State-owned Qatar Petroleum on Wednesday said that it has signed an agreement with Japan’s engineering company Chiyoda to study further boosting its liquefied natural gas (LNG) capacity in order to stay as the world’s largest LNG exporter.

Qatar, the top LNG producer with a capacity of about 77 Mtpa is facing a growing competition from a tide of new LNG sources mostly from Australia and the US.

Under the new deal, a detailed study will be undertaken to identify the modifications that are required for debottlenecking the capacity of Qatar’s LNG trains, located in Ras Laffan Industrial City, in order to process additional quantities of gas that will be produced from the planned new North Field gas project, QP said in a statement.

To remind, Qatar Petroleum had announced last month its intention to develop a new gas project in the southern sector of the North Field with a capacity of about 2 billion cubic feet per day for export.

“As part of its efforts to reinforce Qatar’s leading position in the global gas industry, this agreement provides Qatar Petroleum with the option of increasing its LNG production with minimum investment, by leveraging the existing massive, world-class infrastructure and valuable synergies available in Ras Laffan Industrial City,” said Saad Sherida Al-Kaabi, Qatar Petroleum’s Chief Executive

“Qatar ranks first in the world in the production and export of liquefied natural gas (LNG), the first in the production and export of gas to liquid products (GTL) and the first in the production and export of Helium. Qatar Petroleum is determined to continue its lead position in the gas industry with its expansion plans, both inside and outside the State of Qatar,” Al-Kaabi added.

The study is expected to be completed before the end of this year, which will allow Qatar Petroleum to kick off the FEED work early next year, if it concludes that this option would achieve the optimum value for Qatar, the company said.

http://www.lngworldnews.com/breaking-qatar-to-boost-lng-export-capacity/

Qatar Petroleum is warning Japanese natural gas buyers not to press too hard in long-term supply talks or Japanese companies could be squeezed out of Qatar's LNG projects, sources have told Reuters.

Qatar faces rising competition from a tide of new LNG from sources including Australia, which is expected to surpass it as the world's top exporter by 2019.

That has emboldened buyers as they look for lower prices and more control via shorter contracts and the rights to divert or resell unwanted cargoes, for example.

In Japan, QP, which owns producers Qatargas and Rasgas, counts on customers led by JERA, a joint venture between Tokyo Electric and Chubu Electric.

In the current contract negotiations with Japan, at stake are annual supplies of 7.2 million tonnes of gas expiring in 2021 worth some $2.8 billion, or 10 percent of QP's output.

Underscoring the depth of Qatar's ties to Japan, Marubeni Corp and Mitsui & Co each own 7.5 percent stakes in the three-train Qatargas I project.

Mitsui also holds a 1.5 percent stake in Qatargas 3.

"If Japan pushes too hard or decides to buy LNG from other buyers like Australia, Qatar has said it could force Japanese companies out of their stakes in Qatargas projects," a Japanese diplomat told Reuters.

A QP official confirmed supply renewal talks may impact Japanese ownership stakes in Qatar's LNG projects.

Marubeni and Qatargas did not return requests for comment. JERA declined to comment.

Losing its foothold in Japan would force QP to seek sales among less creditworthy buyers in Africa, the Middle East and south Asia which are riskier to deal with.

Its status in Japan is already under threat, with its market share falling 17 percent last year while Australia's jumped by 20 percent, customs data showed.

One advantage Qatar still possesses is as the lowest cost producer it can undercut on prices.

"Chubu (Electric) has enough contracted supply from Australia and the United States to manage without Qatari supply if they wanted," a source at a Japanese trading house said.

TOUGHER TERMS

Japanese importers value longstanding business ties with Qatar and are unlikely to drop deals altogether, but the utilities are insistent on introducing more buyer-friendly terms, a Japanese trading source said.

"The flexibility to divert and cancel shipments will be one of the main demands from Japanese buyers who see themselves becoming more like traders in the years ahead," the source said, in particular reference to JERA.

Reducing volumes, shortening deals from the current 25 years, and aligning pricing formulas with market conditions will also be important, he said.

Pakistan recently struck a 15-year deal with Italy's Eni, showing how buyers are driving changes to long-term contracts.

Long-term pricing is closely tied to the price of crude oil, expressed as a percentage of a barrel's worth.

Pakistan was able to force Eni down to a price of about 11.8 percent, far lower than the 14.2 percent Japan buyers pay Qatar, industry sources said.

Slashing the premium on Japanese deals could add up to billions of dollars over a contract's lifespan.

Qatar could also be forced to offer contractual devices like those offered by some producers in Australia which protect buyers from oil price spikes.

Aside from Australia, Qatar faces an unlikely source of competition for Japanese market share from Nigeria.

Sources say the world's fourth-biggest LNG producer is courting Japan's city gas companies, power utilities and trading houses as many of its own supply deals with Europe wind down in 2021-2023.

Up to eight million tonnes of annual LNG output from Nigeria is coming off contract at that time and Japanese buyers are being targeted, according to traders.

Nigeria has LNG projects that are fully depreciated, allowing them to offer more flexible terms such as diversion rights and shorter contracts, sources said.

http://www.reuters.com/article/us-qatar-japan-lng-idUSKBN18Q1W3

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Iran eyes 5.3 Bcf/d of additional natural gas production from South Pars phases 17-21

South Pars development phases 17-21 will add more than 150 million cubic meters/d (5.3 Bcf/d) of new gas production from the giant Iranian offshore
field when they achieve full operating capacity, oil ministry news agency Shana reported Saturday quoting the CEO of National Iranian Oil Company, Ali
Kardor.

"We are now witnessing their completion and operation," Kardor said, referring to the five phases inaugurated in April, according to a transcript
Shana published of an interview by Iran Petroleum.

In a separate Shana report, Iran Petroleum put South Pars' current gas output at 540 million cu m/d, up from 280 million cu m/d in 2013, when Hassan
Rouhani first became president.

Development of the field started 15 years ago and has accelerated under Rouhani's administration, Iran Petroleum reported.

To date, eight new South Pars phases have been brought on stream by the Rouhani administration. Rouhani was elected May 19 to his second term in
office. Project phases 12, 15 and 16 were completed earlier.

Iran's petroleum ministry has assigned top priority to the development of South Pars, which has gas reserves estimated at about 500 Tcf, not only
because of the Persian Gulf field's huge size but also because it extends across Iran's maritime border with Qatar.

Qatar calls its side of the gas deposit North Field and estimates the gas reserves at roughly 900 Tcf.

"After the new administration took office, crude oil prices had fallen, we were under sanctions and our oil export rate had declined. Therefore,
NIOC's financial resources had declined sharply and we could not develop all phases together," Kardor said. "Had we done so, none of these phases would
have reached production."

Financial resources were allocated first to projects that had progressed the furthest so that they could be brought into production faster, he added.

Financing remained a serious obstacle to development, Kardor said. With sanctions still in place, about $3 billion in financial guarantees were
extended to contractors by the National Development Fund of Iran to enable South Pars development work to proceed, he added.

Total development costs for phases 17-21 was around $18 billion: nearly $7 billion for the combined phases 17 and 18, $5.5 billion for phase 19 and
$5.3 billion for the combined phases 20 and 21, he said.

Each new South Pars phase would raise Iran's GDP by 1%, Kardor estimated, adding that incremental South Pars gas supplies would displace liquid fuels,
allowing the country's oil exports to rise.

"Any delay in bringing these phases into operation means funneling profits to Qatar's market," he said.

ESSENTIAL EQUIPMENT RELEASED

The lifting of nuclear sanctions in January 2016 after Iran signed a nuclear deal with the P5+1 group of international powers, known as the Joint
Comprehensive Plan of Action, speeded up South Pars development by enabling Iran to import essential equipment that had been impounded in European
countries and the UAE, Kardor said.

Now facing the prospect of production declines at some South Pars phases without facilities upgrades, Kardor said compressors and pressure-booster
platforms were being installed to avert a pressure decline that would hurt output.

"These platforms weigh 19,000 to 20,000 mt. Iranian companies can build platforms weighing up to 7,000 mt and the contractors' yards do not have the
equipment to build pressure-booster platforms. Therefore, we have to apply
special equipment and technology which Iranian companies lack," he said, explaining the need for foreign input. Eventually, as Iranian contractors
worked alongside international partners and gained more experience, the construction know-how would be transferred to Iran, he said.

NEEDS FOREIGN INVESTMENT

Long-term reliance on the National Development Fund of Iran for finance would be unfeasible, Kardor said.

"Mere reliance on the NDFI resources is not a long-term and defendable approach. These resources will help the development of jointly owned fields
until the way is cleared for attracting foreign investment," he added.

"NIOC is making efforts to apply a variety of investment attraction methods in order to reduce dependence on domestic financial resources. This
company is facing numerous financial bottlenecks. In order to deal with development projects under such circumstances we need to develop skills to
attract foreign investment and apply creative methods," he said.

Kardor described NIOC's recent Eur550 million ($615 million) deal to buy corrosion resistant steel tubing from Spanish manufacturer Tubacex as one that
would both assist further development and maintenance efforts at South Pars, where the pipes are extensively used, and facilitate technology transfer to
Iran.

"NIOC is serious pursuing the transfer of technology for building this tubing in the country," he added.

On the development of Iran's offshore North Pars gas field, Kardor said it was a project for future development as the field lay entirely within
Iran's territorial waters. However, North Pars gas could be used to make up for any production shortfalls in the event of a fall-off in reservoir
pressure, he added.

"If not, we can use the North Pars gas for LNG and exports," Kardor said.

https://www.platts.com/latest-news/natural-gas/dubai/iran-eyes-53-bcfd-of-additional-natural-gas-production-26745283

Saudi Arabia's Deputy Crown Prince Mohammed bin Salman and Russian President Vladimir Putin, who together have worked to cut oil production, are to meet in Moscow late on Tuesday.

The two were instrumental in a successful global deal which saw oil production curtailed by 1.8 million barrels per day as part of efforts to prop up prices and reduce bloated inventories.

Kremlin spokesman Dmitry Peskov confirmed at a conference call with reporters their meeting would take place later on Tuesday.

Last time they met in China in September on the sideline of the G20 summit.

Al Arabiya TV said they will discuss the Syrian conflict, while four cooperation agreements are expected to be inked between Saudi Arabia and Russia.

Earlier on Tuesday, Russian Energy Minister Alexander Novak met his Saudi counterpart Khalid al-Falih and discussed situation on global oil markets.

The meetings take place following the agreement by the Organization of the Petroleum Exporting Countries and other large global oil producers led by Russia too extend oil output cuts by another 9 months.

http://www.reuters.com/article/us-russia-saudi-meeting-idUSKBN18Q0S4

Powerful Saudi Deputy Crown Prince Mohammed bin Salman told Russia's President Vladimir Putin on Tuesday that Russia and Saudi Arabia had no contradictions on the oil market.

Putin told the prince that energy agreements between the two countries had high importance and Moscow and Riyadh developed their relations successfully to stabilize the energy market and the oil prices.

http://www.reuters.com/article/russia-saudi-arabia-putin-prince-idUSL8N1IW445

The deal by OPEC and non-OPEC countries to extend output cuts is unlikely to lead to any fall in crude inflows into Asia from the region's main suppliers, who will ensure they keep their key markets well supplied as they strive to maintain market share and limit the prospect of the region being flooded with arbitrage cargoes.

Market participants and experts were of the view that the move by OPEC and 11 non-OPEC producers to extend production cuts by nine months -- a move that would keep nearly 1.8 million b/d of crude oil off the market through March 2018 -- would not be big enough to throttle the supply strategy of major exporters and prevent them from meeting the needs of their traditional Asian buyers.

Takayuki Nogami, chief economist at Japan Oil, Gas and Metals National Corp (Jogmec), said some OPEC producers in the Middle East won't be able to afford to reduce supplies to Asia -- instead they may boost shipments to meet peak demand needs.

"We may see an increase in supplies, even without an increase in production in the summer," he added.

Some traders said that it could be a testing moment for OPEC producers to maintain their output cuts as agreed, as they battle for market share in Asia amid the approaching peak demand season.

OPEC and non-OPEC producers agreed in Vienna last Thursday to extend the current oil output cut deal by nine months to the end of March 2018. The original deal calls on OPEC to cut 1.2 million b/d, while the 11 non-OPEC participants committed to 558,000 b/d in cuts, from January through June.

"The volume cut is not so big. So far we haven't seen any effect from the OPEC cuts in the past six months. The market is generally over-supplied. So even if they extend it by nine months, they may reduce volumes to Asian refiners for at least one month but then gradually increase the volumes again," a North Asian crude trader said. "The cuts will likely be adjusted elsewhere, with little impact on Asian buyers."

The trader added that if Middle East producers start to cut supplies to their key Asian buyers, they may lose out to the competition. "They will start to get lesser number of customers and lose market share," the trader added.

As Asia enters its peak refinery turnaround season, traders dismissed the possibility of any big impact on their prompt crude procurements, adding that the effect from the January-June production cut agreement was largely limited.

APPROACHING SUMMER, WINTER DEMAND

Traders said they would be keeping a close watch on the extent to which OPEC and non-OPEC producers would adhere to their production cut commitments ahead of the approaching summer and winter demand seasons.

"The summer season will be the key," a North Asian refiner source said. "It will be a focal point -- whether producers can comply and endure their production cuts."

Nogami added that some Middle East producers' compliance with production cuts could be tested from as early as June as they may try to meet cargo demand for August-loading programs. If not then, compliance could be seriously strained from around October for November loadings, as the winter demand season kicks in.

Any increase in oil production by OPEC's Middle Eastern producers in the coming months could have an impact on the currently narrow spread between the Dubai and Brent benchmarks in the second half of this year, pushing it back out, Nogami said.

In addition, the Dubai/WTI spread could also be narrowed by increasing US crude exports to the Pacific and the Atlantic, which may support WTI prices ahead, he added.

OPEC crude output in April averaged 31.85 million b/d, flat from March, an S&P Global Platts survey found, with the group still showing high compliance with its production cut agreement as increases in Angola and Nigeria were offset by declines from Libya and Iraq.

DIVERSIFICATION DRIVE

In the wake of the OPEC/non-OPEC production cut deal, Asian refiners have begun to diversify their crude slates, following the narrowing of the Dubai crude benchmark's spreads against WTI and Brent prices.

The Brent/Dubai Exchange of Futures for Swaps, a key indicator of ICE Brent's premium to benchmark cash Dubai, has been narrowing sharply this year as OPEC cuts tightened supplies of Middle Eastern medium, heavy sour grades, thereby raising their values against light sweet crudes in Northern Europe.

"Regionally, the market has already priced in the narrowing EFS for quite some time and is adapting to this scenario," an Asian sweet crude trader said. "The bigger question is which grades will now face more pressure than others. Most likely, the light crudes will come under pressure the most."

The second-month EFS has averaged 86 cents/b in the second quarter to date, down from $1.49/b in Q1. This is down from an average of $2.31/b in Q4 last year and significantly lower than the $3.10/b average in Q1 and $3.54/b average in Q2.

"Asian buyers have diversified their timing of purchasing crude. Before, they used to only focus on purchasing Middle Eastern crudes mid-month to end-month [for two months forward]. But now when they are offered arbitrage cargoes, typically CFR cargoes with good economics and the price is cheaper than Middle Eastern crudes. They will consider to take those cargoes and adjust their requirement for Middle East cargoes," said the North Asian crude trader.

An Asian crude trader said: "We will also be keeping an eye on the WTI/Brent spread, as we could see more US crude coming into the Far East."

US crude exports slowed in March after hitting a record of exporting more than 1 million b/d in February, as domestic crude price discounts to Brent and Dubai widened significantly.

The spread between front-month Dubai crude swap continues to command a premium to the same-month WTI swap for most of this year, with the spread averaging at $1.37/b so far in the second quarter and $0.51/b in Q1 against an average discount of $1.62/b in Q4 last year.

A weaker WTI versus Dubai crude typically makes various North, Central and South American crudes priced against WTI more competitive.

https://www.platts.com/latest-news/oil/tokyo/analysis-opecnon-opec-deal-unlikely-to-alter-27838647

First-quarter net income of Russia's No.2 oil producer Lukoil has increased by 45.5 percent to 62.3 billion roubles ($1.10 billion) compared to the same period last year, the company said on Tuesday.

Analysts, polled by Reuters, expected the January - March net income to rise by 16 percent, year-on-year, to 50 billion roubles.

First quarter sales rose to 1.43 trillion roubles compared to 1.18 trillion roubles in the first quarter of 2016, while EBITDA (earnings before interest, taxes, depreciation and amortization) increased to 207.6 billion roubles from 192 billion roubles year-on-year.

Lukoil is controlled by Vagit Alekperov, the long-standing chief executive, and his deputy, Leonid Fedun.

http://af.reuters.com/article/commoditiesNews/idAFR4N1IP01P

India's diesel demand is expected to rise to record levels again this year as a slew of infrastructure projects boosts use of the transport and industrial fuel, although a government-induced cash shortage will hold growth to its slowest in three years.

Increased fuel efficiency, a fall in commercial vehicle sales, and the use of other fuels for power generation are also expected to dent demand growth for diesel, analysts and traders told Reuters.

"The first quarter saw delayed effects of demonetization but I think (diesel demand) should improve as there are a number of projects going on such as road and railways, which should drive diesel demand up," said Tushar Bansal, director of Ivy Global Energy, a Singapore-based consultancy.

India has budgeted a record $59 billion for 2017/18 for infrastructure such as ports, roads, railways and power.

The world's third largest oil consumer guzzled 6.955 million tonnes of diesel in April, the highest so far this year and near a record of 6.958 million tonnes hit in May 2016, the latest government data showed.

Still, a weak first quarter is expected to hold India's diesel demand growth at 1.6 to 3 percent this year, a gain to 1.63 million to 1.65 million barrels a day, analysts from energy consultancies FGE and Wood Mackenzie said.

This is the slowest annual growth for diesel since 2014, down from a rise of more than 5 percent in 2015 and 2016.

"The slowdown is a result of the demonetization drive, which dampened economic growth for a few months since its implementation in November last year," said Sri Paravaikkarasu, head of FGE's East of Suez Oil.

Prime Minister Narendra Modi in November declared notes of 500 rupees and 1,000 rupees illegal tender, taking about 86 percent of total currency out of circulation, in a move that hit sales of cars and motorcycles and small businesses.

April sales of India's commercial vehicles, which consume mainly diesel, fell 23 percent year-on-year, for instance. Sales of passenger cars and motorcycles, however, mostly powered by gasoline, have started to recover.

Woodmac expects India's diesel growth to moderate at 3.2 percent a year over 2017 to 2025, down from an average annual growth rate of 3.9 percent from 2010 to 2016.

"The main reasons for a slowdown lies in increasing fuel efficiency, more substitution (for) oil, primarily diesel, in the power sector and a bearish outlook for diesel cars in India," said Sushant Gupta, research director for Woodmac's Asia-Pacific refining.

Still India's diesel demand growth in 2017 accounts for one third of Asia's demand growth for the fuel, he said.

"It is a positive story compared with China, where we expect diesel demand to be in slow decline in 2017."

http://www.reuters.com/article/us-india-diesel-demand-idUSKBN18Q0RN

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Attached Files

The Dutch government said on Tuesday that a study of the minimum amount of gas that can be produced annually at the Groningen gas field through 2020 while still guaranteeing supply is 21 billion cubic metres (bcm), assuming average temperatures.

That's slightly below the 21.6 bcm the government has proposed producing for the coming five years beginning October 1.

The study was carried out by national gas grid transmission operator Gasunie following a request by parliament.

The Netherlands has been cutting output at the Groningen field, Europe's largest, to reduce the risk of earthquakes caused by production.

In a letter to parliament, Economic Affairs Minister Henk Kamp said Gasunie and NAM, the Shell/ExxonMobil joint venture that operates the Groningen field, is investigating whether reduction can be further cut at the Loppersum cluster, near to where several relatively strong quakes have occurred.

http://www.reuters.com/article/groningen-gas-idUSA5N1HS002

Following reports on Monday that Greece’s Energean has found buyers for gas from its fields offshore Israel, this has now been officially confirmed.

In an emailed statement, Energean Oil & Gas has confirmed its subsidiary Energean Israel has signed with Dalia Power Energies and its sister company – Or Power Energies, two agreements for the supply of natural gas from the Karish and Tanin fields, offshore Israel.

Dalia and Or will purchase part of their gas requirements from Karish-Tanin to operate the Dalia power plant, the largest private power station in Tzafit, south-central Israel, as well as future power plants to be built by Or.

Energean Israel will supply an overall amount of up to 23 billion cubic meters of natural gas from Karish-Tanin reservoirs over the lifetime of the contracts.

The period of the supply agreements will start from the date natural gas flows in commercial volumes from Karish-Tanin to the buyers, and conclude at the point when the Purchasers’ generation licenses need to be extended.

The buyers have agreed to a Take or Pay arrangement for a minimum annual amount of natural gas from Energean Israel, at a price linked to Israeli electricity markets and underpinned by a floor price.

Energean Oil & Gas Chairman & CEO, Mathios Rigas said: “This is a significant day for the Israeli gas market. These are the first contracts for gas supplies from the Karish and Tanin fields signed with the Dalia group, the largest private power producer in Israel. The agreement is a substantial step towards bringing competition and cheaper energy to the market for the benefit of Israeli consumers and the country’s economy. Energean is in talks regarding further contracts with other potential customers in the market and is aiming to submit a Field Development Plan for the Karish and Tanin project in the next few weeks.”

Dalia Power Energies Company CEO, Eitan Meir added: “Dalia and Or Energy are working to expand the volume of production offered by them, while continuing to reduce the price of electricity. We are pleased to sign the agreement that expands the gas sources and the ability of the companies to offer their customers electricity at a competitive price. Competition in all segments of the electricity sector will serve the public and the Israeli economy.”

http://www.offshoreenergytoday.com/energean-confirms-israeli-gas-deal/

Exxon Squares Off With Shareholders in Annual Climate Showdown

This week will be a public trial by fire for new Exxon Mobil Corp. CEO Darren Woods.

Presiding over his first annual meeting since predecessor Rex Tillerson left to become U.S. secretary of state, Woods will be tested Wednesday on everything from climate change to his own paycheck. Analysts and investors will be watching to see if he proves as adept as his mentor in striking a welcoming tone with restive activists while gently disagreeing with just about everything they say.

So far, Woods has been a stabilizing presence.

“He represents a continuation of what Mr. Tillerson was doing and so far we’ve seen no strategic shift,” said Brian Youngberg, an analyst at Edward Jones & Co. In St. Louis with a “hold” rating on Exxon’s stock. That’s comforting “for long-term holders who own Exxon for the dividend and not much else.”

Woods faces a vote on a resolution requiring Exxon to provide a detailed analysis of whether the energy giant can prosper under strict greenhouse-gas limits. Backers of the measure, which are as diverse as the California Public Employees’ Retirement System and the Church of England’s investment fund, are striving to improve upon the 38 percent support a similar proposal received from shareholders last year. Exxon opposes the resolution because it says it already discloses enough data.

For Exxon, the shareholder-centered event it stages every May in a Dallas symphony hall has become a donnybrook over the environment and corporate governance. Activist groups have shifted in recent years from rowdy bullhorn protests on the sidewalks outside to delivering measured shareholder appeals inside the meeting hall arguing for more prudent financial stewardship.

Woods, an electrical engineer by training who’s spent his entire career at Exxon, will be confronted by investors demanding that Exxon cut new spending on oil fields and hand the cash over to shareholders in dividends instead. And less than five months after his promotion to the jobs of chairman and chief executive officer, Woods and the board he leads will face rising opposition to his $16.8 million pay package and the way it was calculated.

Activist shareholders are hitting Exxon, which produces about 2 percent of the world’s crude oil, with a version of the climate change accounting proposal for a second straight year. Despite the company’s steadfast opposition, the measure attracted more investor support than any of the four other environmental proposals put to a vote last year. This year there are almost 90 Exxon investors planning to support the measure, according to data compiled by investor advocacy group Ceres.

“Exxon’s business is extremely vulnerable to changes in climate regulation and consumer demand,” said New York State Comptroller Thomas P. DiNapoli, a lead sponsor of the climate impact resolution. The company “puts itself and its long-term investors at risk by failing to acknowledge this reality.”

Disclosures Sufficient

Exxon says its current disclosures, which include forecasts of how caps on carbon emissions will affect long-term petroleum demand, are sufficient.

Even with the strictest scenarios envisioned under the 2015 Paris Agreement, global population growth and economic expansion will need vast quantities of oil and natural gas to fuel power plants, vehicles and industrial society, Exxon said in a May 19 letter to shareholders. The Paris accord calls on nations to prevent worldwide temperatures from rising more than 2 degrees Celsius (3.6 Fahrenheit) from pre-industrial levels by slashing fossil-fuel pollution.

“The world will continue to require significant quantities of hydrocarbons for which Exxon Mobil is well-situated to compete,” according to the letter. “Substantial upstream oil and gas investment will be required through 2040, even assuming a 2-degree Celsius scenario.”

Thus far, this annual-meeting season has been bruising for oil producers seeking to beat back activists on the climate and compensation fronts.

Occidental Surprise

A majority of investors in Occidental Petroleum Corp. broke with company leaders and approved a climate impact proposal on May 12 that was almost-identical to the Exxon resolution. Calpers, representing California stateretirees, and other backers persuaded fellow investors to validate the resolution by a 58 percent margin, compared to a 40 percent "yes" vote in 2016.

Such shareholder votes are advisory, and aren’t binding on the company.

In a significant change, the proposal was supported by Occidental’s largest shareholder, BlackRock Inc. The $5.4 trillion asset manager voted in favor of a climate-change resolution for the first time ever after Occidental exhibited a "lack of response" on the issue after last year’s vote, BlackRock said in a statement on its website.

Occidental’s result was historic because it was the first time a proposal of this type succeeded despite company opposition, according to Gregory Elders, a Bloomberg Intelligence analyst.

BlackRock hasn’t yet made a decision on its Exxon vote, Zach Oleksiuk, head of Americas for BlackRock Investment Stewardship, said in an email Thursday. Vanguard Group is considering voting for the proposal, Glenn Booraem, the firm’s investment stewardship officer, said in an email Thursday.

Executive Pay

At ConocoPhillips, the world’s largest independent crude explorer, a majority of shareholders rejected CEO Ryan Lance’s pay package, even after his total 2016 compensation was cut almost 10 percent to $19.2 million. It was the first time Conoco investors said ‘no’ on executive pay.

Sixty-eight percent of shareholders participating in the Houston-based company’s annual meeting either abstained or voted against the executive pay resolution.

Exxon holders have been urged to follow the lead of Conoco investors and turn thumbs down on executive pay. Proxy adviser Institutional Shareholder Services Inc. cited a mismatch between pay and performance as reasons to vote against the package. Exxon’s long-standing compensation system has remained unchanged even as “investors’ expectations around executive compensation” have evolved, ISS wrote in a May 18 report to clients.

“Our compensation program ensures that executives focus on the long-term performance of the business and is aligned with shareholder interests,” Scott Silvestri, an Exxon spokesman, said in a May 19 email. “Exxon continues to demonstrate strong business performance relative to industry peers.”

https://www.bloomberg.com/news/articles/2017-05-30/exxon-squares-off-with-shareholders-in-annual-climate-showdown

A Brazilian court ordered state-controlled oil firm Petróleo Brasileiro SA to sell natural gas to Centrais Elétricas Brasileiras SA despite the power utility's billionaire debt with the oil company.

Eletrobras, as the state-controlled utility is known, plans to use the gas to begin testing a thermal power station under construction in the Amazon region that is scheduled to start operating in June.

Reuters had reported on Feb. 22 that Petrobras had refused to supply natural gas to test the so-called Mauá 3 plant because Eletrobras and some of its subsidiaries did not pay several billion reais for fuel supplies.

The 590-megawatt Mauá 3 thermal plant is close to completion, but is at risk of not getting the gas to run on.

Petrobras will now be forced to sell enough natural gas to allow the testing to take place, the oil firm said in a statement to Reuters, but not the amount needed for the plant to fully operate.

In its first-quarter financial statements, Petrobras said Eletrobras owed Petrobras 9.8 billion reais ($3 billion), of which 8.2 billion reais stemmed from the power firm's subsidiary in the Amazon region.

A media representative for the subsidiary Eletrobras Amazonas Energia said the parties were in talks and that it would comment on the court dispute "in a timely manner."

http://www.reuters.com/article/us-energy-petrobras-eletrobras-idUSKBN18Q2A9

Iraq’s oil ministry has authorized the construction of a refinery in Kirkuk in the semi-autonomous region of Kurdistan that would cost US$5 billion, Kurdish media network Rudaw reported on Monday, citing an Iraqi lawmaker from Kirkuk.

“The Iraqi oil ministry has given the go-ahead for a modern refinery to be built which will cost $5 billion,” Rebwar Taha from the Patriotic Union of Kurdistan (PUK) party told Rudaw. The project will be carried out in phases and could take between 3 and 5 years to complete, Taha noted.

The existing refinery in Kirkuk is 65 years old and refines just 30,000 bpd—a capacity that cannot meet demand in Kirkuk, the lawmaker said.

“This is why we have asked for the refinery’s production rate to be increased to 70,000 barrels a day so that oil from Kirkuk is no longer taken elsewhere under the pretext of refining it,” Rudaw quoted Taha as saying.

The region of Kurdistan in northern Iraq is estimated to have 45 billion barrels of oil reserves. Exports from the fields in northern Iraq held by the Kurdistan Regional Government (KRG) stand at around 600,000 bpd.

A spokesman for Iraq’s oil ministry, Asim Jihad, told Rudaw that the oil ministry had given its consent for a new refinery to be built in Kirkuk.

At the beginning of March, production from the Kirkuk fields was disrupted after Kurdish protestors seized a pumping station in order to protest the policies of Baghdad and Erbil, the capital of the autonomous Kurdish area. The protest was allegedly inspired by Kurdish demands that Baghdad authorize the construction of a refinery in Kirkuk, and they shut down the line shipping oil to Turkey.

A few days later, PUK agreed with Iraq’s central government to keep oil from the Kirkuk oilfields flowing via the pipeline to the Turkish export terminal Ceyhan on the Mediterranean. The deal was reportedly reached after Baghdad agreed to boost the capacity of the Kirkuk oil refinery, and thus PUK withdrew its threat to shut the pipeline to Ceyhan.

http://oilprice.com/Latest-Energy-News/World-News/Iraq-Approves-5B-Oil-Refinery-Project-In-Kurdistans-Kirkuk.html

UK offshore driller Ensco is set to acquire its U.S. rival Atwood Oceanics, expanding its fleet with high end rigs, and becoming the world’s largest jack-up operator.

The two companies have entered into a definitive merger agreement under which Ensco will acquire Atwood in an all-stock transaction. The definitive merger agreement was unanimously approved by each company’s board of directors.

Under the agreed merger, Atwood shareholders will receive 1.60 shares of Ensco for each share of Atwood common stock for a total value of $10.72 per Atwood share based on Ensco’s closing share price of $6.70 on 26 May 2017. This represents a premium of approximately 33% to Atwood’s closing price on the same date.

Upon close of the transaction, Ensco and Atwood shareholders will own approximately 69% and 31%, respectively, of the outstanding shares of Ensco plc.

As for the fleet, once the transaction has been completed, Ensco’s fleet will be expanded by six ultra-deepwater floaters, and five high-specification jack-ups.

The combined company will have a fleet of 63 rigs, comprised of ultra-deepwater drillships, deep- and mid-water semi-submersibles and shallow-water jack-ups.

The expanded fleet will have 37 jack-up rigs, including 27 premium units, which Ensco says will make it the largest jack-up operator in the world.

Ensco Chief Executive Officer Carl Trowell said, “The combination of Ensco and Atwood will strengthen our position as the leader in offshore drilling across a wide range of water depths around the world – creating a broad platform that we can build upon in the future.

Trowell said the acquisition significantly enhanced the company’s high-specification floater and jack-up fleets, adding technologically advanced drillships and semi-submersibles, and refreshing “our premium jack-up fleet to best position ourselves for the market recovery.”

The estimated enterprise value of the combined company is $6.9 billion, based on the closing price of each company’s shares on 26 May 2017. For comparison, Transocean, the world’s largest offshore driller, has an enterprise value of around $9 billion, according to data provided by Ycharts.

The merger transaction, subject to shareholders’ approvals of both companies, is expected to close in the third quarter 2017.  The combined company will have approximately $3.7 billion in revenue backlog.

An interesting fact: Almost exactly six years ago, on May 31, 2011, Ensco completed acquisition of Pride, making it the world’s second largest offshore drilling company at the time.

http://www.offshoreenergytoday.com/breaking-ensco-set-to-buy-atwood-oceanics/

Italian energy giant and LNG player Eni will reach the final investment decision on the development of the Coral gas discovery in the Rovuma Basin, offshore Mozambique.

The company will reach the decision by the end of this week, Reuters reports, citing a company’s spokeswoman.

The project involves the construction of 6 subsea wells connected to a floating LNG production facility, with a liquefaction capacity of over 3.3 million tons of liquefied natural gas per year, equivalent to approximately 5 billion cubic meters.

In February last year, Mozambique government approved the development of the gas field discovered in 2012. Located within Area 4, the field contains about 450 billion cubic meters (16 TCF) of gas in place.

In October, Eni and its Area 4 partners signed an agreement with BP for the sale of the entire volumes of LNG produced by the FNLG Coral South, for a period of over twenty years.

Eni is the operator of Area 4 with a 50 percent indirect interest owned through Eni East Africa, which holds a 70 percent stake in Area 4.

The other concessionaires are Galp Energia, Kogas and Empresa Nacional de Hidrocarbonetos (ENH), each owning a 10 percent stake. CNPC owns a 20 percent indirect interest in Area 4 through Eni East Africa.

http://www.lngworldnews.com/report-eni-to-reach-coral-flng-fid-this-week/

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Kinder Morgan Canada (TSX:KML) kicked off its first day of trading on the wrong foot with the stock falling as much as 7% early in the day after a Monday deal between two political parties in British Columbia that oppose the company’s Trans Mountain pipeline expansion.

The company’s shares had been priced at between Cdn$19 and Cdn$21 last week, and then scaled back to Cdn$17, but were trading at $15.79 Tuesday morning before recovering to about Cdn$16.20 by 12:30 pm ET.

Construction of the $7.4bn project is scheduled to begin in September and should be completed by December 2019.

The value drop can be explained by rising uncertainty about the future of the Trans Mountain expansion, following an agreement between anti-pipeline Greens and NDP to form a minority NDP government in B.C.

Both parties have repeatedly voiced their opposition to Kinder Morgan’s planned pipeline expansion, which would see capacity nearly triple to 890,000 barrels of oil per day from the current 300,000 barrels.

Delays of any kind would be negative for Kinder Morgan, but might provide a boost for rival Enbridge Inc.’s mainline system, according to analyst David Galison, from Canaccord Genuity.

“Based on the current production forecasts there may not be enough demand for both the Trans Mountain expansion project and” TransCanada’s Keystone XL project, he wrote in a note to clients. “New capacity has the potential to put pressure on Enbridge’s mainline system, which is the largest exporter of crude out of Canada.”

Alberta Premier Rachel Notley issued a statement saying the provincial government remains "steadfastly committed" to using all means at its disposal to seeing the project through to completion.

Prime Minister Justin Trudeau also reiterated his federal Liberal party still supports the expansion project.

The expansion of the pipeline, which will carry oil from Alberta's oil sands to B.C. to be exported to global markets, was approved by Trudeau in November. The green light, however, came with a series of both federal and provincial conditions attached.

Construction of the $7.4 billion project is scheduled to begin in September and, according to the company, it should be completed by December 2019.

http://www.mining.com/kinder-morgan-canada-falls-trading-debut-concerns-trans-mountain-project/