OPEC's oil output is likely to reach its highest in recent history in September, a Reuters survey found on Friday, as Iraq boosted northern exports and Libya reopened some of its main oil terminals.

The increase comes despite lower output in top exporter Saudi Arabia and this week's agreement by the Organization of the Petroleum Exporting Countries in Algeria to limit supply to support prices, its first such decision since 2008.

Supply from OPEC has risen to 33.60 million barrels per day (bpd) in September from a revised 33.53 million bpd in August, according to the survey based on shipping data and information from industry sources.

The rise in output could add to scepticism about OPEC's ability to allocate its new production target of between 32.50 million and 33 million bpd, a task ministers left until a meeting in November. Oil rallied towards $50 a barrel on Thursday but was trading near $49 on Friday.

"The agreement still leaves hard and difficult negotiations for the individual caps to be set," said Bjarne Schieldrop, chief commodities analyst at SEB.

"Now, with an OPEC curb on the cards for the first time in eight years, Brent crude is not even able to lift above $50. At least not yet."

Supply has risen since OPEC in 2014 dropped its historic role of fixing output to prop up prices as Saudi Arabia, Iraq and Iran pumped more. Production has also climbed due to the return of Indonesia in 2015 and Gabon in July as members.

The membership changes have skewed historical comparisons. September's supply from OPEC excluding Gabon and Indonesia, at 32.65 million bpd, is the highest in Reuters survey records starting in 1997.

In September, the increase was led by Iraq and Libya. Iraqi state oil firm SOMO and Iraq's semi-autonomous region of Kurdistan began jointly exporting crude from the Kirkuk oilfield again. This lifted Iraqi supply to market to 4.43 million bpd in September, according to the survey.

In Libya, the National Oil Corporation opened three previously blockaded ports, allowing AGOCO, an NOC subsidiary that operates mainly in eastern Libya, to boost output.

Supply in Saudi Arabia has edged down from the record high reached earlier in the summer, sources in the survey said.

Supply in Iran, OPEC's fastest source of production growth earlier this year after the lifting of Western sanctions, has held steady this month as output nears the pre-sanctions rate. Iran is seeking investment to boost supply further.

Angolan output slipped because the Plutonio field was shut for part of the month.

There was no sign yet of higher supply from Nigeria, where attacks on oil installations have cut output. Supply should rise in October if efforts for a restart of Qua Iboe and Forcados crude exports come to fruition.

The Reuters survey is based on shipping data provided by external sources, Thomson Reuters flows data, and information provided by sources at oil companies, OPEC and consulting firms.

http://www.reuters.com/article/opec-oil-survey-idUSL5N1C90Y9

Iran's total crude oil and condensate sales likely reached around 2.8 million barrels per day in September, two sources with knowledge of the matter said, nearly matching a 2011 peak in shipments before sanctions were imposed on the OPEC producer.

The run-up from shipments of around 2.5 million bpd in August comes mainly from condensate, a light oil excluded from OPEC supply quotas that is often produced with natural gas and can be used to make naphtha for petrochemical production.

Iran sold 600,000 bpd of condensate for September, including about 100,000 bpd shipped from storage, to meet robust demand in Asia, the two sources said. September crude exports increased slightly from the previous month to about 2.2 million bpd, they said.

Iran, along with Libya and Nigeria, is allowed to produce "at maximum levels that make sense" as part of any output limits in a surprise deal reached last week by the Organization of the Petroleum Exporting Countries (OPEC).

Still, the Middle Eastern producer has surprised the market by ramping up its oil output faster than expected, to 3.63 million bpd in August, according to OPEC, up a quarter from end-2015 since sanctions were lifted in January.

"Iran cannot produce much more than the present, so around 3.7 million bpd may be the max," said Fereidun Fesharaki, chairman of consultancy FGE.

Even if Iran's output hit 3.8 million bpd - as an oil official said it had in September - it would not be able to sustain that volume as decline rates at its oilfields are about 400,000 bpd each year, Fesharaki said.

National Iranian Oil Co (NIOC) officials did not immediately respond to an emailed request for comment.

Iran has said it plans to raise its output to 4 million bpd, although other analysts agreed production has probably peaked for now because investments to pump out more oil are lagging.

SOUTH PARS CONDENSATE TO PUSH GROWTH

Condensate instead of crude oil will drive Iran's export growth for the remainder of 2016, thanks to developments at its giant South Pars gas field, the sources said.

NIOC drew on condensate stocks from floating storage and onshore tanks in September to help meet growth in demand from China, South Korea, Japan and India.

Iranian ports loaded 2.153 million barrels of crude and 486,000 bpd of condensate in September, according to Thomson Reuters Supply Chain and Commodities Research. That put the month's total at 2.639 million bpd - excluding the condensate loaded out of storage - up from 2.472 million bpd in August, the Reuters data showed.

Condensate sales could reach 800,000 bpd in October, in excess of production at about 550,000 bpd, one of the sources said, suggesting further draws from floating tankers.

"Korea was the main demand driver for the growth. Japanese and Indian plants were also raising imports," said one of the two sources with knowledge of the matter from Beijing, adding that China's Sinopec has also boosted its offtake of condensate since August.

Iran will sell another 2 million barrels, or about 66,000 bpd, of South Pars condensate each month to Hyundai Chemical in Daesan between October and December, the two sources said.

Iranian condensate will meet about 70 percent of the feedstock demand at a new Hyundai Chemical splitter jointly operated by Hyundai Oilbank Co and Lotte Chemical .

A Hyundai Oilbank spokesman declined to comment.

According to trade flow data on the Thomson Reuters Eikon terminal for Iran condensate that discharged in September, about one-third went to South Korea, with the rest going to the United Arab Emirates, India, China and Japan.

Iran's South Pars condensate is usually sold at small premiums to Dubai quotes, free-on-board, much lower than Qatari condensate, which sells at premiums of $2-$3 a barrel, trade sources said.

http://www.reuters.com/article/iran-oil-idUSL3N1C21O7?feedType=RSS&feedName=basicMaterialsSector&utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+MasterMetalsNews+%28MasterMetals+News+Feed%29&utm_term=MasterMetals

Libya's Arabian Gulf Oil Company (AGOCO) said on Monday that its production had risen to 320,000 barrels per day (bpd), from 290,000 bpd late last week.

The increase had come after production at Sarir field rose to around 200,000 bpd, and production at Nafoura had reached 29,000 bpd, spokesman Omran al-Zwai said. He added that AGOCO could reach its year-end target of 350,000 bpd if the Bayda field came back on line.

AGOCO, a subsidiary of the National Oil Corporation (NOC) that operates mainly in eastern Libya, has roughly doubled production since forces loyal to eastern commander Khalifa Haftar seized blockaded oil terminals last month and the NOC announced it would reopen them for exports.

http://www.reuters.com/article/libya-security-oil-idUSL5N1C93I3

If the Nigerian government wants to fight militants blowing up oil pipelines, it should send troops into the creeks and mangrove swamps of the Niger River delta. Not the city.

That’s the suggestion of Babalola Olarewaju, a taxi driver who plies the airport route in Port Harcourt, the largest city in the restive oil-rich region.

“We’re talking about people who blow up pipelines in the night and then disappear,” said Olarewaju, 41, as he perched on the hood of his rickety cab outside the Le Meridien Hotel in the city center, referring to three T-72 tanks, Nigeria’s main battle tank, parked about a mile away. “What has a tank got to do here in the city?”

Dozens of tanks and 3,000 more troops have joined existing forces in and around Port Harcourt in the past month, a sign the government is pulling out the stops to quell a new wave of violence in Africa’s second-largest oil producer. So worrisome are the attacks that OPEC allowed Nigeria to be exempt from production curbs the cartel agreed on last week, the oil ministry said.

A six-week-old cease-fire show signs of weakening: The Niger Delta Avengers, responsible for more than 90 percent of all attacks this year, on Sept. 23 claimed responsibility for an attack, its first since July 24, on a key supply pipeline to Royal Dutch Shell Plc’s Bonny export terminal, a few miles outside Port Harcourt, in a statement on its website. The authenticity of the website, which has proved reliable before, couldn’t be verified.

There’s a lot at stake. Exxon Mobil Corp. is planning to resume some shipments at its Qua Iboe terminal, the country’s largest, at the end of September and expects repairs on the 400,000 barrel-a-day main export line will be completed in December. Shell also expects its Forcados terminal, out since February, to come back on line any time now. The company earlier this month lifted a delivery halt on its Bonny terminal shipments it had imposed in August after saboteurs breached its main supply pipeline.

The crucial challenge for the government is to appease a plethora of militant groups, some of whom never signed on to the cease-fire, such as the Niger Delta Greenland Justice Mandate. President Muhammadu Buhari, elected last year, is loathe to negotiate with the militants and is skeptical they are adhering to the truce. While Oil Minister Emmanuel Kachikwu, who helped broker the truce and also hails from the delta region, favors peace talks, the country’s security chiefs are averse to negotiation. Army chief Lieutenant-General Tukur Burutai would rather deploy more troops to put down the conflict. At least an additional 10,000 will be sent out in 2017, he said Sept. 9.

More Troops

“I do not see a willingness to engage,” said Ledum Mitee, a lawyer and Niger delta minority rights activist who’s part of the peace talks. “The response of the government is to send more troops to the region. There is a growing frustration within various groups that the government is not ready for negotiations and this may lead them back to attacking pipelines.”

In all, output is now estimated to average about 1.5 million barrels a day “at best,” Kachikwu said on Aug. 12. That’s potentially 23 percent lower than last year.

The resurgence of armed conflict in the delta mirrors a 2006 to 2009 campaign by the Movement for the Emancipation of the Niger Delta, or MEND. Attempts by then-president Umaru Yar’Adua to quell the militancy using troops escalated the violence. Attacks were curbed only after a state pardon and monthly stipend was granted to fighters willing to disarm. Violence resurfaced after Buhari stopped the payments and ended pipeline security contracts worth millions of dollars that former President Goodluck Jonathan negotiated with the militants.

Pipeline Knowledge

This has come to haunt the government. The militants today are more sophisticated and their attacks more precise. Led by the Niger Delta Avengers, the groups, now familiar with the layout of oil pipeline networks from their security operations, have in six months struck companies including Shell, Exxon Mobil, Chevron Corp. and Eni SpA where it hurt most: hard-to-fix export pipelines and oil-gathering hubs. So far this year, Forcados, Qua Iboe, Brass River and Bonny oil terminals have made declarations of force majeure -- a legal term that allows companies to miss export commitments -- after attacks on crude supply pipelines.

“A resumption of hostilities in the Niger delta would be disastrous for the government,” said Malte Liewerscheidt, senior Africa analyst at U.K. security consultants Verisk Maplecrost. “Sending the military is no solution.”

http://www.bloomberg.com/news/articles/2016-10-03/nigeria-risks-renewed-oil-supply-curbs-amid-fraying-cease-fire

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Norwegian union Safe is threatening strike action later this week by workers at three onshore plants unless it secures a pay agreement in state-mediated talks with employers, potentially hitting gas supplies to the UK.

http://www.upstreamonline.com/live/1445813/strike-threat-for-norway-plants?utm_source=twitterfeed&utm_medium=twitter

The last two years have clearly been a challenging and, at times, painful period for everyone in the upstream sector.  The dramatic fall in oil prices has forced the industry to look hard at capex plans and the efficiency of operating assets and functions, with significant downward pressure on rates.

There is evidence that the industry’s efforts are delivering some significant cost reductions.  We are seeing reductions in both project development costs and in operating efficiency – our analysis shows that opex per boe, for example, has declined by 11% globally between 2014 and 2015.

As the industry works on plans for 2017, there are two important questions operators must address:  do existing actions and plans go far enough to reset the cost base; and will these actions deliver cost reductions that stick.  As we are seeing signs of an emerging OPEC production agreement, and the associated uptick in oil prices, we think that it is critical to challenge whether the cost reductions of the last 18 months truly are sustainable or whether we are about to see the start of the next upcycle in costs.

We conducted an upstream sector Cost Survey over the last three months. We received over 290 responses from senior people from across the industry, both operators and the supply chain.  The results show that the industry is generally pessimistic when it comes to the sustainability of cost reductions. Less than 45% of respondents believe reductions achieved in the last 12 months to be sustainable and structural – a view shared both by the supply chain and operators. The timing is also interesting as the survey was completed in early September, before this week’s OPEC announcement.



 

Respondents also indicated that the focus of cost reduction over the next year would be on fundamentally tactical measures, such as retendering and renegotiation of contracts.  There was little evidence that the respondents were expecting to see widespread adoption of measures which would take out cost for all parties in the supply chain.

The financial health of the supply chain provides an interesting perspective on the sustainability question.  The impact of reductions in rates and activity levels has been a dramatic deterioration in Oil Field Service (OFS) company  margins since 2014. There is no doubt that re-evaluating contracts and renegotiating rates is a rational strategy for operators, but it is questionable whether OFS players will tolerate such low margins when the market recovers.  History suggests that there will be a push towards higher rates.

It is not only the suppliers who are anticipating a return to price increases. Interestingly 26% of respondents, from operators and the supply chain, expect to see price inflation in 2017 compared to only 8% of our 2015 survey respondents who expected to see inflation in 2016.





Really understanding the composition of the cost reductions over the last two years will be an important step for operators to start to manage this sustainability risk.

We will be publishing a perspective giving a fuller picture of the cost survey results and our views on the sustainability question in October.  If you would like to discuss how we can help you to explore this question for your organisation, please get in touch.



Operating cost: has the oil industry really moved the needle? The dramatic fall in oil prices – from over US$100 a barrel in mid-2014 to less than US$30 a barrel in early 2016 – has left the oil industry scrambling to contain the damage. Upstream operators are deferring investment...



https://www.woodmac.com/blog/progress-on-opex-but-will-it-stick/?utm_source=twitter&utm_medium=social&utm_campaign=sm-cons-pi&utm_content=o

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Qatargas, the world's largest LNG producer, will start operations at its new Ras Laffan 2 condensate splitter by the end of this month, doubling the Gulf state's capacity to process condensate, two sources with knowledge of the matter said on Monday.

The 146,000 barrel per day (bpd) facility had been due to open in September but was delayed due to technical problems, traders said.

It will process deodorized field condensate (DFC) and low sulphur field condensate to extract mostly naphtha and middle distillates.

Condensate exports from Qatar will drop from 500,000 bpd to about 350,000 bpd when the 146,000-bpd splitter starts operating, an official at Qatar Petroleum, Qatargas's state-owned majority shareholder, has said. That will enable the Gulf state to soak up some of its condensate at home as it faces growing competition for condensate sales overseas from U.S. and Iranian light oil shipments.

Commissioning of the new splitter is "99 percent" complete and an imminent handover to operator Qatargas is likely to see the plant start up "within the next two weeks," a Doha-based source, who declined to be named because he was not authorised to speak publicly, told Reuters.

Japan's Chiyoda Corp is building the refinery in a joint venture with Taiwan's CTCI Corp.

"We are at the final moment. There were no technical problems from our end," Chiyoda's general manager in Qatar, Toshiyuki Ito, told Reuters, but would not confirm a start-up date.

Qatari state-marketer Tasweeq withdrew offers for at least 1.5 million barrels of prompt November-loading DFC last week, traders with knowledge of the matter said, possibly indicating the splitter is likely to open imminently.

Initial offers for November-loading cargoes had indicated that the condensate splitter was more likely to start operations in November than October as the oil firm was seen reducing its November feedstock requirements by opting to sell prompt cargoes, traders said.

Tasweeq sold 2 million barrels of DFC for end-October loading prior to its offers for November-loading condensate supplies.

http://www.reuters.com/article/qatar-oil-qatargas-idUSL5N1C92LE

Petrobras, Statoil extend partnership for old wells - sources

Petróleo Brasileiro SA and Norway's Statoil ASA are expanding an existing partnership to help the Brazilian state-controlled company arrest declining production at aging wells in the offshore Campos Basin, two people with direct knowledge of the plan said.

In late August, Petrobras and Statoil signed a memorandum of understanding that has since evolved to targeting aging wells. Both firms are discussing under which terms Statoil could get stakes in some fields in exchange for fresh investment and technological cooperation, the people said.

Press representatives for Petrobras did not have a comment. The sources asked not to be identified because the talks remain private.

However, in an emailed statement to Reuters, Oslo-based Statoil acknowledged the plan, adding that it is too early to elaborate on the evolution of the talks.

The decision underscores steps by Chief Executive Officer Pedro Parente to rationalize capital spending at Petrobras, and cope with the impact of low oil prices and a sweeping corruption scandal involving the company.

The Campos Basin, which was responsible for about 85 percent of Brazil's oil output five years ago, accounts now for 58 percent. Petrobras produces about 80 percent of Brazil's oil and is responsible for developing massive offshore oil finds in a region known as the Subsalt Polygon, which first produced oil in 2008.

The move comes two months after Statoil agreed to pay $2.5 billion for a 66 percent stake in Carcará, one of Petrobras' largest oil and gas prospects. Recently, the companies signed a deal in which they said would collaborate on existing fields in Brazil's Campos and Santos Basins..

BUSINESS PLAN

The Subsalt Polygon is an offshore region near the coast of Rio de Janeiro, where several of the world's largest recent oil discoveries have been made.

Last month, Petrobras cut planned investments for the 2017-2021 period by 25 percent in a drive to reduce the largest debt burden among global oil producers, at $130 billion, and revive investor confidence battered by years of over spending.

Capital spending plans for existing Campos Basin wells suffered the most with the cuts, one of the people said.

The 2017-2021 business plan lowered the estimate for the rate of decline of production in the Campos Basin to 9 percent a year. Petrobras had a prior estimate of a decline between 12 percent and 15 percent.

The plan included the need for production partnerships in the Campos Basin, especially to revive output in the basin's Marlim field.

http://www.reuters.com/article/petrobras-statoil-oil-fields-idUSL2N1C61PL

Perisai Petroleum Teknologi Bhd., a Malaysian offshore oil rig contractor, failed to convince a group of bond investors to agree to its debt restructuring plan.

More than 70 percent of investors who voted on Monday rejected the company’sproposal to extend the maturity of the bond to Feb. 3, 2017, according to Cheng Fong Kiew, a bondholder present at the meeting.

Over 20 bondholders gathered at the basement of an office tower in Singapore’s central business district to vote on the plan to prolong maturity of its S$125 million ($91.6 million), 6.875 percent bond due today. Bond investors last week demanded immediate repayment after talks with the company collapsed.

“Yes, it’s our responsibility that we bought the bonds but the company can’t just brush us aside,” said Cheng, who owns S$500,000 of Perisai bonds. “Trust has been eroded.”

Southeast Asia’s oil and gas industry is being hobbled by a decline in crude prices and slowing global economic growth. Swiber Holdings Ltd. roiled the market when it defaulted on S$460 million of local-currency notes, while shippers including Rickmers Maritime are seeking to reorganize debts.

Perisai’s head of corporate planning Lai Swee Sim, who represented the company at today’s meeting, declined to comment. The notes were last quoted at 55 Singapore cents on the dollar, according to DBS Bank Ltd. prices.

Shares in Perisai have dropped 24 percent in Sept., outstripping the broader KLCI market that has declined 1.5 percent.

http://www.bloomberg.com/news/articles/2016-10-03/perisai-bondholders-reject-oil-rig-contractor-restructuring-plan

Independent oil companies are using the post-OPEC rally to hedge their price risk for next year, banks and consultants said, a trend that’s likely to be viewed with concern from Saudi Arabia to Venezuela.

The clamor to hedge -- locking in future cash flows and sales prices -- could translate into higher U.S. oil production next year, offsetting an output cut that the Organization of Petroleum Exporting Countries outlined in Algiers last week. Shale firms in particular would enjoy extra income to pay for additional drilling.

“We are seeing significant producer flows which early estimates suggest could be the highest we have seen all year,” Adam Longson, commodity strategist at Morgan Stanley in New York said in a note to clients.

Crude futures surged by almost $5 a barrel since OPEC surprised traders by agreeing to trim output at a gathering in Algiers on Sept. 28.

Harry Tchilinguirian, head of commodity research at BNP Paribas SA in London, said on Friday that OPEC had thrown a “lifeline” to U.S. shale firms, prompting them to hedge “in droves.” The bank has “seen many queries coming through” from producers, he said.

The West Texas Intermediate 2017 calendar strip -- an average of future prices next year that’s often used as a reference for hedging activity -- rose above $50 a barrel to its highest since August on Monday. “When calendar 2017 pricing rises into the low-to-mid $50s, as it is doing now, producer hedging rises materially,” Longson said.

U.S. shale producers used a similar rally to hedge their prices in May, when the WTI 2017 calendar strip also rose above $50 a barrel. The current activity comes after industry executives told investors in July and August they planned to use any window of higher prices to lock-in cash flows for next year.

"We would like to be a little bit further hedged than we are today," Pioneer Natural Resources Co. Chief Executive Officer Tim Dove said back in July, noting his company has locked in prices for up to 55 percent of its 2017 exposure. “I’d like to see us get that number up as we go towards at the end of this year.”

U.S. independent oil companies have only hedged 16 percent of their price exposure for 2017, compared with 39 percent for the rest of this year, according to Houston-based boutique investment bank Tudor, Pickering, Holt & Co. "We expect hedge book conversations to tick up during the next round of quarterly calls," it said in a note to clients on Friday.

U.S. shale companies and other independent exploration and production companies usually reveal their level of hedging with a quarter delay. Nonetheless, anecdotal pricing activity already suggests their presence in the market.

The WTI price curve, for example, has flattened over the last week, with spot prices rising more than prices for delivery next year, suggesting producer selling in 2017 and beyond. The spread between the WTI contract for immediate delivery and a year forward narrowed on Friday to minus $4.12 a barrel, from minus $4.77 a barrel before the OPEC meeting. The trend continues further down the curve too, with the spread between oil for delivery in Dec. 2017 and Dec. 2018 also contracting sharply after the decision in Algiers.

At the same time, the open interest in the WTI June 2017 contract has jumped nearly 10 percent over the last week, while the December 2018 contract rose 6.5 percent, another indication of hedging activity. Open interest across all WTI contracts rose by 66,000 lots -- the equivalent of 66 million barrels of oil -- from Tuesday to Friday last week, according to preliminary CME data. The total volume of crude futures on ICE and Nymex combined hit a record on Wednesday, the day of the Algiers meeting at which OPEC members agreed on a plan to limit output.

“Every time prices get above the $50 range we see a lot of activity coming in from producers selling into the rally,” said Hamza Khan, an analyst at ING Bank NV in Amsterdam.

http://www.bloomberg.com/news/articles/2016-10-03/shale-oil-firms-hedge-2017-prices-in-droves-after-opec-rally

Operators have been saying the Bakken is getting better and better, but North Dakota Department of Minerals Director Lynn Helms had the numbers to show it. Not only are today’s wells vastly superior to wells of even two years ago, Helms said during the annual conference of the North Dakota Petroleum Council, but they now have a lifespan that is five years longer.

“Initial production (on new wells) has increased from 1,100 barrels a day to 1,500,” Helms said.

Coupling that with the additional five-year lifespan, that means 25 percent more recovery from every well bore.

The new methods that created better productivity are also creating opportunities for economical refracs of old-school wells even at current prices — an “iteration” Helms called amazing.

An iteration is a successive process in which the next solution is based on the last, but a little bit better than before.

“You are getting more of the reservoir and using no greater footprint than in 2014,” Helms said. “You are still iterating, and it amazes me.”

Helms estimated there are between 8,000 and 8,500 wells drilled with older technology, many of which could be good refrac candidates.

Previous to Helms, a Whiting Oil representative talked about his company’s foray into refracs, and how his company is developing methodologies to determine which wells are good candidates for the process. Prior fracs didn’t use as much sand and had less efficient fractures than what is possible today.

“Data is mounting for why you want to refrac before you do,” Charles Ohlson, a petroleum engineer with Whiting Petroleum Corporation, said.

Those kinds of things mean more opportunities for further reiterations, Helms pointed out.

“There’s just a huge amount of iteration in well design and in well completion that is going on,” he said. “It is far from settled science.”

Helms has developed several scenarios for the lifespan of the Bakken play.

The endpoint of the Bakken shows 65,000 wells and a peak rig count of 150 in 2023. That uses a price of $50 to $60 oil to get there — a price point at which most of the Bakken’s return on investment has been shown to be fairly reasonable, according to state figures shared by Justin Kringstad, with North Dakota Pipeline Authority.

In a slow year such as this, an estimated 2,500 wells don’t get drilled, Helms said. The question is, when will they get drilled? In one scenario, they are drilled in 2035, but what if they are drilled as soon as oil prices pop back up, say mid 2017?

“When I go out and talk to communities and students about their anticipated needs for housing, sewer or water, I tell them to keep the scenario in mind, because this is the scenario that brings back crew camps,” Helms said.

And it also brings revenue for building out infrastructure needs.

In another scenario, oil stays low for longer and only the core of the Bakken gets drilled.

 Helms couldn’t exhaust the core in a reasonable time frame without adding more rigs to the model. Even then, it still took 15 years to exhaust the core, showing that the play has plenty of life to make it through the downturn.

Oil in the $50 to $60 range will make the state’s 900 drilled but uncompleted wells highly economic, Helms said, and will ramp up the number of frac crews operating. That number for now is in the range of five to 11. At peak prices, there were 50 frac crews operating in the Bakken.

“Sixty dollar oil makes the Bakken superior to other plays,” Helms said. “Even to the Permian and Eagle Ford. So that is when you will see drilling rigs go back into service.”

However, even then, you still won’t see as many rigs, Helms said, and you can thank iteration for that, too. Today’s rigs are now achieving 25 wells in a year, versus eight or nine in 2009.

“It’s just an indication of what kind of technology is out there,” Helms added.

Multi-well pads, new bit technology, new motor technology, new mud technology — these are all getting their own iterations, improving the efficiency and lowering the costs of getting along in the Bakken.

Drill times are now down to an average of 12 days, with three of that waiting for cement to set.

http://www.sidneyherald.com/news/breakthroughs-are-fueling-up-the-bakken/article_c6f1fc46-84fb-11e6-afdd-dfcd13a03b34.html

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Marathon Oil Corporation announced that the Company has signed an agreement for the sale of certain non-operated CO2 and waterflood assets in West Texas and New Mexico for $235 million, excluding closing adjustments. The properties averaged approximately 4,000 barrels of oil equivalent per day in the first half of 2016. The effective date of the transaction is Sept. 1, 2016, and closing is expected by year end.

Since August 2015, Marathon Oil has announced or closed non-core asset sales in excess of $1.5 billion.

http://www.oilvoice.com/n/Marathon-Oil-sells-nonoperated-assets-for-235-million/c758a7f85046.aspx?utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+OilvoiceHeadlines+%28OilVoice+Headlines%29

Funds managed by affiliates of Apollo Global Management, LLC (NYSE:APO) (together with its consolidated subsidiaries, “Apollo”) and Post Oak Energy Capital, LP (“Post Oak”) announced today that Double Eagle Lone Star LLC (“Double Eagle”), and Veritas Energy Partners Holdings LLC (“Veritas Energy”) have entered into a definitive merger agreement, creating one of the largest pure play exploration and production companies focused on the Permian’s Midland Basin. Double Eagle was previously a subsidiary of Double Eagle Energy Holdings II LLC (“Double Eagle II”), a portfolio company of Apollo Natural Resources Partners Funds I and II, and Veritas Energy was previously a portfolio company of investment partnerships managed by Post Oak.

The newly combined company, which is called Double Eagle Energy Permian LLC, has more than 63,000 core Midland Basin net acres (over 70% operated) located predominantly in Midland, Martin, Howard and Glasscock counties, and a team with extensive experience drilling and operating wells in the region.

Double Eagle Energy Permian will be headquartered in Fort Worth, Texas, and Cody Campbell and John Sellers, the current Co-Chief Executive Officers of Double Eagle II, will serve as the Co-Chief Executive Officers of the new company with Hollis Sullivan, the current President of Veritas Energy, serving as Chairman.

John Sellers and Cody Campbell commented, “We believe combining the highly complementary Midland Basin acreage positions of Double Eagle and Veritas Energy creates a truly world class asset in the core of the most economic basin in North America.”

Hollis Sullivan added, “With the strength of the new company’s combined management team and its operated, drill-ready acreage position, Double Eagle Energy Permian is uniquely positioned for rapid growth and expansion in the region.”

http://www.bloomberg.com/news/articles/2016-10-03/shale-oil-firms-hedge-2017-prices-in-droves-after-opec-rally

Mammoth Energy Services, Inc. today announced the commencement of its initial public offering of 7,500,000 shares of its common stock at an anticipated initial public offering price of between $15.00 and $18.00 per share.

Certain selling stockholders named in the registration statement are offering an additional 250,000 shares of common stock. In addition, the underwriters have a 30-day option to purchase up to an additional 1,162,500 shares of common stock, at the same price per share, all of which would be sold by the selling stockholders.

Mammoth Energy will not receive any of the proceeds from the sale of the shares by the selling stockholders.

http://www.globenewswire.com/news-release/2016/10/03/876463/0/en/Mammoth-Energy-Services-Inc-Announces-Launch-of-Initial-Public-Offering.html

SM Energy Company announced today that it has engaged Petrie Partners to explore a sale of certain leasehold assets in the Williston Basin. The assets to be sold include approximately 54,500 net acres, consisting of the Raven/Bear Den acreage and effectively all lease-holdings in the basin outside of the Company’s Divide County program.

President and Chief Executive Officer Jay Ottoson comments: “We have outlined a simple strategy to focus on our Tier 1 assets in the Permian Basin and operated Eagle Ford. As part of this strategy, we are continuing to core up our portfolio, such that we can concentrate investment dollars in the highest return programs and bring that value forward through accelerated activity. Raven/Bear Den is a terrific asset that provides attractive full-cycle returns, and we believe it will be of more value to a company that will actively pursue its near-term development.”

Separately, the Company has closed on previously announced divestitures of assets located in New Mexico, North Dakota, Montana, and Wyoming, with associated net production of approximately 3,300 Boe per day, for net proceeds after purchase price adjustments and fees of approximately $186.7 million.

http://www.businesswire.com/news/home/20161003005453/en/SM-Energy-Announces-Additional-Asset-Divestitures