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Oil prices climbed back above $50 a barrel this week, registering a third straight week of gains, after Opec members and other large producers said they would discuss freezing output.
Plans to try and accelerate the long process of bringing supply and demand back into balance have been boosted by Opec kingpin Saudi Arabia and Russia — the biggest exporter outside the cartel — saying they will discuss “possible actions” to stabilise the market when oil ministers convene on the sidelines of a conference in Algeria next month.
While many traders and analysts are sceptical a deal will be reached, with tensions between Saudi Arabia and Iran just as acute as when they scuppered a similar proposal in April, the talk has been enough to relieve pressure on a market still struggling to clear a two-year-old glut.
Brent crude oil, the international benchmark, has gained almost 20 per cent so far in August and on Friday hit $51.22 a barrel, its highest level in two months, before easing. It was below $42 a barrel in July as traders fretted that the massive build up in oil inventories was seeping into fuels like gasoline as refiners turned too much cheap crude into fuel.
“Oil prices are vulnerable to attacks from short-sellers when seasonal surpluses emerge, as was the case recently when [US] gasoline inventories unexpectedly rose”, said Daniel Hynes, senior commodity strategist at ANZ bank in New Zealand.
“It’s clear Opec saw the weakness in oil prices in July as unwarranted and this forced its hand. However, instead of having to cut output, verbally intervening has achieved the same impact.”
While oil prices have bounced and are well above the sub-$30 a barrel they hit in early 2016, they remain at only about half the level they averaged between 2010 and 2014, before rising US shale oil output triggered global competition between producers.
There appears to be no end in sight for that battle for market share,
Saudi Arabia, which has led Opec’s policy of keeping output high with the aim of curbing output from higher-cost producers, raised its supplies to a record level in July and has .
Iran’s output has jumped following the removal of most sanctions tied to its nuclear programme earlier this year. Meanwhile, Iraq’s exports are near a record and it plans to send more oil through the Kurdish north. Combined, these gains have overshadowed falls from Nigeria and Venezuela, two of Opec’s weakest members.
While production outside the cartel is also expected to decline this year, the recovery to around $50 a barrel may also allow some private companies to drill more wells or lock-in better prices for the coming year. Oil that was has also started to sail to customers as prices have risen.
Olivier Jakob of Petromatrix in Zug, Switzerland said prices could fall back given the low probability of Opec agreeing a freeze, with contracts for delivery in late 2017 at a near $5 premium.
“Producers should consider hedging . . . a part of their forward production at current price levels,” Mr Jakob said.
Oil has also been boosted by a weaker US dollar, which makes commodities cheaper for holders of other currencies and can influence hedge funds, who had built up a big bet against crude in June and July.
The sweetened merger deal, he said, has received “constructive feedback” from minority shareholders, who hold the key to the amalgamation.
The company also expects sales volume to touch 10 million KL over the next two-three years from 2.5 million KL now.
The whole of 2014-15 saw 3,070 domestic consumers availing more than 24 cylinders. But just the seven months between April and October of 2015-16, saw 8,023 domestic consumers use more than 24 cylinders.
The slumping oil price has carved a chunk out of Australian oil and gas majors, with reporting that profits halved in the first six months of the year while swung to a loss of more than $1bn.
Woodside said on Friday that net profit after tax halved from a year ago to $340m in the six months to June 30. Sales revenue slid 22 per cent from a year earlier to $1.807bn as oil prices dropped 46 per cent in the same period.
Slumping oil prices fell into a bear market earlier this year, weighed down by a two-year supply glut, though they rose overnight for the first time since June amid persisting hopes an informal Opec meeting next month will yield a production cap.
Peter Coleman, chief executive officer, talked up Woodside’s operational performance, saying: “Combined with the low cost of our operations and a continued focus on cost reduction we are in a robust position as oil price forecasts improve in 2017.”
He said Woodside would add “significant volumes” from its Wheatstone liquefied natural gas project to the company’s portfolio in mid-2017, and further low-cost production from its Greater Enfield project in 2019.
But the company faces major challenges in finding growth opportunities. Earlier this year it indefinitely halted development of the , located off the coast of Western Australia, in which it is the major partner alongside Royal Dutch Shell, BP, a joint venture between Japan’s Mitsubishi and Mitsui, and a subsidiary of PetroChina.
That was the second major blow for Woodside in a little more than three months, after it for smaller rival Oil Search, an ASX-listed and Papua New Guinea-focused producer.
Oil and gas explorer Santos, meanwhile, on Friday reported a net loss of $1.1bn for the first half, hit by a against its new Gladstone liquefied natural gas export project. A year ago, the company reported a $30m net profit.
Excluding impairments, the company posted a loss of $5m in the first half, versus a $25m underlying profit a year ago.
Much like Woodside, Santos’s averaged realised oil prices was down 29 per cent from a year ago, leading to a 6 per cent drop in sales revenue — in spite of production volume rising 10 per cent and sales volume increasing 32 per cent.
Kevin Gallagher, chief executive, acknowledged the company has much work still to do in embedding a new operating model, driving down costs and using available cash flow to reduce debt.
But he said Santos has “made good progress” towards being cash flow break-even at between $35 and $40 a barrel on a portfolio basis, and is “forecasting a free cash flow break-even price of US$43.50 per barrel for 2016, down from US$47 per barrel”.
Following a difficult 2015 in which the company’s share price almost halved as it raised capital and sold assets to bolster its balance sheet, Santos in February scrapped its pledge to maintain or increase its dividend every year.
This week, Australian electricity and gas provider similarly cancelled its final dividend, as it reported a 41 per cent slump in first-half profit.
Shares in Woodside were up 2.2 per cent on Friday morning in Sydney while Santos rose 0.4 per cent, in a broader market that was up 0.1 per cent.
The US’s largest gas pipeline group, , recently attempted to buy its smaller rival, , but was rebuffed in its effort to create an $80bn energy transportation giant, people briefed on the negotiations said.
Despite the rejection, Enterprise Products remains interested in a deal for Williams and may make another offer, the people added. Enterprise Products and Williams declined to comment. Shares in Williams were up 9 per cent in early afternoon trading after the rejection was disclosed, giving it a market value of nearly $21.1bn.
The takeover bid came just weeks after the planned $33bn sale of Williams to another rival, (ETE), following a bitter court battle. Since then, Oklahoma-based Williams has suffered a series of boardroom upheavals, with six of 13 directors resigning following a failed attempt to oust the company’s chief executive, Alan Armstrong.
Among the directors that stepped down from the Williams board were two activist investors, Keith Meister of Corvex Management and Eric Mandelblatt of Soroban Capital Partners, who are thought to be in favour of the company considering fresh takeover offers.
The structure of the offer made by Enterprise Products could not be learned. Both companies declined to comment.
The US oil and gas pipeline sector, which traditionally has not been a hotbed of dealmaking, has been under sustained pressure following the collapse in energy prices since 2014.
Enterprise Products, which is based in Houston, Texas, has seen its share price drop by about 28 per cent over that period. It had a market value of $58.4bn before details of the deal were made public on Thursday. A deal with Williams would allow Enterprise Products to cut costs and reshape its pipeline portfolio.
Williams announced on Monday it had appointed three independent board members. Kathleen Cooper, the board chairman, said they would be adding more soon. “Williams is looking forward to broadening the expertise and perspective of the Board with the addition of three new, independent directors in the near term,” Ms Cooper said.
The previous deal for Williams collapsed after Latham & Watkins, the lawyers for ETE, said they were not in a position to provide an opinion on whether the transaction would be tax-free, which was a mandatory condition to the successful completion of the transaction.
Williams disputed ETE’s position and decided to sue its merger partner to force it to go through with the deal. However, a Delaware judge sided with ETE, arguing that the company had acted in good faith.
Williams accused ETE of using the tax opinion argument as a way to get out of a deal their chief executive Kelcy Warren regretted doing following a sharp fall in oil prices after the takeover was agreed in September 2015.
has stepped up its push to win more foreign buyers for its , according to official data released on Thursday as crude rose back above $50 a barrel.
Data from Saudi Arabia to the Joint Organisations Data Initiative (Jodi) showed the kingdom is directing more of its record crude production towards export markets.
Crude exports in June rose to 7.46m barrels a day from 7.3m b/d in May even as the market continues to struggle under the weight of a near two-year-old glut.
Saudi Arabia’s new oil minister, Khalid al-Falih, had told fellow Opec ministers in June that Riyadh had no intention of flooding the market, but since then its production has increased at a rate faster than it needs to meet domestic demand in the summer months.
The Jodi data showed Opec’s largest producer pumped 10.55m b/d in June, an increase of 280,000 b/d on the previous month. But only 16 per cent of that increase went towards so-called “direct use” — or the amount Saudi Arabia burns in power plants to cope with soaring summer air conditioning demand.
By contrast, 57 per cent of the production increase went towards higher exports.
This month, Saudi Arabia told Opec its output had continued to increase, reaching a record 10.67m b/d in July.
Mr Falih confirmed in a statement last week to not only to meet stronger domestic use but also to supply greater demand from customers.
This has sparked concerns that Saudi Arabia is competing more aggressively for customers in an already oversupplied market.
The kingdom is pushing hard to maintain its export market share in core regions — such as Asia — where it sees growing competition from rivals such as Iran, Iraq and Russia. Earlier this month it drastically cut its prices for the benchmark crude grade it sells into Asia.
“Despite the bearish sentiment engulfing the market, we still see strong demand for our crude in most parts of the world, especially as supply outside of Opec has been declining fast, supply outages increasing and global demand still showing signs of strength,” Mr Falih said in the statement.
More oil has been fed into its refineries as well as the kingdom seeks to expand its exports of refined products.
Saudi Arabia’s higher production coincides with a push by economically weaker Opec members for action to curb any further drops in the oil price.
on the sidelines of an industry conference in Algiers in September, triggering renewed talk of a co-ordination between producers after a failed attempt in April for an output freeze.
Mr Falih has said Saudi Arabia is willing to if it believes it is necessary, but analysts say it is unlikely to act unless Iran also agrees to a freeze.
Talk of producer action has helped push up the price of oil. Brent crude has jumped 14 per cent since last Wednesday. On Thursday, the global benchmark increased 42 cents to $50.27 a barrel. The US marker West Texas Intermediate rose 87 cents to $47.66 a barrel.
Some have suggested a Saudi hike in production ahead of any talks could give the kingdom more room for manoeuvre.
Olivier Jakob at consultancy Petromatrix said: “At this stage we view the mentions of a freeze as a diversion from a continued drive from Saudi Arabia to gain as much market share as it can.”
Oil Minister Dharmendra Pradhan today met visiting Venezuelan Foreign Minister Delcy Rodriguez and Oil Minister Eulogio del Pino and discussed energy issues.
The company also said the amount was the result of a revision from time-to-time which the Petroleum Ministry conducts.
Premier Oil made a profit in the first six months of the year boosted by the decline in sterling following the EU referendum and its purchase of oil and gas fields from Eon.
The company, one of the UK’s largest independent oil producers, revealed on Thursday that it had made $110m in profit before tax in the first half after a $215m loss in the same period last year. Underlying earnings fell from $447m last year to $182m as low oil prices continued to take their toll.
Profits were helped by a $101m reduction in what expects to pay to decommission some of its older fields due to .
said it had been able to negotiate the North Sea assets deal because it was willing to from Eon, which wanted to leave the area.
The company also confirmed higher estimates for production rates. It said last month it expected average production over the year at or above 70,000 barrels of oil equivalent a day, having previously said it would be 65,000-70,000 boe.
On Thursday, it put a formal number on that revision, saying it expected the average to be 68,000-73,000 boe.
Premier has yet to agree a deal with its banks to renegotiate lending terms. The highly-indebted company, which has been in talks with its lenders for months, said it needed more time despite weekend reports a deal had been done.
Its directors said a failure to agree a deal would risk its ability to continue as a going concern, but they felt a deal would be struck.
Tony Durrant, chief executive, said: “Full-year production guidance is now increased, which will drive free cash flow generation. We have made substantial progress with our lending group on the principal terms of a refinancing. Our project portfolio has been expanded, positioning Premier for future growth at lower cost.”
Timing is everything when it comes to investing in commodities.
It seems difficult to believe now but in 2014 oil was considered one of the safest bets around. The reasoning among large financial investors was straightforward. Regulation and technology might well crimp demand in the industrialised west but as more of the developing world’s poor moved into the middle class oil demand and prices would remain strong.
Fast forward to 2016, and many analysts, including those in strategic planning departments of large oil companies, are starting to warm to the idea of peak oil demand globally, not just in the OECD.
In part, the exercise has been driven by shareholders and activists who say the companies are ignoring the risks to their business from a global climate accord. A number of organisations, notably the International Energy Agency, but also including oil companies such as , , , and ConocoPhillips, are modelling outcomes based on a breakthrough in battery technology or that global temperatures rise by no more than 2 degrees Celsius.
These scenarios include rising solar energy and natural gas use, cheaper car batteries, urbanisation supported by millennial ride sharing and public transportation, and a plethora of advanced, digital energy saving technologies. Many of these studies project a significant fall in oil demand to 75m barrels per day by 2040, down from about 95m b/d today.
At the University of California, Davis, we have tested oil demand sensitivities and found that a combination of factors — including slower than expected growth in the developing world, improved logistics, and advances in vehicle efficiency — could, perhaps with a push from policy, see demand for oil peak, at least for a decade or two.
The implications are bigger than they might seem given the number of ifs that surround the idea that oil demand could peak. For the past three decades, investors have assumed that oil under the ground today would be more valuable in the future. That led them to seek companies best positioned to deliver growth.
But if the rise in all bets might be off. That means investors don’t simply want “exposure” to crude. They will need to select a management team that will be smart, nimble and adaptive, no matter whether demand rises, falls or remains flat.
Moreover, in a more competitive world where producers might have fewer opportunities to sell its product, all investable oil assets will not be equal. Investors will have to know what the production cost basis is for a company’s reserves or how well positioned their refinery network is to beat global competitors.
Location of assets will matter. Owning a refining and marketing network in California or Germany where demand will almost certainly fall off might be less attractive than in India or Malaysia.
The use of automation and other emerging technologies to drive returns will also matter. US shale darling ’ chief executive Scott Sheffield told an audience recently in Houston that technology advancements had lowered the company’s production costs, excluding taxes, to $2.25 a barrel for horizontal completions in the prolific Permian Basin of Texas, low enough to compete with Saudi Arabia — one of the world’s lowest-cost producers. By contrast, operating costs in Canada’s harder to develop oil sands are estimated at $37 a barrel.
For 30 years, the oil industry has operated under the principle that it will have difficulty meeting future demand. Against that backdrop, adding reserves to the balance sheet was an end unto itself, sometimes more important to management than if those reserves could be profitably produced.
The thesis was that oil would become increasingly scarce as easy to reach reserves were depleted; the value of booked, warehoused reserves would appreciate with global prices and eventually a day would come that even ridiculously expensive assets would be profitable to produce.
But if global oil demand declines before those expensive reserves are needed, then mindlessly booking reserves is not a strategy Wall Street will want to reward in the future. Instead, investors might ask more critically what a company’s revenues outlook will be this quarter or next quarter, like most other ventures. Understanding which companies can pivot best to these new realities will be key to smart investing in oil from now on.
Amy Myers Jaffe is executive director of energy and sustainability at University of California, Davis. She served as chair to the World Economic Forum (Davos) Global Agenda Council on the Future of Oil and Gas, which recently published a study on the Implications of Peak Oil Demand.
“We are looking at inducting a strategic investor. We may offer up to 50% stake in the joint venture,” said Mukesh Kumar Surana, chairman at HPCL.
This year will prove to be a watershed for the world’s largest sovereign wealth fund as, for the first time in two decades, Norway’s will have money taken out by the government in Oslo.
The withdrawals so far have been small compared with the size of the fund, which has grown rapidly to become one of the largest investors in the world on the back of surpluses made by Norway’s petroleum industry.
But as much as the issue is played down by Norwegian politicians and investment officials, the withdrawals matter as part of a debate about the future of the oil fund and how much risk it is willing to take on during a period when lower interest rates could hit future returns.
“This fund is meant to last generations and yet we are tapping it already — many, many years before we were meant to. If we keep on spending as we are and the fund can’t earn decent returns then we could end up eating into it,” says one of Norway’s leading businessman, who did not want to be named.
Espen Henriksen, associate professor at the BI Norwegian Business School, says the withdrawals should not be seen as too dramatic, however, which is a view shared by Oystein Olsen, Norway’s central bank governor.
The oil fund on Wednesday revealed NKr24bn ($3bn) had been withdrawn by the government in the second quarter following in the first. Another NKr40bn is expected to be taken out during the rest of the year against the fund’s assets valued at NKr7.35tn.
But Prof Henriksen, who is advising the government on the oil fund, argues that two trends are moving against Norway that cause concern: low oil prices and lower expected rates of returns for investors.
Falling oil prices — and higher government spending — are responsible for the current withdrawals. Norway’s government is allowed to spend up to 4 per cent of the fund each year in its budget.
Until this year, the amount of money taken from the fund has always been less than the amount of petroleum revenues put back by the government — resulting in an average annual inflow of about NKr210bn over the past decade.
But the amount of oil and gas revenue — generated through a tax on production as well as dividends from state companies — has dropped sharply in recent months.
The 4 per cent figure was set to reflect the oil fund’s expected rate of return. But many, including the central bank governor, doubt whether the oil fund can now achieve this with its current asset mix of 60 per cent equities, 37 per cent bonds, and 3 per cent property. The fund returned 1.3 per cent in the second quarter and just 0.6 per cent in the past year.
As a result, Mr Olsen has proposed reducing the amount the government can spend to 3 per cent or even lower.
The government has appointed a — including Prof Henriksen — in January to look at whether the oil fund should invest more in equities to chase higher returns as bond yields languish. Its current holdings equate to about 1.3 per cent of every listed company in the world, making it one of the largest global equity investors.
Mr Olsen has suggested bonds need form no more than 20-25 per cent of the fund, with the rest filled by equities or tangible assets such as property or infrastructure.
Trond Grande, deputy chief executive, says: “The question is not really what should we do to reach 4 per cent but what is our risk appetite?”
Mr Grande on Wednesday again underlined the fund’s nervousness over holding such a high share of bonds with almost a quarter of its fixed income portfolio now trading at rates below zero.
“We have seen decades of falling rates and that has given bond investors a capital gain. There is a question mark over how much further rates can fall and if you can expect to have that kind of capital gains in the future,” he added.
Increasing the equity portion is not without risks, however. The fund lost almost a quarter of its value in 2008 and officials worry about how the Norwegian public — the fund’s ultimate owners — would handle an even bigger fall.
Questions also exist about how the fund itself operates. Its inflows have been so large that it was able to rebalance its portfolio in the past without the forced selling that other institutional investors can be pushed into. For instance, it cut exposure to Europe from 60 per cent to 40 per cent in its fixed income portfolio by using new cash to buy emerging markets bonds rather than selling existing assets.
Thus far, the fund says it can cope with the withdrawals through cash flow it receives from dividends and bond coupons, which last year reached NKr191.5bn.
But after increasing rapidly in size over the past decade, some — including the central bank governor — now think the fund may be as big as it is going to get. “The fund may be close to a peak,” Mr Olsen told the FT earlier this year.
That raises the pressure on politicians not to take too much out of the fund. “This has long been the question: will the money burn a hole in politicians’ pockets? So far so good, you have to say, but the desire to spend may get bigger,” says the businessman.
If the oil fund has peaked in size, it will have to face some of the more difficult questions sooner. But Prof Henriksen says the fund has already done its job to an extent by making Norway richer and more diversified by converting oil wealth into financial assets. “It is definitely better to have this fund than not to have the fund,” he adds.
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Norway’s oil fund may be a relative newcomer to owning property but it has amassed a large portfolio that includes some of the most prestigious addresses in the world. The world’s largest sovereign wealth fund owns real estate on Regent Street in London, the Avenue des Champs Elysées in Paris, Park Avenue in New York and Market Street in San Francisco. The fund is set to build this prime portfolio further following a change in its mandate that will allow an increase in the amount of unlisted property investments to 7 per cent of its total assets, up from 3 per cent as present. The oil fund likes to claim it acts cautiously, which is why on Wednesday it revealed it had marked down the value of all its UK property — 23 per cent of the total portfolio — by 5 per cent following the British vote to leave the EU. But other property investors have cut harder, and some in the property industry think it has been buying assets at high prices. “I’d question how good value some of those purchases have been,” argues one large European fund manager. The oil fund has slowed purchases this year in what some read as a sign of concern over the potential valuations of some markets. But insiders point to the recruitment process of a new chief investment officer, who will sit alongside the chief executive of the property arm, Karsten Kallevig. Mr Kallevig told the FT earlier this year that the oil fund had partnered with experienced real estate investors such as Axa, Generali and the Crown Estate to gain expertise. “When we started in 2010 we were very aware we didn’t have an organisation with the institutional knowledge of running a real estate portfolio,” he added. But the oil fund has now started to buy some properties outright, including last month’s purchase for £124m of the leasehold of 355-361 Oxford Street, a retail and office block. |
Central bankers have long understood that a few well-placed words can wield nearly as much power as pulling the actual levers of monetary policy. It is a lesson that Opec and Saudi Arabia has started to heed.
from Saudi Arabia’s energy minister last week sent hedge funds scrambling to cover large bets against the oil price, subsequently propelling Brent crude 10 per cent higher and largely silencing fears the market was on the cusp of another rout.
Following calls from Venezuela for big producers to revisit the idea of freezing output, Mr Falih said the kingdom was willing to “discuss any possible action” needed “to stabilise” prices when Opec ministers gather informally at a conference next month.
For those that had written off Opec and Saudi Arabia’s position as “the central bank of oil” the market’s reaction was notable. Most long-term Opec watchers expect no official agreement to emerge from the Algeria gathering, even as oil-dependent economies struggle under the weight of a two-year price collapse.
Still, prices shot higher at the mere threat of action.
“A lot of traders appear to hold the view that eventually there’s going to be so much pain among Opec that they’ll have to do something,” says Jamie Webster of Columbia University’s Center on Global Energy Policy. “I don’t see anything to make me think outcome is going to be different this time.”
Instead, analysts see an attempt by Opec and Saudi Arabia to verbally intervene in the market during the long process of bringing supply and demand back towards balance, as they stick with the policy of .
That Saudi-led effort, in place since late 2014, is starting to show signs of working. Opec production has risen to its highest on record and supplies outside the group are expected to fall this year.
However, the process is taking time, leaving the oil price vulnerable to attacks from short-sellers when seasonal surpluses emerge, as they did recently in refined fuels markets like gasoline. Where once Opec might have cut output, verbally intervening is now the preferred option.
“By raising the possibility of a freeze it can help them get through this period while the rebalancing continues,” says Ann-Louise Hittle, chief analyst at Wood Mackenzie. “It’s almost as if there’s an attempt to talk the market through what was always going to be a long process.”
The reason last week’s pushed Brent up so much largely reflects market positioning, say traders.
Alarmed by the emerging gasoline glut, hedge funds bet aggressively , leaving the market primed for buying back and closing out bearish bets. Mr Falih blamed “large short positions” for prices undershooting.
The biggest barrier to Saudi Arabia taking more decisive action is its relationship with fellow Opec member Iran. Saudi Arabia has always said that it is willing to consider anything to help balance the market, including production cuts, but only if other big suppliers join in.
Russia, the biggest oil exporter outside Opec, agreed to such a deal in April in Doha but , when Deputy Crown Prince Mohammed bin Salman — the favoured son of the king — ruled there could be no agreement without Iran.
A senior Gulf Opec source says the kingdom believed Russia’s recent remarks about potential involvement were positive for any collaborative efforts that were being led by Qatar, Venezuela and Algeria. However he acknowledges Iran’s position was still uncertain.
After years of sanctions Iran is attempting to win back lost market share and has repeatedly signalled it has no plans to limit output. Iran’s oil minister Bijan Zangeneh said on Thursday he had not decided if he would attend September’s gathering, according to media reports.
“Iran will remain a stumbling block as it simply cannot accept a ceiling on its production,” says Amrita Sen, chief analyst at London-based consultancy Energy Aspects.
, reaching a record 10.7m b/d day in July, up from 10.2m b/d in January when the idea of a freeze was first mooted.
The country’s crude output normally rises in the summer months to meet peak electricity consumption but in his comments to the Saudi Press Agency last week Mr Falih also pointed to “strong demand for its crude” as a reason for its record production.
For some, that remark was significant because it indicates a greater willingness to keep the taps wide open as its competition with Iran heats up.
“If the talks fail, which is likely, the market should not entirely rule out the possibility that Saudi Arabia will give up and throw in the towel, and keep output high, at or above July’s level,” says Mrs Sen.
Investors may need to wait to see if the Kingdom does scale back its summer output as it has done it previous year. But if it keeps producing 10.7m b/d or more than the oil market may not come into balance next year as most analysts currently expect.
It would be a test, analysts say, of the power of verbal intervention to keep the bears at bay. At some point words may need to be backed by action.
Emmanuel Ibe Kachikwu, Nigeria’s oil minister told CNN this week that he was “not optimistic” about any production cuts in September. “we’ve tried that a couple of times and I think we’ve not been able to get the unity we need.”
He says it was important nonetheless to maintain dialogue with non-Opec producers
Ms Hittle at Wood Mackenzie adds in many ways Opec and Saudi Arabia’s trajectory was not that different from most central banks in the post-financial crisis world, who have often delayed adjusting interest rates.
“It used to be that they were compared to a central bank as they would take action. Now, like many central banks, guidance has become much more common,” she says.
Investment in exploration, development of discovered reserves, enhanced oil recovery schemes and technology will be Rs 2.5 lakh crore to Rs 3 lakh crore by 2022.
Decisions like giving pricing freedom to gas produced from difficult fields like deepwater will help unlock 10-15 trillion cubic feet of reserves, Sashi Mukundan said.
Andrew Mackenzie, ’s chief executive, reflected on a year of and financial turmoil as he revealed a record annual loss of $6.4bn by the world’s most valuable mining company.
In Brazil, 19 people were killed in November when a dam gave way at an iron ore mine jointly owned by BHP. Mr Mackenzie acknowledges he and the company were still coming to terms with the disaster at the Samarco venture — which had led to “huge suffering . . . we are doing the best we can to right those wrongs”.
On the commodity markets, BHP — like other miners — was hit by plummeting prices, particularly in the last months of 2015. Underlying attributable profit at the Anglo-Australian group fell by more than 80 per cent to just $1.2bn.
This is a far cry from the $19bn of equivalent profit recorded by BHP in 2011 during the boom in the commodity cycle, and before to the top job.
But in spite of the Samarco disaster and the steep annual loss — as well as BHP’s first dividend cut since its 2000 merger with Billiton — the Scot who has led the mining group since 2013 insisted there were grounds for optimism.
The $6.4bn loss would “get plenty of coverage and we are very disappointed in it,” says Mr Mackenzie.
“But the underlying performance of the business is strong and getting stronger,” he insists.
Investors seemed to agree, sending shares in BHP 3.5 per cent higher as the miner spelt out its view that were no longer in free fall and that its free cash flows could more than double this year.
The $7.7bn of exceptional charges that pushed BHP to its largest ever loss were caused by two main problems. One was Samarco, where BHP booked $2.2bn of costs connected with the uncertainty over when mining could restart. Legal challenges could still hamper BHP’s efforts to put the disaster behind it as it hoped to do when agreeing a clean-up settlement with the Brazil government this year.
The larger problem in financial terms was a $4.9bn post-tax impairment of , part of an oil business that sets BHP apart from many of its mining peers.
Under Mr Kloppers, its previous chief executive, BHP spent more than $20bn on shale acquisitions in 2012 when crude was trading above $100 a barrel. It subsequently ploughed more than $16bn into developing the fields.
After a savage market downturn, crude oil trades for less than $50 a barrel and BHP’s impairment charges reflect the lower price environment and a much reduced drilling programme. In total, BHP has written down the value of its US onshore assets by $13.4bn.
Mr Mackenzie, a former BP executive, continues to back the business in part because of its flexibility. Onshore drilling rigs can be deployed much more quickly than in deepwater oil and gas production.
“What [shale] allows you to do is allow you to rapidly profit from volatility in price,” says Mr Mackenzie. “We don’t really have that flexibility in anything else we do.”
BHP is convinced that oil offers some of the best prospects of any of the raw materials it produces because of its view that industry-wide investment cuts will crimp future supplies.
“Because of the failure to invest and the natural decline rate in oil . . . the chances of the market coming back into balance and boosting the prices probably are higher than some of our other commodities,” he says.
With prices of all its commodities — the others are iron ore, copper and coal — so uncertain, BHP and other miners have been trying to cut costs.
Unit production costs came down 16 per cent during the last financial year and are expected to fall a further 12 per cent this year. That, and the pause in commodity price declines, “gives us the chance to open up pretty decent margins”, Mr Mackenzie says.
After generating free cash flow of $3.4bn last year, BHP says it would be on track for $7bn at current commodity prices and exchange rates. This would give more scope for higher dividends, debt repayment or more investment: this year will probably mark a trough for BHP’s capital spending at $5.4bn, just a quarter of the level five years earlier.
But Mr Mackenzie rules out the sort of acquisition spree that landed BHP with this year’s shale impairments.
Growth through acquisition “is not part of the plan nor can it be . . . there are always other uses of our cash that offer higher returns,” says Mr Mackenzie. “Given the competition we have for capital there are very few deals that can compete.”
Narendra Modi’s government in March simplified licensing rules and offered price incentives to recover gas from difficult offshore fields, giving a fresh lease of life.
Cairn said it is pursuing its rights under Indian law to appeal the assessment, both in respect of the basis of taxation and the quantum assessed.
Nearly $8bn of exceptional items have driven BHP Billiton to a net loss of $6.39bn for the 2016 financial year, as the miner anticipates commodity prices to remain low and volatile in the short-term.
The Anglo-Australian miner underlying earnings of $1.2bn in the 12 months to June 30, slightly ahead of market consensus of $1.09bn, but down by four-fifths from $6.4bn the previous year, writes Peter Wells.
However, a long list of exceptional items topping $7.7bn (after tax) have sent the company to a reported net loss of $6.39bn, from a net profit of $1.91bn in its last financial year. Some of these include charges associated with redundancies and closures across its businesses, impairments in its coal unit and also the recognition of for the deadly collapse of a dam at its Samarco joint venture in Brazil.
It is the first reported loss since the 2001 merger of Australia’s BHP and Anglo-Dutch Billiton, and UBS believes it is the largest reported loss for BHP since inception.
Andrew Mackenzie, chief executive, said the past 12 months have been challenging for both BHP and the industry, but the company’s portfolio remained resilient. He continued:
Over the past five years we have actively reshaped our portfolio, and we are confident we have the right mix of commodities, assets and opportunities to create substantial value over time. While commodity prices are expected to remain low and volatile in the short to medium term, we are confident in the long-term outlook for our commodities, particularly oil and copper.
Full-year revenue fell 31 per cent from a year earlier to $30.9bn, in line with the average of analyst estimates. Prices for iron ore and oil – two of the company’s key commodities – both hit multi-year lows within the past 12 months.
Iron ore with a 62 per cent iron content fell 11.9 per cent in the group’s latest financial year, but prices hit a multi-year low below $40 a tonne in December. So far this year, prices are up 35 per cent. Oil hit a 12-year low, below $30 a barrel in January.
The company said its average realised price for iron ore was down 28 per cent in FY16 to $44 a tonne, while the average realised price for crude oil of $39 a barrel was down 43 per cent from a year earlier.
BHP, like stablemate Rio Tinto, has been ramping up production in the Western Australian Pilbara region. , BHP said iron ore production fell 2 per cent in the 12 months to June 30 to 227m tonnes, with record volumes at its Western Australian Iron Ore operations offset by the suspension of operations at Samarco. The miner said it expected production in its 2017 full year to be between 228m-237m tonnes, an increase of up to 4 per cent.
BHP said it would pay a final dividend of US14 cents, taking the full-year payout to US30 cents, down from $1.26 last year.
In February, the company slashed its interim dividend by 74 per cent and abandoned its “progressive” dividend policy, which had been underpinned for years by the China growth-led mining boom, and shortages in key industrial commodities that had pushed materials prices higher. Mr Mackenzie said at the time: “We now have to recognise we are in a new era, a new world, and we need a different dividend policy to handle that.”
Peter O’Connor, metals & mining analyst at Shaw and Partners in Sydney said the 2016 financial year – and specifically the first half – will be seen as the earnings nadir for the company, with the prior low being in 1999 (on an underlying basis). Rising commodity prices should help, Mr O’Connor added, pointing out prices in FY17 are already tracking 15 per cent higher than in FY16.
“In short not a pretty set of results – the biggest loss ever – but that is backward looking,” Mr O’Connor said in a note to clients. “Other than ‘lessons learnt’ from the past, focus on the outlook = better commodity backdrop, cost out, and heaps of ‘latent’ growth capacity at low capital intensity. Deleveraging will be the story, just not quite yet as the same speed as Rio Tinto, Fortescue Metals, Newcrest Mining et al.”
BHP shares ended 0.5 per cent higher in Sydney on Tuesday, versus an overall 0.1 per cent decline for the S&P/ASX 200. So far this year, shares are up 13.6 per cent versus a 4.5 per cent gain for the broader index.
The company’s decision triggered doubts regarding rationale given that rigs are easily and cheaply available, and ONGC could be more selective than ever.
Petrol will now cost Rs 60.09 a litre in Delhi from midnight as compared to Rs 61.09 a litre currently, said Indian Oil Corp (IOC).
Iraq’s parliament approved the appointment of a new oil minister in a cabinet reshuffle delayed by months of political disputes and against the government’s inaction on promised reforms.
Jabar Ali al-Luaibi, a former head of the state-owned South Oil Company, Iraq’s biggest crude producer, takes over the oil post, while parliament also approved four other cabinet nominees, including for education, transport, water and housing.
The appointments are a boon to Prime Minister Haidar al-Abadi, who has struggled to overhaul his cabinet. He has chosen it as a first step in his bid to cut graft and dismantle a political system based on sectarian quotas and patronage networks.
However, no names were submitted to parliament for Iraq’s other influential and contested cabinet positions, including the foreign and finance ministries.
Mr Abadi tried to reshuffle his entire cabinet in March. But Iraq’s , loath to get rid of a system that has enriched them, was so divided over his proposed changes that they brawled and held sit-ins inside parliament.
Frustration at Mr Abadi’s inability to follow through on promised reforms triggered street protests in which demonstrators stormed Baghdad’s heavily fortified Green Zone and ransacked parliament earlier this year. The new appointments could help him push ahead with his reform plans.
“It was a good play. He needed to make some progress and taking little steps was the best way to do it,” said Renad Mansour, an Iraq analyst at the Carnegie Endowment think-tank. “Abadi realised that trying to do it all at once, as he did in March, was too much of a shock to the system.”
The oil ministry was a critical post to fill as Iraq grapples with an economic crisis caused by the slump in crude prices and the government’s decision to plough money into its military offensive against Isis.
surged over the past decade as foreign companies invested in the industry, and the country now pumps 4.6m barrels a day, making it the second largest Opec producer.
But since the slide in crude prices, the cash-strapped government has struggled to repay international companies, which operate Iraq’s large oilfields. As a result, Baghdad has asked foreign oil players to curb their investments, while company executives have sought to renegotiate their contracts.
Some companies have stopped investment in the sector altogether, industry officials say.
Mr Luaibi now faces the challenge of reviewing contracts and agreeing a new repayment arrangement with the companies, while also restructuring the state oil company and his ministry, analysts say.
“Mr Luaibi needs a supportive parliament and co-operative cabinet that would favour sound legal and constitutional arrangement over fragile political deals,” said Luay al-Khateeb, executive director at the Iraq Energy Institute, who has known Mr Luaibi for more than a decade. “The latter proved to be a failed policy for the past decade.”
Laila Khafaji, a politician in the Islamic Supreme Council of Iraq, an influential Shia party, said she hoped the oil minister’s appointment would ease tensions between Baghdad and oil-producing Basra province. Mr Luaibi hails from the southern region, which has been the scene of protests demanding government reforms.
“We thought it would be fair for the new person to be from Basra as most of the oil is produced in that region,” Ms Khafaji said.
But there are still major hurdles ahead for Mr Abadi and his new ministers.
The prime minister faces a cabinet dilemma following the recent resignation of the interior minister, which risks sparking a struggle over that powerful post. Parliament is also embroiled in a row over corruption with the defence minister, who was called before MPs for questioning on Monday.
The uncertainty around Iraq’s two top security posts comes at a sensitive time with Baghdad preparing to launch its biggest confrontation with Isis — the battle to retake Mosul, Iraq’s second-largest city.
Sajad Jiyad, an Iraqi researcher, also cautioned that ministerial appointments would only make a small dent in the fight against pervasive graft.
“Changing just the ministers is not enough,” he said. “There are under-secretaries and director generals that have been in their position for 10 years, and no minister has been able to unseat them.”
Methane, despite being odourless, can cause a stink. For Australian oil and gas explorer , its bet on exporting natural gas from underground coal seams has proved expensive. On Monday on Gladstone liquefied natural gas, or GLNG. Newish chief executive Kevin Gallagher had to adjust GLNG’s value on the balance sheet, due to lower oil price estimates. He has also something more pressing than book values on his mind: finding the cash flow to cover the company’s large debts. Results later this week are an opportunity for him to explain just how Santos can go about reducing its leverage.
GLNG produces its gas in basins about 300 miles inland from its coastal LNG facilities, and pipes it north-east to Gladstone. While gas has begun to flow this year, the first project stage (known as a “train”) has had a slow start. tend to flow at a leisurely pace, requiring lots of drilling to get volume up. Santos drilled about 25 wells last year, about a tenth of what UBS analysts think is needed to meet production targets. The company will need to show that drilling has increased substantially this year.
All the same, Santos’ share price has performed well in 2016, up nearly a third, beating locally listed rivals and . The fact that capital spending at GLNG has peaked means that most analysts anticipate that Santos will generate free cash flow starting this year. The Australian explorer desperately needs some: its net debt is achingly high at over four times its estimated earnings before interest, tax, depreciation and amortisation.
Whether Santos shares can track higher depends on what Mr Gallagher says later this week. He had forecast that Santos could meet all its investment needs with oil at $47 per barrel. Deeper cost cuts in its other businesses, together with clarity over the outlook for GLNG’s production, would leave him smelling like roses.
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Hedge funds turned more positive on last week, adding to their bullish positions for the first time in over a month after Opec members moved to talk up the market.
Funds trading Brent and West Texas Intermediate futures and options raised their net long positions — the difference between bullish and bearish bets — by more than 10 per cent in both contracts, as Opec reignited discussions over a possible production freeze.
The move helped propel Brent crude oil to its biggest weekly gain since April, rising 6 per cent to almost $47 a barrel, with funds both closing out bets against the price and adding new positions that will benefit should the market rise.
An informal meeting of Opec member countries is scheduled to take place on the sidelines of an energy conference in Algeria next month. At the same time, Venezuela is trying to organise a meeting including big producers outside the cartel to discuss potential measures to prop up prices.
The country’s oil minister Eulogio del Pino is set to begin a tour of Opec and non-Opec countries to see if there is a plan or a strategy they would all be prepared to back.
The cash-strapped country has been at the forefront of seeking a deal to curb global supplies just as other wealthier producer countries look to maintain market share.
“Tomorrow he leaves on an Opec and non-Opec tour,” President Nicolás Maduro said on Friday in a televised broadcast. “I call on all energy players in the world, Opec, non-Opec . . . so that we can really get to work on this.”
Saudi Arabia has a renewed global effort to stabilise glutted markets, but has also raised production to a record level of almost 10.7m barrels a day.
An earlier deal to freeze output failed in April because of Saudi opposition. It refused to back an agreement without the involvement of Iran, which has been ramping up production since the lifting of sanctions linked to its nuclear programme.
With Iran near its short-term production capacity some analysts think an agreement is possible. Others are less sure and say a deal would make little or no difference to the market fundamentals because so many producers are pumping close to or at record levels.
Energy Aspects, a London-based consultancy, warned on Monday there was a risk Saudi Arabia could raise production further.
“In the absence of a successful meeting, there is a non-trivial risk Saudi Arabia throws in the towel, and would then keep its output elevated at 10.7m b/d or higher,” Energy Aspects said.
Russia, the world’s largest non-Opec producer, said it was co-operating with Saudi Arabia, the cartel’s de facto leader, to “achieve market stability”, according to its energy minister Alexander Novak on Monday.
Speaking to Saudi newspaper Asharq al-Awsat, Mr Novak said they were “determined to continue dialogue to achieve market stability”, according to Reuters.
On Monday Brent crude hit a four-week high of $47.67 a barrel — a rise of 68 cents — before falling back.
Oil has rebounded after falling into bear market territory earlier this month, when it dropped 20 per cent from its yearly highs on the back of fresh supply glut fears concentrated on the US gasoline market.
, the Australian oil and gas producer, has been forced to write down $1.1bn after tax from the value of a liquefied natural gas project in Queensland after it failed to produce as much gas as expected in the first half of the year.
The project, called Gladstone LNG, involves pumping gas from coal seams in basins in south-west Queensland, before liquefying it and shipping it around the world.
The pipeline has not delivered as much as expected in 2016, however, leaving having to buy in gas from elsewhere, the price of which has increased during the first half of the year.
Continuing low oil prices have limited the amount of capital spending the company has been able to invest in projects such as Gladstone LNG. The price of a barrel of crude oil is currently around $47, having been $115 two years ago.
Peter Coates, Santos’ chairman, said: “The expected impairment charge for GLNG is clearly disappointing but it is a consequence of the challenging environment which we now face.”
He added: “However, we firmly believe in the strong long-term growth of LNG consumption and demand globally. GLNG will continue to be an important part of our LNG portfolio and a key supplier of LNG to the Asian market.”
The company was expected to announce a net loss of around $100m on Friday when it reveals results for the first six months of the year. The writedown on the LNG project is now expected to substantially deepen that loss.
Kevin Gallagher, chief executive, said: “We will continue to maintain a disciplined approach to capital allocation, reducing costs and seek opportunities to optimise our asset portfolio in a manner that delivers value to shareholders.”
The company’s shares rose 1 per cent on Monday to A$4.78. They have fallen from their most recent peak of around A$14 in summer 2014.
Analysts at RBC said: “We remain concerned that cost cutting, chiefly on development drilling for volumes already committed, may eventually catch up with the company.”
The GST law in its present form excludes a major portion of the oil and gas industry products thereby excluding the industry from most of the benefits of the one-tax-one-nation proposal.
Gujarat State Petroleum Corp Ltd (GSPC) too is in talks to take 1.5 million tons capacity in the floating, storage and regasification unit (FSRU).
“About 14 crore people got LPG connections in 60 years. And we have given 4 crore new LPG connections in 60 weeks,” PM said.
Essar currently doesn’t have any cooking gas distribution but Reliance has a base of about 10 lakh consumers to whom it supplies non-subsidised cylinders.
Jonathan Faiman remembers vividly the “totally random” chance that introduced him to Neos GeoSolutions and led him to a career in the oil business. “I just happened to be with a friend who works in an oil company, who was going to see Neos. He was going to listen to them about their products. And after they’d finished their pitch, I just kept asking them questions.”
That was in the summer of 2014, and as the questions continued, Mr Faiman decided there was something he could do with the business. By May of last year, the British entrepreneur had bought about half the company for $150m and become its chairman.
As one of the , the UK online grocery retailer and, before that, head of emerging market bond trading at Goldman Sachs, Mr Faiman, 47, makes an unlikely oilman. But the leap from online retailing to oil exploration is not as great as it might seem. Neos does not — yet — produce oil, but collects and analyses geological data for resource-holding countries and companies, to help them decide where they should drill and what they can expect to find when they do.
The oil industry uses some of the world’s most advanced technology to investigate what lies beneath the earth’s surface. The three most powerful supercomputers in private commercial hands belong to Total of France and Eni of Italy — two of the largest European oil producers — and to Petroleum Geo-Services, a Norwegian company that maps rock formations beneath the seabed. Neos is trying to compete in that field, but for onshore resources, at a sharply reduced cost.
The company has had a chequered history, including two name changes, since being founded as in the early 2000s with backing from Kleiner Perkins and Goldman. But its purpose has remained the same: using advanced data analytics to produce cheaper and more accurate geological models. As the company puts it, it is “where Silicon Valley meets the oil patch”.
Speaking in his home overlooking New York’s Central Park, Mr Faiman says he saw oil as an industry ripe for disruption. “At the time the company was finding it difficult to get the technology adopted, and it was literally like listening to someone describing the grocery industry,” he says.
“You’ve got these huge companies. Like supermarkets, oil companies have very big balance sheets, which is how they compete. They have huge investments in asset bases, which if the world changes they can’t change very quickly.”
In that sense, a deepwater oilfield off the west coast of Africa is like a big-box, out-of-town store. Companies with high-cost oil reserves are threatened by competition from lower-cost producers, just as bricks-and-mortar stores have been squeezed by online retailing.
“You’ve spent your money, you’ve made your decision, you’re now committed to [the asset base]; you’re wedded to it. And so what you do is you spend all your time hoping that nothing changes,” Mr Faiman says.
“And the reality of the world is that everything changes.”
In the oil business, the assets with the highest production costs are typically offshore fields discovered as the industry has pushed into ever-deeper waters. Mr Faiman argues that the cost-effective oil and gas production of the future will be largely onshore, as the US shale boom has been.
The best onshore fields, such as those in the Middle East, produce the world’s lowest-cost oil, and even the more challenging US than complex offshore projects in deep water.
Increasing the world’s onshore oil and gas production will mean finding new reserves. But Mr Faiman says Neos can explore for resources much more quickly and cheaply than the industry standard, and that its capabilities are constantly improving.
Apart from the potential for disrupting a well-established industry, he says, the other great attraction of Neos was that “technology changes, and it changes quite fast. And what I was looking at with Neos was data-processing technology”.
The usual source for understanding the subsurface is seismic surveying: shooting sound waves into the ground and using receivers to catch the echoes, which can be used to build a picture of rock formations. Neos’s technique is to use other data, including satellite imagery, electromagnetic surveying and gravity measurements, and analyse them to model rock formations without the need for a full seismic survey.
However good Neos’s technology may be, though, finding a business model to make it commercially successful has not been easy. “Here was a business that had half a billion dollars spent on it,” he says. Despite an “amazing series of discoveries”, there was “no real way of making money from it, because they hadn’t thought about how to address what they had”. Neos has not disclosed if it is profitable.
One answer is to sell Neos’s services to countries that need to understand their resources better. It is working in Kazakhstan on the , the plan to develop new oil and gas resources in and around the north Caspian Sea, and talking to Saudi Arabia about exploring for metal ore deposits rather than oil.
Neos is already profitable, but Mr Faiman has decided that Neos needs to get into production itself. The precedents are not auspicious. The history of oil service companies that decided they wanted production of their own is littered with failures.
With $150m of his own money at stake, though, Mr Faiman certainly has an incentive to make it a success. He also insists he is in Neos for the long term.
When he left Ocado in 2009, the year he turned 40, he could have retired. But after breaking his leg in 2012, and spending six months in and out of hospital, he came to a realisation.
“I was at a loss when I left Ocado. I’d like to say it was all easy and it was a comfortable thing to do, but actually it wasn’t. I thought that doing nothing seemed like a nice thing to do, but it wasn’t.”
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Richard Herbert, who was until recently the chief operating officer of exploration at BP, says Jonathan Faiman has at Neos what looks like “a very attractive integrated package of technologies” for collecting and analysing geological data. But Mr Faiman’s ambition of shifting Neos to become an oil producer in its own right will demand additional capital and capabilities. “That’s a very different proposition,” he says. “But Jonathan broke a lot of paradigms with Ocado. And he obviously likes a challenge.” |
He said that HPCL would be coming up with the largest bottling plant in the state, while other oil marketing companies IOC and BPCL were also doing the same.
The company’s wholly-owned subsidiary L&T Hydrocarbon Engineering (LTHE) is eyeing to win at least $1 billion worth contracts in the next 2-3 years.
