Matthew M. Reed is Vice President of Foreign Reports, Inc., a Washington, DC-based consulting firm focused on oil and politics in the Middle East.

Expectations are high that the November 30 OPEC meeting in Vienna will result in a supply pact requiring that some members cut production while others freeze theirs. Such a deal has proven elusive all year. It slipped away most dramatically in April, when a similar deal fell apart at the last minute. Since then, OPEC production has risen by 1.2 million b/d—meaning the Organization has added the equivalent of one more Algeria to the market (plus a little extra).

This time, however, oil ministers from key member states all say they’re “optimistic” like never before. Iraq is maxed out and more inclined to seek a higher price per barrel today, while Iran’s production ceiling is within reach if not already achieved. These twin developments make it easier for OPEC to reach a deal now, as opposed to the last time OPEC met in June, but it’s far from a foregone conclusion. It’s now up to ministers to resolve the thorniest issues and find a formula that’s both impactful and durable.

This time, however, oil ministers from key member states all say they’re “optimistic” like never before.

Positive signals abound but the November 30 meeting will not be a cakewalk. To get a serious deal, Iraq and Iran must be brought on board; combined cuts must add up to more than one million b/d; and ideally non-OPEC producers, most importantly Russia, will reach separate follow-up agreements with OPEC. Only then does OPEC have a chance of balancing markets sooner and raising the revenue so many members desperately need.

Iraq has resisted cuts all year, arguing that it must produce as much as possible to make up for years of sanctions and war and to pay for today’s fight against ISIS. But Baghdad changed its tone just days ahead of this week’s OPEC meeting. “Iraq is ready to cooperate with OPEC and cut production,” Iraqi Oil Minister Jabbar al-Luaibi was quoted last week. Prime Minister Haider al-Abadi was crystal clear too. “What we lose in lowering production we will gain in oil revenues,” he said. “Our priority is to raise the price of a barrel of crude.”

A “fake” cut can’t be ruled out since it would at the very least create the appearance of harmony among OPEC’s top members.

What’s less clear, and remains to be resolved in Vienna, is from which baseline Iraq will cut. This is because Iraqi officials claim all of Iraq, including Kurdish territory, is producing 4.776 million b/d, when secondary sources estimate that it’s producing 4.561 million b/d. The difference is material for an OPEC cut as it amounted to 215 thousand b/d in October and in recent months the gap has swelled to 300 thousand b/d. (As Platts has reported, Baghdad appears to be “double-counting” some oil that’s produced inside Kurdish-controlled territory.)

OPEC is reportedly aiming for a production cut target of 4.5 percent. 4.5 percent of Iraq’s claimed output is equal to the gap between the higher official number and the lower secondary sources estimate. So if Iraq’s official—and possibly inflated—production number is the baseline for a cut, then Iraqi production might only be frozen at around 4.5 million b/d. No barrels would come off the market.

A “fake” cut can’t be ruled out since it would at the very least create the appearance of harmony among OPEC’s top members. But behind closed doors the Iraqis will be pushed to accept secondary source estimates, since they have yet to convincingly refute them, and because it would require actual cuts. Using the secondary source estimates for October as a baseline, a 4.5 percent cut would shave 205 thousand b/d off Iraqi production. Add that amount to what Saudi Arabia and GCC producers can contribute—a plausible 800 thousand b/d—and the one million b/d threshold is feasible. Without Iraq, OPEC’s second-largest producer, it may be impossible.

At home, when speaking to a domestic audience, Iranian officials have claimed higher production levels than they’ve reported to OPEC. They’ve even claimed that volumes today are higher than at any time since the Shah ruled Iran.

Iran represents a real challenge because its messaging has been so confused in the weeks leading up to the Vienna meeting. At home, when speaking to a domestic audience, Iranian officials have claimed higher production levels than they’ve reported to OPEC. They’ve even claimed that volumes today are higher than at any time since the Shah ruled Iran. Statements like these should raise eyebrows when all year Iran has said it would not consider freezing or cutting output until production reached “pre-sanctions” levels, presumably those that prevailed in the mid-2000s. Simply put: Iran can’t claim victory and ignore OPEC. This disconnect isn’t necessarily disingenuous either. If you count crude oil andlighter condensates, the case can be made that Iranian production is at its highest level in decades.

Is that good enough for Iran? Or are they confident production still has room to grow? There are good reasons to doubt that Iran can lift production much more. If Iran is effectively maxed out, will they concede that in Vienna—and at the very least commit to a freeze? I don’t know. They won’t say. Iran’s fellow OPEC members can only hope.

In early February, just after prices had clawed back above $30/barrel and it was obvious OPEC was weighing intervention, I wrote the following: “OPEC needs three things to secure a meaningful production cut: unity among its top five members [Saudi Arabia, Iraq, Iran, Kuwait and the UAE], even if it requires a special arrangement for Iran; confidence in baseline production numbers from which members will cut, which are subject to dispute and possibly oversight; and sustained and significant declines in North American production.”

Those conditions hold true if the goal is balancing the market and raising prices. But almost 10 months later, Iraq and Iran are still toss-ups and U.S. oil production has stalled around 8.8 million b/d. The EIA forecasts that American production will tumble by only another 100 thousand b/d in 2017. Going forward, OPEC can’t expect the U.S. to contribute much more in terms of involuntary cuts, after production fell by 600 thousand b/d from 2015 to 2016.

Any deal is better than no deal for OPEC. In fact, with expectations high, failure this time around could seriously undermine prices. But the best possible deal is one that somehow incorporates Russia. While U.S. production fell over the last year, Russian output surged, averaging 10.73 million b/d in 2015 and surging to 11.2 million b/d in late 2016—coincidentally making up for lost American crude.

There’s some debate inside Russia about whether these volumes are sustainable but OPEC can’t begin to engage Moscow until it gets its own house in order first.

http://energyfuse.org/opec-whats-fight/

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Attached Files

After two tough years of falling oil prices and company valuations, investors in the world’s biggest energy producers have some cause for hope as crude prices continue their recovery from a 12-year low. They will be looking to OPEC not to dash it.

Oil companies around the world have together added $490 billion to their market value this year, the biggest gain in six years following a 25 percent rise in benchmark Brent crude, according to data compiled by Bloomberg. This follows a $850 billion loss in value last year and $720 billion in 2014 as crude prices plunged.

The oil slump has hammered producers around the world, from giants like Royal Dutch Shell Plc to exploration minnows. They have piled on debt, canceled billions of dollars of projects and slashed jobs to ride out the downturn. In September, the Organization of Petroleum Exporting Countries gave these companies hope by reversing a two-year policy of pumping at full throttle and agreeing instead to cut production. Yet, the group is struggling to overcome obstacles to implementing the deal.

“We all know what the oil companies are hoping for — a cut,” said Brendan Warn, a managing director at BMO Capital Markets in London. “The companies have become leaner and meaner than they have ever been, but they would still be looking at OPEC closely. It’s one of the most important OPEC meetings.”

The Bloomberg World Oil & Gas Index of 58 companies is up 12 percent this year, the largest gain since 2009 following two years of declines. Exxon Mobil Corp., Chevron Corp., Shell, Total SA and BP Plc have all increased this year. Energy companies are the second-best performers in the MSCI World Index after languishing at the bottom in 2015.

The year didn’t start so well. Brent crude fell as low as $27.10 a barrel in January, the lowest since November 2003, as OPEC kept its taps open and production from Russia and the U.S. was increasing. Saudi Arabia, which had led OPEC’s free-flowing oil policy, changed course in September amid increasing domestic financial pressure and the group decided to cut production for the first time in eight years.

Oil bosses could be forgiven for hoping OPEC members resolve their differences, since every dollar increase in crude raises BP’s annual adjusted profit by about $300 million, according to the company’s website.

CEOs from BP’s Bob Dudley to Shell’s Ben Van Beurden have reduced their operating costs by renegotiating contracts, making projects smaller and cutting workers. Next year, they’ll be able to balance their cash sources and spending at about $50 to $55 a barrel. Brent traded at about $47 on Monday.

“It’s one thing to hope and another to plan your business for the future,” Warn said. Regardless of the outcome of the OPEC talks “the companies will be focusing on the things they can control, like efficiency and costs.”

https://www.energyvoice.com/oilandgas/125381/oil-investors-490billion-riding-big-opec-decision/

$10 billion worth of potential upstream oil and gas output is at risk in Indonesia

Indonesian workers arrange barrels of oil at a distribution station of the state-owned oil company Pertamina in Jakarta, Indonesia. (AP Photo/Tatan Syuflana)

Some $10 billion worth of potential upstream oil and gas output is at risk in Indonesia with 35 production-sharing contracts (PSCs) set to expire in the next decade.

“The lack of clarity on extensions, and the scale of production at risk, make expiring PSCs one of the biggest issues facing Indonesia’s upstream sector,” energy research company Wood Mackenzie said in its latest report Indonesia’s Expiring PSCs: $10 Billion Of Potential Upstream Value.

As I wrote earlier this year, Indonesian NOC Pertamina is unashamedly targeting many of the expiring legacy production contracts largely operated by the IOCs in an effort to boost its domestic output. The 35 expiring PSCs make up over 1 million barrels of oil equivalent per day (boe/d) of output says Wood Mackenzie.France’s Total and Japan’s Inpex, as well as US companies Chevron, Talisman and ExxonMobil all have blocks expiring in the next five years.

To help meet its long-term production target, Pertamina has set its sights on the expiring contracts. This is largely because they will be the cheapest barrels the company will ever produce, but also because they are generally the easiest to operate.

“Assets such as Offshore Mahakam, Corridor and Jabung would be of interest to Pertamina as these are material gas exporting projects with exposure to LNG and piped gas contracts,” Alex Siow, an Indonesian upstream specialist at Wood Mackenzie said.

http://www.forbes.com/sites/damonevans/2016/11/28/indonesia-has-10-billion-at-risk-with-oil-and-gas-dilemma/#66707ec96b8e

China's commercial crude oil inventories declined 1.9 percent month-on-month in October as crude imports fell sharply, data showed Monday.

Net imports of crude oil fell 12.7 percent in October, while the amount of oil refined increased, bringing stocks down.

Diesel reserves also dropped due to high demand from autumn farming and construction projects in October.

However, gasoline stocks rose slightly as the cold weather affected travelling and reduced demand for petrol.

http://www.chinamining.org/News/2016-11-29/1480383182d78124.html

Wood Mackenzie’s latest study on Libya’s oil production shows the country’s output has doubled from 300,000 barrels a day in early September to close to 600,000 barrels a day today, adding to the global oil supply glut.

Although an OPEC member, Libya’s output has fallen so drastically it won’t be bound by any production restrictions. The country will seek to recover its lost market share, notably in southern Europe where refineries prize its light, sweet blends.

“Libya’s oil production increases have occurred despite the absence of a political agreement between competing administrations, and an ongoing security vacuum,” said Martijn Murphy, research manager at Wood Mackenzie.

Murphy said there are signs recent production gains could be sustained. These include the demise of the widely disliked Petroleum Facilities Guard (PFG) in the east, military success against IS in Sirte and western incentives to reverse Libya’s parlous state. Much will depend on the success of Libya’s state oil company, the National Oil Corporation, in depoliticising the country’s oil.

“Longer term, Libya will take significant time and investment to get back to pre-war levels of 1.6 million barrels a day. Upstream facilities in the east have suffered much damage over the last two years, as have ageing midstream pipelines. Storage tanks will have to be rebuilt at Libya’s largest oil port, As Sidra, following rocket attacks there,” said Murphy.

“Before committing new capital investment to Libya, independent oil companies (IOCs) will want to see a durable political agreement, functioning government institutions and the restoration of security – all currently a long way off. Libya’s national oil company will also have to secure funding for its 50% stake that it has in most projects, or fund its share with crude in kind,” adds Murphy.

Much uncertainty remains, but for the moment, Libya’s production recovery offers much-needed revenues for the state and at least the hope a corner has been turned. Despite UN-sponsored efforts to bring about a political agreement and unity government, Libya remains a divided country.

Wood Mackenzie’s analysis considers recent geo-political factors that led to the increase in Libya’s oil production.

On 11 September, General Haftar, affiliated to the eastern House of Representatives administration, took the ports from the PFG and handed them over to the National Oil Corporation. The state oil company, applauded for its neutrality throughout the civil conflict , quickly lifted force majeure on the ports and increased production from many of its fields in the Sirte Basin. In addition, fields with participation from IOCs including ConocoPhillips, Marathon, Hess and Wintershall have also restarted production for the first time in almost two years. This has led to today’s production levels approaching 600,000 barrels a day.

However, without the reopening of the country’s western export pipeline, Libya may be approaching the upper limit of its near-term production capacity. Reopening the western pipeline to Zawiyah could add an extra 200,000 to 300,000 barrels a day near term, ramping up to full capacity of 470,000 barrels a day within two years. Western infrastructure is newer and unlike As Sidra and Ras Lanuf in the east, Zawiyah hasn’t suffered any damage.

Achieving the National Oil Corporation’s target of 900,000 barrels a day by the end of the year will depend on ending the blockade of the western pipeline. It remains unclear whether the tribes of Zintan’s demands can be met in the absence of a national political agreement.

http://www.hellenicshippingnews.com/libyas-oil-production-signs-of-continued-gains/

Azeri Energy Ministry: Oil minister has cancelled trip to Vienna; will not take part in OPEC meetings

‏@Livesquawk

Liquefied natural gas imports into China, the world’s largest energy consumer, rose 15.1 percent in October year-on-year, according to the General Administration of Customs data.

China imported 1.84 million mt of the chilled fuel in October, as compared to 1.6 million mt in 2015, the data shows.

According to the data, China paid about US$645 million for LNG imports in October, down 2.2 percent on year.

The LNG import figures in the January-October period rose 25.4 percent on year.

The data reveals that China imported 19.7 million mt of the chilled fuel in the mentioned period as compared to 15.7 million mt the year before.

China started importing LNG in 2006 and is currently the world’s third largest LNG importer– representing about 8% of global LNG imports in 2015.

The country’s LNG imports are expected to significantly rise in the next five years as it as it is seeking to cut its addiction to coal to reduce pollution.

http://www.lngworldnews.com/chinas-oct-lng-imports-rise-yoy/

Italian oil and gas company Eni is in talks with various parties to cut its stake in the giant Zohr gas field offshore Egypt to 50 percent, Chief Executive Claudio Descalzi said on Monday.

The company, which owns the whole concession area that includes its Zohr discovery, agreed last week to sell a 10 percent stake to BP for $375 million.

BP, which has an option to buy another 5 percent, will also reimburse Eni for around $150 million of past costs.

"We believe we can operate the field with 50 percent, that's my objective," Descalzi said on the sidelines of an industry event.

Zohr, discovered by Eni in 2015, is the biggest gas field ever found in the Mediterranean with an estimated 850 billion cubic metres of gas in place.

The approval process for development of the field was completed in February and first gas is expected by the end of 2017.

Descalzi said Eni was talking to a series of groups about the sale of further stakes.

"This could happen fairly quickly. In our business that could also mean a few months," he said.

Bank of America Merrill Lynch analysts said in a note the $525 million capital injection Eni had received from the Zohr deal was viewed as good news for the company.

"It helps to cover the dividend in the short term and is evidence that Eni can execute disposals after the failed sale of (chemical unit) Versalis earlier in the year," the bank said.

Eni, whose cash flow fell 19 percent in the third quarter, is committed to selling 5 billion euros ($5.30 billion) of assets in the next two years to help fund investments.

Descalzi said a decision on Mozambique was "ripe" but added permits and bureaucracy were slowing things down.

"I would be happy if we had something to announce at the next strategy meeting," he said. Eni usually gives an annual presentation on its strategy in the first quarter of the year.

Sources have said Exxon Mobil has already clinched a deal to buy a stake in the Area 4 concession but an announcement would not be made for several months.

Merrill Lynch said it believed a sale of up to 25 percent of Area 4 could be announced by the end of this year and raise close to $2.5 billion.

In 2013 Eni sold 20 percent of its Area 4 licence to China's CNPC for $4.2 billion but since then oil and gas prices have come down by more than half.

http://www.reuters.com/article/eni-zohr-ceo-idUSL8N1DT53T

Egypt will import around 60 cargoes of liquefied natural gas (LNG) next year and Glencore will be the biggest supplier, trading sources with knowledge of the results of Egypt's mega tender for 2017 and 2018 said on Monday.

Glencore bagged the right to supply around 25 liquefied natural gas (LNG) cargoes to Egypt, while second-placed Trafigura is understood to have won the right to supply about 18 cargoes of the super-cooled fuel, the trading sources said.

Other parties successful in Egypt Natural Gas Holding's (EGAS) tender included BB Energy, Gunvor and Vitol, the sources added.

State-run EGAS, which issued the import tender in late October, sought 96 cargoes for delivery in 2017 and 2018 in total, with an option to buy 12 additional cargoes in 2017.

The company has now probably secured all of its 2017 requirements, and just six cargoes for 2018, traders said. It was not immediately clear why it did not seek more cargoes for 2018 delivery.

The details of the tender results could not be directly confirmed as EGAS did not respond to Reuters' queries. A Glencore spokesperson also declined to comment on the results.

January-March 2017 cargoes are understood to have been awarded at a slope of around 15 percent to crude, while the remaining cargoes for 2017 delivery are likely to have been priced at a slope of 12 percent and below, the trading sources said.

The steeper premium for the January-March cargoes is estimated to be equivalent to about $7.50 per million British thermal units (mmBtu). In comparison, Asian spot LNG prices for January delivery LNG-AS are currently pegged around $7.10/mmBtu.

"It is bullish news," a Singapore-based trader said, referring to the first quarter 2017 volumes and prices paid by EGAS.

However, the lower price for cargoes to be delivered later in 2017 reflect the weaker demand-supply fundamentals expected in the LNG market, said a second trader based in Singapore. Australia and the United States are due to ramp up production in the second half of next year.

Under the tender terms, LNG suppliers may have to wait as long as six months to get paid for deliveries arriving between January and June 2017. Thereafter payments will take 120 days compared with the 90 days that LNG shippers previously got paid after delivery.

http://www.reuters.com/article/egypt-lng-tenderresults-idUSL4N1DT3V5

Iran says it has signed a memorandum of understanding (MOU) with Schlumberger – the world's largest oil field services company - over the development of several southern oil fields.

The MOU was signed between Schlumberger and the National Iranian South Oil Company (NISOC) – a subsidiary of the National Iranian Oil Company (NIOC) – which is mostly in charge of the developments of prospects in Iran’s oil-rich Khouzestan province.

Accordingly, the French company would be required to study the formations of Shadegan, Parsi and Rag-e Sefid oil fields in Khouzestan.

The projects would be carried out within the framework of Iran’s new generation of oil contracts, Shana news agency reported.

Schlumberger would be the second giant energy corporation to win a deal in Iran’s oil industry. Earlier this month, Total signed a contract to develop a major gas project in Iran’s South Pars gas field. Total and Schlumberger now appear to have provided France with a strong foothold in Iran’s oil industry given that both companies are headquartered in Paris.

Italy’s Eni also announced late last week that it is looking into Iran’s post-sanctions investment prospects, but emphasised that it had to first wait for Iran’s outstanding payments over its previous investments in the country’s oil industry to be settled.

Schlumberger’ contract is one of the most prominent signed the US elections. The upcoming president-elect Donald Trump has vowed to undo the nuclear pact signed with Tehran last year by global powers. His pledge has led many international companies to freeze their plans to enter the Islamic Republic despite the country’s huge potential as an energy and consumer market.

Though most international sanctions on Iran’s energy industry were lifted in January, Washington has maintained a ban on US companies and citizens from investing in Iranian oil fields.

European oil giants have stepped into the breach, culminating with an agreement by France’s Total SA to join a $4.8bn investment in an Iranian gas field hours before Trump was elected.

Despite uncertainty over what the president-elect will do over the Iran nuclear deal, Schlumberger is not the only one to pursue Iranian opportunities. Immediately after Trump’s election, Norway’s DNO signed up to study a key Iranian oil field near the Iraqi border.

http://www.arabianoilandgas.com/article-16432-iran-awards-key-oil-deal-to-schlumberger/

Oil and gas companies operating in Australia may have wrongly claimed billions of dollars in tax deductions in recent years, leaving governments underpaid millions of dollars in royalties.

The Australian National Audit Office has released a report, Collection of North West Shelf Royalty Revenue, which finds “significant shortcomings” in the framework for calculating royalties levied on off-shore petroleum operations from the north west shelf (NWS) off Western Australia.

The NWS project accounts for over a third of Australia’s oil and gas production.

 Australia must catch up with other countries on how it taxes gas

It is a joint venture between seven major international companies including Woodside Energy, BHP Billiton Petroleum, and Chevron Australia.

The ANAO report found the administrative arrangements for royalty payments from the NWS project were so bad that it was impossible to know how accurate the royalties calculations had been.

It said the consolidated royalty schedule, which governs how royalties are calculated, had not been updated in the last 10 years. It also said oil and gas companies had been claiming deductions for things that were not permitted.

“On this basis, the ANAO has doubts about the eligibility of deductions claimed for the cost of debt and equity funded capital, excise paid on crude oil and excise paid on condensate,” the report warns. “There has been limited scrutiny of the claimed deductions.

“Some errors in the claiming of deductions have been identified, but the available evidence indicates that the problems are much greater than has yet been quantified.”

The report said the Western Australian government had commissioned consultants to investigate some deductions claimed by oil and gas companies, and they found $8.6m in underpaid royalties to date.

It said that investigation provided valuable information but a comprehensive review of claimed deductions had not been commissioned.

“The full extent of any errors in the calculation and payment of royalties has been been quantified,” the report said, adding that “significant effort” was required to resolve the status of another $281.4m in operating expenditure deductions and $21.1m in capital expenditure deductions.

The report said more than $5bn worth of deductions were claimed against petroleum revenues in the 18 months to December 2015. It said revenue reported by producers from NWS petroleum sales in the same period was $19.7bn.

From this, $1.9bn in royalties was collected. The Australian government retained $600m (32.3%) and the remaining $1.3bn (67.7%) was paid to Western Australia.

https://www.theguardian.com/business/2016/nov/28/oil-and-gas-royalties-may-have-been-underpaid-australian-audit-office-finds

Sasol chairman Mandla Gantsho last Friday moved to allay shareholder fears about the escalating costs of the company’s Lake Charles Chemicals Project (LCCP) in the US.

Gantsho told shareholders that because the project occupied a strategic position, it would improve Sasol’s competitiveness. The project includes an ethane cracker that will produce 1.5 million tons of ethylene annually.

Read also: Sasol opens polypropylene expansion project

The complex also includes six chemical manufacturing plants. About 90 percent of the cracker’s ethylene output will be converted into a diverse slate of commodity and high-margin speciality chemicals for markets in which Sasol has a strong position.

“(The project) occupies a very competitive position in the global ethylene cost curve,” Gantsho said. “It will transform the whole Lake Charles complex where we already have some assets that are operating by the way. That site will be transformed into a multi-asset site that will allow fixed and infrastructure costs to be spread over a number of other products and product lines.”

Sasol said the project would roughly triple the company’s chemical production capacity in the US. Estimated at $11 billion (R155bn), the project is under construction near Lake Charles, Louisiana in the US, adjacent to Sasol’s existing chemical operations.

In August Sasol announced that the costs of the project had escalated by $2.1bn from original estimate at the time of final investment decision in October 2014.

Responding to a question by shareholder, Theo Botha about the cost overruns, Gantsho said: “Despite the cost estimate increases, we as the board still consider the LCCP to be a very important and strategic investment. We believe that the LCCP will return value to our shareholders.”

The project would create opportunities for investment in additional downstream chemicals facilities, said Gantsho.

The ethylene produced in the facility would be used in six downstream plants on-site to produce high-value derivatives such as ethylene oxide, mono-ethylene glycol, ethoxylates, low density and linear low density polyethylene.

Investment

“So when you look at the cost of the project, you have to look at what else is coming up in terms of additional investment,” he said.

Gantsho said the cost overruns were not symptomatic of Sasol’s project execution history. The company had previously executed big projects below cost and ahead of schedule, he said, citing the synfuels progressive expansion project, known as the Secunda Growth Programme and the Mine Replacement Programme, which entailed the replacement of ageing mines.

http://www.iol.co.za/business/companies/sasol-allays-fears-on-us-project-2093887

Chevron Corp. has joined forces with Petroleos Mexicanos and Japan’s Inpex Corp. to bid next week for the right to explore for oil and natural gas, the first time the state-owned operator will partner with private companies to develop crude in the Gulf of Mexico.

Seven groups and eight individual bidders have been qualified to participate in the Dec. 5 auctions that include the Trion field joint-venture with Pemex and other 10 deepwater blocks, Mexico’s National Hydrocarbons Commission announced in Mexico City on Monday. The regulator didn’t specify which bids were for the joint venture or for the other areas.

Total SA joined forces with BP Plc and Norway’s Statoil in one group, and with Exxon Mobil Corp. in another. Eni SpA and Lukoil also joined up, and Anadarko Petroleum Corp. and Royal Dutch Shell Plc formed another group.

"We are attracting investment and technoloy in deep waters, where a large part of our national reserves are located," Hector Moreira, Commissioner at the Mexico Oil Regulator and former Pemex board member, said Monday. "We have attracted some of the largest companies in the world that have the technology and investment capacities to develop those resources."

Sweeter Terms

The Mexican government made a series of adjustments to sweeten the terms of the Joint Operating Agreement that Petroleos Mexicanos will sign with potential partners to develop the Trion field. Landing a major producer as a partner will signal the beginning of a new era for Mexico’s reeling oil giant. Burdened with nearly $100 billion in financial debt and a 12-year slump in crude output, Pemex has pointed to partnerships as the road to its salvation since the government ended the company’s 76-year production monopoly in 2014.

"We think the offer and opportunity are good enough for Trion to be awarded," Pablo Medina, an oil and energy analyst at Wood Mackenzie, said in a phone interview. "The key to Trion being awarded was the willingness to change the JOA and the conditions of the contract. Becoming Pemex’s first partner could create goodwill down the road as the industry continues to open."

Mexican upstart Sierra Oil & Gas, which has backing from private equity firms Riverstone Holdings and BlackRock Inc, and Malaysia’s Petroliam Nasional Bhd, or Petronas, have joined forces in one group as well as another that includes Murphy Oil Corp. and Ophir Energy Plc. BHP Billiton Ltd and China’s CNOOC Ltd will participate individually.

"Many of the companies that are participating in this bidding have been in Mexico with a permanent office in Mexico for decades waiting for this moment," Juan Carlos Zepeda, National Hydrocarbons Commissioner, said in a Nov. 22 interview in Mexico City. "We have very serious players and there is great expectation."

https://www.bloomberg.com/news/articles/2016-11-28/pemex-seen-attracting-oil-majors-interest-in-deepwater-jv

Genscape Cushing inv: big build: 1.8mbbl in week ended Nov 25.

@zerohedge  

 The oilfield service companies that supply everything from sand to sophisticated robot rigs are seeking a new lease on life as America’s fracking fortunes begin to turn.

Shale drillers have added 158 rigs since May, according to Baker Hughes Inc. At the same time, companies such as Chesapeake Energy Corp. and EOG Resources Inc. have been increasing their efficiency by cramming more and more sand into individual wells, aiming to extend their reach miles further. That’s boosted sand prices roughly 25 percent to about $24 a ton, according to IHS Inc.

It’s an early sign that oilfield services, hard hit by a two-year slump in oil prices, are seeing the first hints of a turnaround. With spending by drillers in the lower 48 states now forecast to be $1 billion higher than analysts expected in the final three months of 2016, pricing talks are heating up as servicers face off against explorers fearful of uncertain oil prices ahead.

“Sand certainly led the way here, and that’s starting to make its way into other product lines,” said James West, an Evercore ISI analyst in New York, in a telephone interview. “It’s going to be a much more rigorous pricing recovery as we go into 2017, given the very ambitious drilling programs and production forecasts from the North American E&P industry.”

Oil-services companies sell explorers everything from the sand, water and chemicals they pump into the ground to the diesel that powers their equipment. Their services can include mapping pockets of underground oil, cementing wells in place and even breathing new life into old reservoirs.

Reopening Conversations

With West Texas Intermediate crude prices now up by more than 70 percent from this year’s low, the industry is starting to use higher sand prices and the added activity in oil fields ranging from Texas’s Permian Basin to the Scoop and Stack plays of Oklahoma as an excuse to reopen conversations over how much they’ll be paid, said Samir Nangia, an IHS analyst.

Already, leases for more-efficient rigs that can walk from well to well and drill out several miles sideways, are up by as much as $5,000 a day, a third more expensive since May, according to Evercore. Spending to drill and complete wells in the lower 48 states will be $13 billion, or about $1 billion more than previously forecast, for the final three months of the year, Jud Bailey, an analyst at Wells Fargo & Co., wrote in a Nov. 11 note to investors. He expects the strong year-end activity to carry over into next year.

IHS’s Nangia said service companies may boost prices by almost 10 percent a year through 2021. "We’re about 30 percent below full-cycle pricing, maybe even 10 percent below cash costs for a lot of the pumpers," he said.

For months, the service companies have been saying that the prices they’re able to charge aren’t sustainable. It’s a claim that’s been largely supported as more than 100 contractors in North America have gone bankrupt over the past two years, according to the law firm Haynes & Boone LLP.

While stock indexes for both explorers and servicers remain down by almost half since the downturn began in mid-2014, explorers are recovering more quickly. Both groups touched bottom on Jan. 20. Since then, oil explorers in the Standard & Poor’s 500 Index are up 61 percent, compared with a 30 percent climb in the Philadelphia Oil Services Index.

Negotiations between the sides won’t be easy, according to recent statements by Jeff Miller, president of Halliburton Co., the world’s largest fracking service provider, and Bob Dudley, the chief executive officer of BP Plc, the London-based explorer.

In a conference call with analysts and investors last month, Miller referred to pricing talks with explorers as "a brawl." Around the same time, Dudley said at the Oil & Money conference in London that he wants 75 percent of the cost reductions producers won during the market downturn to "stick," even if crude prices continue to rise.

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The talks are occurring as oilfield contractors are increasingly teaming up with equipment makers in an effort to cut their own costs and offer oil explorers more streamlined and comprehensive options for the services and gear needed to siphon crude out of the ground. Schlumberger Ltd., for instance, bought manufacturer Cameron International Corp. this year. That was followed by an announced tie-up between Baker Hughes and General Electric Co.’s oilfield business.

Vienna Effect

Much of what happens from here will probably depend on what happens halfway around the world in Vienna. In September, OPEC said it would discuss an agreement to cut production to a range of 32.5 million to 33 million barrels a day. Since then, Iraq, Iran, Nigeria and Libya have sought exemptions. The 14-member group will meet in the Austrian capital on Nov. 30.

The oilfield price increases are “not a leap forward,” said Chase Mulvehill, an analyst at Wolfe Research. "This is a gradual shift upward in pricing, and that probably continues as we move into 2017, assuming that OPEC cooperates. If OPEC holds the line, or production continues to increase with OPEC, that puts a risk to the 2017 recovery story for U.S. onshore.”

In order for onshore explorers to make more longer-term budget decisions, many would trade the higher, volatile oil prices for more consistency, according to IHS’s Nangia.

"Everybody feels that if we can be at $50 a barrel or higher, that would be helpful," Nangia said. "Stability helps."

https://www.bloomberg.com/news/articles/2016-11-28/shale-fracking-rebound-starts-with-more-expensive-grains-of-sand

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Attached Files

Centennial Resource Development Inc., Denver, has agreed to acquire 100% of the leasehold interests and related upstream assets in Reeves County, Tex., owned by Silverback Exploration LLC, San Antonio, for $855 million.

Centennial is backed by energy-focused private equity firm Riverstone Holdings LLC, an affiliate of which agreed to acquire the assets on Nov. 21. The affiliate on Nov. 27 agreed to assign its right to purchase the assets to Centennial. The deal is expected to close on Dec. 30.

The deal comprises 35,000 net acres, of which 95% is operated with an average working interest of 88%, that directly offsets existing Centennial acreage in Reeves County, with current net production of 3,500 boe/d. Once the deal is complete, Centennial will have 77,000 contiguous net acres in the Delaware basin.

Centennial sees at least 600 horizontal drilling locations on the acreage assuming 880-ft spacing prospective for the Upper Wolfcamp A, Lower Wolfcamp A, and Wolfcamp B, which are estimated to have 210, 180, and 220 locations, respectively.

The firm says the acreage has an estimated undeveloped resource potential of more than 600 million boe from the Wolfcamp A and Wolfcamp B formations, with additional upside potential from the Wolfcamp C, Avalon, and Bone Spring formations. The deal increases Centennial’s operated extended lateral locations by 136%.

“This transaction increases our horizontal drilling inventory by 44% and more than doubles our inventory of extended length laterals, which we believe provides the most capital-efficient development,” commented Mark Papa, Centennial chief executive officer.

He added the deal allows Centennial to increases its oil production target for 2020 to 50,000 b/d of oil from 30,000 b/d.

Focused on the southern Delaware basin, Centennial Resource Development was formed earlier this year through the merger of Centennial Resource Production LLC and Silver Run Acquisition Corp., a special purpose acquisition firm created by Papa and Riverstone (OGJ Online, July 22, 2016).

Papa, a Riverstone partner who was chairman and chief executive officer of EOG Resources Inc. during 1999-2013, has led Centennial since that deal was completed. Centennial Resource Production was formed in 2013 by an affiliate of NGP Energy Capital Management LLC of Irving, Tex.

The deal between Centennial and Silverback is among dozens to have taken place since midyear in the Permian basin of West Texas and southeastern New Mexico, where the Delaware and Midland basins have drawn considerable interest.

Last week, Midland, Tex.,-based Concho Resources Inc. struck its third deal for Permian acreage this year alone, agreeing to buy 16,400 net acres in the northern Delaware basin from an undisclosed buyer for $430 million

http://www.ogj.com/articles/2016/11/centennial-to-add-more-delaware-basin-assets-in-855-million-deal.html