A booming British shale gas fracking industry will blow a hole in the UK’s climate change targets unless it is tightly controlled, the government’s advisers on global warming have warned.
At least three conditions must be met to address the risk, according to a by the Committee on Climate Change, a statutory body set up to advise ministers on keeping greenhouse gas levels within legal limits.
Any shale gas produced in the UK should displace imports rather than increase overall use; the risk of methane leaks must be rapidly addressed; and ministers will have to offset shale gas’s impact on the climate by cutting greenhouse gas emissions in other industries.
It is not clear how easy it will be for these conditions to be met, the report says. “Existing uncertainties over the nature of the exploitable shale gas resource and the potential size of a UK industry make it impossible to know,” said Professor Jim Skea, a member of the Committee on Climate Change.
“Under best practice, UK shale gas may have a lower carbon footprint than much of the gas that we import. However, gas is a fossil fuel wherever it comes from.”
That means it is not a climate-friendly option unless it can be used with equipment that carbon dioxide emissions before they enter the atmosphere. Governments around the world, including the UK, have committed billions of dollars to develop carbon capturing technology but high costs have limited its use. A £1bn plan to boost in last November’s Budget.
The shale industry is in its infancy in the UK but the government is determined to turn it into a thriving source of homegrown fuel, despite objections from environmentalists and some local communities.
At present, natural gas provides more than 80 per cent of UK heating and about 30 per cent of electricity generation.
The UK gets about half its gas supplies from imports, mainly through a pipeline from Norway and liquefied natural gas tankers. With North Sea gas production declining, dependence on imports is expected to rise.
Natural gas produces carbon dioxide when burnt and its main component is methane, a potent greenhouse gas in its own right that can leak from drilling wells. Under the 2008 Climate Change Act, the UK is committed to an 80 per cent cut in greenhouse gases by 2050 compared with levels in 1990.
The UK onshore oil and gas industry trade group, UKOOG, welcomed the Committee on Climate Change report, saying it confirmed that widespread shale gas production was compatible with the carbon budgets provided the three tests were met. “As an industry, we look forward to continuing to work proactively with regulators to minimise fugitive emissions from our operations,” said the group’s chair, Professor Averil Macdonald.
Separately, a group of medical professionals repeated their call for the UK to abandon its shale gas plans because of the threats it posed to health.
A report from the London-based charity said risks included reproductive problems from exposure to endocrine-disrupting chemicals and respiratory damage from smog.
The creditworthiness of nations as judged by one of the world’s largest rating agencies has deteriorated at a record pace in the first six months of the year.
Fitch Ratings has downgraded 14 sovereign borrowers so far in 2016, including the UK — citing falling oil prices, a stronger US dollar and Britain’s pending exit from the EU.
The decline highlights the sensitivity to geopolitical shocks felt by the world economy as a result of and rising debts.
Fitch attributes the scale of downgrades in large part to lower commodity prices, noting that borrowers in the Middle East and Africa account for more than half of its negative rating actions. However, it added that the significance of the UK’s exit from the EU was “difficult to overstate”.
“The short-term economic impact of the Brexit referendum will be decidedly negative in the UK,” said James McCormack, global head of sovereign ratings, adding that the ramifications of the vote would spread beyond the country’s borders.
“Europe’s political backdrop could have negative implications for sovereign ratings … Comparatively high government debt levels are observed in several eurozone sovereigns, and are likely to remain effective rating constraints.”
Following the financial crisis, the role of credit rating agencies has been questioned — with some accusing them of biased ratings and irrelevance. However, their decisions remain crucial to investors subject to mandates that determine what sort of assets they can own.
Following the referendum, rival rating agencies Moody’s and S&P also cut the UK’s rating, with S&P stripping it of its final triple A grade and predicting the country would “barely escape” recession.
So far this year, Moody’s has downgraded 24 sovereigns, compared with 10 at the same point last year, while S&P has downgraded 16 — a half-year figure only exceeded once, at the height of the eurozone crisis in 2011.
“I see parallels between the downgrades in peripheral Europe during the eurozone crisis and what is happening in emerging markets right now,” said Bhanu Baweja, emerging market strategist at UBS.
“It’s a very strange time — the credit is undoubtable weakening but investors are still crowding in because there are so few places to find positive yields.”
The crowding has caused the average borrowing rate of emerging markets calculated by JPMorgan’s index of EM bond yields to fall to a two-year low of 5.25 per cent.
“The problem is growth,” said Mr Baweja. “It is so weak that leverage is increasing and credit is weakening. This doesn’t mean there is a crisis but it does mean we haven’t seen the last of the downgrades.”
This year, the IMF expects emerging markets to grow — a modest increase on the previous year.
While there have been some improvements to current account deficits in the so-called “Fragile Five” — countries including India that caused concern a few years ago — other weaknesses have emerged thanks to falling commodity prices. As oil prices have fallen, Opec’s own , including Iraq and Nigeria, are now struggling to replace lost revenues.
| Fitch | S&P | Moody’s |
|---|---|---|
| Azerbaijan | Azerbaijan | Azerbaijan |
| Suriname | Suriname | Suriname |
| Congo | Congo | Congo |
| Kazakhstan | Kazakhstan | Kazakhstan |
| Mozambique — 2 downgrades | Mozambique — 3 downgrades | Mozambique — 3 downgrades |
| Saudi Arabia | Saudi Arabia | Saudi Arabia |
| Brazil | Brazil | Brazil |
| Bahrain | Bahrain | Bahrain — 2 downgrades |
| United Kingdom | United Kingdom | |
| Finland | Finland | |
| Nigeria | Nigeria | |
| Oman | Oman — 2 downgrades | |
| Trinidad and Tobago | Trinidad and Tobago | |
| Lesotho | Jersey | Austria |
| San Marino | Angola | Armenia |
| Costa Rica | Barbados | |
| Poland | Sint Maarten | |
| Guernsey | Croatia | |
| Zambia | ||
| Papua New Guinea | ||
| Angola | ||
| Gabon | ||
| Macao | ||
| Montenegro | ||
| Bermuda | ||
| Sri Lanka | Gabon |
The world risks becoming ever more reliant on Middle Eastern oil as lower prices derail efforts by governments to curb demand, the west’s leading energy body has warned.
The head of the International Energy Agency told the Financial Times that Middle Eastern producers, such as Saudi Arabia and Iraq, now have the biggest share of world markets since the Arab fuel embargo of the 1970s.
Demand for their crude has surged amid a collapse in oil prices over the past two years that has cut output from higher-cost producers such as the US, Canada and Brazil.
Fatih Birol, IEA executive director, said policymakers risk becoming complacent as rhetoric surrounding a rise in North American energy supplies has overshadowed the world’s growing reliance on Middle Eastern crude.
“The Middle East is the first source of imports,” said Mr Birol. “The higher the demand growth the more we [consumer countries] will need to import.”
Middle Eastern producers now make up 34 per cent of global output, pumping 31m barrels a day, according to IEA data. This is the highest proportion since 1975 when it hit 36 per cent. In 1985, when North Sea production accelerated, their share fell to as little as 19 per cent.
Fast-growing supplies from US shale fields triggered the oil price plunge in mid-2014. Unlike in the 1980s, however, Opec producers — led by and its Gulf allies — decided to maintain output to defend market share for the 13-member group, rather than cutting output to bolster prices.
Demand has since surged as prices more than halved following years of trading above $100 a barrel. Mr Birol said efforts to improve energy efficiency and reduce emissions were being thwarted as motorists returned to buying fuel-guzzling cars.
In the US, more than two-and-a-half times as many sports utility vehicles were being bought compared with standard cars, Mr Birol said.
Even more concerning for policymakers is China, where more than four times as many SUVs were bought, suggesting the country’s rapidly growing car culture has adopted America’s taste for larger more fuel-hungry cars.
“Lower oil prices are proving to be bad news for efficiency improvements,” said Mr Birol.
China has been the centre of oil demand growth for the past decade, becoming the second-largest oil consumer — behind the US — and surpassing it as the last year.
Hundreds of billions of dollars in energy investments have been cut since 2014 as oil companies have embarked on the biggest cost-saving measures in 30 years, Mr Birol said. That is cutting supplies outside Opec, with US and other countries’ production expected to decline this year.
Higher output from Iraq, Saudi Arabia and Iran has filled the gap.
“The Middle East is reminding us that they are the largest source of low-cost oil,” said Mr Birol. He said the region was expected to meet three-quarters of demand growth over the next two decades.
Higher had prompted some lawmakers to suggest the country can reduce its engagement in the Middle East. But Mr Birol warned politicians to keep in mind the importance of the region when creating economic and foreign policy. US oil imports are rising for the first time in year as demand has grown faster than supplies.
Mr Birol said policymakers needed to impose stricter fuel efficiency targets to reduce demand, arguing it was not feasible in a world market to completely sever reliance on Middle Eastern oil.
“US oil production will increase, but it is still an oil importer and will be for some time,” Mr Birol said.
“Some have the view the rise of tight [shale] oil will sideline the Middle East. This view, I would never subscribe to.”
The company has also requested the government to treat it on par with state distributors such as IndianOil and Bharat Petroleum on the subsidy front.
UK oil companies lobbied the government in the run-up to the war in Iraq and raised concerns that the US was pledging oil contracts to Russian companies in an attempt to overcome Moscow’s opposition to the invasion.
Documents released as part of the showed that representatives of oil groups such as , and met Baroness Symons, then UK trade minister, in October 2002 — five months before US-led forces entered Iraq — to discuss their potential role in postwar reconstruction.
“These discussions have taken place amid concerns that talks are being held between US officials and companies involved in these sectors from the US and other countries, eg Russia, without any involvement of the UK,” said a civil service briefing note for Sir David Manning, who was then foreign policy adviser to prime minister Tony Blair.
Separate documents cited reports by British officials of a meeting between Dick Cheney, US vice-president, and Yevgeny Primakov, a former Russian prime minister, in which Mr Cheney said: “Bids [for contracts] of those countries which co-operated with the US over Iraq would be looked at more sympathetically than those which did not.”
In her meeting with UK energy companies, Baroness Symons said she “could not make any definitive undertakings, given our determination that any action in relation to Iraq is prompted by our concerns over WMD, and not a desire for commercial gains”.
However, she subsequently told , foreign secretary in Tony Blair’s government, that she had promised to “draw this issue to your attention as a matter of urgency” and that UK companies “were genuinely convinced that deals were being struck and that British interests are being left to one side”.
Numerous similar exchanges are detailed in the Chilcot report laying bare the desire of UK companies for a share of the spoils from the opening of Iraq’s oil and gasfields once Saddam Hussein’s regime was overthrown. Documents show UK ministers and officials were desperate to avoid oil interests being seeing as a motivation for the war but also wary of losing out in the expected scramble for energy contracts.
Responding to a government paper that described securing contracts for British companies as a “second order objective”, Sir Christopher Meyer, then the UK’s ambassador to Washington, argued that this should in fact be a “top priority” in the UK’s planning for postwar Iraq and that “Mr Blair would have to pursue the issue with President [George W.] Bush if the UK were to have any impact”.
In the months and years after the invasion, the mounting frustration becomes clear of UK companies, ministers and officials over a perceived lack of British influence over Iraqi oil policy and over the dominance of US energy groups in the country.
In a letter to Mr Blair in June 2003, Mr Straw asked the prime minister to press the case for British companies “very forcefully” with Mr Bush. “As you know, the US are completely ruthless on favouring US companies, and will not help UK companies unless you play hardball with Bush”.”
Mr Blair subsequently raised concerns with the US president over the stalling of a bid by the UK arm of Siemens, the German group, for an electricity equipment contract in the face of competition from General Electric of the US. A few weeks later, British embassy officials in Washington reported a “favourable change” in attitudes towards the Siemens bid by the US-led coalition authority in Iraq.
Shell and BP declined to comment. BG Group is now part of Shell.
When commodity prices are squeezed, low leverage and high quality assets are preferred. Tullow Oil has the latter, and is working on the former. On Wednesday it announced a that should, counter-intuitively, help.
First, some history. Tullow opted to develop the TEN and Jubilee oilfields offshore Ghana when the global oil price was around $100 a barrel. Both fields are considered high quality assets, but developing them was a long, capital-intensive process. Meantime, both oil and Tullow’s share price dropped; the latter is down four-fifths in three years. The financing needed to develop the fields became a larger part of the balance sheet. Leverage rose just as investors began worrying about leverage.
The structure of that debt is also problematic. Tullow has $1.3bn of bonds coming due after 2020 and around $2.3bn drawn from a $3.5bn credit facility that expires in 2019 (the company’s equity market value is £2bn, or around $2.6bn) But that facility is a “reserve based loan”, collateralised by the Tullow’s reserves. As these resources deplete, or their per-barrel price declines, so does the available credit line.
Operational issues have also surfaced. This year, Tullow identified a problem with one of the vessels used to store oil from the Jubilee field before tankers transport it away. It is insured against the damage, but .
The convertible is relatively small compared to Tullow’s other borrowings, and is costlier than the loan facility. But it extends the debt maturity profile and reduces Tullow’s dependence on reserve based loans, whose terms will look increasingly unattractive if oil prices remain low.
With a plan for managing its liabilities and production in Ghana set to ramp up — the TEN field is expected to start up soon, boosting revenue and cash flow — Tullow might just be through the worst.
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Tullow Oil has launched a $300m convertible bond offering to shore up financing for its big exploration projects in Africa and reduce dependence on lending facilities linked to the volatile price of oil.
Like many in the industry, Tullow has in the past relied heavily on reserve-based lending, which uses a company’s oil and gas reserves as collateral for borrowing.
However, the fall in oil prices over the past two years has caused cuts in this form of credit as the value of reserves has fallen.
The proposed will provide more working capital for at a time when the UK-listed group is preparing to pump the first oil from its Ten field off the Ghanaian coast while pressing ahead with projects in Uganda and Kenya. But Tullow said the main motivation was a desire to diversify its sources of funding rather than a need for more cash.
Net debt at the end of June was $4.7bn, about 4.7 times last year’s earnings before interest, tax, depreciation, amortisation and exploration costs. Tullow has said it expects this to begin falling once its Ten field comes on stream.
Shares in Tullow fell as much as 16 per cent after the bond issue was announced on Wednesday. Analysts attributed this mainly to technical reasons related to funds shorting the stock as a hedge against the bonds.
Stephane Foucaud, analyst at FirstEnergy, said the fundraising was a sensible move to reduce the sensitivity of Tullow’s debt to oil prices.
In common with many industry peers, Tullow has been under pressure from , but Mr Foucaud said the worst had passed.
“Tullow is approaching a turning point where the big capital expenditure will be behind them,” he said. “The profile of the company is changing from an old, higher cost structure to a new one.”
Analysts said the convertible bonds provided a more stable form of finance than reserve-based lending, which is subject to — and potentially its credit limit — every six months.
Some banks, including BNP Paribas, have since the oil price crash, tightening the squeeze on producers.
The recent partial recovery in oil prices to about $50 a barrel has eased the pressure, but Mr Foucaud said companies were still struggling with high cost bases set in a vanished era of higher prices.
Tullow said its bonds would carry a coupon of between 5.875 and 6.625 per cent a year payable semi-annually in arrears. The bonds will be convertible into ordinary shares with an initial conversion price at a premium of 30-35 per cent above the volume weighted average price on July 6.
The first interest payment is due in January 2017, and any unconverted or unredeemed bonds will be due in 2021. Barclays and BNP Paribas are acting as joint global co-ordinators and joint bookrunners.
Initial response from Bangladesh, Pradhan said, has been encouraging and the company would be visiting Dhaka again this month to make a presentation on its plans.
The recoverable resources of the Vankor field as of January 1 stood at 361 million tonnes of oil and condensate and 138 billion cubic meters of gas.
Mega-projects are an endangered species in today’s oil and gas industry. As companies struggle to keep up their dividend payments with sharply reduced revenues, multiyear, multibillion-dollar commitments are increasingly seen as foolhardy excesses.
So the decision by a Chevron-led consortium to spend $36.8bn to increase production at the in Kazakhstan is a significant event.
It would be wrong, however, to interpret it as a sign that oil and gas investment is making a comeback. It has been shaped by a specific set of circumstances for the company and the country. Projects that do not benefit from such a supportive ecosystem may still struggle to make headway.
Chevron’s annual report for 2015 shows just how important its long relationship with Kazakhstan is to the US group.
Chevron was awarded the rights to develop Tengiz — one of the largest oilfields in the world, containing an estimated 26bn barrels — in 1993 following a furious lobbying campaign that began before the collapse of the Soviet Union.
“For Chevron it has been a huge cash cow,” says Dominic Lewenz, managing director at Frontier Advisory and a specialist on Central Asian energy.
“They bet the farm on the project 20 years back and it has been a storming success.”
It remains a vital contributor to Chevron’s earnings, production and reserves.
Chevron’s 50 per cent stake in TCO, the consortium that runs Tengiz, last year accounted for 27 per cent of its oil reserves, 8 per cent of its gas reserves and 13 per cent of its combined oil and gas production.
Because TCO’s costs are very low, its contribution to Chevron’s earnings is even greater. The consortium last year contributed $1.9bn of net income to Chevron, which was about 42 per cent of the group’s total earnings.
Average production costs at TCO in 2015 were just $4.32 per barrel equivalent of oil and gas; a little over a quarter of Chevron’s average cost of $16.60 per barrel in the US.
That is why it is a looming concern for Chevron that the contract that governs its participation in TCO and Tengiz will expire in 2033; relatively soon in the multi-decade timescales of big oil projects. Observers say they expect that the investment in the future growth project at Tengiz will help Chevron secure a contract extension, even if there is no formal link.
Chevron this week refused to make a link between the investment and the contract, saying its focus was on “ensuring the project is successfully executed, on time and on budget”.
It gave a clear indication, though, that it would be seeking to extend the relationship. “Discussions on the extension will be addressed at the appropriate time,” it said in a statement.
The $36.8bn investment is a bet on the oil price after the extra production comes on in 2022. It will break even with crude at about $50 a barrel, according to people close to two of the companies in the Tengiz consortium, meaning that it is unlikely to be spectacularly profitable should oil prices remain “lower for longer” as some analysts expect.
The good news for the company is that just as Tengiz is critically important for Chevron, it is vital for Kazakhstan. In 2014, Tengiz paid $11.2bn in taxes and other payments to the Kazakh budget, equivalent to about a quarter of the total government expenditures that year.
TCO says it has made $112bn in direct payments to Kazakhstani entities since it was established in 1993; a figure that includes dividends to the Kazakh national oil company, employee salaries and local equipment purchases as well as taxes and royalties.
Chevron and its partners, ExxonMobil, KazMunaiGas of Kazakhstan and Lukoil of Russia, have agreed to use 32 per cent local content, which means that about a third of the $36.8bn project cost will flow directly to local companies.
From a strategic point of view, the Kazakh government has been counting on the expansion of Tengiz, together with the long-delayed launch of the troubled Kashagan field, to lift the country’s oil production to more than 2m barrels per day, propelling it towards the big league of global oil producers.
With the more ambitious plans for Kashagan on hold, and the Kazakh economy struggling under the weight of the fall, “the Kazakhs are desperate for something to be successful”, says Matthew Sagers, senior director of Russia & Caspian Energy at IHS.
For , Kazakhstan’s president for the past 25 years, who has faced a wave of protests in recent weeks, the good news on investment in Tengiz may be particularly welcome.
Frontier Advisory’s Mr Lewenz says: “Nazarbayev needs something to point to. He’s always stood by Chevron; they’ve got to stand by him.”
LONDON — Bucking the trend of conserving cash at a time of low prices, the American oil giant said on Tuesday that it would go ahead with a $37 billion expansion of a gargantuan oil field on the Caspian Sea in Kazakhstan.
Giving the green light to such an expensive project, called Tengiz, looks on the face of it to be an unusual move, but analysts say the field has been lucrative and important for Chevron and its partners, who include Exxon Mobil.
Tengiz, which began producing oil in 1993, has been Chevron’s star, earning the company as much as $50 a barrel when prices were more than $100 a barrel, estimates Iain Reid, a London-based oil analyst at Macquarie, an investment bank. Prices were about $46a barrel as of midday Tuesday.
In a telephone interview, Todd Levy, a Chevron regional president, said that the company believed that, contrary to conventional wisdom, now “is a good time in the industry to proceed.” Chevron figures it can obtain low prices from suppliers, who might otherwise be idle.
In recent years Chevron has invested heavily in big undertakings like the $54 billion Gorgon liquefied natural gas project off Australia, but lower oil and gas prices have left Chevron and other companies with costs that are too high in comparison to current revenue.
In April, Chevron reported a $725 million loss for the first quarter of 2016, in contrast to a $2.6 billion profit in the same period a year earlier.
The company also had little choice but to move forward in Kazakhstan, which has become a cornerstone of its business. The company, which is based in San Ramon, Calif., obtains about one-sixth of its global oil production from Kazakhstan.
Over the last three decades, Chevron has been gradually ramping up production at Tengiz and a nearby field called Korolev. The latest increment will add another 260,000 barrels a day, Chevron says, making the pair among the world’s rare million-barrel-a-day producers.
Analysts say that investing in Tengiz was also a top priority for the Kazakhstan government, which is heavily dependent on oil and obtains about one-third of its production from Tengiz.
“It is a key project for Kazakhstan and also for Chevron and Exxon Mobil,” said Samuel Lussac, a Caspian specialist at Wood Mackenzie, an Edinburgh-based consultancy focused on energy. “It had to go ahead.”
The government withdrew “the partial exemption granted to the oil companies on sale of Liquefied Petroleum Gas (LPG) for domestic use within Assam” with immediate effect.
The company, which is close to commercially launching 4G telecom and high-speed internet services, has in the past held annual general meetings (AGM) in June or July.
A $36.8bn expansion of the Tengiz oilfield in Kazakhstan, the largest development to be approved since the crude price crash of 2014, has been given the go-ahead by Chevron of the US.
The investment will add about 50 per cent to production at TCO, the Chevron-led consortium that runs the field, raising it by about 260,000 barrels per day of crude, up from an average of about 514,000 b/d last year. The expansion is scheduled to deliver first oil in 2022.
The green light for the plan is a rarity at a time when oil companies worldwide have been slashing capital spending and holding back on new commitments to large developments because of the slump in since mid-2014.
The industry’s between 2015 and 2020 has dropped by about $1tn since 2014, according to Wood Mackenzie, the consultancy.
The TCO consortium is 50 per cent owned by Chevron, 25 per cent by ExxonMobil, 20 per cent by KazMunaiGas, Kazakhstan’s state oil company and 5 per cent by Lukoil of Russia.
The $36.8bn investment has two elements: the “wellhead pressure management project”, to maintain output from the field through its existing equipment, and the “future growth project” to boost production by injecting gas into the reservoir.
Chevron has several mega-projects coming on stream between 2015 and 2017, including the giant Australian liquefied natural gas plants Gorgon and Wheatstone, and has set of shifting towards smaller more flexible investments. The commitment to Tengiz is an exception to that general policy.
John Watson, Chevron’s chief executive, said in a statement the Tengiz expansion project “represents an excellent opportunity for the company … [it] builds on a record of strong performance at Tengiz and will add value for Chevron and its stockholders”.
Jay Johnson, Chevron’s executive vice-president for oil and gas production, added the project had “undergone extensive engineering and construction planning reviews”, and was “well-timed to take advantage of lower costs of oil industry goods and services”.
’s new chief executive has signalled that one of his main priorities is to boost revenues at the Danish shipping-to-oil conglomerate after a decade of stagnation.
In his first interview since starting the job last Friday, Soren Skou told the Financial Times that the group was buffeted by short-term “headwinds” in all of its businesses — from the world’s largest container shipping line to oil production and drilling rigs.
“In the long term, we are challenged on top-line growth. Obviously, for us it’s important that we have a group that is both profitable but also has a growth path . . . If you have a business that isn’t growing the top line it’s very hard to deliver attractive returns to shareholders,” said Mr Skou, who is also head of Maersk Line, the group’s container shipping unit.
The European industrial heavyweight sent shockwaves through the markets last month when it fired its chief executive and hinted that it could the 112-year conglomerate.
Maersk’s chairman, Michael Pram Rasmussen, told the FT 10 days ago: “Should we be a group as we are today, or might it be an idea to have a number of different separate businesses instead?”
He has charged Mr Skou with leading a of the conglomerate and the board will update investors by the end of September.
Mr Skou gave little away in the interview as to the likely outcome, but he indicated that there were no sacred cows.
“The board has asked me to look at the strategic options. We are not starting with a lot of do nots, or areas where we don’t want to go. We are going to look at the full menu of options,” he added.
Mr Rasmussen hinted that Maersk Line — which accounts for more than half of the conglomerate’s revenues — would be the cornerstone of any future company as Mr Skou will permanently combine his job running it with his new role as group chief executive.
The 51-year-old Mr Skou, who has worked at the Danish group for the past 33 years, gained a reputation with investors as a cost cutter after he boosted Maersk Line’s profitability and made it the market leader in not just volumes but also margins after taking over in 2012 as its head.
Before that, he was for a decade head of Maersk Tankers, whose ships transport oil and gas all over the world. “He has been impressive at Maersk Line and we hope he can shake the group up,” said a leading Danish fund manager.
Mr Skou said his latest initiative at Maersk Line of “standardising, automating, digitalising” gave it “some new growth opportunities” that could be applied to the conglomerate’s other transport-related businesses that include port terminals and a slew of marine service companies.
Maersk generated $40bn of revenues last year, compared to $44bn in 2006 and a peak of $61bn in 2008. Like Mr Rasmussen, Mr Skou said acquisitions could take place at Maersk, without giving any specifics.
Nils Andersen, Mr Skou’s predecessor, streamlined the conglomerate by selling off its big stakes in Denmark’s largest bank and supermarket chain. But during Mr Andersen’s more than eight years in charge, Maersk’s shares fell by about 40 per cent, although shareholders benefited from a multibillion-dollar special dividend and stock buyback programme.
Mr Skou said creating value for shareholders was another of the main goals of the strategic review. “We have created a massive amount of value previously. In the last decade we have not. We have to figure out how to change that,” he added.
Some analysts have speculated that Maersk Oil, the conglomerate’s midsized exploration and production business, could be sold, especially after it last month had its main asset — a Qatari oilfield representing about 40 per cent of revenues — stripped from it after losing out in a tender process.
Mr Skou refused to speculate if assets could be sold but added that Maersk has been a conglomerate for a long time. “The ability of the group to have financial strength and leverage different businesses in different cycles has many times been shown to be an advantage,” he said.
But he also hinted at some frustration inside Maersk that the strategy of diversifying away from container shipping in an attempt to offset the volatility of that business had not worked in the current business cycle.
Freight rates for container shipping were at a record low earlier this year while oil prices are still weak, leading Mr Andersen in February to warn that for the company were worse than at the peak of the 2008 financial crisis.
Mr Skou said: “Those headwinds are short-term challenges, but I think it’s rather unfortunate that we have them in both of our industries at the same time. I still see them as short term, though.”
Krishna Godavari LNG Terminal Pvt (KGLNG) has got green nod for development of an offshore LNG floating storage and re-gasification unit.
The company, which had as many as 2.64 million shareholders as on March 31 this year, was usually holding its Annual General Meeting in June.
The Distya Ameya took on the crude cargo at Marsa el-Hariga in eastern Libya © EPA
Essar Projects has established capabilities in designing, planning and executing complex pipeline projects involving oil and gas, water and iron ore slurry.
Royal Dutch Shell wants to leave behind steel and concrete structures as large as the Empire State Building when it abandons one of the biggest oil and gas fields in the North Sea.
The decommissioning plan for the Brent field, 115 miles north-east of the Shetland Islands, will require exemptions from international regulations, which demand that all traces of oil and gas production are removed after offshore operations end.
Shell said on Monday it had concluded that the safety and environmental risks involved in removing much of the Brent infrastructure would far outweigh the benefits. It plans to submit its proposals for approval from the UK’s Department for Energy and Climate Change by the end of this year.
The case marks an important test of rules on what should happen to abandoned oil and gas fields in the North Sea as in the coming decades as reserves run down.
Countries in the north-east Atlantic are bound by the Ospar regulations, agreed after the furore in the 1990s over Shell’s abortive plan to dump its Brent Spar oil storage facility in deep waters off the Scottish coast. However, from the “leave no trace” rules are allowed if companies can demonstrate that full removal of infrastructure would be too difficult or risky.
Shell said this was the case for hundreds of thousands of tonnes of concrete and steel subsea structures beneath its four Brent platforms.
North Sea decommissioning has climbed the industry agenda as the sharp fall in oil prices of the past two years has of a declining basin that was already among the most expensive places in the world to drill offshore.
But companies are looking for ways to lower the cost of closing their North Sea facilities — forecast to reach £30bn-£60bn by the 2050s — as lower prices curb profits.
Shell said it had consulted widely, including with environmental groups and the fishing industry, while drawing up its Brent plans and that a 60-day consultation would start once they were formally submitted.
The decommissioning project is being headed for Shell by Duncan Manning, a former Royal Marine who was involved in security planning for the 2012 London Olympics. He acknowledged there would be some risks to shipping and fisheries from leaving the structures in place. But these could be reduced by navigation beacons and other measures to warn vessels away from the area.
Environmental groups have also raised concerns over multiple “cells”, each the size of Nelson’s column, which surround the base of the main subsea structures and contain sediment, water and oil. Mr Manning said these would also be left in place but the oil would be siphoned off.
The “topside” of the oil and gas rigs would be removed and transported by the world’s biggest ship — 382m long and 124m wide — to be dismantled at a yard in Teesside. Shell is aiming for 97 per cent of the material to be recycled.
Three of its four Brent platforms have already ceased production and Shell has been working on capping the 154 wells in the field for the past 10 years. It expects the project to take another decade to complete.
At its peak in the 1990s, Brent accounted for 13 per cent of the UK’s oil and gas needs and Shell said the field had produced £20bn of revenues for the Treasury since it started producing in the 1970s.
More recently-installed platforms were designed with decommissioning in mind but Mr Manning said Brent was part of the first generation of North Sea facilities which were never intended for removal.
Bond sales by US independent oil and gas companies have fallen to their slowest rate for more than a decade, in a warning sign of financing constraints that could hold back the industry’s recovery.
US exploration and production companies sold just $280m of bonds in the second quarter, making it a slower period than any during the financial crisis of 2008-09, according to data provider Dealogic.
New bank lending via syndicated loans also fell to $10.7bn, making it the weakest quarter since the start of 2014.
The since February has encouraged rising optimism among the exploration and production companies that led the US shale boom. In a recent survey from the Federal Reserve Bank of Dallas, 48 per cent of E&Ps in and around said their business outlook had improved in the past three months, and only 14 per cent said it had deteriorated
Some companies have been bringing into production wells that were drilled earlier but left uncompleted, and others have started to step up drilling activity.
The number of rigs running in the US to drill the horizontal wells used for shale oil production has been rising since May. At 272 last week it was at its highest level since early April, according to Baker Hughes, the oilfield services company.
Other companies have said they will add more rigs if oil prices remain at about $50 a barrel, raising the prospect that the decline in production under way since April 2015 could be halted.
However, US exploration and production companies have in aggregate continued to run at a cash deficit, meaning they need to raise money from asset sales, share and bond issues and bank borrowing to finance capital spending.
The leading listed US exploration and production companies cut their capital spending to $14.9bn in the first quarter, less than half its level in the equivalent period of 2015, according to Bloomberg data. But that figure was still $10bn more than they earned in cash from operations.
Even after the rebound in oil and gas prices in recent months, it is still likely that the sector as a whole ran at a cash deficit in the second quarter.
Equity issuance by E&P companies has been very strong, hitting a record $17.8bn in the first half of the year. Companies including Pioneer Natural Resources, Southwestern Energy and Cabot Oil & Gas have sold shares this year to strengthen their balance sheets and finance capital spending.
During the boom years, however, the growth of the US shale industry was largely financed by debt, with E&P companies raising almost $860bn from bond sales and bank loans during 2007-2014.
The data suggest that smaller production groups face difficulties raising bond finance that may hamper their ability to invest in the future.
The largest bond issues in the US oil industry this year have come from the majors, ExxonMobil and Chevron, and from the larger independents including Occidental Petroleum and ConocoPhillips.
Gary Ross of Pira Energy, a consultancy, said access to capital would be critical for US oil production. “It’s not going to be easy to reconstruct this industry,” he said
The 6 million tonne refinery, spread over 2,100 acre and including a captive port and power plant, was originally scheduled for commissioning in April 2014 at a cost of Rs 11,500 crore.
Muhammadu Buhari, Nigeria’s president, has removed the deputy oil minister from his joint role as the national oil company’s managing director and appointed a new board.
The decision to remove Emmanuel Ibe Kachikwu from the top job at the Nigerian National Petroleum Corporation is viewed by industry insiders as positive and long overdue.
Mr Kachikwu had, for more than six months, been running the oil ministry, though the president is officially the minister. This was regarded by many executives and analysts in Africa’s top energy producer as a conflict of interest.
The arrangement had meant that Mr Kachikwu oversaw regulation of the industry and other policy issues while also running a key commercial player in that industry: the state-run company that sells almost half of the country’s oil output.
“This is the right thing to do,” a former executive from an international oil company operating in Nigeria said. “Never in the history of Nigeria has the same person done these two jobs,” he added, suggesting the arrangement was “not tidy”.
Mr Kachikwu is to remain on the board as chairman. The new group managing director is Maikanti Kacalla Baru, a technocrat with years of experience at the NNPC. He was most recently in charge of the company’s exploration and production division but was removed from that role by Mr Kachikwu this year and transferred to the oil ministry.
“In terms of key decision makers [at the NNPC] it is a major shift but I don’t expect any short-term, immediate impact on the direction of the oil sector,” said Rolake Akinkugbe, head of energy and natural resources at FBN Capital in Lagos.
Abba Kyari, the president’s chief of staff, was named as a board member.
Mr Buhari won elections last year pledging to tackle corruption, particularly in the oil sector, which generates 70 per cent of the country’s income. When he took office, he said he had inherited near-empty federal coffers, despite the fact that oil prices had been above $100 a barrel for several years before they plunged in mid-2014.
Low prices have pushed Nigeria into financial crisis. Recent militant attacks in the main oil-producing region have slashed production, another blow to federal revenues.
Cleaning up the oil industry through reform of the NNPC is critical to attracted badly needed new investment. Nigeria’s oil output is expected to over the next decade because uncertainty over government reforms are keeping investment on hold.
Frustration is growing among oil majors operating in the country, however, because discussions intended to resolve disputes between the NNPC and its joint venture partners, including Royal Dutch Shell and Eni, have stalled. Mr Kachikwu, a former ExxonMobil executive, had pledged to reach agreement with the majors on outstanding disputes by mid-May. That deadline has passed with no agreements announced.
The US holds more reserves than Saudi Arabia and Russia, the first time it has surpassed those held by the world’s biggest exporting nations, according to a new study.
estimates recoverable oil in the US from existing fields, discoveries and yet undiscovered areas amounts to 264bn barrels. The figure surpasses Saudi Arabia’s 212bn and Russia’s 256bn in reserves.
The analysis of 60,000 fields worldwide, conducted over a three-year period by the Oslo-based group, shows total global oil reserves at 2.1tn barrels. This is 70 times the current production rate of about 30bn barrels of crude oil a year, Rystad Energy said on Monday.
Recoverable reserves — those barrels that are technologically and economically feasible to extract — are analysed by the energy industry to determine company valuations and the long-term health of an oil-producing nation’s economy.
Conventional oil producers, such as Saudi Arabia, have traditionally used their huge resource riches to wield power globally, particularly among big consumer countries such as the US.
This relationship has been disrupted in recent years by hydraulic fracturing and other new technologies that have helped the US unlock vast reserves and enabled it to become more energy independent.
“There is little potential for future surprises in many other countries, but in the US there is,” said Per Magnus Nysveen, analyst at Rystad Energy, noting recent discoveries in the Permian Basin in Texas and New Mexico, which is the nation’s most prolific oil producing area. “Three years ago the US was behind Russia, Canada and Saudi Arabia.”
More than half of the US’s remaining oil reserves are in unconventional shale oil, Rystad Energy data show. Texas alone holds more than 60bn barrels of shale oil.
Other global oil reserves data, like the closely watched that is based on official reporting from national authorities, show the US still ranks behind countries such as Saudi Arabia, Russia, Canada, Iraq, Venezuela and Kuwait.
Rystad Energy said government data across the world are collected using a range of metrics that are often opaque. Many countries’ numbers often include yet undiscovered oil.
While the reserves numbers are crucial, the cost of production is just as vital, said Richard Mallinson at London-based consultancy Energy Aspects.
“Reserves numbers matter but lots of other factors also determine short and long term returns from what the oil companies and nations hold,” said Mr Mallinson. “The rise in prominence of the US doesn’t diminish the role of Saudi Arabia or Russia, which have some of the cheapest to produce oil in the world.”
nations, led by Saudi Arabia, have over the past two years allowed oil prices to fall to ensure their long-term market share is secured over higher cost producers.
Although US shale oil has become more economical to produce — costs have halved over the past two years to below $40 a barrel in some instances — Saudi Arabia and other Middle Eastern producers still pump oil for less than $10 a barrel.
“There is a sweet spot for conventional producers in Opec. They want prices high enough to generate solid revenues to fund social spending in their countries, but not high enough to make too much expensive oil economically feasible,” added Mr Mallinson.
The was a factor behind the recent oil price collapse that toppled the Brent crude benchmark from a mid-2014 high of $115 a barrel to below $30 earlier this year.
Nagarjuna Oil Refinery, which is setting up the refinery, is controlled by the Nagarjuna group that owns about 35% of the firm. The group, led by K S Raju, also has fertilizer units.
Nigerian energy group has sold a majority stake in its fuels business to trading house Vitol and Helios Investment Partners for $276m as it moves to restructure its business to deal with low oil prices.
The transaction allows Vitol, the world’s largest independent oil trader, to expand its footprint in Africa’s top energy producer.
The downstream and retail business of Oando Plc, to be renamed OVH Energy, will be Nigeria’s second largest downstream fuels business with 12 per cent of the market, it said. The 60 per cent stake will give the Vitol-Helios consortium a total of 400 service stations and more than 600,000 barrels of storage and terminal capacity in the country of 180m people.
Nigeria is in its worst financial crisis in decades because of low crude prices. The government’s response over the past year has led to capital flight and the decision last month by the central bank to abandon a currency peg has led to a severe shortage for foreign investors and local businesses.
Renewed militant attacks on oil-producing facilities in the Niger Delta have hit output in recent months, worsening the crisis.
The downturn has hurt indigenous energy producers and heavily to them when oil prices were twice what they are now. Oando bought an oilfield from ConocoPhilips for $1.65bn in July 2014, just as the price of oil began falling and the company declared a record $1.10bn loss in 2014. Its debt stood at 301bn naira ($1.06bn) at of the end of last year, according to Renaissance Capital.
The company is now restructuring its business away from marketing refined petroleum products to focus on oil and gas exploration and production.
The deal is “very positive” for Oando because of its “huge debts”, said Temilade Aduroja, an energy equities analyst at RenCap in Lagos.
Vitol and Helios have an existing partnership called Vivo Energy that sells and distributes Shell-branded fuels in 16 African countries. Ian Taylor, president and CEO of Vitol, said investment reflects the company’s confidence in the Nigerian economy.
Oando signed a restructuring loan last month and said it would sell assets worth $350m this year, so further transactions are expected.
Although Nigeria has Africa’s largest oil production capacity, its refining sector has struggled to produce enough fuel to meet the local population’s needs. The country imported more than 150,000 barrels a day of petroleum products in 2014, according to the US Energy Information Administration, but still suffers from frequent fuel shortages.
LNG imports to India jumped 43 percent in May from a year earlier, a contrast to western Europe where shipments have stagnated over the past three months.
Among key conditions specified, RIL has been asked to ensure gas produced during the testing should be flared with appropriate flaring booms.
IOC will expand its refining capacity to 104.55 mt by 2022 from the current 80.7 mt per annum with an investment of about Rs 40,000 crore, he said.
The delay and pressure from the Indian partners is just one of many challenges for new Petrobras Chief Executive Pedro Parente, named by Michel Temer’.
Indian Oil Corp-owned Gujarat refinery will supply Bharat Stage(BS)-IV compliant diesel from January 2017, a senior official has said.
CEA Arvind Subramanian last month submitted an approach paper to the Finance Ministry on scenarios to deal with a rise in crude oil prices.
“Phase-1 will be 40 million tons together with an aromatic complex, naphtha cracker and polymer complex,” Sanjiv Singh, Director (Refineries), IOC, told.
India aims to more than double its LNG import terminal capacity in six years to cater to growing demand from refineries, fertiliser and power plants.
While CNG price in Delhi was raised by 25 paise per kg in Delhi, increase in Noida, Greater Noida and Ghaziabad was 30 paise.
