Eni SpA posted a second-quarter loss, missing analysts’ estimates as the Italian oil major suffered the effects of the collapse in crude prices.

The company’s adjusted net loss was 290 million euros ($321 million) compared with a profit of 505 million euros a year earlier, the company said in a statement Friday. That compares with the 78.2 million-euro average profit estimate from 13 analysts surveyed by Bloomberg. The company maintained its dividend at 40 euro cents a share.

“Our strategy, including the optimization initiatives and a reduced cost base, has allowed us to absorb part of the impact of a low oil price,” Chief Executive Officer Claudio Descalzi said in the statement. “We are maintaining our strong balance sheet, funding capex with our cash flow at a Brent price of $50 a barrel.”

The plunge in crude prices since the middle of 2014 has weighed on oil company earnings, forcing them to cut costs, postpone or cancel expensive projects and in some cases reduce dividends. BP Plc,Royal Dutch Shell Plc and Total SA all reported sharp declines in second-quarter profit. Eni reiterated that it would cut capital expenditure by 20 percent this year, exceeding the 17 percent drop last year.

Brent averaged $47.03 a barrel in the quarter compared with $63.50 a year earlier and $35.21 in the first quarter of this year.

Production of oil and gas fell 2.2 percent from a year earlier to 1.72 million barrels of oil equivalent a day. That compares to an average forecast of 1.7 million barrels a day in eight analyst estimates compiled by Bloomberg. Output was disrupted in Nigeria and Italy in the second quarter, while full-year output should be little changed from 2015, the company said.

Eni shares have risen 1.8 percent so far this year, compared with 6.3 percent increase for the Stoxx Europe 600 Oil and Gas Index.

Oil majors have produced a mixed set of second-quarter results, with Shell posting the lowest earnings in 11 years while Totalmanaged to beat estimates thanks to deepening cost cuts.

http://www.bloomberg.com/news/articles/2016-07-29/eni-misses-estimates-to-post-second-quarter-loss-amid-oil-slump

Oilfield services provider Baker Hughes Inc said it did not expect a substantial recovery in drilling and pricing in North America this year, in contrast with comments from bigger rivals Schlumberger Ltd and Halliburton Co.

Baker Hughes' shares, however, rose about 3 percent to $45.88 after the company said it expected margins to improve across its businesses due to recent job cuts and other restructuring actions.

"I don't subscribe to the hopeful commentary," Baker Hughes Chief Executive Martin Craighead said on a post-earnings conference call on Thursday.

Schlumberger said last week the oil downturn appeared to have bottomed out, while Halliburton said it expected a "modest uptick" in North American rig count in the second half of 2016.

"I believe oil prices in the upper $50s (per barrel) at a minimum are required for a sustainable recovery in North America," Craighead said.

Baker Hughes' outlook was more "sanguine" than its peers', said Evercore ISI analyst James West, noting that oil prices have slid from last week, when Schlumberger and Halliburton reported results.

Prices for both globally traded Brent futures and U.S. crude are down about 5 percent this week.

In May, Baker Hughes and Halliburton scrapped their long-stalled deal - valued at about $35 billion when it was announced in 2014 - due to opposition from U.S. and European antitrust regulators. The companies had hoped the merger would help them weather the worst oil price crash in a generation.

Baker Hughes said in May proceeds from a $3.5 billion breakup fee from Halliburton would fund a $1.5 billion share buyback and a $1 billion debt repayment.

Baker Hughes, which expects to save an annualized $500 million in cost by the end of 2016, said it cut 3,000 jobs in the second quarter.

The company had laid off 2,000 employees in the first quarter and 18,000 last year. Baker Hughes had about 43,000 employees at the end of 2015.

The company also said it was planning to launch new products this year, most of them for lowering costs and optimizing oil production.

Net loss attributable to the company widened to $911 million, or $2.08 per share, in the quarter ended June 30.

Excluding charges related to restructuring and asset writedown, the company reported a loss of 90 cents per share, bigger than the 62 cents analysts had expected, according to Thomson Reuters I/B/E/S.

Revenue fell 39.3 percent to $2.41 billion.

http://www.reuters.com/article/us-baker-hughes-results-idUSKCN1081C8

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National Oilwell Varco Inc, the largest U.S. oilfield equipment provider, said demand rose for some of its products and services in North America in recent weeks, as drillers put rigs back to work.

"Like others in our space, we believe we are seeing some isolated green shoots of activity," Chief Executive Clay Williams said on a post-earnings call.

A 60 percent fall in global oil prices since mid-2014 has forced producers to scale back drilling and idle rigs, weighing on demand for equipment manufactured by companies such as National Oilwell.

But some producers have begun to return rigs to work, encouraged by U.S. crude prices touching $50 in late May.

U.S. drillers have since added about 55 oil rigs.

The company was in discussions with customers in North America, Middle East and other markets about equipment upgrades and new field opportunities, Chief Financial Officer Jose Bayardo said on the call.

These talks centered around land activity, with offshore opportunities expected to remain limited for the foreseeable future, he said.

"We believe our land business will bottom in Q3 and begin to recover as we enter 2017."

However, the company said it was "not ready to call bottom yet".

The comment echoed that of Baker Hughes Inc, which said on Thursday it did not expect a "meaningful" recovery in North America this year.

National Oilwell, which has been aggressively cutting costs to offset the impact of low crude oil prices, said it slashed about 10 percent of its workforce during the quarter.

The company had about 44,000 employees at the end of the first quarter.

National Oilwell also said it is in the process of shutting down about 250 facilities since the downturn began in mid-2014.

Net loss attributable to National Oilwell was $217 million, or 58 cents per share, in the second quarter ended June 30, compared with a profit of $289 million, or 74 cents per share, a year earlier.

Excluding items, the company lost 30 cents per share, smaller than the average analyst estimate of 32 cents loss, according to Thomson Reuters I/B/E/S.

The Houston-based company's revenue more than halved to $1.72 billion, missing the average estimate of $1.79 billion.

http://www.reuters.com/article/us-national-oilwell-results-idUSKCN10818W

Improved fracking techniques have helped cut Pioneer Natural Resources Co's production costs in the Permian Basin to about $2 a barrel, low enough to compete with oil rival Saudi Arabia, CEO Scott Sheffield said on Thursday.

The comments from Sheffield, who is retiring soon, were perhaps the most concrete sign yet that the fittest U.S. shale oil producers will survive the price crash that started in mid-2014 when Saudi Arabia and OPEC moved to pump heavily to win back market share from higher-cost producers.

Dozens of shale companies, many with marginal assets, have filed for credit protection in the biggest wave of corporate bankruptcies since the telecoms crash of the early 2000s. Sheffield said high costs would continue to make U.S. shale plays outside the Permian basin relatively less competitive.

On Pioneer's second-quarter results call, Sheffield said that, excluding taxes, production costs have fallen to $2.25 a barrel on horizontal wells in the Permian Basin of West Texas, so it is nearly on even footing with low-cost producers of conventional oil.

"Definitely we can compete with anything that Saudi Arabia has," he said.

"My firm belief is the Permian is going to be the only driver of long-term oil growth in this country. And it's going to grow on up to about 5 million barrels a day from 2 million barrels," even in a $55 per barrel price environment, he added.

Oil traded near $50 a barrel for much of the second quarter but is currently around $42. Pioneer's shares were up more than 3 percent on Thursday at $155.91 each.

Sheffield said other U.S. shale plays, notably the Bakken in North Dakota and the Eagle Ford in South Texas, may not be able to weather the downturn as well given their higher costs.

"The Bakken and the Eagle Ford I think there's no way they can recover to the levels that they've already had," he said.

Pioneer expects output to grow 15 percent a year through 2020 after posting production of 233,000 barrels of oil equivalent a day this past quarter. It sees most of its growth in the Permian, though it also has acreage in the Eagle Ford.

Pioneer helps limit costs by doing much of its oilfield services work in-house. It also has its own sand mine, and uses effluent water from the city of Odessa for frack jobs using pressurized sand, water and chemicals to unlock oil from rock.

Pioneer said it is now introducing its third generation of well completion techniques, called version 3.0, that is using even more sand and water than the super-sized volumes introduced at the start of the price crash to pull more oil out of rock.

Its newest wells are using up to 1,700 pounds per foot of sand, up to 50 barrels per foot of fluid, and frack points as often as every 15 feet with wells that are now nearly 10,000 feet long.

Wells fracked using completion techniques known as version 2.0 have produced about 2,000 barrels per day in their early days, double what they were producing with earlier wells.

While the newest wells appear more productive, the company declined to say what output from wells fracked with the third generation completion techniques would ultimately be, partly because it chokes, or restricts, initial output from new wells to ensure their longevity.

http://www.reuters.com/article/us-pioneer-natl-rsc-fracking-idUSKCN10828Q

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Norwegian oil major Statoil ASA said on Friday it had agreed to buy Petrobras' 66 pct operated interest in the BM-S-8 offshore license in Brazil's Santos basin for $2.5 billion.

The acquisition also includes a substantial part of the Carcará oil discovery, one of the largest discoveries in the world in recent years, which was discovered in 2012, it said in a statement.

Statoil estimated the recoverable volume within the BM-S-8 license to be in the range of 700 to 1,300 million barrels of oil equivalents (boe) and said it would significantly increase production volumes "in the 2020s and beyond".

The two firms are also in discussions regarding a long-term strategic cooperation.

"The focus will be in the Campos and Espírito Santo basins, as well as new cooperation within gas and technology projects in the Santos basin", Statoil said.

Half of the money it will be paid on completing the deal, which is subject to partners' and government approval, while the remainder will be paid when certain milestones have been met, Statoil said, adding that the effective date for the transaction is July 1 2016.

http://www.reuters.com/article/us-statoil-petrobras-assets-idUSKCN1090JI

'The forest fires in the Fort McMurray area significantly impacted the region,' said Steve Williams, president and chief executive officer. 'We shut in our Oil Sands production and focused on the safe evacuation of employees, their families and the community. I'm tremendously proud of the Suncor team. Their resilience and professionalism was readily apparent throughout our response and ensured our assets safely returned to service.'

Highlights of the second quarter of 2016 include:

* Cash flow from operations of $916 million ($0.58 per common share).
* Operating loss was $565 million ($0.36 per common share), driven by the shut in of Oil Sands production in response to the forest fires, combined with low benchmark prices for crude oil. Net loss was $735 million ($0.46 per common share).
* By mid-July, all Oil Sands assets had returned to normal production rates after being shut in due to the forest fires and the completion of turnarounds at Oil Sands Base and Syncrude.
* The forest fires reduced second quarter Oil Sands production by approximately 20 million barrels. The company also incurred $50 million of after-tax incremental costs related to evacuation and restart activities, which was more than offset by operating cost reductions of $180 million after-tax while operations were shut in.
* Strong realized refining margins resulted in Refining and Marketing operating earnings of $689 million and cash flow from operations of $885 million, which included a first-in, first-out (FIFO) gain of $275 million.
* Acquired an additional 5% interest in Syncrude from Murphy Oil Company Ltd. (Murphy), adding 17,500 barrels per day (bbls/d) of synthetic crude oil (SCO) capacity and increasing the company's ownership interest to 53.74%.
* Completed a common share offering for net proceeds of $2.8 billion to fund the acquisition of an additional 5% interest in Syncrude and to reduce debt to provide ongoing balance sheet flexibility.
* Suncor's total upstream production decreased to 330,700 barrels of oil equivalent per day (boe/d) in the second quarter of 2016, compared with 559,900 boe/d in the prior year quarter, due primarily to shutting in production at Oil Sands operations and Syncrude as a result of the forest fires in the Fort McMurray region, being partially offset by a higher working interest in Syncrude and increased production from E&P.
* Oil Sands operations production was 177,500 bbls/d in the second quarter of 2016, compared to 423,800 bbls/d in the prior year quarter, with the decrease primarily due to the forest fires noted above, as well as the completion of a turnaround at the Upgrader 2 facilities, the first completed since the company moved to a five-year turnaround cycle.

http://www.oilvoice.com/n/Suncor-Energy-announces-second-quarter-2016-results/724094686b06.aspx?utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+OilvoiceHeadlines+%28OilVoice+Headlines%29

Royal Dutch Shell PLC is deferring a final investment decision this year on a big facility to export liquefied natural gas from Lake Charles, Louisiana, citing a current oversupply of the fuel and affordability of the project amid lower oil prices, the company's chief executive said Thursday.

It is the second delay Shell has made to a big LNG project. Earlier this month the Anglo-Dutch oil giant said it was delaying FID on an LNG export project in Kitimat in Canada.

"This is not the moment to commit to large-scale capital outlays, even though the fundamentals of these projects in their life cycle still look good," Ben Van Beurden said on a conference call.

Shell's Chief Financial Officer Simon Henry said gearing at the company, which in February completed a roughly $50 billion acquisition of BG Group PLC, could increase further to its 30% limit if oil prices don't rise from current levels.

Gearing, a measure of the extent to which a company's operations are funded by debt, rose sharply to 28.1% at the end of the second quarter, compared with 12.7% in the second quarter of 2015, reflecting the BG acquisition, Shell said.

"It [gearing] may go up before it comes down again, simply because the oil price today is at a level that we would not generate positive cash flow unless we were doing the divestments," Mr. Henry said, referring to the company's plan to sell assets.

Shell's net debt at June 30, 2016 was $75.1 billion versus $25.96 billion in the same period a year ago.

http://www.marketwatch.com/story/shell-defers-decision-on-louisiana-lng-investment-2016-07-28-84855613?mod=mw_share_twitter

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Exxon Mobil Corp. is in advanced negotiations with Eni SpA over acquiring a minority stake in natural-gas discoveries off Mozambique, according to two people with knowledge of the talks.

Exxon Chief Executive Officer Rex Tillerson discussed the plan with Mozambique President Filipe Nyusi last week in Maputo, the African nation’s capital, according to one of the people, asking not to be identified because the matter isn’t public. The U.S. oil major’s participation would potentially accelerate development of one of the world’s largest liquefied natural gas projects.

Exxon is also in talks with Anadarko Petroleum Corp. over acquiring a stake in the adjacent Area 1 in Mozambique’s offshore Rovuma Basin, the people said. Three years ago, China National Petroleum Corp. purchased 20 percent of Eni’s Area 4 for $4.2 billion.

The talks underline Exxon’s focus on gas assets after the company last weekagreed to acquire explorer InterOil Corp. for as much as $3.6 billion to add gas discoveries in Papua New Guinea.

Eni CEO Claudio Descalzi said May 12 that the company is in talks on selling a stake in its Mozambique discovery and expects to reach a final investment decision on an LNG project this year.

Exxon is already focused on Mozambique after winning three exploration licenses in October for offshore blocks to the south of the Anadarko and Eni discoveries. It has teamed up with Qatar Petroleum to look at assets in the country, four people familiar with the plans said earlier this month.

Exxon also has a working interest in Statoil’s Block 2 in Tanzania, north of the Rovuma Basin.

http://www.bloomberg.com/news/articles/2016-07-28/exxon-said-in-advanced-talks-with-eni-over-mozambique-gas-stake-ir65tjlm

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Houston-based Baker Hughes reported Thursday that its second quarter loss widened to $911 million  even though the oilfield services firm received a $3.5 billion payout from Halliburton from its failed merger.

Baker Hughes’ net loss was significantly worse than the $188 million loss in the second quarter of 2015. Revenues plunged 40 percent to $2.4 billion $4 billion, the company said.

Baker Hughes cut about 3,000 jobs in the second quarter, bringing its 18-month tally to more than 25,000 positions.

Halliburton had planned to acquire Baker Hughes, but the deal fell through in May after the Justice Department intervened because of anti-competitiveness concerns.

Baker Hughes received a $3.5 billion termination fee, but it was almost entirely offset by restructuring and impairment charges.

Baker Hughes employs about 36,000 people globally now, down 26,000 people from a headcount of more than 62,000 employees before the oil bust began in late 2014.

“Although we expect the market dynamics to remain challenging near term, the structural changes we implemented this quarter have created a stronger foundation for delivering on our strategy,” Baker Hughes Chairman and CEO Martin Craighead said in a prepared statement. “We have made significant progress in a short amount of time, and we remain focused on accelerating our momentum.”

http://fuelfix.com/blog/2016/07/28/baker-hughes-posts-loss-despite-halliburton-payout/

The buildout of a pipeline system that likely spells the end of the truck and train boom in the Bakken is continuing.

The latest in the series involves a short segment of 12-inch pipeline that travels a mere 1.1 miles, but could have a major impact on Bakken crude. The line is being built by the Hess Corp.; and while short, it connects to something long indeed: the Dakota Access pipeline, which travels 1,172 miles to Patoka, Ill. Its maximum overall capacity is listed online as up to 570,000 barrels a day.

That line, which is being built by Energy Transfer Partners, can ultimately tie North Dakota’s sweet Bakken crude — naturally low in sulfur —  to other markets, including Texas, where ExxonMobil announced on Tuesday that it is expanding its ultra-low-sulfur fuel production at the Beaumont Refinery by 40,000 barrels a day.

The capacity of the Hess pipeline segment is listed as a maximum of 70,000 barrels, but is estimated to have a more normal throughput of 50,000 barrels a day.

The cost of the Hess midstream project is $4.5 million. A request for a building permit filed on behalf of Energy Transfer Partners with Williams County lists a Ramberg Truck Terminal project as $2.6 million. The application lists a pump house and a main meter as parts of the project.

The Hess connecting pipeline is to originate at the existing Ramberg Truck Facility, and extend to a new Energy Transfer Partners facility, which will be located 7 miles south of Tioga.

A representative with Dakota Access confirmed the Hess pipeline will tie directly into the Dakota Access project.

At the hearing in Tioga on Tuesday, company officials talked about the extra measures they will take for this short segment of pipeline, which will pass by a wetland on its way to Dakota Access. The area is also in the vicinity of the whooping crane’s fall migration pathway.

Since construction is scheduled for the fall, they will be monitoring for the whooping crane, and if one is sighted within a half mile of the project, use of heavy equipment will be halted while it is within that range.

They will minimize water body crossings and avoid all wetland crossings entirely, according to documents filed with the PSC. A Hess representative did not immediately respond to a request for further clarification on the measures being taken for the wetlands safety.

http://bismarcktribune.com/bakken/hess-project-to-bring-bakken-oil-to-dakota-access/article_9faeb672-8075-5674-80f4-0b5b5f572a48.html

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U.S. oil producer ConocoPhillips reported a bigger-than-expected quarterly loss and cut its 2016 budget for the third time this year amid a crude oil slump that has lasted for two years.

ConocoPhillips, whose shares were down 1.7 percent in premarket trading, cut its capital budget to $5.5 billion from $5.7 billion.

Global oil prices have slumped 60 percent since mid-2014, prompting oil producers to scale back drilling and severely curtail spending.

ConocoPhillips said its total realized price fell to $27.79 per barrel of oil equivalent (boe) in the second quarter from $39.06 per boe, a year earlier.

The company's production dipped by 49,000 barrels of oil equivalent per day (boe/d) to 1.546 million boe/d due to the impact of wildfires in Canada among other things.

ConocoPhillips's net loss widened to $1.07 billion, or 86 cents per share, in the second quarter ended June 30 from $179 million, or 15 cents per share, a year earlier.

Excluding items, the company lost 79 cents per share, well above the average analyst estimate of 61 cents, according to Thomson Reuters I/B/E/S.

http://www.reuters.com/article/conocophillips-results-idUSL4N1AE432

National Oilwell Varco Inc, the largest U.S. oilfield equipment provider, reported a smaller-than-expected quarterly loss as cost cutting helped cushion the impact of a slump in demand from oilfield service providers.

The company, like other oilfield equipment providers, has been hard hit by a slump in crude prices that has forced customers to limit spending and cut back on drilling.

National Oilwell has been aggressively cutting costs to weather the downturn by reducing its dividend and slashing jobs.

The company has also said it is the process of closing about 200 facilities since the downturn began in mid-2014.

Oil rig count fell to 316 in May, its lowest since October 2009 and about half the 646 rigs a year earlier, according to Baker Hughes Inc rig count data.

However, drillers have added a net 46 oil rigs since early June after crude prices topped $50 a barrel. U.S. drillers added 14 oil rigs in the week to July 22, the fourth straight week of additions.

Net loss attributable to National Oilwell was $217 million, or 58 cents per share, in the second quarter ended June 30, compared with a profit of $289 million, or 74 cents per share, a year earlier.

Excluding items, the company lost 30 cents per share, smaller than the average analyst estimate of 32 cents loss, according to Thomson Reuters I/B/E/S.

The Houston-based company's revenue more than halved to $1.72 billion, missing the average estimate of $1.79 billion.

http://www.reuters.com/article/us-national-oilwell-results-idUSKCN10818W

The accumulation of gasoline stocks in the United States has been driven by excess gasoline production rather than lack of demand, according to Valero, the largest independent refiner in the United States.

"A lot of it is really more a result of utilisation, especially utilisation in periods where we typically see refineries cut," the company noted during its second quarter earnings call on Tuesday.

"Typically we see refineries cutting in the fourth quarter and the first quarter, and this year we saw refineries running very high utilisation rates" due to the steep contango in the gasoline futures market.

Valero's comments corroborate data from the U.S. Energy Information Administration showing refineries running at record rates between November and March.

Consumption of gasoline and distillate in the domestic and export markets "remain robust" executives told analysts (Conference call transcription, SeekingAlpha, Jul 28).

The company exported record volumes of gasoline and distillate fuel combined in the second quarter, particularly to Latin America, but gasoline sales at home also showed strong growth.

RUNNING IN WINTER

Valero executives were quizzed by analysts on whether demand had been overstated or whether the problem was on the supply side.

Valero chief Joseph Gorder responded: "our gasoline volumes through the wholesale are up 3 percent, and even on the distillate side, we're moving about 1 percent more through the wholesale channel of diesel than we did last year."

"We've seen very strong product demand", the company's head of supply and operations explained, but "refinery utilisation has been such that we have been able to keep up and even outpace demand."

"With the steep contango in the market, especially early in the year, some marginal refining capacity that typically you would see cut in the winter had incentive to go ahead and run and produce summer grade gasoline".

Very high rates of refinery utilisation, especially in January and February, resulted in an overhang of refined products that has persisted through the middle of the year.

The steep contango in futures prices at the start of the year encouraged refiners to produce summer-grade gasoline and send it into storage ("U.S. refiners pay price for making too much gasoline", Reuters, Jul 14).

MAXIMISING GASOLINE

The big premium for gasoline over middle distillates also encouraged refiners to shift their refining operations to produce as much gasoline as possible and reduce production of heating oil, diesel and jet fuel (tmsnrt.rs/2a1Ifhw and tmsnrt.rs/2ad74DG).

"We've been in a strong maximum gasoline signal for the most part up until about a month ago," the company's head of engineering explained, "so our assets we just had them pointed to make as much gasoline as possible".

The company foresees the need for some run cuts by the refining industry during the third and fourth quarter to rebalance the market though it would not be drawn on its own plans.

But the company did note that it had switched from maximising gasoline production to maximising the output of jet fuel by changing the cut points in its distillation process.

ECONOMIC RUN CUTS

The company denied it would use the forthcoming maintenance period to implement additional cuts in refinery throughput though it noted that other refiners might try to do so.

"We have a strategy of planning our turnarounds a couple of years in advance ... We have a big system and we don't try to move our turnarounds based on what prompt economics are. But in the rest of the industry there may be some of that," the company's engineering chief observed.

"I'm sure that people are looking at whether the refineries are struggling from a maintenance perspective and they may bring maintenance forward" and fix systems early as an effective economic run cut, he added.

EAST COAST IMPORTS

Valero executives were also asked why the United States was still importing so much gasoline, especially to the East Coast, where the build up of stockpiles has also been highest.

The continued importation of so much gasoline, as well as crude oil, at a time when domestic oil producers and refiners are struggling, has become politically controversial.

Valero explained its big refineries along the U.S. Gulf Coast have a "competitive advantage" exporting to Mexico and South America rather than moving gasoline to U.S. Northeast because of the Jones Act shipping restrictions.

Shipping gasoline from the Gulf Coast to the U.S. Northeast is more expensive because the law requires Valero to use U.S. flagged and built vessels with U.S. officers and crews.

"The natural flow of our barrels is to south into South America and there's been an incentive to send barrels from Northwest Europe into New York Harbor."

http://www.reuters.com/article/usa-gasoline-idUSL8N1AE581

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Dow Chemical Co, the No.1 U.S. chemical maker by sales, reported a better-than-expected quarterly profit as cost cuts helped boost margins.

Dow, which is merging with DuPont, plans to slash costs by $300 million this year. Of that, $90 million was realized in the second quarter.

Dow's operating margin expanded by 160 basis points to 21 percent on an earnings before interest, taxes, depreciation and amortization (EBITDA) basis.

Dow and DuPont have been clearing the decks ahead of the expected closure of their merger this year.

The deal, valued at $130 billion when it was announced in December, is the first step toward breaking the businesses into three separate companies focused on agriculture, material science and specialty products.

DuPont also reported a higher-than-expected quarterly profit on Tuesday, and forecast a 50 percent jump in third-quarter operating earnings as it steps up cost cutting.

Dow's strategy to focus on high-margin products by shedding volatile commodity businesses such as its century-old chlorine business are also paying off.

The company's net income attributable to shareholders nearly tripled to $3.12 billion, or $2.61 per share, in the quarter ended June 30.

Excluding items, it earned 95 cents per share, much higher than the average analyst estimate of 85 cents, according to Thomson Reuters I/B/E/S.

These items included a $2.20 per share gain related to the Dow Corning deal.

However, sales fell 7.4 percent to $11.95 billion.

Dow said in December it would assume full control of Dow Corning, its venture with Gorilla glass maker Corning Inc.

http://www.reuters.com/article/dowchemical-results-idUSL4N1AE40C

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Mexico's oil regulator on Wednesday said state-owned oil company Pemex must take a minimum 45 percent stake in its first-ever proposed joint venture with would-be private partners to develop oil reserves in the Gulf of Mexico's deep waters.

Global oil majors are widely expected to bid in the December auction to help develop the Trion light oil field in the Perdido Fold Belt just south of Mexico's maritime border with the United States.

Companies such as Royal Dutch Shell and Exxon Mobil operate lucrative developments in nearby U.S. waters while Mexico has yet to achieve commercial production on its side of oil-rich Perdido due to a lack of technical expertise to tap such fields.

The call for bids to partner with cash-strapped Pemex on Trion follows the constitutional energy reform enacted in 2013 which promised to reverse a decade-long slump in crude production by luring new players to explore for and produce oil.

The regulator said the Trion joint venture will be bid out in the form of a license contract, which is similar to a concession, and will include two operators, one of which must have between a 30 to 45 percent stake in the project.

Interested bidders have until Sept. 15 to pre-qualify for the auction by meeting both financial and technical minimum requirements, while the final version of the contract and bid terms will be published on Sept. 30.

The license contract to partner with Pemex on the project will be awarded on Dec. 5. Mexico will also auction 10 separate deep water fields, including four that surround Trion, in December.

Under the terms of the energy reform, Pemex can partner with companies in exploration and production projects, but rather than being allowed to pick its partners, they will instead be selected by an auction run by the oil regulator, known as the National Hydrocarbons Commission.

The partnership will allow Pemex to share the investment needed to successfully develop the field, the company's first major deep water oil project.

The Trion field holds some 480 million barrels and will require about $11 billion worth of investment.

The field covers about 483 square miles (1,250 square km) and is located under more than 8,202 feet (2,500 meters) of water.

http://in.reuters.com/article/mexico-oil-pemex-idINL1N1AD18Z

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Anglo/Dutch oil giant Royal Dutch Shell on Thursday posted a sharp drop in second quarter 2016 profit compared to a year earlier quarter as lower oil and gas prices weighed on the company’s earnings.

On a current cost of supplies (CCS) basis, Shell’s 2Q 2016 earnings were $239 million, a drop of 93% from $3.361 billion in the first quarter of 2015.

On a CCS basis, Shell’s 2Q 2016 earnings, excluding identified items, were $1.045bn, a fall of 72% from $3.76bn in the second quarter of 2015.

Shell explained that, compared with the second quarter 2015, CCS earnings attributable to shareholders excluding identified items were impacted by the decline in oil, gas and LNG prices, the depreciation step-up resulting from the BG acquisition, weaker refining industry conditions, and increased taxation. Earnings benefited from increased production volumes from BG assets.

During the quarter, Shell’s capital investment was $6.3bn.

Oil and gas production in 2Q 2016 was 3.508 million barrels of oil equivalent per day, an increase of 28% compared with the second quarter 2015. The impact of BG on the second quarter 2016 production was an increase of 768 thousand boe/d.

Shell’s CEO Ben van Beurden said: “Downstream and Integrated Gas businesses contributed strongly to the results, alongside Shell’s self-help programme. However, lower oil prices continue to be a significant challenge across the business, particularly in the Upstream.

“We are managing the company through the down-cycle by reducing costs, by delivering on lower and more predictable investment levels, executing our asset sales plans and starting up profitable new projects.”

http://www.offshoreenergytoday.com/shell-posts-sharp-drop-in-profit-over-low-oil-prices/

French oil and gas company Total said it had met its cost saving target ahead of schedule as it reported a better-than-expected rise in second quarter net profit led by increased output and a rebound in oil prices.

Total said it had achieved $900 million in savings so far this year. On top of $1.5 billon saved last year, this brings it to its targeted $2.4 billion of savings for the period leading up to the end of 2016. It now hopes to save more by year-end.

Chief Executive Officer Patrick Pouyanne said that while oil prices remained volatile, Brent crude had recovered from the start of the year to average $46 per barrel in the second quarter.

"Total captured the benefit of this rebound, and adjusted net income rose to $2.2 billion in the second quarter 2016 (versus the first quarter), an increase of 33 percent compared to the first quarter," Pouyanne said in statement.

Compared with a year ago though, the fourth-biggest western oil company's revenue fell 17 percent to $37.215 billion, reflecting much lower oil prices and even though oil production in the quarter rose by over 5 percent.

A Reuters poll of analysts had forecast second quarter net adjusted profit of $1.9 billion, expecting production levels to be lower.

Total said the increase in oil output due to new projects coming on stream was dampened by deteriorating security in Nigeria and Yemen, and forest fires in Canada.

It said projects in Bolivia and Kazakhstan were expected to start in the second half of the year, helping it meet a 4 percent production growth target in 2016.

Capital expenditure in 2016 is expected to be $18-19 billion, it added.

Total kept its dividend unchanged for the second quarter, at 0.61 euros per share to be paid in January.

http://www.reuters.com/article/total-results-idUSP6N196037

Brazil’s oil exports used to cover Chinese debt obligations

Brazil is considering scrapping nationalistic oil legislation – which was implemented by President Dilma Rousseff – in favor of a concession model which would attract more international investment. While the legislation was put in place to primarily benefit Petrobras, widespread corruption in the state-run oil company and low oil prices have led to the change of heart. While the changing of legislation may take up to a couple of years, its implementation would remove the obligation for Petrobras to operate all oil fields – encouraging outside investment.

According to our ClipperData, Brazilian crude exports averaged just shy of 600,000 bpd last year, and are currently closer to 560,000 bpd this year. The leading recipient of Brazilian crude is China, accounting for about a third of exports. Brazil currently has a $10 billion credit line with China, which it is repaying in cash or oil, depending upon China’s request.

This is in addition to a deal where Petrobras sends up to 200,000 bpd per month to China, in a long-term deal struck in 2009 (hark, their last financial crisis). Uruguay is a close second in terms of export volumes, while the U.S is a distant third, accounting for ~10%. India is fourth.

http://fuelfix.com/blog/2016/07/27/market-currents-brazils-oil-exports-used-to-cover-chinese-debt-obligations/

Iraq is negotiating with Exxon Mobil Corp. and Petrochina Co. to develop two oil fields in the south of the country as it seeks to maintain overall production at about 4.8 million barrels a day for the rest of 2016, Deputy Oil Minister Fayyad Al-Nima said.

The companies have submitted offers to develop the Artawi and Nahran Omar fields, which Iraq’s Oil Ministry hopes will produce a combined 550,000 barrels a day, Al-Nima said Wednesday in an interview in Baghdad. The fields together are pumping about 70,000 barrels daily, and the ministry wants to start the project in six months, he said. Al-Nima assumed the duties of oil minister after Adel Abdul Mahdi suspended his participation in the cabinet in March.

Iraq, OPEC’s second-biggest member, is producing 4.78 million barrels a day, with 4 million barrels coming from fields in the south, Al-Nima said. The self-governing Kurdish region in northern Iraq contributed the remainder, pumping more than 700,000 barrels a day independently of the central government, he said. Exports from the south are averaging 3.19 million barrels a day, and the ministry sees shipments reaching 3.2 million by month-end and staying at about that same level until the end of the year, he said.

http://www.bloomberg.com/news/articles/2016-07-27/iraq-seeks-exxon-petrochina-help-to-develop-two-oil-fields

French oil services company Technip said on Thursday plans to cut spending due to the fall in oil prices was ahead of schedule as it reported a better-than-expected second quarter revenue.

* Technip says cost reduction plan ahead of schedule with 900 million euros ($995.94 million) savings to be delivered by 2016 (previously  700 million) out of the total planned of 1 billion euros.

* Technip says adjusted revenue at 2.8 billion euros, stable versus 1Q 16; balanced between both business segments.

* Says Adjusted operating income from recurring activities at 260 million euros, net Income of  123 million.

* Says upgrades 2016 objectives.

* Order intake in the second quarter at 1.5 billion euros.

* Says continue to expect for some time yet a slow rate of new orders and continued competitive pressure across the industry, notably for offshore developments: the prolonged and harsh downturn has not ended.

* Says received a successful early conclusion of the U.S. antitrust review from U.S. regulators.

http://www.reuters.com/article/technip-results-idUSP6N196038

Italian major Eni has been ordered to stand trial in a long-running case of alleged bribery in Algeria involving related company Saipem, which used to be a full Eni subsidiary.

Milan-based Eni on Wednesday confirmed reports that it has been ordered by a judge in Italy to stand trial over the alleged actions, but denied it was involved in any wrongdoing.

“In relation to court proceeding for the alleged bribery case relating to Saipem’s activities in Algeria, Eni acknowledges that the new GUP (judge for the preliminary hearing) in charge of the case decided the commitment for trial for Eni,” a brief statement on Wednesday read.

“Eni continues to deny any illegal conduct and is confident that this will be ascertained in court proceeding.”

Reuters reported earlier in the day that the Italian judge had ordered Eni, Saipem and immediate past Eni chief executive Paolo Scaroni to stand trial over the allegations.

Saipem has stated to various media outlets that it is confident that the impending trial will prove any allegations against it are groundless.

A lawyer acting for Scaroni told Bloomberg that he is confident judges will prove his client's innocence.

In October a Milan court ruled that Saipem and five individuals should stand trial on charges that the contractor secured deals in Algeria through bribery. However, that ruling cleared Eni and Scaroni in the case.

Prosecutors at that time alleged that Saipem paid intermediaries €197 million ($216.7 million today) to win contracts worth €8 billion with Algeria’s state-owned Sonatrach. The charges related to events that took place up to the beginning of 2010.

http://www.upstreamonline.com/live/1439858/eni-to-stand-trial-over-algeria-payments?utm_source=twitterfeed&utm_medium=twitter

"PADD 1 Is A Holy Mess" - Is This What Finally Drags Crude Oil Lower

Several months ago we reported that the next big threat to oil prices had nothing to do with oil fundamentals, either lack of demand or excess supply, or technicals, i.e., algo buying or selling, and everything to do with the upcoming glut of the most important crude byproduct: gasoline.

Sure enough, now that summer is here, this prediction is playing out just as expected and as Reuters reports, summer driving season is in full swing and American motorists are filling their tanks at a healthy clip, but that is not swelling the profit margins as much as usual at U.S. independent oil refiners such as PBF Energy and Valero Energy Corp.

How come?  As it turns out, the optimism that refiners had in the spring that the gasoline excess would clear out has not materialized. During the first quarter earning season, refining executives shrugged off the industry’s lousy earning as an aberration that would be remedied this summer. “We still are bullish gasoline and bullish octane," PBF CEO Tom Nimbley told investors in an earnings call back then. “The driving season really hasn't hit that hard yet.”

It has now, and while Nimbley was right about the surging summer demand, refiner margins are still being squeezed as gasoline and diesel inventories stubbornly sit well above five-year averages. Historically, summer gasoline demand usually fattens margins for refiners with seasonally high levels for the crack spread, the premium of a barrel of gasoline over a barrel of crude oil. But not this year said analysts who expect the situation to remain bleak in the weeks ahead unless there are large drawdowns in inventories.

Earlier today the DOE reported a modest 122K drawdown in gasoline stocks, which however is nowhere near enough to pressure gasoline inventories lower which remain much higher than they were last year at this time, and analysts have slashed earnings estimates for big U.S. refiners who report second-quarter results in coming weeks.

Nowhere is the situation more dire than the US East Coast, where refineries have been forced to cut production, just as we forecast several months ago they would have to as the relentless supply in crude did not balance out the demand for refined product. As Reuters points out, refiners on the East Coast, also known as "PADD 1" by the U.S. Energy Department, are typically the first to feel a profit pinch, because their margins tend to be thinner than those of other regions.

“PADD 1 is a holy mess,” said Andrew Lebow, senior partner at Commodity Research Group in Darien, Connecticut. “It is very unusual. If a market becomes extremely oversupplied, like PADD 1, they are going to have to cut runs.” That is another way of saying refiners will have to stay shut, which in turn will force crude to  build up in various on and offshore storage locations.

As a result, the U.S. gasoline crack spread a proxy for refiner margins, has dropped 34 percent in two weeks. On Wednesday, it hit a five-year low for this time of year below $13 a barrel. That is less than half the crack spread of $28 a barrel at this time last year.

http://www.zerohedge.com/news/2016-07-07/padd-1-holy-mess-what-finally-drags-crude-oil-lower

                                                Last Week  Week Before     Last Year

Domestic Production '000.......... .. 8,515            8,494               9,413
Alaska .......................................    482                449                   460

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

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U.S. crude oil refinery inputs averaged 16.6 million barrels per day during the week ending July 22, 2016, 277,000 barrels per day less than the previous week’s average. Refineries operated at 92.4% of their operable capacity last week. Gasoline production increased last week, averaging about 10.1 million barrels per day. Distillate fuel production decreased last week, averaging over 4.9 million barrels per day.

U.S. crude oil imports averaged over 8.4 million barrels per day last week, up by 303,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged 8.2 million barrels per day, 8.7% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 869,000 barrels per day. Distillate fuel imports averaged 93,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 1.7 million barrels from the previous week. At 521.1 million barrels, U.S. crude oil inventories are at historically high levels for this time of year. Total motor gasoline inventories increased by 0.5 million barrels last week, and are well above the upper limit of the average range. Finished gasoline inventories decreased while blending components inventories increased last week. Distillate fuel inventories decreased by 0.8 million barrels last week but are above the upper limit of the average range for this time of year. Propane/propylene inventories rose 2.2 million barrels last week and are at the upper limit of the average range. Total commercial petroleum inventories increased by 2.7 million barrels last week.

Total products supplied over the last four-week period averaged over 20.2 million barrels per day, up by 0.7% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged about 9.8 million barrels per day, up by 2.6% from the same period last year. Distillate fuel product supplied averaged over 3.7 million barrels per day over the last four weeks, up by 0.2% from the same period last year. Jet fuel product supplied is up 4.2% compared to the same four-week period last year.

Cushing inventory up 1.1 mln

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

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The parade of quarterly updates continues. CONSOL Energy, once one of the largest coal companies in the U.S., now one of the largest independent drillers in the Marcellus and Utica Shale, issued their update. And in interesting one it is.

After having idled its rigs, CONSOL reports they will begin a “modest” drilling program once again in August. However, the strategy is shifting. CONSOL plans to drill eight new Utica wells (in Monroe County, OH) and only two new Marcellus wells (in Washington County, PA).

CONSOL will own 100% of the Utica wells but only has a 50% working interest in the Marcellus wells–which may be the biggest reason why they are focusing on the Utica for now.

Also in the update: CONSOL’s natgas production jumped 32% in 2Q16 over 2Q15. The big financial news is that CONSOL lost $470 million in 2Q16, but that’s an improvement over 2Q15 when the company lost $603 million.

Revenue dropped almost in half–from $545 million in 2Q15 to $286 million in 2Q16. Yesterday’s comprehensive update contains breakdowns of production by shale play, details on a 10-well “plugless” completion, and much more.

http://marcellusdrilling.com/2016/07/consol-energy-to-restart-drilling-in-august-mainly-in-utica/

Range Resources, one of the largest (and the very first) Marcellus Shale drillers, issued their second quarter 2016 update.

While there was plenty of good news Range highlighted at the beginning of the release–Marcellus production was up 16% year over year at 1.379 billion cubic feet per day, costs were down 8%, total debt as low as it’s been since 2012–there was no getting over the 800-pound gorilla in the room: Range lost $225 million for the quarter in 2Q16, versus losing $119 million in 2Q15.

One of the things Range seems most jazzed about is buying Memorial Resource Development Corp. and drilling in Louisiana instead of the Marcellus.

CEO Jeff Ventura did mention the company can quickly ramp up drilling on 200 well pads in the Marcellus when/if the time is right.

http://marcellusdrilling.com/2016/07/range-resources-loses-225m-in-2q16-marcellus-production-up-16/

Capital expenditure cuts of $150 billion for 2016 and 2017 by U.S. exploration and production companies are expected to result in average production losses of 4.2 million barrels per day in the Lower 48 through 2020, according to Wood Mackenzie.

This is not only a trend in the U.S., with upstream companies around the world trimming capex by more than $370 billion for 2016 and 2017. Wood Mackenzie believes that this will impact oil production and the world will result in 7 billion fewer barrels of oil through 2020.

“The plays that saw the highest proportion of their capital expenditure cut were Eagle Ford and the Bakken,” said Jeanie Oudin, Wood Mackenzie Senior Research Manager, Lower 48. “That’s because the two plays were in full-scale development, with most operators' acreage held by production at the time oil prices began to fall, allowing for a more responsive slowdown in activity,” she added, asquoted by Oil and Gas Journal.

While Bakken and Eagle Ford plays account for thirty-six percent of those cuts, the Midland and Delaware Basins have witnessed fewer declines in drilling activity.

“People expected that overall tight oil production would collapse when companies stopped drilling; however, it hasn’t collapsed, it’s only declined,” said Oudin. “Not only have operators built up a backlog of DUC wells, they are also utilizing longer laterals and enhanced completions to increase the productivity of wells as they bring them online. They’re just not adding new volumes as quickly.”Related: Forget The Glut – This Is Why Oil Prices Will Rise

When the shale boom started, the output from the new wells dropped by 90 percent in the first-year itself. By 2012, North Dakota’s Bakken shale four-month decline rate reduced to 31 percent, and in 2015, the decline rate stood at only 16 percent for the same time frame, according to data compiled and analyzed by oilfield analytics firm NavPort for Reuters.

Similarly, in the Permian Basin of West Texas, the drop from the peak production through the fourth month of a new well’s life has improved from 31 percent decline in 2012 to 18 percent in 2015.

"We're exposing more of the reservoir and breaking it up so we don't get as sharp a decline," Scott Sheffield, chief executive of Pioneer Natural Resources Co, a top Permian producer, told a recent energy conference, reports Reuters.

The recovery in crude prices from below $30 to $50 per barrel has led to an increase in the onshore oil active rotary rig count, as measured by Baker Hughes, which will lead to an increase in production from new wells after a few months, as shown in the chart below.



Nevertheless, the Eagle Ford rig count is still 60 percent below previous year’s numbers.Related: Faulty Data? Why The Oil Glut Could Be Much Smaller Than Believed

Higher crude prices have also encouraged companies with a strong balance sheet to announce large mergers and acquisitions (M&A). The average value of the deals stood at $182 million, in the second quarter of 2016, the largest since the third quarter of 2014, which further increased to $199 million for the seven deals announced in the first three weeks of July, reports the U.S. Energy Information Administration.

The largest among the deals was the $560-million purchase of Permian Basin leasehold interests by Diamondback Energy from Luxe Energy LLC.

If the recovery in oil prices continues in the second half of the year, a few companies are likely to revise their capex up, however, if prices again correct, this will deliver a blow to the improving sentiment across the industry.

http://oilprice.com/Energy/Crude-Oil/Low-Oil-Prices-Kill-Off-7-Billion-Barrels-Of-Oil-Production.html

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Amid an unprecedented global gasoline glut, the world’s oil refineries are finding a little solace in fuel oil, the product they try not to make. Russian plants, encouraged by the government, are making less and less of the substance that propels ships and is a feedstock in some power plants. With about three-quarters of that ever-diminishing output hitting export markets, fuel oil futures for North West Europe are close to the smallest discount to crude since 2014.

http://www.bloomberg.com/news/articles/2016-07-27/global-oil-refineries-get-surprise-gift-from-russia-chart

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A company set up by investment fund Emerstone Energy has won a contract for shale gas exploration in Ukraine, after Royal Dutch Shell PLC withdrew as separatist violence erupted in Ukraine's east.

State company Nadra Ukrainy on Wednesday named Yuzgas B.V. as the winner of the tender.

Shale would help Ukraine's ambitions to cut its gas purchases from Russia. Relations between the two plunged after Moscow's 2014 annexation of Crimea.

The Yuzivska Field of 7,800 square kilometers could, according to preliminary estimates, yield about 8-10 billion cubic metres of gas per year.

It is located in the Kharkiv and Donetsk regions in areas bordering territory seized by pro-Russian separatists. Since 2014 the conflict there has claimed more than 9,400 lives.

Ukraine in 2015 produced about 20 billion cubic meters of gas and imported 16.5 billion.

"In circumstances of falling world oil prices Ukraine sharply reduced the search of hydrocarbons," Nadra Ukrainy said in a statement without giving an exact amount of planned investments. "That is why it is important that the winner committed to invest several hundred million dollars into the programme of geological exploration at the Yuzivska site."

Yuzgas B.V. says on its website it was set up specifically for the tender by Emerstone Energy, owned by Emerstone Capital Partners.

The latter was founded by Jaroslav Kinach, head of a private Canadian company Iskander Energy Corp and a former Ukraine country head of the European Bank for Reconstruction and Development (EBRD).

http://www.reuters.com/article/ukraine-shalegas-idUSL8N1AD3EH

U.S. oil producer Hess Corp (HES.N) reported a smaller-than-expected quarterly loss, helped by its efforts to keep costs low, and the company further cut its exploration and production budget for the year.

Oil producers have been drastically cutting their capital budgets for the year in response to the slump in oil prices that began in June 2014. Hess cut its E&P budget by $300 million to $2.1 billion.

Hess also cut its production forecast for 2016, mainly because of unplanned downtime at two Gulf of Mexico fields.

The company now expects net production of 315,000-325,000 barrels of oil equivalent per day (boepd), down from its previous forecast of 330,000-350,000 boepd.

The oil producers' net loss narrowed to $392 million, or $1.29 per share, in the second quarter ended June 30 from $567 million, or $1.99 per share, a year earlier.

The company reported an adjusted loss of $1.10 per share, while quarterly revenue fell 34.4 percent to 1.27 billion.

Analysts were expecting a loss of $1.24 per share and revenue of $1.21 billion for the quarter, according to Thomson Reuters I/B/E/S.


http://www.reuters.com/article/hess-results-idUSL4N1AD44J

2016 will see the start of a barren period for the offshore oilfield service (OFS) sector. A significant drop in project sanctioning brought about by the downturn, coupled with low rig dayrates, will see annual expenditure average $48.6 billion (bn) over 2016-2020, 25% lower than 2014's annual total of $65.3bn. The recent growth in offshore drilling seen since 2010 has been sharply halted - offshore well spuds saw an 8% reduction last year and a further 9% is anticipated for 2016. Even in the event of a rapid recovery in oil prices, offshore activity will be supressed as a result of final investment decisions (FIDs) for several developments in key offshore basins have been deferred - including Anadarko's flagship Shenandoah project and Woodside's Browse FLNG.

Asia - the largest-spending region - is predicted to see a 9% drop in drilling activity in 2016 as a result of Capex cuts from China's CNOOC as well as independents and supermajors cutting back in Indonesia and Malaysia. Also contributing to the decline is the scaling-back of operations by Chevron in the Gulf of Thailand - where in recent years the company has drilled thousands of wells. DW predicts offshore spending in Asia will decline to $15.2bn in 2017 before rallying slightly to $16.5bn by the 2020 - though it must be noted this is still 74% of 2014's peak.

Elsewhere, all other regions covered in this report will see declines in spending over the forecast period with the exception of the Middle East - where annual spending will increase 5% year-on-year from $6.6bn to $7.4bn over 2016-2020. This will largely be as a result of the full implementation of the giant South Pars gas development as well as brownfield developments of some of the world's largest offshore oilfields - namely Safaniya (Saudi Arabia) and Upper Zakum (United Arab Emirates).

As well as the drop in drilling activity, suppression of offshore rig dayrates will be a big issue for offshore OFS expenditure. The offshore drilling sector is currently heavily oversupplied with units brought to market during the boom years of 2011 to 2014, despite widespread scrapping of older rigs. DW therefore estimate offshore rig & crew spending will decline 2% year-on-year over 2016-2020.

Considering operators significantly cutting spending in most offshore plays and the current rig oversupply, DW foresee a flat trend in offshore OFS expenditure for the rest of the decade following declines in 2015 and 2016. Even in a scenario of a rapid recovery in oil prices, it is unlikely spending will recover to 2014 levels until well into the 2020s.

http://www.oilvoice.com/n/Global-Oilfield-Services-Offshore-Spending-Stuck-in-the-Doldrums/7b9a305863d0.aspx

Foreign engineering companies have bid to build Saudi Aramco's clean fuels project at the state oil giant's Ras Tanura refinery, industry sources told Reuters.

The bid deadline was July 17 for the $2 billion-plus scheme which will remove sulphur from refined oil products and is part of a drive by the kingdom to meet stricter environmental standards in export markets.

The project is split into two packages, one which includes the clean fuels units and the other for the supporting utilities and offsites.

Companies which bid for both packages, sources said, were:

-Japan's JGC

-South Korea's GS

-Hyundai Engineering and Construction

-Samsung Engineering

-Tecnicas Reunidas

Companies that only bid for the utilities and offsites package were:

-UK's Petrofac

-India's Larsen and Toubro

Saudi Aramco does not discuss ongoing business plans, it said in response to a Reuters emailed query.

Both Samsung Engineering and Hyundai Engineering & Construction confirmed they had bid for both packages but declined to give other details.

A spokesman for JGC in Yokohama said the company is interested in the project, but declined to comment on whether or not it bid.

Petrofac and GS Engineering & Construction Corp declined to comment.

Tecnicas Reunidad declined to comment while Larsen and Toubro did not immediately respond to an emailed request for comment.

The Ras Tanura project, including a naphtha hydrotreater, was to be part of a second phase of upgrades to Aramco's refineries and was originally due to go on stream in 2016.

There had been fears the project would be scrapped, part of a long list of schemes scrapped by global oil majors which have been paring back investments to cope with lower oil prices.

This was not helped by the fact there have been at least three rounds of bidding for the project.

However, Saudi Aramco has said it is proceeding with its key projects. Chief Executive Amin Nasser saying last week it was evaluating the project at its largest and oldest oil refinery in Ras Tanura.

Last week, Aramco signed deals to build a 50-billion riyal ($13.33 billion) plus gas project in Fadhili and has said more projects are in the pipeline to keep up with growing gas demand needs for power generation and industry.

http://www.reuters.com/article/saudi-aramco-refinery-idUSL8N1AC3WC

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Cyprus received expressions of interest from ENI, Total, Statoil, Exxon Mobil, Qatar Petroleum, and Cairn in a licensing round for offshore hydrocarbon blocks which lapsed last week, its energy ministry said on Wednesday.

Cyprus had placed three offshore blocks up for exploration. The most pronounced interest from two consortia and one company was for an offshore sea block in close proximity to the Zohr field offshore Egypt, where ENI reported the discovery of an estimated 30 trillion cubic feet of natural gas last year.

The east Mediterranean island is located in the Levant basin, where both Israel and Egypt have made some of the world's biggest natural gas discoveries in the past decade.

Cyprus found an estimated 4.5 trillion cubic feet of natural gas in one prospect in late 2011.

Cairn through its Capricorn Oil unit had applied jointly with Israel's Avner and Delek over one block, ENI and Total jointly over two blocks, ENI on its own over another, Exxon Mobil and Qatar Petroleum over one, and Statoil Upsilon Netherlands B.V. on its own, a news release from the Cypriot energy ministry said.

http://www.reuters.com/article/cyprus-gas-bids-idUSL8N1AD38L

Norwegian oil giant Statoil on Wednesday posted a loss for the second quarter of 2016 due to low oil prices, compared to a profit in the same period last year, and decided to cut its capex guidance by $1 billion.

The company’s net operating income in the second quarter 2016 dropped to $180 million, compared to $3.6 billion in the same period of 2015. The reduction was primarily due to the drop in prices for oil and gas and lower refinery margins. Cost reductions contributed positively to the results.

Statoil reported a loss of $302 million for the quarter, compared to a profit of $866 million in the corresponding quarter of 2015.

Further, the company’s revenues dropped 37 percent during the quarter to $10.895 billion, from $17.4 billion in the same period last year.

The Norwegian company delivered equity production of 1,959 mboe per day in the second quarter. The underlying production growth in the quarter, after adjusting for divestments, was 6% compared to the second quarter of last year.

Statoil said it is lowering its capex guidance for 2016 from $13 billion to $12 billion and its exploration guidance for 2016 from $2 billion to $1.8 billion. Production guidance remains unchanged, and expected annual organic production growth is 1% from 2014 to 2017.

“We delivered solid operational performance with strong production growth and progress on project development and execution. Our financial results were affected by low oil and gas prices in the quarter,” says Eldar Sætre, President and CEO of Statoil ASA.

http://www.offshoreenergytoday.com/statoil-sinks-to-red-in-2q/

Unconventional development in the US Lower 48 has been the most reactive to the oil price collapse, with operators nimbly halting drilling plans and scaling back activity to balance the books.

US tight oil operators drilling with positive NPV today are generating interest for investors, but will they continue to be economic in the future? After looking at data for more than 120 operators across the Lower 48, we can see where the largest low-cost inventories reside.

While most operators across the major tight oil plays high-graded to the core, focusing the majority of spend on the more prolific and economic areas, operators in the Bakken withdrew the most rigs and stopped development in hundreds of wells - so much so, that the Bakken is now home to more drilled but uncompleted wells (DUCs) than any other play in the US Lower 48.

These DUC inventories are critical to forecasting production volumes and are responsible for a slower production and supply reponse relative to the rig count, as rigs are no longer fully indicative of how many wells will be brought online. These DUCs provide cash flow to these operators, enabling them to focus on completions at will once rig commitments expire.

US Lower 48 DUC backlog and horizontal rig count



The Permian, after a decade in the shadows of the Bakken and the Eagle Ford, is showing more promise in the US tight oil space due to its substantial drilling inventory of stacked pay and low breakeven resource.

Compared to our global view in 2014, we now expect 7 billion boe less will be produced from 2016 to 2020, with the US Lower 48 accounting for more than 70% of those volumes in the near-term, through 2017. The agility that brought costs and breakevens down will slowly resurrect them again, with dormant inventories coming online and getting back on track to profitability.

http://www.woodmac.com/lp/highest-returns/Lower48_NPV/?utm_source=twitter&utm_medium=social&utm_campaign=sm-lower48-capex-buyside&utm_content=p

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For international oil companies that saw access to Brazil’s gargantuan offshore reserves curtailed back in 2010, the tide is turning.

Brazil’s interim government is studying the benefits of scrapping nationalistic oil legislation that was championed by now suspended President Dilma Rousseff and her leftist Workers’ Party, said three people involved in the discussions who asked not to be to be named because the plans aren’t public. The government is considering going as far as returning to a concession model that companies prefer and consider more profitable, the people said.

The studies are expected to be presented in September to Acting President Michel Temer, who has yet to take a side in the debate, one of the people said. The plans under study go beyond a bill currently in Congress that, if passed, would remove the obligation that state-controlled oil company Petrobras operate all pre-salt fields even if it doesn’t find them attractive.

The discussion has just begun and any changes to the oil legislation would require a broad debate in Congress, which could take a couple of years, the people said. Rousseff’s predecessor, Luiz Inacio Lula da Silva, put Petrobras in charge of the country’s most prolific oil fields during the commodities boom. The Workers’ Party also pursued interventionist policies in the electricity industry, discouraging foreign investment.

Temer’s press office didn’t respond to an emailed request for comment on studies to change the auction model for the pre-salt oil fields.

Ideological Issue

Under the current production-sharing model for Brazil’s most promising offshore region known as the pre-salt, Petrobras and its partners share a portion of production with the federal government through a consortium member known as PPSA, which represents the government’s interests. The first and only time this model was put to the test at the Libra field auction in 2013, only one consortium participated and paid the minimum signing bonus, underscoring the reluctance by foreign oil companies.

The rules governing access to the country’s oil reserves are a deeply ideological issue for many Brazilian, especially members of Rousseff’s Workers’ Party who accuse Temer of trying to hand Brazil’s geologic riches to foreign oil companies. But now Brazil’s oil industry, dominated by Petrobras, has been slammed by widespread corruption, government interference and low oil prices, and those who support changing the legislation say new rules are necessary to attract investment and create jobs.

A return to a more traditional concession model for the pre-salt fields, which hasn’t yet been discussed publicly, could generate more competition at licensing rounds and accelerate the development of the region, bringing much-needed tax revenue to producing states and the federal government. The concession regime doesn’t have a mandatory participation by the state, and all oil production belongs to concession partners after paying royalties and taxes.

Even if Temer decides to throw his administration’s support behind such changes, the legislation would probably not be sent to Congress until at least next year, two of the people said.

The government is also preparing other changes that could be implemented faster to attract foreign investment to the industry. The government plans to start announcing new measures in August that include easing buy-in-Brazil requirements, extending a tax refund on imported equipment, and clarifying how to develop oil deposits that extend outside of the concession boundaries into unlicensed acreage, Oil and Gas Secretary Marcio Felix said in a Tuesday interview. The lack of clarity has delayed several large discoveries, including Petrobras’ Carcara field and Gato do Mato, operated by Royal Dutch Shell Plc, he said.

http://www.bloomberg.com/news/articles/2016-07-26/brazil-said-to-study-scrapping-nationalist-deep-water-oil-rules

Valero Energy Corp, the largest U.S. refiner, expects to get hit with a half-billion-dollar bill in the second half of the year thanks to the rising cost of meeting government mandates to blend biofuels.

For the full year, the company's cost to blend renewable fuels like ethanol will swell to between $750 million to $850 million, mainly to pay for the paper credits used to meet the U.S. biofuels program, the Renewable Fuel Standard (RFS), the San Antonio, Texas-based refiner said on Tuesday as it reported second-quarter results.

The RFS program requires oil refiners and importers to blend more renewable fuel or buy paper credits in an opaque, sometimes volatile market. Compliance credits to meet the standards, known as Renewable Identification Numbers (RINs), were about 25 percent higher in the second quarter than a year earlier.

It is another blow for the company, which is already dealing with weak refining margins.

The price tag would be up from the $440 million Valero paid for biofuels compliance in 2015, the most it has paid to meet RFS requirements since at least 2009, according to U.S. Securities and Exchange Commission filings.

Valero spent about $334 million in the first six months of 2016 on biofuels compliance, the company said.

Elevated costs for RINs credits are one of the headwinds the company faces, said John Locke, Valero's vice president of investor relations, on a call with investors.

The biofuels program was launched more than a decade ago to boost the use of renewables to cut greenhouse gas emissions and promote energy independence. This year's more ambitious requirements could hurt U.S. refiners, already facing what could be their worst year since the shale boom began.

That puts expected second-half costs at as much as $516 million, nearly matching the $517 million it spent for all of 2013, when RIN prices surpassed a record of $1.40 apiece. The current price is around 96 cents.

Prices of RINs have been rising since regulators set annual targets in May for the amount of biofuels including ethanol required to blend with gasoline and diesel and as worries have mounted of tightening inventories.

"If I'm a refiner with a lot of gasoline and distillate production, why wouldn't I be concerned about rising RIN prices? The conditions are there for them to (rise)," said Timothy Cheung, vice president at ClearView Energy Partners in Washington. He estimated that RIN prices could rise another 25 percent by year-end.

Valero and companies such as Delta Air Lines Inc (DAL.N), which owns a refinery, are stepping up their push to get regulators to tweak the program to shift onus to comply further downstream.

http://www.reuters.com/article/us-valero-energy-results-biofuels-idUSKCN1062K4

Oil and gas producer Anadarko Petroleum Corp (APC.N) reported a smaller-than-expected quarterly loss as it cut costs to counter a prolonged slump in crude prices.

The company, which has cut this year's capital budget by half, said costs were lower by 11.8 percent in the quarter ended June 30.

The company said early this year that it laid off about 1,000 workers and sold more than $1 billion in assets.

Texas-based Anadarko raised the mid-point of its full-year sales volume forecast by 2 million barrels of oil equivalent (MMBOE) on increased sales from Gulf of Mexico, Delaware and DJ basins. The company estimated in March sales volumes of 282-286 MMBOE after adjusting for divestitures.

Net loss attributable to Anadarko was $692 million, or $1.36 per share, in the second quarter, compared with a profit of $61 million, or 12 cents per share, a year earlier.

Excluding items, the company lost 60 cents per share, compared with analysts' average estimate of 80 cents, according to Thomson Reuters I/B/E/S.

Revenue fell 27 percent to about $1.92 billion, above analysts' estimate of about $1.89 billion.

http://www.reuters.com/article/us-anadarko-petrol-results-idUSKCN1062J5

Chemical company BASF's adjusted operating profit dropped 16 percent in the second quarter, hurt by a slump in oil and gas unit and by weak demand for its agricultural pesticides.

The world's largest chemical company by sales reported earnings before interest and tax (EBIT), adjusted for one-off items, of 1.7 billion euros, compared with the average forecast for 1.71 billion in a Reuters poll of analysts.

The group reaffirmed its forecast for a considerable decline in 2016 sales - due to the sale of its gas trading business and as it adjusts prices to lower energy and raw material costs - and for adjusted EBIT to be slightly below the year-earlier level.

It repeated that the goal was ambitious and depended on oil prices.

http://www.reuters.com/article/us-basf-se-results-idUSKCN1070FA

Just last week MDN predicted that Atlas Resource Partners (ARP), a publicly-traded exploration and production master limited partnership (“MLP”) with operations in basins across the United States including the Marcellus and Utica Shale plays, was heading for a bankruptcy.

Yesterday ARP announced it has been working behind the scenes with the people it owes money (lenders and bondholders) on a deal to convert their debt into common units (in essence, shares of stock). The deal worked out will eliminate $900 million in debt ARP owes.

The deal is like many others we’ve written about over the past six months or so–where a company waves the magic wand and turns debt into ownership.

The problem with these plans, in our humble opinion, is that it punishes those who currently own equity in the company. The stockholders (in this case, since it’s a master limited partnership, called unitholders), find their shares are devalued to the point of being worth toilet paper.

We live in a screwed up world where owning debt is better than owning equity. But we digress. Here’s ARP’s so-called pre-packaged bankruptcy plan to screw current owners, and turn debtholders into the new owners. ARP plans to file the paperwork in court tomorrow…

http://marcellusdrilling.com/2016/07/atlas-resource-partners-filing-for-bankruptcy-tomorrow/

Former InterOil CEO Phil Mulacek issued a comment on the recent ExxonMobil’s US$2.5 billion offer to acquire InterOil, claiming the shareholders will forego billions of dollars of value.

He added that by accepting the ExxonMobil proposal, the InterOil shareholders would also miss on five cash payments Total agreed with InterOil in 2014.

According to Mulacek, the contingent resource payment (CRP) is “vastly inadequate for InterOil shareholders” as well as potentially manipulative and structurally flawed.

“The recent certification of the Elk and Antelope resource, which Oil Search, recently conducted in connection with its purchase of a minority interest in PRL15 in 2014, shows an average estimated 2C resource of only 6.43 tcfe,” Mulacek said.

He added that this is materially below the 10 tcfe estimate Oil Search suggested claiming this supports the view that the CRP as proposed by ExxonMobil would have only a minimal value unless modified.

Mulacek, representing the group called ‘Concerned InterOil Shareholders’ said the group’s main concern is that the ExxonMobil’s CRP proposal is based only on a single resource estimate performed after Antelope-7 and before any gas or LNG is produced, which will not fully reflect the true resource size.

The group calls for ExxonMobil to provide for recertifying the resource after production is underway and for supplemental payments based on the recertification, in each case back-to-back with similar recertifications and payments under the existing Total agreement with InterOil, saying, “this is reasonable and fair to both parties.”

Mulacek urged ExxonMobil to amend the CRP proposal and certification review process “to provide a fair outcome for InterOil shareholders as well as Exxon.”

http://www.lngworldnews.com/exxonmobil-offer-inadequate-former-interoil-ceo-says/

Understanding reservoir parameters can help successfully optimize fracturing treatments per well

Hydraulic fracturing operations affect reservoir flow dynamics and increase production in unconventional tight reservoirs. The control of fracture growth and geometry presents challenges in formations in which the boundary lithologies are not highly stressed in comparison to the pay zone, thus failing to prevent the upward migration of fractures. Several factors influence the growth and geometry of fractures, including reservoir, wellbore, and fluid/proppant parameters. Successful results require a thorough knowledge of reservoir parameters, including stress distribution and the appropriate use of corresponding wellbore components and fluid/proppant. The success of a hydraulic fracturing treatment is highly correlated with control of the created fracture geometry.

This paper discusses a study in which a numerical fracture model is used to design the fractures in a tight oil reservoir. Fracture treatment designs include the selection of fracturing fluids, additives, proppant materials, injection rate, pumping schedule, and fracture dimensions. Using the fracture model, a statistically representative synthetic set of data is generated for each parameter to build data-driven models.

Follow link to paper https://www.onepetro.org/conference-paper/SPE-177549-MS

China National Petroleum Corp., the country’s oil and gas behemoth, said first-half profit rose 11 percent and that spending cuts at the country’s largest field helped boost earnings.

The parent company of listed unit PetroChina Co. posted a profit of 27.58 billion yuan ($4.13 billion) in the six months ended June 30, according to a Beijing-based spokesman, who asked not to be identified, citing company policy. That compares with a profit 24.82 billion yuan a year ago, according to data compiled by Bloomberg. Sales were 853.4 billion yuan, according to the spokesman, versus 1.02 trillion yuan a year earlier.

“CNPC is doing what it can to cut costs, but low oil prices still sets a floor for how much the company can really make,” Tian Miao, an analyst with policy researcher North Square Blue Oak Ltd., said by phone. “PetroChina owns the best-quality assets of CNPC, including upstream, pipeline and refining, so improved CNPC earnings are a good sign that PetroChina may also report improved performance.”

CNPC saw “better than expected” results in the first half, Chairman Wang Yilin said earlier this month, without providing details. “Operational performance” improved every month in the first six months, though the company’s crude oil business still posted a loss, according to Wang. The state-owned explorer will give priority to natural gas exploration and production in the second half of the year, he said.

China’s largest oil and gas producer said in a separate statement Tuesday that its Changqing field produced 26.5 million tons of oil equivalent in the six months through June and that the unit operating it posted a profit during that period, overcoming losses during January and February.

Changqing produced 11.76 million tons of crude (about 473,600 barrels a day), less than half the field’s total, while gas production reached 18.52 billion cubic meters. CNPC improved single-well output at Changqing and controlled production costs by investing the “lowest possible” amount in exploring for new reserves, the company said.

Brent crude, the global benchmark, averaged about $47 during the second quarter, up from about $35 during the first three months of the year. Prices during the first half of the year averaged about $41 a barrel, down roughly 30 percent from the same period in 2015.

PetroChina may break even in the first half on one-off gains and higher oil prices in the second quarter, Citigroup Inc. analysts including Graham Cunningham wrote in a July 15 research note. The listed unit posted a 13.8 billion yuan loss in the January to March period, its first-ever quarterly loss since listing in 2000. The company closed 1.3 percent lower at HK$5.28 on Tuesday, compared with a 0.6 percent gain in the city’s benchmark Hang Seng Index.

http://www.bloomberg.com/news/articles/2016-07-26/china-oil-giant-s-income-rises-as-costs-cut-amid-shift-to-gas

BP will forge ahead with at least three more new projects this year, its CEO said, despite the British oil major reporting a 45 percent drop in second-quarter earnings that prompted a cut in its 2016 investment budget to below $17 billion.

Tuesday's results missed expectations, with analysts surprised by higher corporate charges, including administrative costs relating to Gulf of Mexico oil spill liabilities, and a lower contribution from BP's stake in Russian oil producer Rosneft.

Rivals Shell, Statoil, Total and Eni also report second-quarter numbers this week, sharpening the focus on Tuesday's drop in crude oil prices towards $44 a barrel, well short of the $60 previously cited as the level at which oil majors can break even.

Though BP chief Bob Dudley acknowledged that the global oil glut's impact on refining margins and revenue continues to make for a challenging environment, he said that capital expenditure plans have been helped by a drop in associated costs.

"We're going to choose our projects really carefully and the cost reductions and re-engineering of the projects has really brought them down to what I think is a very attractive (price range)," Dudley told Reuters.

Dudley said that BP could make another three final investment decisions this year, having already signed off on the expansion of its Tangguh liquefied natural gas (LNG) plant in Indonesia and the Atoll offshore gas project in Egypt.

PROJECTS EARMARKED

A gas project in India, the second phase of the Mad Dog deepwater oil field in the Gulf of Mexico and a Trinidad project could all get the green light, he said.

BP's projects pipeline is expected to add 500,000 barrels of oil equivalent a day by the end of 2017, with a further 300,000 bpd by the end of the decade.

Shares in the company fell 2.5 percent to 429 pence by 1128 GMT, but RBC Capital Markets analyst Biraj Borkhataria said: "We think continued cost and capex deflation reads positively for the sector."

Second-quarter underlying replacement cost profit, BP's most-watched profit measure, was $720 million, down from $1.3 billion in the same period last year and $120 million below an analyst consensus provided by the company.

BP's refining margins hit a six-year low for the second quarter and the company said they would remain under significant pressure in the coming months.

It continues to reduce costs and now expects full-year capital expenditure to come in below the previous target of $17 billion target, saying that its 2017 investments could drop to as low as $15 billion if crude prices remain weak.

"I don't think BP should go below that because then you start to take away from important growth," Dudley said.

Total costs for the 2010 Deepwater Horizon explosion and oil spill, which killed 11 workers, has reached $62 billion but the majority of claims have now been settled.

BP maintained its quarterly dividend at 10 cents a share, reassuring investors in a sector valued for its consistent payouts.

http://www.reuters.com/article/us-bp-results-idUSKCN1060J7

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Valero Energy Corp reported a bigger-than-expected quarterly profit as the U.S. refiner continued to benefit from low crude costs.

Crude oil prices have remained depressed for the past two years, lowering costs for refiners and weighing on prices for refined products, which has boosted consumer demand.

"We are also encouraged by ample supplies of medium and heavy sour crude oils in the market, which should help to expand their discounts relative to Brent crude oil, and by a positive demand outlook," Chief Executive Joe Gorder said in a statement on Tuesday.

However, crack spreads - the difference between the prices of crude oil and refined products - have narrowed sharply due to a spike in gasoline and distillate inventories in the United States.

This has hurt refining margins. Valero's refining throughput margin fell to $8.93 per barrel in the second quarter ended June 30 from $13.71 per barrel, a year earlier.

Net income attributable to shareholders fell to $814 million, or $1.73 per share, in the latest quarter, from $1.35 billion, or $2.66 per share, a year earlier.

Operating revenue fell 22 percent to $19.58 billion, but total costs and expenses fell by a fifth.

Excluding items, Valero reported earnings of $1.07 per share, beating analysts' average estimate of $1, according to Thomson Reuters I/B/E/S.

http://www.reuters.com/article/valero-energy-results-idUSL4N1AC3S7

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DuPont reported a higher-than-expected rise in quarterly profit as lower costs boosted margins, and the chemicals and seeds producer said it expected a 50 percent jump in operating earnings per share in the current quarter from a year earlier.

The company, which is in the process of merging with Dow Chemical Co, raised the low-end of its 2016 operating earnings forecast by 10 cents per share to $3.15. It maintained the upper end at $3.20.

DuPont continues to expect to close the merger later this year as the companies are working closely with regulators in all relevant jurisdictions, Chief Executive Ed Breen said in a statement on Tuesday.

European Union antitrust authorities are expected to rule on the merger by July 28.

Both Dow and DuPont have said that any asset sales required would likely be minor, but pressure to scrutinize the impact of the rapid consolidation in agriculture on farmers and consumers is mounting.

The chairman of the U.S. Senate Judiciary Committee last month urged federal antitrust officials to conduct a "careful analysis" of the merger between Dow and DuPont.

DuPont and Dow are merging in an all-stock deal, a first step toward breaking up the combined company into three separate businesses focused on agriculture, material science and specialty products.

DuPont, which gets about half of its revenue from outside the United States and Canada, said on Tuesday it now expected a strong dollar to hurt full-year profit by about 15 cents per share, less than the 20 cents it had estimated earlier.

The company is also benefiting from its cost-cutting program, and is on track to reach $1 billion in cost savings on a run-rate basis by year-end.

Net income attributable to the company rose to $1.02 billion, or $1.16 per share, in the second quarter ended June 30 from $940 million, or $1.03 per share, a year earlier.

Excluding items, the company earned $1.24 per share, easily beating analysts' average estimate of $1.10, according to Thomson Reuters I/B/E/S.

Net sales fell 0.8 percent to $7.06 billion, but beat analysts' expectation of $7.01 billion.

http://www.reuters.com/article/dupont-results-idUSL4N1AC3ES

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UK oil giant BP on Tuesday posted a lower profit for the second quarter of 2016 of $720 million on an underlying replacement cost basis, compared with $1.3 billion for the second quarter of 2015.

According to the oil company, compared with a year earlier, the underlying second quarter result was impacted by lower oil and gas prices and significantly lower refining margins, but this was partly offset by the benefit of lower cash costs throughout the group as well as lower exploration write-offs.

The Brent oil marker price averaged $46 a barrel in the second quarter, up from $34 in the first quarter but still significantly lower than $62 a year earlier. While improved from the previous quarter, refining margins were the weakest for a second quarter since 2010, BP said.

Underlying operating cash flow for the quarter – before pre-tax Gulf of Mexico payments – was $5.5 billion. This underlying cash flow resulted from continuing reliable operation of assets, BP explained.

BP’s cash costs over the past four quarters were around $5.6 billion lower than in 2014 and BP continues to expect these costs for 2017 to be $7 billion lower than in 2014. Organic capital expenditure for the first half of 2016 was $7.9 billion; full year 2016 capital expenditure is now expected to be below $17 billion.

BP on Tuesday announced an unchanged dividend for the quarter of 10 cents per ordinary share ($0.6 per ADS), expected to be paid in September.

Earlier in July BP announced that it had made progress in resolving outstanding claims from the Deepwater Horizon accident and oil spill, including claims associated with the Plaintiffs’ Steering Committee settlement and by individuals and businesses that opted out of and/or were excluded from that settlement.

The progress made in resolving the opt-out and excluded claims was confirmed by a court order of July 14, 2016. As a result, BP said it can now reliably estimate all remaining material liabilities in connection with the incident.

BP has taken a net post-tax non-operating charge in the quarter of $2.8 billion. This includes a pre-tax non-operating charge of $5.2 billion associated with the Deepwater Horizon liabilities and other positive tax credits. Including fair value accounting effects and inventory gains, this resulted in a reported loss for the quarter of $1.4 billion.

Including this quarter’s $5.2 billion pre-tax charge, the total cumulative pre-tax charge for the Deepwater Horizon incident is $61.6 billion. This now includes BP’s estimation of all material liabilities associated with the incident; any liabilities not covered by this charge are not expected to be material to BP.

Bob Dudley, BP group chief executive said: “We are very pleased to have finally drawn a line under the material liabilities for Deepwater Horizon. We will always be mindful of what we have learned from that tragic accident.”

Dudley added:“As we look forward we expect the external environment to remain challenging, but we have a strong pipeline of new projects which will add 500,000 barrels of oil equivalent a day of new production capacity by the end of next year. Beyond this lie further opportunities, including a number which we expect to deliver through innovative structures such as the recently announced Aker BP venture.”

The oil company’s production for the quarter was 2,090mboe/d, 1.0% lower than the second quarter of 2015.

Looking ahead, BP said it expects third-quarter reported production to be lower than the second quarter due to seasonal turnaround and maintenance activities and the impact of the plant outage at the Enterprise Pascagoula gas processing plant in the Gulf of Mexico.

http://www.offshoreenergytoday.com/bps-second-quarter-profit-slips-on-lower-oil-prices/

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Royal Dutch Shell says it’s cutting one-quarter of its deep-water Gulf of Mexico workers, the oil company’s latest bid to reign in costs amid anemic crude prices.

The move to shed 200 out of its 770 Gulf of Mexico employees and contractors, located across the United States, is part of Shell’s broader plan to cut 2,200 jobs by the end of the year as it makes room for BG Group, the British gas producer it acquired for $50 billion this year.

It’s part of an “ongoing effort to maintain safety, identify efficiencies and increase accountability in our global operations,” said Kimberly Windon, a Shell spokeswoman, in an emailed statement. Some of Shell’s deep-water Gulf employees may be transferred internally to other areas.

http://fuelfix.com/blog/2016/07/25/shell-to-cut-25-percent-of-deep-water-gulf-jobs/

Russia is planning to overhaul its oil industry tax, introducing a profit-based system designed to boost government revenue and lift output from 2018, according to documents seen by Reuters and industry sources.

The current tax is currently based on production and exports. Companies have long been lobbying for profit-based taxation, saying it will spur production and it better reflects exploration costs and risks.

The proposed tax system could be applied first to pilot projects with total production of between 10 million tonnes and 15 million tonnes per year (between 200,000 barrels per day and 300,000 barrels per day).

Low oil prices and western sanctions have left holes in the state budget. Under the new scheme, the budget may still lose up to 50 billion roubles ($771 million) if it is introduced under an oil price of $50 per barrel. But the loses could be eliminated if production increases by a third.

According to a document obtained by Reuters, the energy ministry and the finance ministry have worked out the new system for both mature and new fields. An industry source confirmed the authenticity of the document, which was dated June 30.

The energy ministry told Reuters "the issue is still under discussion".

A source close to the finance ministry said all the proposals are subject to change, and the industry source said there are several unresolved issues.

"Debates are still raging about whether to hike the export fee for fuel oil or not," the industry source said, requesting anonymity as he is not authorised to speak publicly on the issue.

A rise in fuel oil fees will hit companies that have lagged behind a massive modernisation of refineries that was launched in 2011 to improve the quality of oil products.

The industry source said next year's rate of mineral extraction tax for gas giant Gazprom was also still being discussed.

Russian Energy Minister Alexander Novak has said the finance and energy ministries have overcome disagreements over a new tax system for the sector.

The finance ministry, the custodian of the state budget, had opposed the idea of profit-based tax, claiming that will allow producers to conceal income in order to minimise tax payouts.

The new system for brownfields may cut tax by between 16 and 20 percent depending on the oil price, while the internal rate of return for greenfields in Eastern Siberia is seen rising to 19.3 percent, up from 16.9 percent under the current tax system.

According to the draft proposal, several greenfields which are currently benefiting from lower taxes will increase their payment into the budget by 6 percent.

The source also said it was not clear which greenfields would could continue benefiting from the lower tax rate.

"For example, the government is still discussing (Lukoil 's) Imilor and Shpilman new fields," the source said.

http://www.reuters.com/article/russia-oil-taxation-idUSL8N1AB3GP

There was never any fundamental reason why oil prices should have doubled between January and June this year. There were no physical shortages of product, or long-term outages at key producers. But of course, there was never any fundamental reason for prices to treble between 2009 - 2011 in the Stimulus rally, or to jump nearly 50% between January - May last year.

Instead, prices once again rose because financial players expected the US$ to decline
They realised this meant they could make money by buying oil on the futures market as a 'store of value'
Now, as the US$ has started to recover, they are selling off these positions
And so oil prices are falling again

The problem is that the financial volumes swamp the physical market - they were 7x physical volume at their 2011 peak- and so they destroy the oil market's key role of price discovery based on the fundamentals of supply/demand. As I worried in an interview back in March:

'Now the central banks are doing it again. And so, once again, oil prices have jumped 50% in a matter of weeks, along with prices for other major commodities such as iron ore and copper, as well as Emerging Market equities and bonds. In turn, this will force companies to buy raw materials at today's unrealistically high prices, as the seasonally strong Q2 period is just around the corner. Some may even build inventory, fearing higher prices by the summer.

'If this happens, and prices collapse again as the hedge funds take their profits, companies will ... be sitting on high prices in a falling market in Q3 - just as happened in January. Only Q3 could be worse, being seasonally weak, and so it may take a long time to work off high-priced inventory.'Today, just as I feared, the hedge funds are indeed now unwinding their bets and leaving chaos behind them. As Reuters reports, they have already 'slashed positive bets on US crude oil to a 4-month low':

Russia has confirmed the myth of an OPEC/Russia oil production freeze is now officially dead
US oil and product inventories hit an all-time high of almost 1.39bn barrels
China's gasoline exports have doubled over the past year, and its diesel exports tripled in H1
Saudi Arabia's Oil Minister has warned 'There are still excess stocks on the market - hundreds of millions of barrels of surplus oil. It will take a long time to reduce this inventory overhang'

Even worse is that the world is now running out of places to store all this unwanted product, as Reuters reported earlier this month:

'Storage tanks for diesel and heating oil are already so full in Germany, Europe's largest diesel consumer, that barges looking to discharge their oil product cargoes along the Rhine are being delayed'.

Similarly, the International Energy Agency has reported a major backup of gasoline tankers at New York harbor, due to storage being full, whilst Reuters added that tankers are being diverted to Florida and the US Gulf Coast to discharge.

Plus, of course, the recent rally has proved a lifeline for hard-pressed oil producers, who have been able to hedge their output at $50/bbl into 2017. As a result, companies have started to increase their drilling activity again, and are expected to open up many of the 4000 'untapped wells' - where the well has been drilled, but was waiting for higher prices before it was sold.

Yet wishful thinking still dominates oil price forecasts. $50/bbl has always been the 'Comfortable Middle' scenario, as we noted in the Demand Study - and most companies and analysts are most reluctant to break away from this cosy consensus. Yet even in February this year, only 3.5% of global oil production was cash-negative at $35/bbl - just 3.4mbd. Today's figure is likely even lower, as costs continue to tumble.

And in the real world, oil prices have already fallen more than 10% from their $50/bbl peak. Unless the US$ starts to fall sharply again, it seems highly likely that prices will now revisit the $30/bbl level seen earlier this year. Given the immense supply glut that has now developed, logic would suggest they will need to go much lower before the currently supply overhang starts to rebalance.

http://www.oilvoice.com/n/Oil-heads-back-to-30bbl-and-probably-lower/aa9ab559a692.aspx

MDN told you in May that Halcon Resources, a Utica Shale driller that “guessed wrong” by leasing 140,000 Utica Shale acres in the northern part of the play (in Ohio) and currently doesn’t drill on any of that acreage, was preparing to file for bankruptcy.

In June Halcon outlined how they will go about filing–converting some $1.8 billion of debt into shares of stock/ownership in the company. It’s called a “pre-packaged bankruptcy” because the company gets all of the debt holders to agree before the plan is filed. Stockholders (i.e. owners) on the other hand, get screwed. Their stocks become worthless at the end of the process.

Halcon issued a statement outlining their progress. They now have enough debt holders signed up to move forward with filing the pre-packaged bankruptcy…

http://marcellusdrilling.com/2016/07/halcon-gets-majority-buy-in-for-pre-packaged-bankruptcy/

Genscape Cushing inventory +1.14MM for week ended July 22

@zerohedge

Mozambique's long-delayed offshore gas project with Italy's Eni could be approved within months, sources close to the deal said, sparking investments with the potential to transform one of the world's poorest countries into a major energy player.

Mozambique made one of the world's biggest gas finds in a decade in 2010 but negotiations with operators Eni and U.S. firm Anadarko have dragged on for years due to disputes over terms and concerns about falling energy prices.

But Eni has in recent weeks struck deals with contractors and Mozambique's government which could help it to make a final investment decision (FID) on Oct. 31, industry sources said.

Eni declined to comment. The company's Mozambique concession is split between two huge gas fields, called Coral and Mamba. Eni has previously said it expects to make FID on Coral this year and Mamba in 2017.

Reserves in Mozambique's Rovuma Basin amount to some 85 trillion cubic feet -- enough to supply Germany, Britain, France and Italy for nearly two decades. It is likely to take at least five years after FID before gas production begins.

Samsung Heavy said last week it was in exclusive talks with Eni to provide a floating liquefied natural gas (LNG) platform as part of a consortium with Technip and Japan's JGC, in a contract worth around $5.4 billion.

General Electric has also been approved as a contractor, two sources said.

Negotiations with government over tax terms and the funding of the Mozambique national gas company have also made moved forward in the last two months, the sources said.

Eni has already reached a deal to sell the gas to BP.

"There has been significant progress in the last few weeks. It's making investors a lot more optimistic FID isn't too far away," one banker involved in the deal told Reuters.

FINANCING

The last major sticking point is how Eni will finance the $11 billion development, the sources said.

Eni is expected to raise several billion dollars by splitting its concession in two and selling up to 20 percent of its Mamba gas field, and the operating rights, to Exxon Mobil , sources involved said.

Any sale by Eni would provide a much-needed capital gains tax windfall for the Mozambican government during a period of economic crisis and as it struggles to make repayments on $1.35 billion in controversial foreign loans.

The International Monetary Fund suspended aid to Mozambique in April because of the hidden debt.

"There's definitely been more urgency on the government side to get these gas deals moving," one industry source said.

While Eni will drill and process gas from floating offshore platforms, Anadarko is building sprawling LNG facilities on the northern Mozambican mainland, causing complications due to local residents who will need to be relocated.

Anadarko submitted a plan to resettle thousands of mostly farmers and fishermen who will be displaced by the LNG project last month, one of the last hurdles to jump before getting the go-ahead on a $24 billion project, two sources said.

Mitch Ingram, who was previously with BG, was hired by Anadarko last year to head its LNG business. Ingram's experience has given investors more confidence about Anadarko's ability to raise financing, the sources said.

Anadarko's project is expected to lag Eni's and its final investment decision is unlikely this year, the sources said.

http://uk.reuters.com/article/mozambique-gas-idUKL8N1A756D

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Attached Files

Freeport-McMoRan Oil & Gas has a deal in place to sell shale US acreage to joint venture partner Chesapeake Energy, according to sources.

Eight years after a predecessor company paid Chesapeake $3.3 billion for the original position.

http://www.upstreamonline.com/live/1439595/chesapeake-eyes-freeport-mcmoran-acreage?utm_source=twitterfeed&utm_medium=twitter

A Marcellus well has produced 17 Bcf of natural gas in less than 4.25 years online. Many other wells in the play have already produced over 10 Bcf.

In the most prolific sweet spot, the average cost to find and develop natural gas is estimated to be just $0.25 per Mcf.

Across the play, the current average cost to bring production online is less than $0.50 per Mcf.

The Marcellus and Utica represent one of the world’s most economic and abundant natural gas fields, with major mainlines already in place to deliver gas to destinations.

One of the slides in Cabot Oil & Gas' recent presentation caught my attention. The slide shows cumulative production to date from the top twenty wells in Pennsylvania. The "biggest" well of the twenty has produced 17 Bcf of natural gas to date. The "smallest" has produced 10 Bcf.




Several observations are worth noting.

First, as the title indicates, 17 wells of the 20 belong to Cabot and were drilled in the play's dry gas sweet spot in Susquehanna County. In other words, these wells by no means provide a representative sample for the entire play but rather prove the magnitude of leading-edge wells in a select, albeit very large, sweet spot.

http://seekingalpha.com/article/3990978-shale-gas-food-thought-disbelievers

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GeoPark Limited , a leading independent Latin American oil and gas explorer, operator and consolidator with operations and growth platforms in Colombia, Chile, Brazil, Argentina, and Peru1, today announced the successful drilling and testing of the Jacana 4 development well in the Jacana oil field in the Llanos 34 Block (GeoPark operated with a 45% working interest) in Colombia.

GeoPark drilled and completed the Jacana 4 development well to a total depth of 10,370 feet. A test conducted with an electric submersible pump in the Guadalupe formation resulted in a production rate of approximately 1,950 barrels of oil per day of 16 degrees API, with 1% water cut, through a choke of 40/64 mm and wellhead pressure of 70 pounds per square inch. Additional production history is required to determine stabilized flow rates of the well. Surface facilities are in place and the well is already in production.

The Jacana 4 well followed the recent successful Jacana 3 appraisal well, which extended the size of the Jacana field. Jacana 4 was drilled to TD in a record-time of 8.8 days at a total drilling and completion cost of $2.9 million. At current oil prices, Jacana 4 is expected to have an IRR greater than 200% and a repayment period of less than six months (before year-end 2016).

GeoPark has identified approximately 40-45 additional drilling locations to fully develop the oil reserves in the Tigana and Jacana oil fields in the Llanos 34 Block.

http://www.businesswire.com/news/home/20160725005597/en/GeoPark-Announces-Development-Drilling-Success-Jacana-Oil

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Attached Files

SABIC and an affiliate of Exxon Mobil Corporation (ExxonMobil) (NYSE:XOM) are considering the potential development of a jointly owned petrochemical complex on the U.S. Gulf Coast.

“The proposed venture would capture competitive feedstock and reinforce SABIC’s strong position in the value chain.”

If developed, the project would be located in Texas or Louisiana near natural gas feedstock and include a world-scale steam cracker and derivative units.

Before making final investment decisions, the companies will conduct necessary studies and work with state and local officials to help identify a potential site with adequate infrastructure access.

“We are focused on geographic diversification to supply new markets,” said Yousef Abdullah Al-Benyan, SABIC vice chairman and chief executive officer. “The proposed venture would capture competitive feedstock and reinforce SABIC’s strong position in the value chain.”

Neil Chapman, president of ExxonMobil Chemical Company, said: “We have the capability to design a project with a unique set of attributes that would make it competitive globally. That is vitally important as most of the chemical demand growth in the next several decades is anticipated to come from developing economies.”

ExxonMobil and SABIC have worked together for 35 years in major chemical joint ventures in Saudi Arabia.

http://www.businesswire.com/news/home/20160725005667/en/SABIC-ExxonMobil-Evaluating-Petrochemical-Joint-Venture-U.S.

GAIL India Ltd. is seeking to defer a 20-year contract to buy liquefied natural gas from Gazprom PJSC until the Russian company’s Shtokman project begins production, officials at the South Asian country’s biggest gas transporter said.

New Delhi-based GAIL signed a contract in 2012 to buy 2.5 million metric tons a year of LNG from Gazprom starting in 2018 and 2019. The Russian exporter was to supply LNG from the Shtokman project under the contract, according to GAIL’s website.

Now that the Arctic project is on hold, Gazprom has offered to supply LNG from other sources, said the GAIL officials, who asked not to be identified citing company policy. The Indian company is insisting on supplies from Shtokman and has said it will consider lifting LNG from other sources at a renegotiated price that is closer to spot-market rates, the officials said.

GAIL is struggling to find buyers for its gas amid an abundance of cheap alternative power generation supplies, including coal. The price of spot LNG to Asia during the past year has fallen 28 percent amid a global glut.

Reuters earlier reported GAIL was seeking to delay the gas purchase deal with Gazprom.

http://www.bloomberg.com/news/articles/2016-07-25/india-s-top-gas-utility-seeks-to-defer-gazprom-lng-contract

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Golar LNG, one of the world’s largest owners and operators of LNG carriers, and oilfield services giant Schlumberger on Monday created OneLNG, a joint venture aiming to “rapidly develop low-cost gas reserves” to LNG.

The two companies have agreed an initial investment commitment to cover the estimated equity needed to develop the first project.

In addition, the parties will, on a project-by-project basis, discuss additional debt capital as required, according to a joint statement issued on Monday.

Golar and Schlumberger have 51/49 ownership of the joint venture, the statement reads.

Commenting on the formation of the JV, Golar vice chairman, Tor Olav Troim sad it provides a union of Schlumberger oilfield services technology and production management business, and Golar’s FLNG solution.

According to the statement, the two companies have reviewed the current market opportunities coming to a conclusion that “40 percent of the world’s gas reserves can be classified as stranded”, which is the market the JV is looking to cover.

To remind, Golar LNG and Schlumberger signed a memorandum of understanding to cooperate on developing greenfield, brownfield and stranded gas reserves in January.

Both companies reinforced the commitment to the cooperation despite Schlumberger’swithdrawal from the Fortuna FLNG project agreement with Ophir.

In terms of the newly formed joint venture, both companies said they are “confident that the JV would conclude 5 projects within the next 5 years.”

http://www.lngworldnews.com/golar-schlumberger-create-flng-jv/

The number of rigs actively exploring for or producing oil and natural gas in North Dakota is up 10 percent from last week, state data show.

State data shows 32 rigs actively exploring for or producing oil and gas as of Monday, an increase of 10 percent from last week. The move in North Dakota mirrors developments elsewhere in the United States, where relative stability in crude oil prices, since a collapse below $30 in early 2016, is building confidence in the industry.

Data from Baker Hughes show the number of active rigs for the week ending July 22 increased for the fourth straight week. Crude oil prices moved lower last week after Baker Hughes released its data as traders worried a recovery in rig counts would push markets back toward the supply side.

Morgan Stanley said in a research note that crude oil prices are near their lowest level since the middle of May and higher crude oil inventories, coupled with higher rig counts, could add negative pressure to the price for oil.

The North Dakota figures may show a lag time in a balancing under way in the oil market between supply and demand. Rig counts in North Dakota, which hosts parts of the Bakken shale oil basin, hit a historic low early this year after oil sank below $30 per barrel.

May rig counts in North Dakota were at or near record lows. However, in a monthly report, the North Dakota Industrial Commission's Oil and Gas Division said rig counts are down nearly 90 percent from their all-time high.

North Dakota is the No. 2 oil producer in the United States behind Texas. State lawmakers hold a special session next week to review revenue options in the face of lower crude oil prices. Without a course correction, the state estimates its general fund will be short about $310 million by the end of the current biennium.

http://www.upi.com/North-Dakota-rig-count-up-10-percent/9511469448849/

Imports of liquefied natural gas (LNG) by world’s largest consumer of the chilled fuel, Japan dropped 5.6 percent in June as compared to the same month a year ago.

Japan imported 6.26 million mt of LNG in June, provisional data from Japan’s Ministry of Finance showed on Monday.

The country’s coal imports for power generation also dropped 8.6 percent to 8.52 million mt, the data showed.

According to the data, Japan paid about US$1.93 billion for LNG imports in June, down 43.9 percent on year.

To remind, the price of spot LNG cargoes arriving in Japan in June reached $4.5 per mmBtu on DES basis, showing the first glimpse of recovery following record lows in the previous two months.

http://www.lngworldnews.com/japans-lng-imports-decline-in-june/

Vedanta sweetened the deal for Cairn India Ltd. shareholders by increasing the number of preference shares four times to salvage a deal which would help create a natural-resources group to compete with BHP Billiton and Vale.

Vedanta will offer minority shareholders of Cairn India one equity share and four redeemable-preference shares with a face value of 10 rupees each, it said in a statement Friday. The preference shares will carry a coupon of 7.5% and tenure of 18 months. The revised deal implies a 20% premium to the one-month volume weighted-average price of Cairn shares, according to the statement.

The merger was announced in June last year when Vedanta offered one equity share and one preference share to merge Cairn with itself. In January, Vedanta chairperson Anil Agarwal had said the merger will be completed by March, though it was then delayed as the approval of key shareholders could not be secured.

“The revised terms are a bit of a sweetener,” said Dhaval Joshi, a Mumbai-based analyst at Emkay Global FinancialServices Ltd. “This clearly shows Vedanta is seeking quicker approvals from major shareholders.”

Cash Reserves

The merger will also help the group weighed down by 780 billion rupees of debt. Vedanta Ltd. is India’s most-indebted base metals company. Cairn India had 233.9 billion rupees of cash and near cash as of June 30.

“The simplified corporate structure will better align interests between all shareholders for the creation of long-termsustainable value,” Agarwal said in the statement. On Thursday, Cairn India Chairman Navin Agarwal had said the merger is likely to be completed by March 2017.

Shares of Cairn India closed 8.5% higher at 191.90 rupees inMumbai on Friday. Vedanta Ltd. ended with a 7.8% advance to 169.30 rupees, while the benchmark S&P BSE Sensex was 0.3% higher.

Vedanta Plc’s ownership in Vedanta Ltd. is expected to fall to 50.1% on completion of the merger from 62.9% now, according to the statement. The courts will convene meetings of shareholders of Vedanta Ltd. and Cairn India in September to discuss the new terms. Cairn India’s minority shareholders will own 20.2% and Vedanta minority shareholders 29.7% in the merged entity.

http://www.miningweekly.com/article/vedanta-sweetens-deal-for-cairn-merger-to-sway-shareholders-2016-07-22

U.S. drillers this week added oil rigs for a fourth consecutive week, according to a closely followed report on Friday, with the recent return to the well pad
expected to soften the decline in domestic crude production.

Drillers added 14 oil rigs in the week to July 22, bringing the total rig count up to 371, compared with 659 a year ago, energy services firm Baker Hughes Inc said. That is the biggest weekly increase since December. RIG-OL-USA-BHI    
 
Most of the new rigs were in the Permian shale basin in west Texas, where drillers added eight, bringing the total count up to a five-month high of 168.

Since early June when U.S. crude prices settled over $50 a barrel, drillers have added 55 oil rigs.

Analysts and producers said $50 was a key level that would prompt a return to the well pad after the biggest price rout in a generation prompted a slump in the oil rig count since it peaked at 1,609 in October 2014.
 
That increased drilling should stop the decline in production in a few months, the U.S. Energy Information Administration projected in its latest Short-Term Energy
Outlook.

"Higher and more stable crude oil prices are contributing to increased drilling in the United States, which may slow the pace of production declines," the EIA said.    

After sliding every month this year from 9.2 million barrels per day in January, the EIA expects crude output to bottom at 8.1 million bpd in September before edging up to 8.2 million bpd in October and 8.3 million bpd in November and December. In 2015, production averaged 9.4 million bpd.

"While declines from existing wells are expected to result in a net decrease in production, increased drilling and higher well productivity are expected to soften the decline."

http://www.reuters.com/article/usa-rigs-baker-hughes-idUSL1N1A812Q

Southwestern Energy, a major Marcellus and Utica Shale driller, filed its second quarter 2016 update yesterday.

Bill Way, Southwestern CEO, called 2Q16 a “defining time” for the company.

During 2Q the company has extended and delayed debt payments, and sold more stock.

Financially the company is improving. In 2Q16 Southwestern lost $620 million, versus losing $815 million in 2Q15. The patient is still bleeding, but not as bad.

The vast majority of their planned capital spending ($395M out of $750M) will get spent on Marcellus/Utica drilling. Speaking of which, the company placed 17 new Marcellus/Utica wells online in 2Q16, with plans to drill another 50 or so wells in the second half of this year.

http://marcellusdrilling.com/2016/07/southwestern-energy-2q16-bleeding-slows-17-new-marcutica-wells/

The $10 billion Angola LNG project, led by U.S. energy giant Chevron, has been shut down with production expected to resume again in September.

The recent shutdown is part of the restart and commissioning programme, an Angola LNG spokeswoman told LNG World News on Thursday.

“We expect that LNG production will be resumed in late September,” the spokeswoman said.

The 5.2 million tons per year liquefaction plant at Soyo loaded its first cargo in June after resuming production in May.

To remind, the facility was closed for more than two years due to a major rupture on a flare line that occurred in April 2014.

LNG World News understands that the plant exported four cargoes of the chilled fuel since June.

Angola LNG is a joint venture between Sonangol (22.8%), Chevron (36.4%), BP (13.6%), Eni (13.6%), and Total (13.6%).

http://www.lngworldnews.com/angola-lng-shut-down-production-to-resume-late-september/

Oil and gas company Santos produced a record 31.1-million barrels of oil equivalent in the first half of 2016 and significantly boosted its sales volumes, but a 29% decrease in the average realised oil price has dented its revenue.

Santos increased its production by 10% year-on-year in the first six months of 2016, comprising 15.6-million barrels in the first quarter and 15.5-million barrels in the second quarter.

Half-year sales volumes increased by 32% year-on-year to 40.9-million barrels of oil equivalent, but Santos suffered a 29% decrease to $43/bl in the average oil price achieved.

Sakes revenue fell by 6% year-on-year to $1.19-billion, compared with $1.26-billion in the first half of 2015. Second-quarter sales revenue declined by 3% year-on-year to $590-million.

The company maintained its 2016 production guidance of between 57-million and 63-million barrels of oil equivalentand its sales guidance of between 76-million and 83-million barrels of oil equivalent.

Santos MD and CEO Kevin Gallagher said on Friday that the company’s commitment to improving productivity and lowering costs was starting to deliver tangible results.

“There is a lot of work ahead of us, but today’s results show we are heading in the right direction,” he stated.

Santos will release its results for the half-year ended June 30 on August 19.

http://www.miningweekly.com/article/santos-half-year-production-hits-record-2016-07-22

The number of dormant crude and natural gas wells in the U.S. stopped growing in the first quarter -- and may all but disappear in the nation’s biggest oil field should prices hold steady.

As of April 1, there were 4,230 wells left idle after being drilled, a figure little changed from January, according to an analysis by Bloomberg Intelligence. While some explorers have continued to grow their fracklog of drilled but not yet hydraulically fractured wells, others began tapping them in February as oil prices rose, the report showed.

Crude in the $40- to $50-a-barrel range may wipe out most of the fracklog in Texas’s Permian Basin and as much as 70 percent of the inventory in its Eagle Ford play by the end of 2017, according to Bloomberg Intelligence analyst Andrew Cosgrove. While bringing them online is the cheapest way of taking advantage of higher prices, the wave of new supply also threatens to kill the fragile recovery that oil and gas markets have seen so far this year.

“We think that by the end of the third quarter, beginning of the fourth quarter, the bullish catalyst of falling U.S. production will be all but gone,” Cosgrove said in an interview Thursday. “You’ll start to see U.S. production flat lining.”

Drillers that expanded operations in U.S. shale fields found that sidelining wells was the easiest way to cut costs when oil and gas prices plunged. Since then, these wells have been “just sitting around, basically waiting for a better price to come along,” said Het Shah, an analyst at Bloomberg New Energy Finance.

U.S. oil producers extended the biggest shale drilling revival since last summer as rigs targeting oil and gas in the U.S. rose by 7 to 447 last week, according to Baker Hughes Inc. Dave Lesar, chief executive officer of Halliburton Co., the world’s largest provider of hydraulic-fracturing work, said Wednesday that the market in North America has turned and that he expects a “modest uptick” in drilling in the second half of the year.

U.S. oil futures have rallied 21 percent this year, settling at $44.75 a barrel on Thursday. Gas is up 15 percent, closing at $2.692 per million British thermal units.

“With oil hovering below $50, decisions on whether to tap the idled supply are increasingly driven by local well economics and company-specific factors,” Bloomberg Intelligence analysts Cosgrove and William Foiles wrote in the report.

EOG Resources Inc. began reducing its fracklog in early February. The company is focusing on completing dormant wells and has said it plans to trim the backlog to 230 from 300 this year.

Bakken Basin

Meanwhile, Continental Resources Inc. added 78 dormant wells in the Bakken formation, where it’s the biggest leaseholder, from Sept. 1 to April 1 -- more than all the drillers in the play combined. The company had more long-term rig contracts and likely has the capital to complete wells as prices rise, Foiles said.

"It shows management is pretty confident in their situation," he said.

Among the three major U.S. oil plays -- the Permian, the Eagle Ford and the Bakken -- the number of untapped wells increased the most in the Permian, which saw a 12 percent jump in the first quarter. That topped the 4.4 percent increase in the Bakken. Dormant wells across the three plays may fall 25 this year, with the Permian leading the way.

"The Permian drawdowns will continue to trump those you see in other basins," Cosgrove said.

New output from the wells will equal the decline from older ones in four shale oil basins, according to Everscore ISI. That means tapping them will only temporarily stem production declines.

And while dormant wells "coming online may cause prices to remain flat" until the end of the year, sometime in 2017 prices will gradually improve, said Brian Youngberg, an energy analyst at Edward Jones.

http://www.bloomberg.com/news/articles/2016-07-21/the-fracklog-isn-t-growing-anymore-and-that-s-bad-news-for-bulls

The world’s two largest providers of oilfield drilling and fracking services have now declared that the worst may be over in the two-year-old oil market crash.

Schlumberger Ltd. said Thursday that the oil industry appears to have reached the bottom of the cycle, echoing smaller rival Halliburton Co., which on Wednesday said the North American market reached its lowest point in the second quarter and is poised for modest growth the rest of this year.

"They’re the two dominant players in the market, both of whom just called the bottom," James West, an analyst at Evercore-ISI in New York, said Thursday in an interview. "It’s a positive. Calling the bottom in the market sends the right signal and Schlumberger has a ton of credibility."

As the downturn dragged on, executives at the world’s largest oilfield services provider have had to push back their expectations for an improvement in drilling and fracking work, with crude prices remaining more than 50 percent lower than their peak in 2014.

Schlumberger reported a unexpected second-quarter loss of $2.16 billion, or $1.56 cents a share, compared with a profit of $1.12 billion, or 88 cents, a year earlier, according to a statement Thursday. The Houston- and Paris-based company was expected to post a $296.3 million profit, according to the average of 28 analysts’ estimates compiled by Bloomberg. The company also said it cut another 8,000 jobs in the second quarter after slashing a similar amount in the first three months of the year.

"In the second quarter market conditions worsened further in most parts of our global operations," Kibsgaard said in the statement. "But in spite of the continuing headwinds, we now appear to have reached the bottom of the cycle."

The stock, which closed 0.7 percent lower at $80.02, gained as much as 0.7 percent in after-hours trading. It traded at $80.43 as of 6:16 p.m. in New York.

The nearly doubling of oil prices this year has Schlumberger shifting its focus to renegotiate contracts with explorers and trying to recover some of the discounts it was forced to give during the downturn, Kibsgaard said.

Pricing Outlook

"That is a positive that they’re seeing that there is a little bit of appetite to renegotiate those contracts," Rob Desai, an analyst at Edward Jones in St. Louis who rates the shares a buy and owns none, said Thursday in a phone interview. "I think pricing will still be weak for a while. It could be a couple of years before pricing really recovers."

Schlumberger’s President Patrick Schorn said last month that the second quarter "may represent the final approach to a market bottom." In April, Schlumberger closed its $14.8 billion takeover of Cameron International Corp., marking the largest deal among oilfield contractors this year.

The service provider has made several rounds of job cuts to adjust to lower spending by its customers. The company has now cleaved off more than 50,000 jobs since the downturn began in late 2014, and its total headcount now stands at more than 100,000 with the addition of Cameron’s workforce, Joao Felix, a spokesman, said Thursday in an interview.

‘Modest Uptick’

Halliburton, the world’s second-largest oilfield services provider, reported a second-quarter loss of 14 cents per share, excluding certain items, earlier this week. The company also forecast a "modest uptick" in the U.S. rig count for the remainder of the year.

"They both are bullish for the medium- to long-term," Desai said. "Maybe Schlumberger is a little bit more cautious on the near term, but that’s to be expected, given the history of the two companies and Halliburton’s reliance more on North America."

http://www.bloomberg.com/news/articles/2016-07-21/schlumberger-posts-surprise-2-2-billion-loss-cuts-more-jobs

The Canadian oil and gas earnings season kicked off on Thursday with signs of an industry recovery as Encana Corp and Precision Drilling Corp outlined plans to boost activity.

Calgary-based Encana reported an unexpected quarterly operating profit and said it would boost 2016 capital spending by $200 million from a previously announced range of $900 million to $1 billion. It also plans to increase production by about 13,000 barrels of oil equivalent per day at its core shale operations.

Precision Drilling, despite posting a second-quarter loss, said oil producers were increasing capital budgets due to the 70 percent rally in crude prices since February and putting more rigs back to work.

"Our customers appear to be looking beyond the oil price lows of earlier this year, resetting spending to current commodity price levels, and beginning the early stages of planning for improved longer-term fundamentals," said Precision Drilling Chief Executive Officer Kevin Neveu.

Both companies operate in Canada and the United States, and analysts said the uptick in optimism might be mirrored by some U.S. shale companies like Pioneer Natural Resources Co.

Analysts on average expect Pioneer to post a second-quarter loss of 35 cents per share when it reports next week, according to Thomson Reuters I/B/E/S.

While Encana has benefited from a cash injection from recent asset sales, analysts said the move to boost spending indicates the best North American light oil plays, like the Permian and Eagle Ford in the United States and the Montney in western Canada, could start to attract a surge in investment.

Encana said 75 percent of the additional capital would go to its Permian shale operations.

Morningstar analyst David Meats said he expected many companies to add one or two extra rigs, plan to complete more drilled but uncompleted wells and generally be more optimistic.

"It's a sign of the first step on a long journey back to light oil production growth," Meats said. "Certainly it's very likely that other producers will follow suit and allocate other capital to the Permian."

Encana CEO Doug Suttles said the company had made its operations "massively more efficient." Operating costs were down 32 percent from a year earlier, and Suttles said two-thirds of those savings would be sustainable even if oil prices rise.

http://www.reuters.com/article/canada-energy-results-idUSL1N1A715J

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Attached Files

ExxonMobil Corp said on Thursday it would buy InterOil Corp for more than $2.5 billion in stock, adding a gas field to expand exports from Papua New Guinea and better positioning it to meet Asian demand for liquified natural gas.

Oil majors are targeting Papua New Guinea for growth as the quality of its gas, low costs and proximity to Asia's big LNG consumers make it one of the most attractive places to develop projects following a collapse in oil and gas prices.

"I think (the deal) shows that Exxon views LNG as a very strong growth business. I believe that LNG demand over time will grow faster than oil," said Brian Youngberg, oil analyst with Edward Jones in Saint Louis.

Exxon sealed the deal for InterOil after Australia's Oil Search Ltd said earlier on Thursday that it would not pay more than the $2.2 billion it offered in May, a proposal that was backed by French giant Total SA.

InterOil owns a 36.5 percent stake in the Elk-Antelope gas field, which is operated by Total. The acquisition will give Exxon interests in six licenses in Papua New Guinea covering about four million acres.

Oil Search said it and Total agreed that letting Exxon take over would help speed up development of the Elk-Antelope field.

Exxon said it would pay InterOil shareholders $45 per share in stock and that it would also make an additional cash payment based on the size of the Elk-Antelope field.

That payment is worth $7.07 per share for each trillion cubic feet equivalent (tcfe) of certified gross resource from the field above 6.2 tcfe and up to a maximum of 10 tcfe.

Exxon said it would evaluate processing of gas from the Elk-Antelope field by expanding its LNG export plant in Papua New Guinea. Oil Search also owns a stake in the LNG plant.

The plant is a 6.9 million tonne per annum integrated project operated by Exxon. The gas is sourced from seven fields and Elk-Antelope gas could be used to feed an expansion.

"It will be interesting to watch how Exxon pursues the development of InterOil's gas resources. Will it be by expanding the existing LNG plant already operating in the country, or building a brand-new project?," said Pavel Molchanov, an energy analyst with Raymond James.

http://www.reuters.com/article/interoil-ma-exxon-idUSL4N1A758E

The Nigerian government is talking to militants in the Niger Delta to end a wave of attacks on oil and gas facilities which have cut oil production by 700,000 barrels a day, top officials said on Thursday.

But the Niger Delta Avengers, a militant group that has claimed responsibility for a series of attacks, said it was not aware of any talks, saying there would be no dialogue without involving the international community

The government was using oil companies and security agencies to talk to the militants "to find a lasting solution to insecurity in the region", President Muhammadu Buhari said in a statement.

Buhari also said his government was reviewing an amnesty program for former militants, which offers cash and job training, after initially slashing the scheme's budget by two-thirds and angering militants.

"We understand their feelings," Buhari said. "We are studying the instruments (of the amnesty). We have to secure the environment, otherwise investment will not come."

In June, government officials said a one-month ceasefire had been agreed with the Niger Delta Avengers but the group reiterated on Thursday no talks were going on.

"We are not aware of any peace talk," the group said in a statement on its website. "President Buhari... is not sincere to the Nigeria people and their foreign allies."

Militants say they want a greater share of Nigeria's oil wealth to go to the impoverished Delta region. Crude sales make up about 70 percent of national income and the vast majority of that oil comes from the southern swampland.

Nigeria, an OPEC member, was Africa's top oil producer until the recent spate of attacks pushed it behind Angola.

Pipeline vandalism has reduced oil production by 700,000 barrels a day, Maikanti Baru, the new managing director of state oil firm NNPC, said in a statement.

"The 2016 national budget plan was based on 2.2 million barrels per day of crude oil production," Baru said. "However, the budget plan is now grossly impacted due to renewed militancy: with about 700,000 bpd of oil production curtailed due to pipeline vandalism."

"Domestic natural gas supply to power is equally impacted with (an) estimated drop of about 50 percent from 1,400 million standard cubic feet of gas per day," he said.

http://www.reuters.com/article/us-nigeria-oil-talks-idUSKCN1012HA

U.S. independent refiners such as Valero Energy Corp and Phillips 66 look set to post another quarter of disappointing earnings, putting the industry on track for its worst year since the U.S. shale boom began in 2011.

The companies had hoped to rebound from a weak first quarter on the back of strong U.S. gasoline demand. But while U.S. motorists have taken to the highway in record numbers, refiners have been undone by record supplies of gasoline and diesel products.

High volumes of imports, combined with refiners switching to maximum gasoline output earlier than usual, resulted in inventories climbing well above seasonal highs and even hitting record highs on the East Coast.

In recent weeks, analysts have slashed second-quarter estimates ahead of earnings season and tempered their expectations for the remainder of the year. Several are now predicting that refiners may have to take more drastic action to protect margins and force a drawdown of stockpiles.

"I expect the refiners to exit summer driving season with higher-than-usual inventories, so margins will get to the point that refiners will need to consider run cuts to balance things," Blake Fernandez, a Houston-based analyst at Scotia Howard Weil, said. "The back half of the year will be rough."

Over the last 30 days, analysts have sharply reduced earnings expectations for big refiners. Valero, for instance, has seen earnings-per-share forecasts for the next 12 months drop by 19 percent, according to StarMine, a Thomson Reuters subsidiary. Phillips 66 estimates are down 17 percent in that time. Several other refiners have seen estimates decline a similar amount.

Wells Fargo analysts Roger Read and Lauren Hendrix said the weak start to the third quarter means any optimism for a good summer performance is "rapidly evaporating."

Delta Air Lines kicked off the poor earnings season earlier this month by announcing that its 182,000 barrel-per-day refinery outside of Philadelphia lost $10 million in the second quarter, following a loss of $18 million in the first quarter. Chief Financial Officer Paul Jacobson said Delta now expects the refinery to lose money this year.

The facility, which Delta bought in 2012, reported $176 million in operating income in the first half of 2015 and was profitable in both 2014 and 2015.

The largest 10 independent U.S. refiners booked a combined net income of $944 million in the first quarter, down 74 percent from last year's $3.6 billion, a Reuters analysis showed. That compares with annual profits of more than $10.6 billion in the past five years, when the refiners feasted on the abundance of domestic crude flowing from U.S. shale fields.

The group of refiners recorded $6.2 billion in profits in the second quarter of last year, the best quarter in the past five years, Reuters data showed. The U.S. gasoline crack spread 1RBc1-CLc1, a proxy for refiner margins, averaged more than $25 a barrel during the second quarter last year. It hovered around $19 a barrel during the same period this year.

Among other headwinds for refiners in the second quarter, global oil prices hit six-month highs in June. That squeezed margins and costs rose for renewable fuel credits, which refiners can earn by blending biofuels like ethanol into gasoline and diesel.

Renewable fuel credits averaged about 78 cents apiece in the second quarter of 2016, about 25 percent above the same period a year ago, according to prices from the Oil Price Information Service analyzed by Reuters.

Prices for the credits, which can also be bought in an opaque market, have rallied on what traders and industry sources have said are more ambitious targets from U.S. regulators on the volumes of ethanol required to be blended with gasoline.

http://www.reuters.com/article/usa-refineries-results-idUSL1N1A724Q

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