Medium sour crude values have found fresh support, following an announcement on April 22 that the US will end all waivers from Iran sanctions when they expire on May 2.
May barrels of USGC sour crude benchmark Mars were heard talked between $4.80/b and $5.05/b above WTI cash in the morning of April 22 and then later heard traded at WTI plus $5/b, up from the previous assessment of WTI plus $4.55/b on April 18. Also on the day of the announcement, June barrels of Mars were heard trading at WTI plus $5.10/b on, up from over $4.70/b.
The strengthening of USGC sour grades follows a general weakening trend in the market over the past several weeks as domestic refinery tastes continue to evolve to include an increased diet of light sweet crudes.
“If you think about it, Mars is back to a more historical level,” one crude trader said. “Refiners are running more light sweet in cokers.”
The differential for front-month US Gulf Coast benchmark Mars had fallen $3.55/b since hitting its strongest point in five years of WTI plus $8.10/b on February 14. Tightness in the sour crude market, as a result of OPEC crude production cuts, sanctions on Venezuela, and production curtailments in Canada, all helped boost sour crude in the US Gulf Coast at the beginning of the year. However, demand seemed to shift in recent weeks, sending USGC sours lower. The expiration of Iran sanctions waivers could send US Gulf Coast crudes higher once again.
The waiver expirations will impact some of Iran’s biggest buyers of crude and condensate, including China, India and South Korea, all of which have been allowed to continue buying crude from Iran despite US sanction on the country. Any country that continues buying Iranian crude after the waivers expire will be risking US sanctions enforcement. The Trump administration aims to “bring Iran’s oil exports to zero, denying the regime its principal source of revenue,” the White House said in a statement. Without the extension of the waivers, crude buyers around the world will be under pressure as less supply will be available. The timing will put maximum pressure on the market, especially as demand typically ramps up during the summer season.
A recent uptick in interest for storing US Gulf Coast sour crudes also is an indication that values for Mars, and other similar grades such as LOOP Sour, are expected to be stronger in coming months.
Storage at the Louisiana Offshore Oil Port was heard trading late last week for May, June and July at between 5 cents/b and 3 cents/b.
Latin sours supported
Sources also expect differentials of sour grades from Colombia and Ecuador to continue climbing in coming days as the waivers for Iranian crude importers were scheduled to expire in May. Since the last quarter of 2018, more cargoes of heavy sour Colombian Castilla Blend and Ecuadorian Napo Oriente crudes have been imported by Asian refiners, specifically Japan, South Korea and China, as they are seen as replacements for Iranian and Venezuelan crudes.
The average differential of Castilla Blend in the third quarter of 2018 was minus $9/b compared to ICE Brent, according to S&P Global data. However, due to strong buying interest and limited supplies of heavy sour grades in the global markets, recent tenders of the Colombian crude for May loadings have been awarded around minus $4.50-4.00/b vs ICE Brent.
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Independent commodity traders, often viewed as the secretive, but highly lucrative, footloose middlemen of the energy markets, are facing a tough time adjusting to the industry’s new economics.
The rise of data transparency has stripped traders of their information advantage, while regulatory pressures over accountability continue to grow. New competition from national oil companies looking to leverage their massive supply-side clout in trading swap deals is also on the rise.
Commodity trading margins have fallen by more than 20% from their recent peak in 2015 and could fall by another 15% to less than $30 billion by 2025, according to a recent report by consultants Oliver Wyman.
Top trading houses such as Glencore, Vitol, Trafigura, Gunvor and Mercuria have been bulking up with refining, distribution and storage assets for years in order to maintain a trading edge over their rivals.
But competition for new downstream assets to enhance core trading earnings has become fierce, further complicating the current asset-backed trading model. More pressingly, the rise of automated, algorithmic trading and reduced arbitrage opportunities have compressed traditional margins.
Most of the commodities that generated big bucks for traders in the past are now traded on markets that are transparent and liquid, and the value of contracts traded on standard electronic platforms has doubled in the last decade.
“This trading margin meltdown will continue as commodity markets become more mature, stable and liquid,” Oliver Wyman said in a report. “This cutthroat environment will weed out the players that continue to follow the tactics of the past from those pioneering new trading strategies.”
Speaking at a major commodities summit in Switzerland last month, Trafigura CFO Christophe Salmon conceded that the age of “easy margins” is over, signaling a growing need for diversification to maintain a competitive advantage.
One area of growth in the energy space has been moves to tap opportunities within the rising tide of US shale oil exports. Trafigura is seeking permission for an offshore loading terminal off Texas in the Gulf of Mexico, and other traders are looking to open up export terminals.
The push toward more LNG, where trading volumes have been growing rapidly, is also gaining pace with traders signing long-term supply contracts. Gunvor, which became the biggest independent LNG trader last year after delivering about 11 million mt, is looking to acquire natural gas and LNG assets. Other key LNG traders, including Glencore, Trafigura, and Vitol, are investing in ships and terminals to handle the fuel.
Traders are also branching out into renewables and power grids. Gunvor recently acquired two biofuels plants in Spain, and Vitol is in a venture which last year completed construction of the UK’s largest battery-park portfolio.
Threat from NOCs
Traders are also facing an emerging threat from national oil companies looking to expand trading operations and take a bigger role in directly marketing their crude and products.
Saudi Aramco, the world’s biggest oil exporter, wants to become a top three global oil trader, trading as much as 6 million b/d of crude and refined products as it expands its downstream reach. Last week it agreed to swap its crude for high-sulfur fuel oil from Polish refiner PKN Orlen.
Iraq’s state oil marketer SOMO is opening offices to trade spot crude and ADNOC is now hiring traders.
One key hurdle to a profitable trading operation, however, is a corporate culture which allows traders to extract value from deals across a fully integrated asset network, the head of oil trader Gunvor, Torbjorn Tornqvist, believes.
“If they are going to succeed, they are going to have to adapt to the rules of how a trading company works,” Tornqvist told the commodities summit last month. “I’m not sure that’s fully understood, and that they are prepared to give the entrepreneurial freedom to act, which is needed to create a successful trading company.”
Despite Tornqvist’s optimism, it is not clear that “entrepreneurial freedom” treasured by independent traders is guaranteed as regulation is getting tougher.
Market watchdogs are increasingly demanding greater transparency in energy trading and the cost of technology and data solutions needed to monitor, operate and report energy trading activity is pushing up overhead.
A growing chunk of trading revenues are going on IT departments to maintain a competitive edge and comply with legal and reporting scrutiny.
Feeding the algorithms
One of the few bright spots for oil traders is the expected higher volatility in fuel markets under the new International Maritime Organization sulfur cap for shipping fuel in 2020.
Some players are buying bunkering infrastructure as a way of monetizing the ensuing oil market shake-up. Mercuria is buying up bankrupt marine fuel logistics firm Aegean Marine Petroleum Network. Trafigura has set up a new bunkering team and merged its middle distillate and fuel oil trading desks in the hope of profiting from the market disruption.
According to Oliver Wyman, the longer-term answer to staying ahead of game in trading is for players to embrace analytical technology and hire more data scientists to forge new trading strategies and recapture the information edge.
With booming volumes of data from radar, thermal and optical satellite imagery, smarter machine-learning algorithms are needed to spot and predict patterns and trading opportunities across commodities and geographies.
“Commodity traders need to embrace new ways of working,” the consultant report concludes. “The most important driver of the shakeout of the industry is trading giants’ investments in predictive analytics …previously unthinkable digital capabilities will determine who will be the industry’s leaders in the long term.”
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Saudi Arabia, the world’s largest oil exporter, has ambitious plans to tap into the potential of renewables to fill a shortfall in regional power demand. But opinions are divided on how realistic the Kingdom’s strategy is, given its track record of delayed projects and a shortage of domestic policies to help support investment.
The drive to increase renewables generation in the region is not limited to Saudi Arabia. With economies in the Middle East region set to grow in the coming years, power demand is projected to surge in tandem. Despite an abundance of natural resources, electricity supply is a major issue for Gulf countries and oil-fired generation is still the dominant source.
The case for renewables
Saudi Arabia’s economy is set to grow 2.7% over the next year, according to ratings agency Moody’s, and S&P Global Platts Analytics expects Saudi power demand to continue to grow at a rate of 3.3% through to 2030. The looming threat of a power crisis has helped speedball the idea that including more renewables in the region’s energy mix could be the solution.
“Populations in the region are growing much faster than other areas of the world and are set to maintain a rapid pace of growth to [the] middle of the next decade,” Edward Bell, commodity analyst at Emirates NBD told Platts. “The power infrastructure that’s in place will need to be expanded or enhanced to meet that growth so a push into renewables makes obvious sense as part of that dynamic.”
The push towards renewables has been led by Saudi Arabia, which earlier this year announced intentions to develop and install 60 GW of clean power sources over the next decade, including 40GW of solar power, and plans to eventually generate 200 GW from renewables. Around 30% of the power mix is to be supplied by renewables by 2030, with the remainder to be sourced from gas and some nuclear. This compares with a target of 15% of the power mix for Kuwait to be supplied by renewables by 2030, and a target of 10% for Oman by 2035, according to the latest GCC report from the International Renewables Energy Agency (IRENA).
Saudi Arabia’s energy ministry has also set an interim target of developing 27.3 GW of clean power by 2024, of which 20 GW will be from solar.
“The region can’t afford not to be too ambitious in trying to get more and more of its power mix provided by renewable sources given the power demand pressures and what will likely be increasing international pressure to clean up the energy mix in the region,” Bell said. “So the ‘over ambitious’ nature of the targets may be more an issue of capacity to tender, construct and deliver projects rather than a lack of ‘resources,’ either in the form of capital or solar irradiation.”
This year, the ministry released expressions of interest for the seven solar PV projects that will be tendered in the first half 2019, with a combined capacity of 1.51 GW which the ministry expects to attract $1.51 billion of investment this year. Saudi Arabia’s energy minister, Khalid al-Falih said in January that around 12 renewables projects would be tabled for investment this year, including four solar PV parks and 300 MW solar power stations in Rabigh and Jeddah.
“By using our two awarded projects [Sakaka 300 MW Solar PV and Dumat Al Jandal 400 MW onshore wind] as benchmarks, we can estimate that required capex per 100 MW of Solar PV is $100 million and $125 million per 100 MW of onshore wind,” Turki M Shehri, head of renewable energy projects at the ministry of energy, industry and mineral resources told Platts. “These two projects involved a capital investment of $800 million in 2018.”
This can be compared with an investment of $765 million to develop Abu Dhabi’s 100 MW Shams 1 project, the first concentrated solar power project in the Gulf region.
Aside from solar, Middle East countries are also increasingly looking to wind as an option for development. Oman, which already boasts the first onshore wind farm in the Gulf region (50MW), has been mulling the possibility of developing offshore wind farms.
One of the biggest obstacles facing Middle Eastern governments in their drive to push renewables is the sizable subsidies that they offer to their citizens. In 2018, the cost of electricity consumption for Saudi residents ranged from Riyal 0.18 – 0.30/kWh (Eur0.042–0.071/kWh). This eats into the profit margin for renewables developers, making it essentially economically unviable to develop alternative energy sources for consumer use.
At the moment, generation costs are higher than consumer electricity tariffs. Saudi Arabia is making attempts to raise tariffs and fuel prices, which could eventually bring consumer tariffs in line with or lower than the cost of renewables, plus the infrastructure needed to use them.
“Efficient price signals in both the electricity and fuel markets can certainly play a role in attracting more renewable investment,” King Abdullah Petroleum Studies and Research Centre, also known as KAPSARC, told Platts. “The speed of the development is subject to additional factors such as the regulatory framework and the financing mechanism available to support these projects.”
Some countries, including Bahrain, are in the midst of developing incentive policies that would effectively make it cheaper for industrial customers to use photovoltaic solar power rather than gas. This is a first step, but the gap between current consumer prices and those required to breakeven or profit on renewable-generated power is much greater than it is at the industrial level.
“The [Bahraini] government is working on [policies] to try and incentivize,” Shaikh Mohammed bin Khalifa Al Khalifa, Bahrain’s minister for oil, told Platts in an interview. “Today you can buy and install photovoltaic that will generate you power cheaper than you can buy on the grid, for commercial customers.”
In Saudi Arabia, industry tariffs were not raised at all in 2018, which means that for solar to be cost-competitive in this sector, deeper reforms are needed than those that have begun implementation in the consumer, agricultural and commercial sectors.
Despite question marks over how robust investor appetite would be following the killing of Saudi critic and journalist Jamal Khashoggi, one banking analyst who wished to remain anonymous told Platts that investor sentiment into Saudi Arabia remains strong and that a view towards commerce is prevailing over conscientious concerns.
“Given that auctions have already been awarded for both wind and solar, and sites have been carefully selected and are clearly assigned, we expect that the projects will be realized,” David Linden, director at Wood Mackenzie told Platts. “Previous plans were not organized in the same way as the most recent ones, which may have contributed to earlier problems with execution.”
More than 16 bidders took part in the latest Saudi auction from outside Saudi Arabia which vindicates this view, but investors have been concerned over the implementation of local content strategies, both for materials and for staff, and how this affects businesses operating in the Kingdom. Projects need to use at least 30% of local content, which limits the amount of imported material which can be used in development.
There are several reasons why Saudi Arabia’s renewables plans could prove important for advancing its economy. The local content requirement will serve to create jobs and reduce the country’s unemployment rate. And rising renewable generation will eat into the share of petroleum-product fired plants in the energy mix, freeing up crude that can be exported at international prices, hopefully fetching prices that will be worth making the switch.
To really entice consumers, it is critical that the Kingdom can offer supporting infrastructure and pricing structures which will enhance development. The Kingdom would do well to ensure cheap panels and turbines are available through ultra-large scale PV manufacturing, Linden told Platts. A $2 billion deal with China’s Longi and South Korea’s OCI could also give the Kingdom competitive panel pricing that will further the case for developing the technology. The deal will bring fully integrated solar manufacturing to Saudi Arabia. Feasibility studies for the deal are scheduled for completion in the first half of this year.
Saudi Arabia’s past experience with renewables projects rings a cautionary note. A giant 200GW deal the Kingdom signed in March last year with Japan’s Softbank Group Corp would be the world’s biggest solar project and nearly triple Saudi Arabia’s power generation capacity but there has been little sign of progress on the venture.
“Negotiations and [requests for proposals] with potential partners are ongoing and are being led by the Public Investment Fund (PIF) and the Saudi Arabia General Investment Authority (SAGIA) – these partners include, but are not exclusive to, Softbank Energy,” Shehri told Platts. “Most recently the PIF and SAGIA have issued an RFP inviting qualified companies to propose plans to build 1-to-2 GW per year of solar PV components manufacturing based within the Kingdom.”
Nonetheless, the drive at least appears to be there, and despite a tumultuous 2018, investors do not seem to be shying away from the Kingdom. In the past, several government agencies were all pursuing renewables. Since 2017, they are all run and overseen within the ministry of energy, industry and mineral resources. “This unification of governance means that the Kingdom has been able to deploy two projects totalling 700 MW within one year – a process that would usually take closer to five years,” Shehri told Platts.
The rate development of will rest on how quickly Saudi Arabia can implement deals and pass supporting legislation. The scale of the projects and timeframe for their development is not impossible, but without action on the Kingdom’s side and changes aimed at supporting foreign investors, like clarity on local content requirements and available solar manufacturing in country, their grand plans may yield much more modest results.
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A tight spread between international crude benchmarks Brent and West Texas Intermediate has depressed US crude export flows during the past four weeks, according to sources and data from US Customs and S&P Global Platts Analytics. However, low freight rates have created opportunities to move US crude cheaply.
The US exported 2.35 million b/d for the week ending April 5 – the lowest outflow since January 25, when 1.94 million b/d was exported, according to weekly data from the US Energy Information Administration. An estimated 2.28 million b/d of crude was exported from the US last week, according to Platts Analytics and data from Platts trade-flow software cFlow. This is the lowest estimated total reported since February 8. US crude exports were hindered in late January and February as dense fog along the Gulf Coast impacted vessel traffic.
Values for US crudes for export have been pressured lower on a narrow spread, which indicates a decrease in the competitiveness of WTI-based crudes on the global market as they become closer in price to their Brent-based peers.
The front-month swap spread last week reached $6.20/b – its narrowest level since July 26, 2018. However, the spread began widening again, reaching $6.99/b to end the week. The 30-day rolling average of the spread is about $7.70/b.
Despite the relatively narrow Brent-WTI spread, sources have said low freight rates and favorable margins elsewhere could help increase the flow of US crude to international destinations, as the costs to transport barrels are at multi-month lows.
“Brent/WTI has sold off quite a bit the last couple days since [crude inventory statistics], so [the arbitrage] is looking kind of workable,” one market source said last week.
“Ebbs and flows. If barrels back up [in Houston, WTI at the Magellan East Houston terminal] will weaken and the arbitrage opens,” another market source said about arbitrage opportunities. “One quiet period does not make a trend.”
Low freight creates export opportunities
Low freight rates continue to provide a glimmer of opportunity for crude exports.
Freight for Aframaxes originating in the US Gulf Coast have reached their lowest level since August 2018 amid a buildup of tonnage in the region. Lists have lengthened on the back of weaker US crude export volumes and reduced regional Aframax voyages following US sanctions on the Venezuelan oil sector, shipping sources have said.
Freight for Aframaxes on the 70,000 mt US Gulf Coast-UK Continent route was last assessed Friday at Worldscale 67.5, or $12.35/mt, last assessed lower on August 17, 2018, at $11.61/mt. Freight for the route has averaged $13.2680/mt so far in the second quarter of 2019, $7.4820/mt, or 36.1% lower than Q1 2019.
A flurry of fixture activity was reported last week, reflecting depressed freight rates amid an overtonnaged market.
ExxonMobil was seen fixing eight, prompt-loading crude cargoes aboard Aframax vessels that collectively can carry roughly 3.2 million barrels of oil for a trans-Atlantic voyage, according to S&P Global Platts fixtures data. Most of the vessels were positioned off the Gulf Coast near Galveston and Port Arthur on Monday, according to cFlow. At least one, Songa Coral, was observed Monday docked for loading at the Energy Transfer terminal in Nederland, Texas.
VLCC rates have also been at depressed levels, with freight for the 270,000 mt USGC-China route reaching its lowest level since July 2018 last week at lump sum $4.5 million. Rates for the long-haul route have firmed however, rebounding on the back of an uptick in cargo inquiry and limited ship availability. Freight climbed $250,000 Friday to lump sum $4.85 million, with shipping sources talking rates as high as $5.2 million Monday morning.
VLCC loading terminals in the US Gulf Coast such as Moda Midstream at Ingleside, Texas, and Enterprise Texas City have maintained loading levels in recent weeks – with a four-week average of 1.5 million barrels per week and 789,000 barrels per week, respectively.
However, export activity has been limited at the Louisiana Offshore Oil Terminal, which is the only location in the Gulf Coast where VLCCs can be fully loaded without the need for ship-to-ship transfers. The last VLCC reported to load and sail from LOOP was the Dilam on March 13. That vessel is set to arrive either in Singapore or Northern China later this month, according to cFlow.
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Upstream oil and gas producers in the US are trapped in a dilemma they might have previously thought would be desirable: abundant production at low cost.
For decades, higher production from oil companies was what the market wanted and rewarded. If producers had to borrow and overspend to do it, the attitude was “c’est la vie”. But in the last couple of years, it has become clear that what is desired, often voiced and certainly rewarded, is slower production growth and reined-in spending.
Capital discipline has been the watchword among upstream producers and Wall Street alike for at least 18 months. That could help brake production growth this year, along with small decreases in well productivity and efforts to return more capital to shareholders.
Increases in US unconventional production from shale, particularly shale oil, are the product of years of innovation. In particular, during the industry downturn between 2015-2017, E&P companies hacked away at their costs and forced down their breakeven prices. The industry has more than doubled production since 2011, and the fastest growth has been in the last couple of years.
According to US Energy Information Administration data, domestic oil production breached the 12 million b/d mark in March, and nearly 2 million b/d of that was added last year alone. S&P Global Platts Analytics forecasts year-end production at 12.78 million b/d and end-2020 production at 13.48 million b/d.
Long-time energy economist Phil Verleger, in a report in January cited EIA projections of 800,000 b/d additional production from December 2018 to December 2019, adding that the International Energy Agency figures on 780,000 b/d of added production in the same time span and OPEC, 1.7 million b/d.
“The level of activity last year will be difficult to maintain without oversupplying the market,” Credit Suisse analyst Jim Wicklund observed in a recent investor note.
But operators can’t help it: the efficiencies achieved in recent years have made it easier to produce more oil from every well. They’re not going away anytime soon, so something else will have to slow down their progress.
When crude prices dropped from over $100/b in mid-2014 to about half that level at the end of the year, operators learned the meaning of efficiency the hard way. Suddenly each barrel they produced was bringing in 50% of the money it had done just months earlier, so they had to make each drilling and production dollar they spent work harder.
From necessity to invention
Through diligent operational streamlining, they squeezed every last drop of value out of each stage of the E&P chain.
They eventually brought their breakeven price – the cost of producing a barrel of oil to get a 10% return – down to levels that would have seemed miraculously low a few years before. These days, oil breakevens for the best operators in the most prolific plays are not too much more than the cost of an extra-large pizza with the works, plus a magnum of Coca-Cola and tip for delivery.
The continuous technological wizardry of well drilling and completion improvements allowed the industry to produce far more oil and gas in far less time at ever-lower costs – and at extremely economic return rates which often yielded 100% or more. But it also brought the supply genie ahead of the demand curve faster than expected.
Producers exploiting US plays from Texas to North Dakota, from Pennsylvania to Wyoming, have pulled gargantuan volumes of shale oil and gas out of the earth in the last 15 years. Gas was the initial commodity to be produced unconventionally – meaning horizontally – starting in the early 2000s. So successful were producers at coaxing large gas volumes out of shale wells that eventually the domestic market was facing a glut that pushed gas prices to low levels within a few years. Prices have continued to stagnate.
Pre-shale, a decent initial flow rate for a conventional gas well was about 1,000 Mcf/d. Now many shale wells yield initial rates of 20,000 Mcf/d and double that rate is not unheard of. Those numbers have kept gas storage bins full and gas exports to markets around the world humming.
Increases in crude well outputs are also robust even if not as dramatic. Conventional oil wells of the past might have yielded 500 b/d, while early shale oil wells saw typical initial outputs of 1,000 b/d. That has frequently doubled and sometimes tripled, while in rare cases 5,000 b/d or 6,000 b/d have been eked out of wells. Even so, total oil production growth over the last eight years as the shale oil revolution blossomed has been phenomenal. In January 2011, US oil production was just below 5.5 million b/d. By January 2015, just as the recent industry downturn had begun, domestic oil production stood at 9.3 million b/d. That increase was largely achieved at prices of $90/b-$100/b.
Production peaked in April of that year at 9.6 million b/d, but fell back because operators cut back activity and capex during the downturn. The 50 largest E&P companies slashed their 2015 capital budgets collectively more than 40% year on year, and another 25% or so for 2016, according to research from EY (formerly Ernst & Young). By that time, oil prices had fallen to levels around $30/b just as operators were releasing their annual budgets at the start of that year.
But then, oil prices stabilized around $50/b for several months, and heading into 2017, E&P operators were more sanguine. The constancy of prices lent confidence to the sector and the operational improvements forced by low crude prices had put them in good stead to produce oil for less than before. Capital budgets rose that year about 32% to a total $114.5 billion – still far below the $198 billion spent in 2014. But spending didn’t need to return to former levels, as E&P operators found they could still grow production at $50/b.
Even at capex levels 65% to 70% lower, during the downturn, US production from January 2015 to January 2017 dropped only about 6%, to 8.8 million b/d. And given the efficiency improvements achieved during that time, it didn’t take long for US production to climb back up.
From November 2016 to November 2017, at an average price of $50/b, US oil production grew by 1.2 million to 10 million b/d. And from November 2017 to November 2018, at an average price of $64.83/b, production grew just under 1.8 million b/d, hitting 11.9 million b/d.
In the low oil-price environment of 2015-17, operators drastically reduced the number of days needed to drill wells. They became more precise in placing drill bits within an oil formation to land in a reservoir’s sweetest spot. And they continually streamlined and perfected their recipes for completing wells at increasingly lower costs.
Continually evolving well completion designs have allowed operators to bring down the cost of a well by about a third or more. At the start of 2014, the Permian Midland –the eastern and part of that giant West Texas basin– had an average oil breakeven cost of about $44/b; currently it is around $30/b, according to S&P Global Platts Analytics data.
Prices point to slowing growth
What to do about the US supply glut, then? It is likely that a combination of technical production limits, investor demands and the simple factor of oil price will start to redress the imbalance this year. Lower crude prices should put a brake on production growth this year by some order of magnitude. E&P company capital budgets for 2019 are coming in flat or lower on average, and some operators that late last year guided this year’s spending at higher levels, have revised them down.
Also, operators are being encouraged by market forces to spend money in other ways than growing production. E&P companies that return more cash to shareholders are being rewarded, since in some cases dividends were reduced or eliminated during the downturn. Companies that are more disciplined and keep spending at the level of cash flows – which was uncommon in years past when operators typically outspent their income – have also been rewarded with higher share price. Access to credit is also a likely consideration in times of volatile oil prices, as a more restrained approach to spending may help when companies are looking to the capital markets for funding.
In any case, premium acreage – the so-called “Tier 1” areas – is starting to decline for many companies, although some claim that continued efficiencies and cost control can turn many drilling locales to premium status that were not originally deemed that way.
Well productivity also appears to be reaching a plateau, many operators say. In a recent report on basin trends in Q4, Evercore ISI analyst Stephen Richardson said more corporate level efficiencies are expected in 2019, although finding the optimum spacing between wells remains an ongoing challenge.
Richardson’s examination “reveals the pace of incremental [well] performance gains have tapered across basins,” he said, adding: “The market needs producers to exhibit restraint in 2019 plans.”
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The global sugar industry is grappling with slowing growth in consumption coupled with oversupply, which have pushed prices down to unsustainable levels.
In such a challenging environment, it’s understandable that the sector is searching for a holy grail to fix its demand-side problems, while also watching carefully for black swan events that could upend the current fundamental picture. This was the mindset in evidence at the Ninth Platts/Kingsman Geneva Sugar Conference held on April 2-3.
For Alexandre Luneau, executive vice-president of Tereos, the world’s second-largest corporate sugar produce, the holy grail is a food product that is natural, healthy and tasty – but that includes sugar as an essential part if its formulation. The concern with promoting sugar’s role as a vital ingredient comes in the wake of anti-obesity campaigns in many countries targeting sugar consumption.
For some consumers, acceptance on grounds of taste has to be weighed against the health factor. After the introduction of the sugar tax in the UK, both PepsiCo and Coca Cola kept the sugar level unchanged in their classic colas, according to Martin Todd, managing director of market intelligence and analysis provider LMC.
Many at the conference said reformulating soft drinks was relatively easy – just cut sugar, add water – but for confectioners it is much more complicated. They not only have to take into account taste, they also have to deal with bulk and consistency. As Mars Wrigley’s Senior Strategic Sourcing Manager Yury Sharanov said, if you reformulate incorrectly you can end up with a Snickers bar the size of a credit card.
That will be cold comfort in the face of slowing demand, mainly due to lower sugar consumption in developed markets. Combined with overproduction, it has led to benchmark futures prices below the cost of production in even the most efficient producers. This was unsustainable for exporters, Luneau said. To illustrate the tough times the sector is facing, on the same day of his presentation, S&P Global Ratings changed the outlook on its BBB- rating of the world’s largest corporate sugar producer, Germany’s Suedzucker, to negative from stable. However, Luneau did see some relief ahead, forecasting that the 2019-20 (October-September) and 2020-21 seasons would be in deficit.
One of the factors in this was lower sugar production from Center-South Brazil due in part to a large part of the sucrose going to make fuel ethanol. Luneau said he thought Brazil was the best place for the sugar investment because of its Renovabio biofuels program and a pro-sugar industry environment not found in other regions.
However, the key to fuel ethanol consumption lies in the gasoline price. For drivers of Brazil’s large fleet of flex-fuel cars the ethanol price needs to be 70% the gasoline price to be economical, because it is less efficient. One of the game changers in ethanol consumption in recent years has been state-controlled oil company Petrobras aligning its ex-refinery gasoline price with the world price, making ethanol more attractive to drivers. Any move toward subsidizing gasoline or a major drop in the world price could be a potential black swan event.
Another fuel-related development, IMO 2020, could also be a black swan for the sugar sector – judging by the low number of raised hands in the conference hall when asked who had heard of it. This is the implementation by the International Maritime Organization of a 0.5% sulfur emissions limit from marine transportation fuel starting January 1, 2020, down from 3.5% now.
Claudio Galimberti, head of oil demand and refining analytics at Platts, said the need to produce lower sulfur fuel for the marine sector would result in refineries making less gasoline. As a result, gasoline prices would rise, which in the case of Brazil could mean more sucrose going to ethanol and lower sugar production. However, for Brazil, the world’s largest sugar exporter, the effect of IMO 2020 on freight rates might be a game-changer. Similarly, changes in freight rates due to the new regulation have the potential to alter trade flows in general, as well as the economics of refining raw sugar.
A more tangible opportunity may lie in Africa’s growing demand for sugar. With the continent’s population expected to grow to 4.4 billion or 39% of the global population in 2100, from 1.3 billion or 17% in 2018, sugar consumption looks set to soar, according to Alexander Stewart, director of consultancy Abercore. Assuming annual per capita sugar consumption remains constant at a relatively low 17 kg – less than half the approximately 35kg consumed in the US and EU – the continent would need an extra 19 million mt of sugar by 2050 and 53 million mt by 2100, Stewart said. That compares with current world production of around 180 million mt a year. Africa imports around 50% of its sugar needs.
However, Stewart warned of a whole host of risks, albeit manageable ones: currency risk, credit risk, long routes to market, security risk consisting of theft, losses and smuggling, as well as political and macro-economic risks. He gave an illustration of the logistical problems combined with the theft risk in the method of taking sugar from a slow-moving truck climbing a hill, using a hole bored in one of the bags, and attaching a bucket to the truck to collect the stolen sugar.
El Nino normally brings wet weather to the south of Brazil, which can delay cane harvesting and dilute its sucrose content. Equally important, it could reduce the monsoon rains in the world’s largest sugar producer, India.
It was perhaps fitting then that the final image of the conference was a family of black swans gliding along a body of water.
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As Alaska’s oil production declines, enormous attention is being paid to even the slightest hint of a find that could turn the state’s fortunes around.
Much hope has been pinned on the development of the Nanushuk, a broadly-dispersed set of rocks along the Colville River that extends west into the National Petroleum Reserve-Alaska.
Some companies have had success finding oil, with claims ranging from a conservative 500 million barrels to over 3 billion barrels of recoverable resources.
But a recent dry hole in the Nanushuk has brought to light some of the economic and technical challenges facing those who want to tap into those potential riches.
The stakes are high for Alaska. The Nanushuk discoveries have created new interest in the North Slope within industry and excitement among state leaders who have long worried about the gradual decline of the existing fields.
Alaska is now producing about 500,000 b/d, one fourth of production in 1988.
While enormous reservoirs are believed to exist offshore, attempts to explore there have not been successful. And while the Arctic National Wildlife Refuge is also believed to hold prolific resources, political and environmental opposition makes development there problematic.
High hopes and dry holes
For months, Alaska and industry officials have talked up the Nanushuk.
ConocoPhillips and Repsol, along with independent Armstrong Oil and Gas, have made potential billion-barrel discoveries in the area. Keiran Wulff, president of Oil Search Alaska, which has taken over Armstrong’s properties, told an Alaska industry conference last fall his company believes reserves at the Pikka discovery will reach a billion barrels after winter drilling results are evaluated.
ConocoPhillips said last summer the Willow find could reach 700 million barrels of oil equivalent. The company is still drilling evaluation wells at the project.
Alaska Gov. Mike Dunleavy gushed about Nanushuk’s potential at the CERAWeek conference in Houston in March, claiming companies have found 5 billion barrels, although that has not been confirmed.
But not everyone hits it big. One exploration group, a consortium of three small independents, has seen its hopes sour. Led by 88 Energy, an Australian company, the consortium drilled Winx-1, an exploration well a few miles east of Horseshoe-1/1A, a big discovery drilled in 2017 by Armstrong.
But the drill bit at Winx-1 dug into bad reservoir rock this spring. It is the first known dry hole in the Nanushuk, at least where results are public. All signs initially looked good at Winx-1. Nanushuk rocks were present and seismic profiling indicated the presence of potential traps. Other tests indicated the presence of liquids in the rocks consistent with the nearby Horseshoe well.
Then came bad news: Drilling showed that layers of clays dispersed through the rocks served to bind the petroleum fluids to prevent them from flowing. Winx-1 was abandoned by 88 Energy and Red Emperor Resources, one of the Australian partners. The third partner, UK -based Pantheon Resources, has refocused its efforts to other North Slope prospects.
Geological and economic risks
The Nanushuk and a related geologic formation, the Torok, are still new on the horizon for industry explorers. But the existence of the rocks and the fact they hold oil have long been known.
Over decades, companies exploring the NPR-A and state lands along the Colville River drilled through the Nanushuk and Torok on the way to deeper prospects that appeared of better quality. Over the years about 150 wells have been drilled in the area, said Dave Houseknecht, a US Geological Survey geologist, at an Alaska resources conference last fall.
Paul Decker, a former state geologist, said in an interview there were oil shows in many wells but no one stopped to take a close look at the rocks until recently.
Now, the advent of advanced seismic imaging and other analytic tools give industry the ability to spot stratigraphic traps that were previously undetected, and new drilling techniques like horizontal wells allow companies to develop resources previously thought uneconomic.
Decker said ConocoPhillips was the first to reassess the Nanushuk in its exploration in the northeast NPR-A and that put the company on the path to Willow, a potential billion-barrel discovery now planned for development.
Repsol and its partner Armstrong followed, exploring the Nanushuk on state-owned lands near the Colville River, discovering Pikka, another hoped-for billion-barrel find. Armstrong recently sold its interests to Oil Search, an Australian company.
Caelus Energy, a Dallas independent, said it made what may be a significant find in the Torok, another geologic formation, in nearshore waters at Smith Bay, northwest of Willow and Pikka.
“We estimate that there is a lot of oil in these plays, but there is also a lot of uncertainty because the reservoir quality (of the Nanushuk) appears to deteriorate from north to south,” Houseknecht said at the Alaska Resource Development Council conference in November. The Torok formation appears to be of lower quality, too.
Besides the geologic risk there’s also more economic risk as prospects are explored further west and farther from infrastructure in the NPR-A, requiring expensive roads and pipelines. Another complication may be that wells in the Nanushuk and Torok, where the rocks are tight, may have to be hydraulically fractured. That will require mobilization of equipment and possibly trucking water, because water sources are scarce in the petroleum reserve.
For the long run, Houseknecht is bullish, however. “We believe there could be eight billion barrels discovered in the Nanushuk and Torok across NPR-A and the adjacent state submerged lands,” he said.
Most of the resource potential, about 7 billion barrels, is onshore in the northeast NPR-A where ConocoPhillips is exploring.
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Commodity markets were weighing supply side risks this week, as key producing countries continue to grapple with sanctions and political upheaval.
In Libya, Africa’s third-largest oil producer and a significant supplier of gas to Europe, violence has escalated and the country is in danger of falling back into civil war. International oil companies like Italy’s Eni have started evacuating staff from Tripoli.
Meanwhile, despite sanctions Iran’s oil exports recovered in March off the back of Chinese and South Korean buying. But based on data and information from market sources, Iranian production has recently declined, and the country drew heavily on stocks to support the export surge.
Russia’s energy sector is also subject to US sanctions, which include measures targeting the development of Russian deepwater and Arctic offshore projects. Speaking at a regional forum, Russian President Vladimir Putin said that sanctions had hampered, but not stopped, development of hydrocarbons in the Russian Arctic.
Separately, there were new question marks in Europe over key routes for the transport of Russian fuels. The European Commission cast doubt over the timely startup of the Nord Stream 2 pipeline, while the Belarusian president threatened to suspend Russian oil transit through the country amid trade frictions with its neighbour.
GRAPHIC OF THE WEEK
US states are ramping up their mandates for clean and renewable energy in the face of federal climate inaction, declining renewable costs and demands from electricity customers, but new policies and yet-to-exist technology will be needed for states to meet ambitious 100% clean energy goals.
VIDEO: LNG’S SECOND WAVE
Vivek Chandra, CEO of Texas LNG and author of the book Fundamentals of Natural Gas: An International Perspective, talks to Eric Yep, senior editor at S&P Global Platts. They discuss the second wave of US LNG projects, what it means for Asian customers, the impact of trade war tensions and his proposed LNG export terminal.
Logistical issues, a wide open arbitrage for US LPG to Asia and an evolution in global trade flows have pushed freight for Very Large Gas Carriers to multi-year highs in the Middle East and US Gulf Coast regions.
Global sales of plug-in electric vehicles fell by 21% in February month on month, led by a sharp fall in China due to seasonal factors and ahead of the government cutting subsidies for EVs in March, according to S&P Global Platts Analytics.
An oil policy fight is heating up as Alberta prepares to go to the polls on April 16, following production cuts and lack of progress on new pipeline capacity. Premier Rachel Notley’s party could lose to opposition leader Jason Kenney, who has promised quicker action to bring more Alberta crude to international markets.
THE LAST WORD
“This will require more diligence be done by every business that is considering doing things that are even now second and third orders removed from what you might think of as a traditional connection to the Iranian economy.”
– Mike Pompeo, US Secretary of State, as the government moved to designate the Islamic Revolutionary Guard Corps a terrorist group.
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With the withdrawal season officially over, US gas storage fields stand at their second-lowest level in 16 years. Several regions face obstacles as they look to climb out of deep deficits and re-stock before the next heating season begins.
In particular, grid constraints on moving Permian gas, along with a new major export route to Mexico to be commissioned in April and incremental demand from LNG terminals, will make Texas and the Southeast a focal point this summer.
Total US storage inventories tumbled to a low of 1.11 Tcf this year before the first net injection occurred during the last week of March. Outside of winter 2013/14, which featured the frigid polar vortex, the injection season has not started at a lower level since 2003, according to data from the US Energy Information Administration.
Despite starting the season at one of the lowest levels seen in the 21st century, a forecast by S&P Global Platts Analytics projects US inventories reaching volumes on par with 2018 by the end of October. The month is expected to end at 3.25 Tcf, 12% below the five-year average. The current deficit is 31% behind the five-year average.
The forecast represents additions of 2.126 Tcf over the injection season. This is slightly more than usual as fields injected an average of 2.07 Tcf during the season over the past five years. It requires 300 MMcf/d more injected through the summer.
Given the forecast 2.1 Tcf build is close to the five-year average net build, the current deficit will not be eliminated, and as a result, underlying fundamentals should support a summer price closer to $3/MMBtu as opposed to the more recent NYMEX levels of approximately $2.75/MMBtu, according to Platts Analytics. However, multiple regions face hurdles to replenish stocks at or above average.
For example, the Pacific region is currently 44% below the five-year average, and will find trouble rebuilding back to normal without gas curtailments this summer. Total California storage inventories entered the summer injection season at a 10-year low, according to Platts Analytics. The Pacific Gas & Electric system trails the five-year average by 75 Bcf while Southern California Gas Company’s inventories are 10 Bcf behind the three-year average.
Although strong injections late in March helped to narrow the overall deficit, PG&E must nearly double last year’s daily injection average this summer just to reach last year’s record-low summer exit level of 145 Bcf. SoCal Gas must also strengthen injections by 33% year on year to an average of 211 MMcf/d in order to bring inventories back to the system’s already limited storage capacity of 84 Bcf.
With total pipeline receipts likely to remain limited to 2.4 Bcf/d this summer, based on the average system demand the past three years, only 60 MMcf/d of additional volumes will be available for storage. SoCal Gas will likely require operational flow orders and voluntary or mandatory curtailments to keep a lid on demand.
Texas and Southeast regions
Back in the Southeast and Texas storage inventories are poised to exit this summer and enter next winter’s withdrawal season at their lowest mark in the past ten years, according to Platts Analytics. The combination of rising demand from LNG and exports to Mexico, constraints moving Permian gas east on the Texas intrastate grid, and competition with Midwest markets for slowing Northeast production will leave the Southeast and Texas region short in its bid to refill this coming summer, thereby driving stronger price premiums across the Gulf Coast, including at Henry Hub.
While injections in early April have been strong, evidence suggests the refill this summer will be more challenging. Demand in the Southeast and Texas is forecasts to grow 3.4 Bcf/d summer over summer, according to Platts Analytics. Texas exports to Mexico will account for 1.1 Bcf/d of that growth, driven by the massive 2.6 Bcf/d Sur de Texas pipeline, which is set to begin service this month.
Also, incremental LNG feedgas demand from Sabine Pass Train 5, Corpus Christi Trains 1 and 2, Elba Island Trains 1-10, Freeport Train 1 and Cameron Train 1 are expected to add as much as 2.2 Bcf/d of demand summer-over-summer, though risk remains to the downside amid possible construction delays and tightening netbacks to Europe and Asia.
Southeast and Texas inventories currently sit at 381 Bcf, 148 Bcf less than 2018’s mark and 195 Bcf less than the five-year average. Platts forecasts the combined regions will inject 240 Bcf over the course of the summer and fill to roughly 620 Bcf by the end of October, the lowest mark since 2005.
The East region is the best-supplied of all the EIA’s storage regions, relatively speaking, at 22.5% below the five-year average. Despite holding a head start in the refill race over other regions, pricing issues might slow the process, especially in the Northeast.
The summer forward curve for Dominion has become so strong it is trading only 5 cents below the winter 2019/20 strip, according to Platts Analytics. This creates little incentive for people to put gas in storage now and withdraw it later after accounting for cycling costs and the time it spends sitting there. At this time last year, the winter spread was 20 cents higher than the summer spread, creating a greater incentive to store gas over the summer.
Additional reporting by Eric Brooks, Kent Berthoud and Jack Winters, S&P Global Platts Analytics
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In March, China’s elite gathered in Beijing for the annual “two sessions” meeting of China’s legislative bodies, the National People’s Congress (NPC) and the People’s Political Consultative Conference.
While much of what happens at the two sessions is at best marginalia for all but the most dedicated of China watchers, the key themes of the meeting and the government Work Report that outlines policy, priorities and targets for the coming the year, are worthy of attention.
As expected, the overall direction follows the 13th Five Year Plan released back in 2016: coordinated “innovation-driven development”, environmental protection and plenty more “opening up”. But as always with Chinese policy documents, the devil is in the detail.
Slower growth over more debt
That economic growth will continue to slow is hardly a surprise. But this year’s target of 6 – 6.5% offers more leeway than last year’s target of around “6.5%”. This is recognition of the uncertainties facing the economy in 2019, from domestic risks in the financial sector and excessive local government debt to uncertainty around the global outlook and trade tensions with the US. The government does not want short-term growth if that means a buildup of debt that could pose a risk to long term financial stability. Those hoping for a cheap hit of stimulus to boost demand for everything from steel to diesel should growth start sagging will likely be disappointed in 2019.
The focus has moved instead to supporting growth and employment by reducing costs for manufacturers and small businesses. VAT has been cut across a range of sectors and the amount of social insurance that companies need to pay to employ workers has been reduced. The China Iron and Steel Association (CISA) estimates that the VAT cut will reduce the tax liability of CISA member mills by around Yuan 22 billion ($3 billion). But the main effect will be felt by consumers with lower prices supporting domestic consumption – albeit at a cost. The tax cuts will put pressure on government budgets at all levels. Local governments will be able to access special bonds to help balance their books, but overall, governments will have to tighten their belts in 2019 by reducing spending or finding new ways of raising money.
A greater role for the private sector
There has always been tension at the heart of the Chinese economic model between the role of government and the private sector in the economy. This year the private sector appears to be in the ascendant with no less than nine mentions of private enterprise, investment and capital in the government Work Report, up 50% on last year. This should mean a more favorable environment for private business and startups as well as increased lending to small and private businesses, which have historically found it hard to obtain finance.
Markets and reform of SOEs
At the same time, the government will continue to reform the SOEs. This won’t necessarily mean rolling back the state. But it should lead to a better managed, more profitable state sector with fewer unprofitable companies that are a drag on the economy and a drain on government budgets.
Market reforms will continue in the energy sector with further development of electricity spot markets building on the pilot power trading schemes already underway in some regions. Creating more competitive electricity markets will help address the problem of idle renewable capacity as well as reduce the role of coal. Ultimately, it could help lower the cost of electricity for industry.
Where power leads, so oil and gas will follow. The government has experimented with setting up gas pricing hubs, but the dominance of the “three barrels of oil”, as Chinese the oil and gas majors are often called, has impeded the development of competitive markets. In order to lay the groundwork for these the government will create a new national oil and gas pipeline company from the transmission assets currently in the hands of the integrated SOEs. Separating distribution from sales of oil and gas is just the first step in allowing oil and gas markets to develop in China. The government also envisages opening up upstream oil and gas exploration to non-state capital. But without further detail, it’s hard to judge how transformative introducing more competition into the upstream sector might be.
There is no letup in the battle against pollution as we move into the second year of the “three critical battles” (the others are guarding against financial risk and poverty alleviation). Structural adjustments and “supply side reform” will also continue, but the language is around strengthening and upgrading industry rather than removing overcapacity. Expect emissions reductions by upgrading steel plants and promoting the use of cleaner coal, rather than another round of coal and steel capacity cuts. Meanwhile, increasing utilization of solar, wind and hydro capacity and increasing the use cleaner fuels in heating in northern China will constrain the growth of coal.
If the government Work Report is anything to go by we may have reached peak “Belt and Road”. The term is referenced just five times throughout the report, down from six mentions last year. Instead the talk is of defending economic globalization, free trade, and win-win development.
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