad, more specifically in Europe and Asia, where LNG exporters with a presence are prepared to cut their prices in order to preserve their market share – something not so easily achievable for U.S. exporters.

http://oilprice.com/Latest-Energy-News/World-News/Cheniere-Shuts-Down-LNG-Terminal-for-Repairs.html

Brazilian state-run oil company Petróleo Brasileiro SA,or Petrobras, cut its investment budget for the coming years and plans to raise more cash from the sale of assets, amid efforts to reduce its huge debt.

Petrobras on Tuesday said it would invest $74.1 billion in the 2017-21 period, down from $98.4 billion projected for the 2015-19 period, which was announced in January.

Meanwhile, the company said it would seek to accelerate the sale of assets to reduce its debt.

For 2017 and 2018, Petrobras is planning to sell a total of $19.5 billion in assets. By comparison, for 2015-16 period, the company had planned to sell a total of $15.1 billion in assets.

With less investments and more assets sales planned, Petrobras said it seeks to reduce its net debt to Ebitda ratio to 2.5 times in 2018, from 5.3 times at the end of 2015.

Petrobras ended the second quarter with a total debt of $123.92 billion.

http://www.wsj.com/articles/petrobras-reduces-its-five-year-investment-plan-1474372806

Oil and gas exploration economics were broken, even while oil prices were above US$100. Our new research shows that the upstream exploration sector is poised to emerge from the current slump leaner, more efficient and more profitable. Here we look at how they're changing their approach, and what that means for the future.

The oil price downturn has been a catalyst for the industry to fix exploration economics. Rising costs, reducing returns combined with high-risk exploration strategies meant that the sector could not continue to operate in the same manner.

Where does the industry go from here?

Our research shows that the majors have started to look at exploration differently, and they've cut investment more drastically than other sectors. As the industry readjusts, there are now fewer wells being drilled. It's not that there's less oil to find – they're simply investing in less-risky operations. A lot of recent discoveries were not getting commercialised. And the economics of exploration were already broken back in 2014, when oil was at $100 per barrel.

One of the positive findings that we have seen from the majors changing the way they approach exploration is improved returns even at lower prices.






Focussing on high-yield options

Dr Andrew Latham, Vice President of exploration research at Wood Mackenzie says: "The new economics of exploration mean that rather than pursuing high-cost, high-risk exploration strategies – elephant hunting in the Arctic, for example – the majors have become more conscious of costs. Smaller budgets have required them to choose only their best prospects for drilling, including more wells close to existing fields. The industry now has in prospect a different – and potentially more profitable – future."

We've identified five ways that explorers can recover:

1. Focussed investment
Reduced exploration investment has forced only the best-quality prospects to be drilled.

2. Focus on returns and value over volume
A shift towards lower-cost locations, more emphasis on tax shelters against existing production, more focus on near-term opportunities and generally less above and below ground risk.

3. Redirecting investment
Focussing on areas where government support and fiscal terms are most appropriate.

4. Reduce costs
Ongoing efforts to reduce the costs of developing discoveries through project re-design, standardisation and innovation.

5. Lower-cost renewals
Longer-term acreage inventory renewals at a low cost.

Lower costs and more targeted investment

To achieve these aims, the majors have started to change the way they operate. They've cut conventional exploration spend by 53% in 2015 vs 2014. But the number of exploration wells completed fell by just 11% compared to the average of the previous four years. The average spend per well is back down to levels not seen since 2008. They've also refocused exploration on proven basins, nearer to existing production infrastructure, and reduced activity in high-risk frontiers.




Conventional versus unconventional spend



As the majors trim spend and refocus, they will discover smaller conventional volumes. This will lead to them relying more on other renewal options – unconventionals, discovered resource opportunities, enhanced recovery and M&A. We estimate that only 50% of production will be replaced by conventional exploration. This means that unconventionals are now attracting over 15% of exploration spend and have outperformed returns from conventional exploration since 2013. The end result will be a leaner, more fit-for-purpose sector, and will see the majors and the rest of the industry returning exploration to profitability at US$60 oil price.

https://www.woodmac.com/analysis/how-upstream-exploration-economics-are-recovering?utm_source=twitter&utm_medium=social&utm_campaign=wmorganic&utm_content=o

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 Major oil producers will rely on acquisitions for about half their reserve replacement in the future after cutting exploration budgets to weather the crude-price collapse, according to Wood Mackenzie Ltd.

Big oil companies are no longer trying to replace all their production through conventional exploration, the energy consulting company said in a report published Tuesday.

"Now their reserves replacement will also require inorganic, brownfield or shale investments," Andrew Latham, vice president of exploration research at Edinburgh-based WoodMac, said in an interview. "Exploration has become incremental."

Investors often use the reserve-replacement ratio -- the proportion of oil and gas production offset by new resources -- to value companies since it forms the basis for future output. Among seven oil majors, only three added more oil than they pumped last year. Exploration spending dropped by half from a year earlier to $7 billion, according to WoodMac, whichsees the industry slashing $1 trillion from exploration and development until the end of the decade.

Acquisitions Push

“The need for M&A in exploration is likely to be here for a considerable time," Latham said. The focus “will be on assets rather than on taking over companies.”

Woodside Petroleum Ltd. is among those snapping up exploration assets. The Australian company agreed to buy ConocoPhillips’ interests off Senegal for $350 million in July. The purchase included the deep-water SNE discovery, which operator Cairn Energy Plc estimates has 473 million barrels in resources.

Exxon Mobil Corp. was also said to be intalks with Anadarko Petroleum Corp. for a stake in a natural-gas discovery off Mozambique, and in advanced discussions with Eni SpA over a stake in another prospect in the same area.

Lower oil prices have taken a toll on majors’ reserves, with some of them -- such as Royal Dutch Shell Plc -- forced to write down as much as 200 million barrels. Shell had the worst reserve-replacement ratio last year at minus 20 percent, the lowest in 12 years, it said in February.

The companies are also disposing of costly assets as oil prices below $50 a barrel curb revenue. The Hague-based Shell aims to raise $30 billion from asset sales in three years following its $54 billion acquisition of BG Group in 2015. Among the assets it may sell are aging North Sea fields.

http://www.bloomberg.com/news/articles/2016-09-20/oil-majors-must-count-on-m-a-to-replenish-reserves-woodmac-says

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India’s crude oil imports peaked in August as refineries stepped up purchases to meet record domestic fuel consumption.

Indian refiners imported 18.81 million metric tons (about 4.45 million barrels a day) of crude oil during the month, a 9.1 percent increase over last year, according to the oil ministry’s Petroleum Planning & Analysis Cell. That is the highest level in data on thePPAC’s website going back to April 2009.

The South Asian nation of 1.3 billion people, which meets over 80 percent of its crude oil requirements through imports, has emerged as a bright spot for global oil demand as the the fastest economic expansion among major economies spurs increased use of trucks, cars and motorbikes. The International Energy Agency expects India to be the fastest-growing crude consumer in the world through 2040.

“India’s domestic fuel demand has been rising at a scorching pace,” according to Tushar Tarun Bansal, director at Singapore-based Ivy Global Energy. “To meet this strong growth, India’s refinery runs have been on an uptrend, leading to higher imports.”

The nation’s gasoline consumption reached a record in August, surging 25 percent from a year earlier, while demand for diesel rose 13 percent, the fastest pace since March. Virendra Chauhan, an oil analyst at Singapore-based consulting firm Energy Aspects Ltd., expects India’s oil demand to grow by 0.4 million barrels a day this year and by 0.2-0.3 million barrels a day next year.

Indian refiners are racing to add capacity, spending billions of dollars amid rising fuel consumption. State-run Indian Oil Corp., the country’s biggest refiner, aims to increase its capacity by 30 percent, or about 2 million barrels per day, over the next six years by expanding its existing refineries across the country.

The country’s 23 refineries have a total capacity of 230 million tons a year, while total fuel demand was 183.5 million tons during the financial year that ended March 31, according to the oil ministry.

“There has been strong demand -- gasoline growth is unprecedented and diesel growth will rise after monsoon,” Sanjiv Singh, director of refineries at Indian Oil, said.

http://www.bloomberg.com/news/articles/2016-09-20/india-s-monthly-crude-imports-touch-7-year-high-as-demand-booms

Libya's Arabian Gulf Oil Company (AGOCO) said on Tuesday its output had risen to 210,000 barrels per day (bpd) after production resumed at the Nafoura and Hamada fields.

"We will maintain production at this level and we are capable of increasing it, though we are suffering from a financial crisis at the moment," AGOCO spokesman Omran al-Zwai told Reuters.

http://www.reuters.com/article/libya-security-oil-idUSL8N1BW2PR

At $500 Million A Pop, It's An Oil Gamble That Has No Precedent

In a far corner of the Caribbean Sea, one of those idyllic spots touched most days by little more than a fisherman chasing blue marlin, billions of dollars worth of the world’s finest oil equipment bobs quietly in the water.

They are high-tech, deepwater drillships -- big, hulking things with giant rigs that tower high above the deck. They’re packed tight in a cluster, nine of them in all. The engines are off. The 20-ton anchors are down. The crews are gone. For months now, they’ve been parked here, 12 miles off the coast of Trinidad & Tobago, waiting for the global oil market to recover.

The ships are owned by a company called Transocean Ltd., the biggest offshore-rig operator in the world. And while the decision to idle a chunk of its fleet would seem logical enough given the collapse in oil drilling activity, Transocean is in truth taking an enormous, and unprecedented, risk. No one, it turns out, had ever shut off these ships before. In the two decades since the newest models hit the market, there never had really been a need to. And no one can tell you, with any certainty or precision, what will happen when they flip the switch back on.

It’s a gamble that Transocean, and a couple smaller rig operators, felt compelled to take after having shelled out millions of dollars to keep the motors running on ships not in use. That technique is called warm-stacking. Parked in a safe harbor and manned by a skeleton crew, it typically costs about $40,000 a day. Cold-stacking -- when the engines are cut -- costs as little as $15,000 a day. Huge savings, yes, but the angst runs high.

“These drillships were not designed to sit idle,” said Willard Duffey Jr., an electrician who spent two decades with Transocean. The Deepwater Pathfinder, a ship he had served on for four years, was among the first to be parked off the Trinidad coast. The ship made the voyage there from the Gulf of Mexico about a year ago. Duffey was one of the last men aboard before the engines were turned off. He fretted constantly -- “did I do everything I could?” -- as he flew back home to Ore City, Texas. “To get the Pathfinder back up would be very difficult to guess actually,” he said.

All of these fancy elements, though, are what make turning the ships back on so daunting. Chip Keener, whose rig-storage consulting firm advises Transocean, compares it to what would happen if you left a high-tech new car parked in the garage for months. The battery would be dead, sure, but then there’d also be a slew of pre-sets to reprogram. On a drillship, there are thousands and thousands of pre-sets. And unlike your car, those on a ship are essential to its proper functioning. “It’s a big deal,” says Keener.

http://www.rigzone.com/news/article.asp?hpf=1&a_id=146684&utm_source=GLOBAL_ENG&utm_medium=SM_TW&utm_campaign=FANS

Saudi Arabia's oil exports rose in July as the kingdom pumped record high levels of crude, keeping the global market well supplied.

The world's largest oil exporter has been maintaining high output levels since mid-2014 despite a global supply glut, in line with a strategy of defending market share against rival producers.

Saudi Arabia's crude oil exports in July rose to 7.622 million barrels per day from 7.456 million bpd in June, official data showed on Monday.

The kingdom produced a record high 10.673 million bpd in July, up from 10.550 million bpd in June with the increase due to summer demand and requests from customers. However, its output slipped in August to 10.63 million bpd, industry sources have said. Export data for August is not yet available.

Several members of the Organization of the Petroleum Exporting Countries have called for an output freeze to rein in an oil glut that triggered a price collapse in the last two years, hitting the revenues of major producers.

In the past, analysts have persistently discounted the possibility that OPEC members such as Saudi Arabia, Iran, Nigeria and Libya will agree to production curbs as they protected market share, but some analysts have become more hopeful an agreement can be reached.

Venezuelan President Nicolas Maduro said on Sunday that OPEC and other major oil producers were close to reaching a deal on price stability that could be announced later this month.

Saudi Arabia's domestic crude inventories totalled 281.463 million barrels in July, down from 289.445 million in June, data provided by the Joint Organisations Data Initiative (JODI) showed.

JODI compiles data supplied from oil-producing members of global organisations including the International Energy Agency and the Organization of the Petroleum Exporting Countries.

Saudi Arabia's oil inventories peaked last October at a record high 329.430 million barrels but have declined since as the country has drawn down its stockpile to meet domestic demand without impacting its exports.

As it expands oil product exports, the kingdom has been feeding more crude to domestic refineries.

Domestic refineries processed 2.611 million bpd of crude in July, up from 2.381 million in June. Exports of refined oil products in July totalled 1.367 million bpd versus 1.371 million in June.

State oil firm Saudi Aramco has stakes in more than 5 million bpd of refining capacity at home and abroad, placing it among the global leaders in making oil products.

In July, crude oil used to generate power fell to 697,000 bpd from 704,000 bpd in June, the JODI data showed.

http://www.reuters.com/article/saudi-crude-jodi-idUSL8N1BV459

Militants have blown up a crude oil pipeline operated by Nigeria's state oil firm NNPC in the Niger Delta, a group claiming responsibility for the attack and a youth leader said on Monday.

The Niger Delta Greenland Justice Mandate group said it carried out the attack on the Afiesere-Ekiugbo delivery line, in the town of Ughelli in Delta state, on Sunday night at around 11:30 p.m. (6.30 p.m. ET). The line is operated by NPDC, a unit of NNPC, and Nigerian energy company Shoreline.

It is the latest in a series of attacks on energy facilities in the restive region that have cut Nigeria's oil production by 700,000 bpd.

"The Niger Delta Greenland Justice Mandate is just starting, you are yet to see what we are about," said the group which, unlike other militants in the region, is not taking part in a ceasefire to hold talks with the government.

Lucky Solue, a youth leader, confirmed the attack took place. An NNPC spokesman could not immediately be reached for comment.

There was no immediate information on any impact on production.

The Niger Delta Avengers group, whose attacks on oil pipelines in the southern region crippled crude output earlier this year and pushed Africa's biggest economy into recession, said in August it agreed to a ceasefire.

The government has held out the prospect of holding talks on the grievances of people in the Delta with militant groups that maintain a truce.

http://www.reuters.com/article/us-nigeria-oil-pipeline-idUSKCN11P1UX

Venezuala comments on oversupply worries markets

Oil prices fell on Tuesday after Venezuela said that global supplies needed to fall by 10% in order to bring production down to consumption levels, and technical indicators also pointed to cheaper crude futures.

Global oil supply of 94 million barrels per day needs to fall by about a tenth if it is to match consumption, Venezuela's Oil Minister Eulogio Del Pino said on Monday.

International benchmark Brent crude oil futures were trading at $45.81 per barrel early on Tuesday, down 17 cents from their last close.

US West Texas Intermediate crude futures were down 22 cents at $43.08 a barrel.

"Global production is at 94 million barrels per day, of which we need to go down 9 million barrels per day to sustain the level of consumption," Del Pino said in an interview with state oil company PDVSA's internal TV station.

Del Pino is also president of PDVSA.

The statements came the same day as credit ratings agency Standard & Poor's said that a proposed bond swap by PDVSA was a "distressed exchange" that would be "tantamount to default" if completed, a blow to the cash-strapped firm's effort to seek a financial lifeline.

Technical market indicators were also weak, with WTI likely to test support at $42.78 per barrel soon, after which a fall toward $42 would be likely, according to Reuters analyst Wang Tao.

http://www.upstreamonline.com/live/1444470/oil-slips-on-oversupply-worries?utm_source=twitterfeed&utm_medium=twitter

Cheniere Energy Partners L.P. has announced that Train 2 at the Sabine Pass liquefaction project in Cameron Parish, Louisiana, US, has achieved substantial completion. Commissioning has been completed and Cheniere’s engineering, procurement and construction (EPC) partner, Bechtel Oil, Gas and Chemicals Inc., has turned over care, custody and control of Train 2 to Cheniere Partners. This turnover will be done in coordination with the previously-announced planned outage to improve the flare systems’ performance at the project, as well as to carry out scheduled maintenance work on both Train 1 and other facilities.

As set out in a sales and purchase agreement (SPA) with Gas Natural Fenosa LNG GOM Ltd, Train 2’s first delivery is expected to occur in August 2017. At this point, the 20-year term of the SPA will commence. Before this occurs, Gas Natural Fenosa holds certain rights to early cargoes that Train 2 produces.

Cheniere Partners, through Sabine Pass Liquefaction, is planning to construct up to six liquefaction trains at the facility. Trains 1 and 2 have achieved substantial completion; Train 3 is undergoing commissioning; Trains 4 and 5 are under construction; and Train 6 has been fully permitted. Each Train is expected to have a nominal production capacity of approximately 4.5 million tpy of LNG.

http://www.lngindustry.com/liquefaction/19092016/Sabine-Pass-Train-2-achieves-substantial-completion-3070/

Oil and natural gas activity in shale-rich North Dakota is on a steady increase, though operators are still cautious about recovery, state data show.

State data show 32 rigs are actively exploring for or producing oil and natural gas in North Dakota, down one from last week but relatively in line with levels since July. Rig counts serve as a loose metric for investor confidence in the energy sector and a reflection of the appetite for spending from oil and gas companies.

Crude oil prices rallied earlier this year above the $50 mark on suggestions the gap between supply and demand had narrowed to the point of balance. Monthly market reports from the Organization of Petroleum Exporting Countries and the International Energy Agency said an expected balance had yet to materialize.

Lynn Helms, a director at the North Dakota Department of Mineral Resources, said in a statement that rig counts have seen a steady increase since June, though caution was the prevailing mood in state shale deposits.

"Operators remain committed to running the minimum number of rigs while oil prices remain below $60/barrel. ... Oil price weakness is the primary reason for the slow-down and is now anticipated to last into at least the fourth quarter of this year and perhaps into the second quarter of 2017."

North Dakota oil production in July was around 1.03 million barrels per day, a slight increase from June, but still 16 percent below the all-time high set in December 2014. Natural gas production increased 2 percent in July, but was about 0.6 percent below the record high established in March.

Helms said drilling permit activity was moving higher in response to an expected recovery in crude oil prices by later next year.

"Operators have a significant permit inventory should a return to the drilling price point occur in the next 12 months," he said.

http://www.upi.com/North-Dakota-shale-on-slow-recovery/1021474289468/?spt=su&or=btn_tw

Steelhead LNG and Seven Generations Energy of Canada on Monday signed an agreement to explore midstream supply chain infrastructure that would link natural gas resources to Steelhead proposed LNG export projects on Vancouver Island.

The two companies also agreed to engage Aboriginal groups during the development of the infrastructure, according to a joint statement.

Steelhead LNG proposed to build the Malahat LNG project on the Bamberton Industrial Lands, south of Mill Bay and the Sarita LNG project at Sarita Bay at the southern end of the Alberni Inlet.

The arrangement, through which Seven Generations has also acquired a minority interest in Steelhead LNG, is expected to provide potential new markets for Seven Generations’ production as well as increased certainty of natural gas supply for Steelhead LNG, the joint statement reads.

“This agreement with Seven Generations is a positive step toward realizing our sustainable and economic delivery model for LNG. At the same time the economic circumstances are challenging and there is more work to do and milestones to achieve for our projects to succeed,” said Steelhead LNG CEO, Nigel Kuzemko.

The company is additionally looking to refine its at-shore LNG concept design that uses floating LNG production and storage units moored to marine jetties. The concept can be replicated enabling scalable production capacity at Steelhead LNG’s proposed facilities.

The National Energy Board has granted Steelhead LNG five licenses to export in the aggregate of up to 30 million tonnes of liquefied natural gas per year for 25 years.

Steelhead LNG is also exploring ways of accessing newly emerging LNG markets such as the conversion of international shipping vessels to LNG from bunker fuel and diesel, Steelhead LNG said.

http://www.lngworldnews.com/steelhead-7g-join-forces-on-lng-projects-supporting-infrastructure/

A recent spate of land deals in the sprawling Permian Basin illustrates a counter-intuitive trend: Real estate in the country’s most active oil field is even more expensive today than it was before commodity prices crashed.

QEP Resources Inc. agreed to pay a price that works out to close to $60,000 per net acre in June for a slice of the Permian, in the basin’s priciest land deal on record.

That’s more than double the average $30,000 per net acre explorers paid for Permian land during the first nine months of 2014, when oil topped $100 a barrel, according to data from Citigroup Inc. Oil has been hovering at $45 to $50 per barrel since mid-August.

Over the past few months, at least four other explorers agreed to pay more than $30,000 per net acre to expand in the Permian: Concho Resources Inc., Parsley Energy Inc., SM Energy Co., and Silver Run Acquisition Corp., according to data compiled by Bloomberg.

“The valuations are pretty lofty,” said Bryan Lastrapes, managing director at Moelis & Co. “When you look at the prices being paid for a flowing barrel, they are higher than when oil was at $100.”

Unusual geography

The obvious question: With oil so much cheaper today, why has Permian land become so pricey? There are a few explanations. The first comes down to the same reason a dingy is more valuable on a sinking ship.

“It’s about scarcity,” said Bruce Cox, global head of energy acquisitions and divestitures with Credit Suisse Group AG.

The Permian is one of the few places in the U.S. where drilling remains profitable amid low prices, thanks to its unusual geography, in which different layers of oil- and gas-soaked rock are stacked like layers in a cake, he said. An explorer can drill multiple horizontal wells after digging straight down.

“What you can’t find in most plays is the Permian hydrocarbon column,” Cox said. “Companies can drill two to four times as many wells over a 10-year development period” in the Permian than in other basins.

QEP rationale

This is a key part of the rationale QEP used to justify the price it agreed to pay for the 9,400 net acres in the Permian in June.

The company told investors it sees a chance to drill more than 400 horizontal wells along four different benches of shale, more than a half-mile down, where it has already determined there is oil. It sees additional upside potential drilling riskier, wildcat wells on three other benches. So it isn’t buying just one field, but as many as seven.

That deal also addresses a perpetual critique from investors that QEP isn’t big enough in the Permian, by increasing its position there by 50 percent, Richard Doleshek, QEP’s chief financial officer, said in August.

“From a dollar-per-acre standpoint, we heard a lot of conversation about how that was a big number,” Doleshek said during a presentation at an oil and gas conference sponsored by Enercom Inc., according to a transcript compiled by Bloomberg.

“When you look at it on a target basis, it’s relatively reasonable,” he said. “It’s pristine acreage.”

Lower costs

Another factor driving up Permian land prices is the fact that it has some of the lowest break-even costs in the world. The area has more than a half-dozen fields where drilling can stay profitable even when oil falls below $30 a barrel, according to data compiled by Bloomberg.

The oil rout has set off a land grab for that reason, said Ron Gajdica, co-head of energy acquisitions and divestitures with Citigroup.

“When oil prices were high, there was a high supply of acreage with economic drilling opportunities,” he said. “Now, in a $40 to $50 oil price environment, acreage with economic locations is scarcer. There are only a limited amount of opportunities and many of them are in the Permian.”

A couple of other things are driving up the price of Permian land. First, development costs have come down sharply during the downturn, thanks to lower service costs, technological advances and more efficient techniques, Gajdica said. That means explorers can justify paying higher prices for land.

Second, Wall Street is helping the trend. Publicly traded Permian explorers such as Concho and Parsley trade at a premium to other shale players. They paid for their recent acquisitions with stock. Since their currency is worth more, they can afford to pay up.

In addition, other explorers with operations elsewhere, such as QEP and SM, saw their share prices spike after striking deals in the Permian, which could spur even more dealmaking in the area.

“The market tends to respond favourably when these Permian deals are announced,” Gajdica said.

http://fuelfix.com/blog/2016/09/19/oil-gas-stacks-make-permian-deals-costly-in-spite-of-downturn/?

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Genscape shows Cushing inventory build of 180,000 bbls in latest week

‏@zerohedge

Hedge funds have built their largest bullish position in U.S. natural gas for more than two years amid signs the gas glut is being eroded quickly and the market could tighten in 2017.

Hedge funds and other money managers have amassed a net long position in the two main futures and options contracts on NYMEX and ICE equivalent to 2,293 billion cubic feet of gas.

The net long position has almost quadrupled over the last four weeks, and is now at the highest level since June 2014, according to an analysis of data released on Friday by the U.S. Commodity Futures Trading Commission.

Positioning has been shifting steadily from bearish to bullish since November 2015 but the pace of adjustment has accelerated sharply.

The most recent weekly increase in the net long position was the third-largest since the start of 2010.

The majority of the adjustment has come from the short side of the market, where hedge funds with bearish short positions betting a fall in gas prices have scaled them back.

Hedge fund short positions have declined by the equivalent of 1,127 billion cubic feet, or 40 percent, in the last four weeks. By contrast, long positions have risen just 544 billion cubic feet, or 16 percent.

Hedge funds are reacting to signs the gas market is rapidly rebalancing from oversupply in 2015 towards a potential deficit in 2017 (“U.S. natural gas market rebalancing well underway”, Reuters, Sep 16).

Low gas prices have gradually eroded the excess supply by causing production growth to stall and go into reverse while encouraging record consumption by power producers.

Rebalancing has been accelerated by unusually hot weather across the most populous parts of the United States this summer.

Temperatures and airconditioning demand have been far above normal almost continuously since the end of May (“U.S. natural gas market rebalances on hot weather, low prices”, Reuters, Aug 19).

Working gas stocks have risen by just 1,022 billion cubic feet so far this injection season, compared with an average increase of 1,594 billion cubic feet at this point during the previous five years.

Stocks have risen by just 160 billion cubic feet in the last four weeks compared with 309 billion cubic feet over the same period in 2015 and a five-year average of 266 billion cubic feet.

LIQUIDATION RISK

Winter 2016/17 is likely to be colder than the record warm winter of 2015/16 which should increase gas consumption.

Looking to 2017, more gas-fired power plants are scheduled to come into service, according to the U.S. Energy Information Administration (U.S. power producers maximize gas burn at expense of coal”, Reuters, Aug 31).

Most of the new gas-fired generating capacity will be combined cycle power plants designed for baseloading rather than steam turbines or combustion turbines operating at peak times.

The implied increase in gas consumption will tighten the market even further unless gas prices rise to stimulate more drilling and stimulate some shift from gas combustion back to coal in 2017.

Hedge funds have already anticipated and likely accelerated the price rise by accumulating a large long position in futures and options.

The calendar average futures price for gas delivered in 2017 has risen to $3.14 per million British thermal units from a low of $2.14 back in December 2015.

The fundamental outlook for prices looks fairly strong at present, but the emergence of a large hedge-fund long position has increased the risk of a price reversal if position holders try to take some profits.

The net long position amassed by hedge funds over recent weeks is large by the standard of the last five years, though below the peaks reported in 2013/14.

So, while fundamentals should continue to support higher gas prices into 2017, liquidation risk has increased substantially and is a negative factor for prices in the short to medium term.

http://www.reuters.com/article/us-usa-natgas-kemp-idUSKCN11P15H

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Hedge funds and other large money managers have raised their weekly bets on rising crude oil prices, with net long positions in Brent stabilizing around levels seen in mid-August when the market got the first indications of a possible OPEC output deal.

Investors increased their net long positions in Brent by 8,192 contracts to 359,173 lots in the week to Sept. 13, ICE reported.

That is pretty much in line with the levels of 354,915 lots seen in the week to Aug. 16 but still far off record highs of over 419,000 lots seen at the end of April.

Bullish bets on Brent have risen and then fallen again since mid-August, mainly driven by concerns over whether OPEC and non-OPEC Russia can clinch a meaningful deal to stabilize the oil market, amid returning supplies from Libya and Nigeria and a worsening global oil glut.

OPEC and non-OPEC Russia are due to meet next week in Algiers.

http://www.reuters.com/article/us-ice-oil-idUSKCN11P12N

Eni revealed Monday that the Laarich East-1 well onshore Tunisia has a delivery capacity of approximately 2,000 barrels of oil per day.

The Laarich East-1 well, which was spudded in June, has already been connected to production. In the meantime, exploration activities in Tunisia are continuing with the drilling of additional prospects, which have been already identified on 3D Seismic, according to an Eni statement.

Laarich East-1 reached a final depth of 13,487 feet, discovering hydrocarbons in sandstone layers of Silurian and Ordovician age. The drilling of Laarich East-1 is part of Eni’s near field strategy, adopted to cope with the low oil price environment, which aims to conduct exploration activities in the proximity of existing infrastructures with available spare capacity.

Eni owns a 50 percent stake in the Makhrouga-Laarich-Debbech license, where Laarich East 1 is located, with the Tunisian state company ETAP holding the remaining 50 percent stake.

http://www.rigzone.com/news/oil_gas/a/146675/Eni_Laarich_East1_Well_Onshore_Tunisia_Has_2000Bpd_Capacity

Liquefied natural gas exports from Cheniere’s Sabine Pass facility reached 63.47 billion cubic feet for the February-July period.

Data from the United States Department of Energy shows that, including the first cargo shipped from the facility in Louisiana on February 24, Cheniere dispatched 21 cargoes during the period under review.

The cargoes were delivered to a number of locations including, Brazil, India, U.A.E., Argentina, Portugal, Kuwait and Chile with first cargoes delivered to Spain, China and Jordan in July.

Export point prices were ranging from US$3.12 per MMBtu to $5.60 per MMBtu.

DoE’s July report also shows that American LNG Marketing exported 19,330 Mcf of domestically produced LNG in ISO containers in the February-July period. LNG was shipped from Miami, Fla. to Barbados with export point prices ranging from $10.00 per mmBtu to $15.78 per mmBtu.

LNG imports into the U.S. reached 53.06 Bcf in the period from February to July, all sourced from Trinidad and Tobago, the report showed.

http://www.lngworldnews.com/doe-sabine-pass-lng-exports-reach-63-47-bcf-in-feb-july/

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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/

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

 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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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/

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/

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

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

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

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

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

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

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/

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/