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Block chain could be a new killer app for the power utility sector. It will either kill the industry, or will be used by the industry to kill. Why the Power Industry? Recently I spent a couple of hours with a power utility on the…
South Korean thermal coal buyers have been working hard over the past year to diversify their supply sources and take advantage of price arbitrages in the seaborne market, according to a S&P Global Platts analysis.
Trade and customs data for South Korea show that operators of power plants fired by imported thermal coal have increased their purchases from non-traditional supply sources such as Canada, Colombia, and the United States.
These three countries typically supply customers in the Atlantic Basin market – including Europe, where demand for imported thermal coal is shrinking – and accounted for 10.6 million mt of South Korea’s 109.5 million mt of imports in 2017.
South Korea has more than tripled to 7.8 million mt in 2017 its intake of thermal coal shipments from South Africa – a swing supplier to the Atlantic, Indian, and Pacific seaborne markets – up from only 2.2 million mt in 2016.
At the same time, South Korean thermal coal buyers have more or less kept steady their purchases from traditional suppliers such as Australia and Russia at about 31 million mt and 16 million mt, respectively, last year.
Indonesia increased its thermal coal shipments to South Korea in 2017 to 41.2 million mt compared with 36.3 million mt in 2016 when South Korea’s total intake from the seaborne market that year was 93 million mt.
Several market factors have fostered the growth of Atlantic seaborne exports to South Korea, which is the third largest export market in East Asia for thermal coal shipments after China and Japan.
According to Platts’ data, delivered prices in the South Korean market as shown by Platts’ NEAT index are high enough to attract cargoes away from the European market where CIF ARA delivered prices have been lower. Colombian has been consistently cheaper for South Korea than Russian thermal coal shipped the short distance from Russia’s Pacific ports.
The expansion of the Panama Canal to accommodate larger ships could allow thermal coal shippers to trim 17 days from the 45- to 50-day voyage for Capesize ships sailing from Colombia to South Korea. But canal user fees of about $300,000 for a Capesize ship would reduce the potential savings of a shorter 30-day Pacific Ocean voyage, such as from lower bunker fuel costs on a reduced sailing time.
Still, a number of South Korean power utilities have pursued a flexible strategy in their long-term sea freight contracts to take advantage of competitively-priced Colombian thermal coal.
They have redeployed Capesize ships operating on the Australia-South Korea vessel route to the longer return voyage to Colombia, although three deliveries can be made by a Capesize ship from Newcastle to Korea in the time it takes for a ship to return from South America.
By taking an inventive approach to purchasing and shipping imported thermal coal, South Korean buyers have been able to keep in check the marketing muscle of traditional suppliers and save money on power station fuel costs.
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Many of the digital innovations that I’ve reviewed seem clever enough, but struggle to get a customer trial. Why is that and what can entrepreneurs do to improve their success rate? Duration: 9m 02s
LOOP Sour crude became lighter and more sour in April, with an average API gravity of 29.8 degrees and typical sulfur content of 2.86%. The crude’s minimum-maximum API gravity range was 29.3-30.7 degrees, while sulfur content ranged from 2.37%-3.26%, according to data from the Louisiana Offshore Oil Port.
API and sulfur are two of many characteristics refiners look at when deciding which crudes to run to maximize or minimize production of particular refined products. Other factors include acidity, metals content, the presence of asphaltenes and a distillation curve.
LOOP Sour is comprised of the US Gulf of Mexico medium sour grades Mars and Poseidon and a crude blend called Segregation 17, into which the Middle Eastern grades Arab Medium, Basrah Light and Kuwait Export Crude can be delivered.
About 10.203 million barrels of Basrah Light were imported to Morgan City, Louisiana, in April, with a total of nine cargoes making their way to LOOP, according to data from S&P Global Platts Analytics and the US Customs Bureau. This represents a month-on-month increase of 8.176 million barrels
compared with March.
Meanwhile, imports of Kuwait Export Crude at LOOP ceased in April, representing a month-on-month drop of 1 million barrels. Arab Medium imports also continue to go elsewhere, with no barrels of the Saudi Arabian grade having made their way to the offshore port since January.
The ‘In the LOOP’ Americas crude oil wrap runs each Monday in Crude Oil Marketwire, North American Crude and Products Scan and on the Platts Global Alert. You can read the FAQ: USGC LOOP Sour crude here and find the full special report LOOP Sour Crude: A benchmark for the future here. Also be sure to download our LOOP app by searching for ‘Platts LOOP’ in your app store.
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Boards in oil and gas must now take into account the wave of digital change that is impacting the sector, and help shape appropriate goals for management. The Pressure on Boards Boards in oil and gas can no longer ignore the wave of digital change…
For years indigenous people living in small villages along Alaska’s Arctic coast fiercely fought offshore drilling. Now they want a piece of the action.
When Shell first showed up in 2007 with a fleet of drillships and support vessels, and parked them in the migration path of the bowhead whale in the eastern Alaska Beaufort Sea, the Inupiats went to court. An injunction from the US Ninth Circuit stopped the company and started a chain of problems that would ultimately defeat Shell’s multibillion dollar Arctic initiative.
Fast-forward to 2018. The Inupiats have now taken over Shell’s offshore Beaufort Sea leases, where there were also earlier oil discoveries, and intend to develop them, most likely by partnering with larger firms.
In a decade, indigenous people in northern Alaska have come full circle, from hostility to cautious embrace of offshore drilling.
Arctic Slope Regional Corporation, owned by all Inupiats of the North Slope, is playing its cards close on its plans for 20 former Shell OCS leases off Camden Bay, in the Eastern Beaufort.
The US Bureau of Safety and Environmental Enforcement approved the transfer of Shell’s leases to ASRC April 13.
The area is highly prospective and includes Union Oil’s small “Hammerhead” oil discovery made in 1986 and two Shell prospects, Sivulliq and Torpedo, outlined in 2012. A well was partly drilled by Shell at Sivulliq but not completed.
A PIECE OF THE ACTION
It helps to have an economic stake.
Over several years Alaska Native-owned development corporations – ASRC isn’t alone – have gradually become dominant players in industry support and service work on the North Slope.
Doyon, Ltd., owned by Athabascans of Interior Alaska, owns Doyon Drilling, the largest Alaska drilling contractor on the North Slope.
Bristol Bay Native Corp. and Calista Corp., of southwest Alaska have stakes in oil field services and drilling. Even tiny Nuiqsut, an Inupiat village of 300 near the Alpine oil field west of Prudhoe Bay, owns a drilling company.
Nuiqut’s Kuukpik Drilling is working this year for ConocoPhillips and also works in Cook Inlet, in south Alaska.
ASRC began working in oil field construction on the slope and expanded over several years into a variety of technical service fields.
It’s all about owning the resource The big money is in owning the resource, however.
It is here that Arctic Slope has played its cards shrewdly. Alaska’s Native corporations were formed in 1971 when the US Congress resolved long-standing land claims that had become an impediment to securing rights-of-way for construction of the Trans Alaska Pipeline System.
Congress transferred 45 million acres of Alaska to Native ownership and paid a cash settlement of $962 million to twelve regional Native development corporations that were also formed.
It seemed logical for the new Native corporations to invest in businesses and services to the fast-growing Alaska oil industry, and it turned out to be a successful strategy.
The initial moves into catering, facilities management and services in the 1970s evolved into drilling and construction.
ASRC pursued a similar path in oil field services but also had different cards to play.
As a landowner on the North Slope, ASRC held part of the mineral rights in the Alpine field and began splitting royalties with the state of Alaska when that field began production in 2000.
ASRC is now a working interest owner in the small Badami field east of Prudhoe Bay, which is producing, and it has a working interest in Liberty, a small deposit in shallow offshore waters near Prudhoe.
The corporation also acquired its own onshore state leases in lease sales and has done exploration drilling on the acreage.
ANWR OWNERSHIP IS KEY
Its biggest coup, however, was in securing mineral rights in a 92,000-acre inholding in the Arctic National Wildlife Refuge’s coastal plain, which is prime real estate after Congress approved exploration in ANWR in the 2017 tax act.
ASRC made its move in the 1980s, years before the national spotlight focused on ANWR.
The inholding was held by Kaktovik Inupiat Corp., the Native village corporation for Kaktovik.
ASRC was able to swap land it owned in areas where the US wanted to preserve parkland for mineral rights under some vilage-owned land in ANWR.
The Native corporation went on to do a deal with Chevron and BP to drill an exploration well, KIC No.1. Because no development of the Native-owned land could occur until Congress voted to open the entire coastal plain, the results of that well were held confidential, and have been for decades.
Chevron and BP still hold rights under the deal, but the terms are also confidential.
The shipping industry’s vessel loans are typically taken on the basis of a premium over LIBOR. LIBOR has been experiencing upward pressure since early 2017, as major central banks have moved to a tightening stance. The three-month LIBOR has risen to 2.3% as of April 2018, the highest rate seen since November 2008, the early days of the financial crisis.
As LIBOR increases, stresses on shipping industry balance sheets, cash flows and earnings also rise. With rates still at relatively low levels in historic terms, further increases are likely, and for a highly capital-intensive sector like shipping, this will undoubtedly weigh heavily on already debt-laden companies.
To get an idea of just how much leverage the shipping sector is exposed to in the context of the wider economy, we used the median leverage ratio for S&P 500 companies as a baseline and compared it to the leverage ratio for shipping players as listed on S&P Global Market Intelligence’s platform. The difference between the two is startling: while the median net debt to EBITDA of S&P 500 firms is 1.5x, the rate for shipping firms is around 8.0x
Another solvency measure commonly used is the Interest Servicing Coverage ratio, which is EBIT over interest expense. A higher figure indicates a stronger debt repayment capability. The mean ISC ratio for shipping firms listed on S&P Global Market Intelligence’s platform was around 0.6x, sharply lower than the S&P 500 mean of 5.5x. Though the shipping companies included on the S&P Global Market Intelligence platform are typically larger, publicly listed entities, it is clear that smaller shipping players will also feel similar stress.
Information produced in the IMF’s Global Financial Stability Report in April 2017 demonstrates that a marginal increase in lending rates can lead to disproportionally higher pressures on corporate debt servicing. This means that a 1% increase in LIBOR would in general contribute to roughly more than a 10% increase in a company’s interest cost as a share of its operating income.
Shipping companies have accumulated more debt in recent years to fund a strong appetite for newbuild vessels, as well as mergers and acquisitions. Among the publicly listed companies in the sector, there are a substantial proportion of junk rated entities: 15 of 17 shipping firms have been given a speculative grade by S&P Global Ratings as of February 2018. Notably, these companies all have particularly weak leverage factor scores, which contribute a substantial proportion of the final rating.
In view of mounting debt, bond investors could demand higher interest rates, fueling further distress among shipowners. Similarly, an exogenous shock could precipitate a repricing of risk premiums, which could lead to further downgrades by rating agencies.
Are these unwarranted concerns over systemic risk, when the global economy is progressing toward the late end of the cycle, or is LIBOR the elephant in the room? Only time will tell.
Overall, despite recent recoveries in some shipping sectors, lackluster freight rates remain a drag on many highly leveraged businesses and it is uncertain whether freight earnings would be able to outpace higher financing expenditures moving forward.
The US government forecasts that summertime gasoline prices this year will be at their highest level since 2014, when Taylor Swift’s “Shake It Off” was at the top of all the music charts and Andrew Garfield still played Spider-Man.
SUV owners and those who love to take summer road trips may not be pleased by the news, yet it’s important to view the outlook in context: Prices will be higher this summer, but things could also be worse for the average US driver.
The US federal gasoline tax was last changed in 1993, when it was raised to 18.4 cents/gal, but was not indexed for inflation.
According to figures from the Brookings Institute, once adjusted for inflation, federal gasoline tax revenues peaked in 1994 and have been falling ever since. While there was some talk this year of a 25-cent/gal increase in the federal gasoline tax, even a novice to politics can see that the Republican Party – in control of both the White House and Congress – is unlikely to push a tax hike with pivotal midterm elections on the horizon. It’s true that some states increased fuel taxes at the start of 2018, but these changes were marginal and nowhere near the 25-cent/gal increase under discussion in Washington.
Americans can be somewhat reassured that supply and demand fundamentals – rather than the taxman – will be moving prices higher this summer.
Whether driving a pickup or a Toyota Prius, drivers should keep in mind that they are all direct beneficiaries of higher fuel prices in the form of cleaner air.
Specifically, gasoline values usually find their highest levels within any given year during the summer because the US Environmental Protection Agency requires that blenders hit a lower Reid Vapor Pressure, which makes fuel burn more cleanly, but is more expensive to produce. This is especially the case in larger cities, where the EPA requires the use of reformulated gasoline, which burns even more cleanly and emits less volatile organic compounds and nitrogen oxide, two of the main ingredients in smog.
The EPA says these standards “represent a significant part of the country’s smog reduction strategy” and that “about 75 million people breathe cleaner air because of RFG.”
INCOME AND EXPENDITURES
An analysis from Bloomberg shows that fuel purchases in recent years have come to represent a shrinking portion of US household incomes even as prices at the pump have risen.
In the first quarter quarter of 2018, US drivers spent 1.76% of a typical day’s wages on gasoline, down from 2.41% in the same quarter of 2014. In other words, the impact of higher fuel prices this summer could be mostly nominal.
This is not something that should be taken for granted. In countries like Mexico and South Africa, gasoline prices rose from 2014-2017, while also taking up an increasingly larger portion of consumer expenditures.
The same analysis found that when viewed as a portion of income, the US has some of the most affordable gasoline in the world. It is in the same league as countries such as Kuwait and the UAE.
ELECTRIC VEHICLES AND DEMAND
In 2017, US gasoline consumption fell for the first year since 2012 even as the economy expanded at a healthy clip and Americans drove more collective miles than ever before.
The increasing popularity of electric vehicles no doubt played a role in making this possible. EVs now account for less than 1% of US vehicles and while that may seem trivial, it is increasingly clear they are on track to begin affecting liquid fuel demand. The Boston Consulting Group forecasts that EVs could account for 20% of America’s new-car registrations by 2030.
That outlook is not so different from S&P Global Platts Analytics’ projections, which assume that EVs will see their share of new car sales grow toward 40% by 2040. Platts Analytics notes that the process of turning over the existing fleet will be slow, however, and conventional vehicles will still account for well over 90% of miles traveled in the US through 2030.
But in the future, those conventional engines are expected to be more fuel efficient than they are now, which, combined with enhanced EV penetration, could mean that US gasoline demand will drop by 10%-15% by 2025 and 30%-35% by 2035 compared with 2015 levels, according to BCG research. This is a scenario being taken quite seriously among oil companies. Total recently acquired an electric utility after Shell announced plans to make electricity the “fourth pillar” of its business.
Citing EVs as a key reason, BP has said global oil demand could peak by the end of the 2030s. In short, American motorists can fill their tanks this summer with a bit more optimism as the outlook for gasoline demand (and by extension prices) seems to be trending in their favor, particularly in the long term.
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Russia’s Gazprom continues to supply high volumes of natural gas to the EU despite long-running disputes over pipelines, competition and Ukraine, the latest S&P Global Platts guide to EU-Russian natural gas relations shows.
Flows via its 55 Bcm/year Nord Stream 1 pipeline to Germany hit a record high of 51 Bcm in 2017, helped by increased access to the onshore OPAL gas pipeline, at first just in January and then continuously from August.
The European Commission’s decision in October 2017 to allow Gazprom to access up to 12.8 Bcm/year of extra OPAL capacity through public auctions was intended to settle that particular dispute, running since 2013.
But state-owned Polish gas company PGNiG gained an interim court order to suspend the decision, causing the interruption in capacity sales from February to July. It has also asked the EU General Court in Luxembourg to annul the decision completely.
The court has said it will rule on this in 2019, and that capacity booked for after this ruling may not be guaranteed. That leaves an element of doubt over Gazprom’s future access to OPAL until the ruling is given.
EC BATTLES AGAINST NORD STREAM 2
While the EC has given Gazprom the green light to use more of Nord Stream 1, it is still battling fiercely against Gazprom’s planned 55 Bcm/year Nord Stream 2 project, due onstream at the end of 2019.
The latest salvo is the EC’s proposal to apply EU third energy package internal market rules to all offshore gas links with non-EU countries up to the limit of EU countries’ exclusive economic zones, which go beyond their territorial waters.
The EC argues this is a simple “clarification” of the EU’s gas directive which governs all onshore gas pipelines within EU territory, but in reality it is a hugely controversial move.
The proposal as written would cover long-standing links to Algeria, Tunisia and Libya, as well as the Nord Stream 1 pipeline, and any new links such as Nord Stream 2. It would also cover links to the UK after Brexit. But the clue as to the real target is in the option for national authorities to give existing pipelines long-term derogations — meaning protection from the internal energy market requirements for an unspecified time.
EU national energy ministers are looking at allowing those derogations to last for up to 20 years, and be renewable. If agreed — and there is no guarantee that the EC’s proposal will make it into binding EU law at all — this would effectively cover existing pipelines till the end of their operational life, if national authorities so desired.
That leaves Nord Stream 2 as the most exposed to requirements including ownership unbundling, third-party access and transparent, non-discriminatory tariff regulation for the EU section of the pipeline.
Ownership unbundling and third-party access would make little difference to Nord Stream 2. Existing vertically integrated companies such as Gazprom are eligible for very lightly supervised separation of their supply and transport arms under EU rules; and Gazprom still has an export monopoly, so there are no third parties to ask for access.
So the real focus is on transmission tariffs. The EC clearly wants Nord Stream 2’s tariffs to be more transparent, to give Ukraine a fighting chance to compete with them after 2019, when its transit contract with Russia expires. Russia has said that it is willing to consider sending gas through Ukraine if the price is right. The scene is thus set for tense talks on post-2020 transit tariffs.
Meanwhile, the EC’s proposal on offshore gas pipelines is also likely to complicate a long-running WTO case. The WTO panel investigating Russia’s formal complaint that the EU’s third energy package rules discriminate against Russian infrastructure has already delayed its final report several times, saying the issue is highly complex.
The EC has been surprised to discover that the WTO panel considers Russia may have a case, suggesting that the EU’s projects of common interest funding program discriminates against non-EU projects.
One dispute which could progress soon is the EC’s antitrust case against Gazprom’s alleged market abuse in Central and Eastern European countries. The EC is in advanced talks with Gazprom on commitments to resolve the case without a formal judgement, thus avoiding potential fines.
Closing that case with effective binding commitments could take some of the heat out of complaints that Nord Stream 2 may allow Russia to continue dominating these markets.
Overall it is clear the EU still wants to buy Russian gas in large volumes, and Russia still wants to sell to the EU. The commercial benefits to both sides continue to drive trade despite the disputes, and these benefits are unlikely to change much in the coming years.
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