Ahead of the S&P Global Platts Global Power Markets conference in Las Vegas, April 8-10, 2019, The Barrel presents a series of articles on the global and US electricity sectors. Here, Felix Maire and Jared Anderson look at the prospects for battery storage across the US. Battery energy storage deployment in the US has rapidly increased in recent years and appears set for further growth, assuming costs continue decreasing and pending market rule changes increase opportunities for storage resources to participate in wholesale power markets. But importantly, the economics, policy drivers and use cases differ widely among regions. The US currently has a little over 1 GW of installed battery storage capacity and could have more than 7 GW of utility-scale and grid-connected battery storage operating by 2022, according to S&P Global Platts Analytics’ most recent US Power Storage Outlook. Lithium-ion battery prices have sharply declined in recent years driven by steadily expanding manufacturing capacity, which has led to economies of scale and improved learning. That learning curve is expected to continue as battery companies are planning a six-fold manufacturing capacity increase by 2023. Over the medium to longer term, Platts Analytics anticipates that mass-market electric vehicle adoption will continue to drive battery costs down despite concerns around raw material prices. Lithium-ion battery prices are expected to decline 40% by 2025, making it difficult for other technologies such as flow-batteries to compete, particularly for shorter durations. One potential battery storage deployment growth metric lies in the interconnection queues maintained by each wholesale power market operator, known as independent system operators (ISO) or regional transmission organizations (RTO). Any resource that wants to connect to a regional power grid must progress through a formal interconnection process. Not every resource will ultimately connect to the grid, but the queues provide a view of the level of market participants’ interest in storage. Battery capacity in RTO/ISO interconnection queues more than doubled in 2018, surpassing 30 GW of capacity. The largest queued capacities are in the California ISO (CAISO), supported by storage mandates, and in the Southwest Power Pool (SPP), where several large solar-PV-with-battery projects entered the queue in 2018. The Federal Energy Regulatory Commission’s (FERC) energy storage order 841 will impact the volume of wholesale power market energy storage participation over the longer term, but the impact is expected to vary by region. The ISOs filed plans with FERC detailing market rule changes that would allow energy storage resources to participate in regional power markets on a level playing field with other resources. FERC is reviewing the proposals that were filed in December. Market observers were initially concerned that a 10-hour participation requirement for storage in PJM Interconnection’s proposal would limit the ability of battery storage to engage. PJM Interconnection is an RTO whose territory spans a number of states in the eastern US. However, president and CEO Andy Ott explained in a recent interview that changes to its energy and reserves markets are expected, to allow storage resources to earn the bulk of their revenue from those market segments. The 10-hour requirement only applies to the capacity market, which is not ideal for storage resource participation, according to Ott. Outside those regions covered by RTOs/ISOs, several utilities have announced plans to procure battery storage as part of their Integrated Resource Plan processes. Portland General Electric recently announced a first-of-a-kind combined facility with 300 MW of wind, 50 MW of solar PV and 30 MW of batteries. And Arizona Public Service Company in February said it plans to add 850 MW of battery storage and at least 100 MW of new solar generation by 2025. Platts Analytics estimates that solar PV with storage will become increasingly competitive with natural gas peaking plants in regions with high solar resources. Read more articles in this series: Tracking global power capacity: Renewables growth outpaces fossil fuels US power policy grapples with renewables growth, capacity gaps The post Batteries included: US poised for expansion of grid-connected power storage appeared first on The Barrel Blog. from https://blogs.platts.com/2019/03/28/us-expansion-power-battery-storage/
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It’s now a year since China took the first steps to opening up its mainly domestic futures market to the world with the launch of the Shanghai crude oil futures contract. It was the first of three to be “internationalized” last year – the other two were the existing iron ore and PTA futures contracts. But Shanghai crude was different to those in that it was a new contract, hosted on a new trading venue – the Shanghai International Energy Exchange (INE) – and designed specifically to attract international participants. The goal was to create a new China-based global pricing point for crude alongside incumbent international crude futures contracts NYMEX WTI and ICE Brent. The success of a new futures contract is typically measured by its liquidity, market depth and open interest. In the case of a physically settled contract, the delivery mechanism of any new contract will also be closely scrutinized by the market. Liquidity & market depth While liquidity is not everything when it comes to benchmarks, when it comes to derivatives it certainly helps. In February, less than a year after it started trading, 2,116 million barrels of Shanghai Crude were traded. It took ICE Brent more than 14 years to reach a similar monthly volume. But the comparison has to be seen in historic context. When Brent was launched in 1988, electronic trading had yet to be invented and orders were taken by brokers in colorful jackets shouting at each other across the trading floor. It was only when ICE moved Brent over to fully electronic trading in 2005 that volumes really soared and it became the derivatives success it is today. Liquidity on Shanghai crude is generally concentrated in just one contract. This is usually the contract that expires at the end of the current month. However, in the last 10 days before expiry liquidity moves to the next month forward as traders who are not allowed to take physical delivery are forced to liquidate their positions and roll them into the next contract. On March 25, with just four days before the April 2019 contract expires, virtually all the volume and open interest had moved to the May 2019 contract, which expires at the end of April. A medium sour contract The price of Shanghai crude reflects the price of one of seven medium sour crudes – all but one of them from the Middle East – held in bonded tanks located on the coast of China. While one might expect the price to track Platts Dubai, the Middle East benchmark, the price of Shanghai crude actually more closely follows ICE Brent. This is reflected in its trading patterns: Shanghai crude is most active during the night session after 9 pm Beijing time when European and US exchanges are active and it can be traded against other futures like ICE Brent and NYMEX WTI. It is also worth noting that because the Shanghai contract is denominated in Chinese yuan not US dollars, the value of the contract is susceptible to changes in the yuan-dollar exchange rate; as the Chinese currency strengthened against the dollar in February, the price of Shanghai crude when converted into dollars fell by around $2/b against ICE Brent and Dubai. Delivery Seven monthly contracts have expired since the INE launched Shanghai crude, with six of these being settled by physical delivery. The first delivery in September last year saw 600,000 barrels change hands. The very low volume of crude in exchange-approved tanks in the month of the first contract expiry – at one point it fell to just 100,000 barrels – saw the price of the contract whipsaw compared to other crude benchmarks, in response to fears that there would not be enough oil in tank to meet delivery. Since then the volume of crude on warrant and volume delivered has risen, averaging slightly over 2 million barrels over the last three deliveries. And prices have been less volatile versus international benchmarks over the last few deliveries. While the intention of the INE is to internationalize the contract, a year after its start it remains primarily a domestic affair. INE data from mid-December shows that around 92% of the trading volume and around 80% of the open interest was accounted for by Chinese traders. Retail investors account for slightly over three-quarters of the volume and more than half the open interest, with oil companies, physical traders as well as funds and investment companies making up the remainder. The exchange does not release information on parties involved in delivery but market sources suggest that not only physical traders and Chinese oil majors, but also financial firms like domestic futures brokerages, used the physical settlement mechanism. It may seem surprising that companies with no use for physical oil have chosen to close positions physically but the settlement process does not require scheduling logistics and chartering vessels. Delivery is typically done by transferring ownership of a warrant – a receipt that allows the holder to take delivery of oil held in a specific tank – from seller to buyer. The seller chooses the grade and location of the warrant they wish to deliver to settle their position. In a contango market – where prices in later months are higher than the current month – money can be made by selling a later month and buying the current month. This works as long as the profit from this trade is greater than the cost of holding the oil on warrant until it has to be delivered to settle the short position. The Shanghai crude contract was in quite a strong contango for much of the period from November to mid-March, making this trade possible. The first year of the Shanghai crude contract has been a success in many ways, but from a physical market perspective, it is still early days. There has been talk of independent refiners possibly using Shanghai crude rather than ICE Brent as the basis on which they buy cargoes. But currently there does not appear to be much, if any, use of Shanghai crude as a basis on which to price term contracts or spot cargoes. On March 22, 131 million barrels of Shanghai crude were traded with open interest of 28 million barrels. ICE Brent saw 946 million barrels traded with open interest of 2.4 billion barrels. This was more than eighty times that of the Shanghai crude and reflects the widespread use of Brent as a risk management tool across the global oil sector. It is worth remembering that Shanghai crude has only been trading for 12 months – ICE Brent turned 30 last year. As it passes its first birthday the challenge for Shanghai crude will be to draw in more international participation and build market depth and open interest along the curve. It will also take time to build trust in the physical settlement mechanism. But if these issues can be successfully addressed, Shanghai crude may well find its seat at the table with Brent, WTI and Dubai. When the first premier of the People’s Republic of China, Zhou Enlai, was asked in 1972 about the impact of the French revolution he famously retorted that it was “too early to tell”. History does not relate whether he was referring to the revolt of 1789 or the student riots of 1968, but taking a long view may be wise advice for those trying to judge the success or otherwise of the Shanghai crude oil futures contract. The post Insight from Shanghai: China’s international crude contract marks first birthday appeared first on The Barrel Blog. from https://blogs.platts.com/2019/03/27/china-shanghai-crude-futures/ Ahead of the S&P Global Platts Global Power Markets conference in Las Vegas, April 8-10, 2019, The Barrel presents a series of articles on the global and US electricity sectors. Platts’ US generating fuels news team report on policies at state and federal level that will have consequences for energy security and the transition to renewables. As the US power industry contends with reliability concerns due to low electricity prices, rapid renewables growth and baseload generation retirements, policymakers are scrambling to offer solutions. Regulators are also trying to work out how to best incentivize adequate generation capacity additions, and how to ensure compensation of existing power plants and other resources operating in competitive markets. The current challenges have already led to a variety of complicated market design proposals and other potential fixes created at both state and federal level. Among the major federal issues being watched closely this year are efforts by the White House to keep nuclear and coal-fired power plants afloat, although so far the Trump administration’s efforts have been frustrated. Among the states, meanwhile, Texas has made market design changes to encourage generation capacity development at a time when reserve margins are extremely low. PJM Interconnection also has the daunting task of installing reforms to maintain a competitive marketplace in the face of state subsidies designed to prevent the retirement of major baseload nuclear facilities because of low energy prices. And in California, the effort to go 100% renewable has led to a number of reliability questions. Appealing to the base(load) The White House’s effort to keep struggling coal and nuclear plants solvent is perhaps the highest-profile power industry event in 2019. However, many Washington insiders have grown increasingly skeptical that action at the federal level to keep these baseload coal and nuclear plants online can find a legal foothold. In a recent development, the board of the federal government-owned utility Tennessee Valley Authority voted February 14 to close two coal generation units despite pressure from President Donald Trump, who tweeted ahead of the vote that the utility “should give serious consideration to all factors before voting to close viable power plants”. TVA responded that while coal was an important part of its generation mix, the Paradise and Bull Run coal plants at issue no longer met its system needs. Retiring the plants is expected to save TVA customers more than $1 billion. This latest snub to the White House’s efforts comes over a year after the Federal Energy Regulatory Commission rejected the administration’s original plan to prop up coal and nuclear generators. That involved a notice of proposed rulemaking from the Department of Energy that sought to guarantee full cost recovery and a return on investment for generators that had 90-day, on-site fuel supplies. “I think it’s just going to be very difficult to do anything on the federal level although I think the administration is going to continue to try,” Barry Worthington, executive director of the United States Energy Association, said in an interview. Action from states could be more likely, he said. States such as Illinois, New York and New Jersey have turned to zero emissions credits programs to save their nuclear fleet, and Worthington said coal-producing states may look to craft programs to help coal units. FERC Chairman Neil Chatterjee said on the sidelines of an industry conference that if a threat is identified, his preference would be to resolve it with a market solution. “Whatever action we take on resilience will be based firmly on the record, on evidence, on science without any political influence or favoritism for one fuel source or another. We just want to make sure we do it right.” ERCOT struggles with tight capacity Among the state initiatives being watched are the Electric Reliability Council of Texas’ market reform strategies to encourage development and retention of dispatchable generation resources, in light of the low reserve margins the Texas grid is expected to face again this summer. A number of recent capacity retirements resulting from renewable power generation growth, cheap and abundant natural gas, and low power prices have put the state grid in a precarious supply situation. Over 5 GW of fossil-fuel generation – including 4.2 GW of coal-fired generation – has been retired in ERCOT since May 2017. This summer the market has a projected 7.4% planning reserve margin, the lowest on record and well below the system’s target of 13.75%. In February, ERCOT issued a market notice stating that it would implement the first change to its Operating Reserve Demand Curve on March 1. ORDCs are used to calculate scarcity prices when supply and demand tighten, providing incentives for new generation development. ORDCs enable wholesale prices to increase automatically as available operating reserves decrease. The actual price adjustment is based on the level of increasing risk that a rotating outage could occur and the potential consumer impacts associated with an outage. In order for the ORDC change to have the desired generation retention and growth effect, investors and developers must have faith that the resulting higher wholesale prices will be sustained, and such faith may be hard to find during a biennial legislative session in which lawmakers may hear complaints from consumers about surging electricity bills. ERCOT, market stakeholders and industry observers all seem to disagree about how successful the market reform actions will be – or indeed can be – in encouraging new generation capacity. “Market reforms are good but probably not enough to yield new dispatchable capacity within 2-3 years,” said Gurcan Gulen, energy economist and principal of G2 Energy Insights. However, Gulen said that if the reforms enable developers to obtain financing, 2 to 3 GW of gas-fired generation may result. In contrast, Cyrus Reed, conservation director of the Sierra Club’s Lone Star region, said, “We do not think the ORDC adjustment will make a large difference in providing an incentive to more dispatchable generation, though it could provide an incentive for investments in demand response as a reaction to higher prices.” In Texas, demand response often takes the form of on-site fossil-fueled generation, either with natural gas or by a liquid fuel such as diesel or gasoline. Such relatively high-cost, inefficient resources could be aggregated and dispatched to serve the grid in high-demand situations. “Alliance” of renewables, oil, gas In February, the ERCOT Board of Directors learned the Far West weather zone’s peak demand has doubled since 2009 – from about 1.8 GW to about 3.7 GW – largely because of Permian Basin oil-and-gas development. ERCOT projects about 20 significant new wind and solar projects in West Texas by 2033, but Neil McAndrews, an energy market consultant based in Austin, Texas, said the region’s natural gas production is a more significant impediment to ERCOT’s thermal generation fleet. “The essential problem faced by all US utilities is that natural gas is priced, in large part, as a by-product,” McAndrews said. “The Permian oil field is wasting 55 Bcf per year via flaring, according to industry sources. … The gas that is flared is considered valueless.” “Look for many more retirements of coal and nuclear units in the US,” McAndrews added. “Without addressing the fundamental problem of natural gas oversupply, there is little ERCOT or the PUC of Texas can do.” PJM markets in flux ERCOT has not been alone in attempting to manage challenging capacity trends. PJM Interconnection has been at the forefront of the situation in large part because of low power prices due to cheap natural gas from the Appalachian Basin, as well as several state efforts to subsidize uneconomic baseload facilities in response to those low power prices and the likelihood of plant retirements. In its 2018 capacity auction, the PJM base residual auction RTO clearing price came in at $140/MW-day for capacity in the 2021-2022 period, an 83% increase from the previous year’s clearing price of $76.53/MW-day. The capacity price increase was attributed to a response to continuing energy prices declines, and thus, net revenue for generators, Stu Bresler, PJM’s senior vice president of operations and markets, said when the results were released. Since generators have been receiving less revenue from the energy market, they have looked to earn higher capacity payments and thus bid into the auction at higher prices. PJM has been working to adjust some of its energy market pricing rules, adding uncertainty to the pricing dynamics between the energy and capacity markets. In addition, the Federal Energy Regulatory Commission issued an order in June 2018 that found the PJM Interconnection’s existing tariff governing its capacity market is unjust and unreasonable, which set off a major proceeding to adjust the rules. The order said PJM’s capacity pricing model had become “untenably threatened by out-of-market payments provided or required by certain states”. Illinois, New York, New Jersey and Connecticut have passed laws or issued regulations designed to financially support a number of at-risk nuclear plants, while several other states are considering similar actions. A decision from FERC is expected in the first half of 2019 to keep the capacity auction on schedule for August. The upcoming auction already has been delayed three months due to the complexity of the process. FERC’s order will be one of the most important capacity market developments of 2019. PJM’s energy price formation contains two main elements: fast-start pricing and reserve price reform. Fast-start pricing, which would modify pricing treatment for generation resources that can start up quickly, awaits a FERC response. A contentious filing on reserve reform from PJM at FERC can be expected around mid-March, PJM president and CEO Andy Ott said in a recent interview. Reserve pricing reform is expected to include multiple components affecting several major aspects of the wholesale power market in the region. Go deeper: Podcast – PJM CEO Andy Ott on energy and capacity markets Initial S&P Global Platts Analytics modeling of the impact of both fast-start pricing and reserve reform resulted in an overall price increase of $1-2/MWh. Since the analysis was conducted, updates to the proposed ORDC as well as a larger penalty adder could increase this estimate, according to Platts Analytics power market analyst Kieran Kemmerer. Ott said in the interview that he believes reserve price increases will incentivize new alternative technologies to provide more reserves and “compete away the advantage that generators have had and so the price will drop”. As the rule changes encourage technologies such as storage and demand response, providing additional reserves to the market, the increased supply of reserves could exert downward energy price pressure. The outcome will provide valuable lessons that could influence future state or federal actions. ISO New England faces controversy Stakeholders in ISO New England’s capacity market also recently raised concerns that low prices, a renewable exemption and a specific contract with the gas-fired Mystic power plant near Boston in a recent capacity auction, all conspired to damage the viability of generation resources in the region. ISO-NE’s 13th forward capacity auction held in February closed at a preliminary clearing price of $3.80/kW-month, an 18% decline from last year’s auction price and the lowest clearing price in six years. Worries arose that the Mystic power plant’s exemption and contract dampened the impact of ISO-NE’s rules for competitive auctions with sponsored policy resources. In December 2018, FERC accepted a cost-recovery proposal for Mystic, providing ratepayer support for the plant, which was allowed “price-taker” status in the next three annual capacity market auctions. The New England Power Generators Association said that with Mystic entered as a price taker, the auction undervalued other fuel-secure resources in the market. “Coupled with the future scale of subsidized new entry, competitively-determined adequate revenues are at grave risk in New England,” NEPGA President Dan Dolan said. New York carbon price In New York, efforts to price carbon emissions into the wholesale market could lead to price increases. The New York Independent System Operator’s five-year power grid plan sets out strategic initiatives to guide its projects and resource allocation that include pricing carbon emissions into the wholesale market, which could increase power prices by about $10-$15/MWh, according to Platts Analytics. “The carbon prices being discussed for implementation in New York are significantly higher than the current [Regional Greenhouse Gas Initiative] RGGI prices,” said Manan Ahuja, senior director of North America power modeling at S&P Global Platts Analytics. If implemented, the carbon prices could add significantly to the wholesale power prices, increasing location-based marginal prices “by about $10-$15/MWh (in the proposed carbon price vs the RGGI price) based on our recent modeling,” Ahuja said. Such changes would also impact decisions about what type of supply resources get built or retired, he added. “Analysis conducted by the Brattle Group on the carbon pricing proposal under consideration, found a slight, short-term increase of roughly $1.50 on the average consumer’s monthly bill,” said Kevin Lanahan, vice president of external affairs at NYISO. “However, the same analysis found that costs drop quickly in the out-years, and produce savings as markets respond,” he added. The initiative could go into effect in the second quarter of 2021, NYISO has said. California worships renewables Many states have ambitious clean energy goals and vague perceptions of the challenges they carry, but none are as far along or as deep into the difficulties as California. The state is forging ahead toward a goal of 100% clean energy by 2045, but to get there it will need new rules and at least some gas-fired power to ensure resource adequacy. Meeting the target with only renewables and the current storage technology is likely to be too expensive, stakeholders say. Not every megawatt needs to be clean and green under the state law that set the mandate, and there are certain resources needed for reliability that have a carbon footprint, said Karl Meeusen, senior advisor for infrastructure and regulatory policy at California Independent System Operator. But while some thermal generation is needed in the short term, the possibilities are endless for the resource mix in the future, Meeusen said. And both Cal-ISO and the CPUC are working on rule changes to help transition to a low-carbon grid. Getting to 100% clean energy with only wind, solar and short-duration storage is cost-prohibitive because it requires a massive overbuild of the renewable and storage portfolio to ensure reliability, according to Arne Olson, senior partner with consultancy Energy and Environmental Economics. But getting to 80-90% clean energy can be done without sacrificing reliability, Olson said. “Natural gas capacity will continue to be needed indefinitely barring a breakthrough in nuclear, carbon capture and sequestration, or very long-duration storage,” he said. While solar and storage will play a major role in California, there is also room for other resources, said Morris Greenberg of S&P Global Platts Analytics. Remote wind in Wyoming and New Mexico could be an important source of clean energy as inland coal retirements free up transmission, Morris said. The state can also rely on in-state hydro, some Pacific Northwest hydro, and California utilities’ share of the Palo Verde nuclear plant in Arizona, he explained. The CPUC could improve the way the resource adequacy program accounts for the value of projects that combine renewables and storage, said Mark Specht, an energy analyst at the Union of Concerned Scientists. These projects create a value that is greater than the sum of their parts, he said. Conversely, the CPUC might also need to weigh whether to require longer durations for storage projects to qualify as resource adequacy capacity, Specht said. Current CPUC rules allow four-hour storage to qualify. In many ways, California will be the power sector’s guinea pig for the relationship between clean energy and reliability. Big questions remain in many ISOs about the appropriate generation fuel mix and capacity levels to meet reliability standards, and the answers may hinge on technological advances in storage. However, one of the biggest challenges is establishing the right market design that leads to appropriate price signals to meet those reliability goals. Reporting by Jared Anderson, Mark Watson, Kate Winston, Rocco Canonica, Jasmin Melvin and Jeff Ryser The post US power policy grapples with renewables growth, capacity gaps appeared first on The Barrel Blog. from https://blogs.platts.com/2019/03/27/us-power-policy-renewables-growth/ Despite receiving fewer barrels of crude oil from Venezuela, US Gulf Coast refineries and terminals, including the Louisiana Offshore Oil Port, have not started to import more heavy, sour crudes from other markets. On January 28, the US imposed sweeping sanctions on Venezuelan state PDVSA, which analysts widely expected would drastically cut US imports of Venezuelan crude and cause US refiners to seek alternative barrels from other Latin American countries and the Middle East. However, while USGC refiners have cut Venezuelan crude imports, as expected, they have not made corresponding increases in imports of heavy, sour crudes from other markets, according to the latest US Commerce Department import data. And, the data shows, overall US imports of all foreign crudes by vessel has fallen sharply in the nearly two-month period since the PDVSA sanctions were put into place. Since imposing sanctions on Venezuela, US imports of crude by vessel have averaged about 3.25 million b/d, compared to 4.26 million b/d over the same two month stretch in 2018 and 4.52 million b/d over that time period in 2017, according to Commerce data. Since PDVSA sanctions were imposed, US imports of Venezuelan crude have fallen to an average of about 185,200 b/d, eventually dwindling to zero. The US has not imported Venezuelan crude since March 9, according to US Customs data and S&P Global Platts Analytics. Even without sanctions, US imports of Venezuelan crude have been falling steadily for years, but averaged about 420,100 b/d over the same two-month stretch last year. While Venezuelan imports have plummeted, US imports from other countries have yet to surge, Commerce data shows. Go deeper: Podcast – Will Venezuela’s oil sector ever recover? US imports of Mexican crude, for example, averaged about 645,200 b/d over the two-month stretch since sanctions were imposed, down more than 39,000 b/d from the same timeframe last year, and imports of Saudi crude averaged about 640,000 b/d, down about 62,000 from the same stretch last year. Imports of Iraqi crude, one of the suppliers analysts expected might fill the gap created by the loss of Venezuelan crude, fell below 314,600 b/d, less than half the amount imported over the same time a year ago. At LOOP, a terminal designed to take in mostly heavier, sour crudes, the drop in Venezuelan and Saudi Arabian crudes imports has been more dramatic, with zero cargoes recorded for both countries so far this year. Imports of Iraqi grades also plummeted to 2 million barrels in the post-Venezuelan sanctions period, from nearly 10 million barrels in the same period of 2018, according to US Customs Bureau data. US Gulf looks south for make-up volumes However, there is some indication that the Latin American crudes have stepped in to take the place of missing Venezuelan and Middle Eastern barrels, in part. Latin imports to the LOOP remained slightly higher so far this year, despite the supply tightness of heavy-sour crudes produced by Mexico and Colombia and some seasonal turnarounds. The total volume of Latin grades imported at LOOP totalled 1.7 million barrels from February 1 to March 25. That’s compared with 1.4 million barrels in the same period of last year, Platts data showed. Last week, Pemex raised for the first time its K factor of constant terming for its formula pricing for April Maya deliveries to Asia, after dropping it for three consecutive months. The price hike was attributed to a spike in buying interest from Asian refiners due to the sanctions on Venezuelan and Iranian crudes. US Gulf Coast refiners’ weakened appetite for foreign crudes could be an indication that more refineries are taken in domestically available crudes, including light sweets produced in major US shale basins. The dip in imports also coincides with planned turnarounds including work being done at ExxonMobil’s 505,200 b/d Baton Rouge refinery, which scheduled to restart at the end of the month. Valero’s 215,000 b/d St. Charles refinery also undergoing maintenance most of February. The post In the LOOP: US imports fewer heavy sour crudes, despite supply crunch appeared first on The Barrel Blog. from https://blogs.platts.com/2019/03/26/loop-fewer-heavy-sour-crudes/ Ahead of the S&P Global Platts Global Power Markets conference in Las Vegas, April 8-10, 2019, The Barrel presents a series of articles on the global and US electricity sectors. Here, Bruno Brunetti and Lin Fan analyze world power capacity additions in 2018 and look at factors that will drive developments this year. Global investment in renewable power capacity continues to outstrip that in fossil fuels and nuclear, but growth has softened recently as a result of policy U-turns – with solar additions notably impacted. A major change in the support for renewables was announced in May 2018 in China, creating uncertainty in a country that had been a global leader in terms of solar growth over the past several years. PV tariffs and installation quotas were reduced, while China is looking to introduce tenders for utility-scale plants and market-based allocation for distributed PV. Capacity additions in China during 2018 have totaled only about 44 GW, a decline by 16% on the year. Early in 2019, some encouraging signs for solar developers once again emerged, as the Chinese government removed quotas on projects built without central government support and made efforts to reduce taxes, land costs, administrative burdens for developers and also prioritize grid access to non-subsidized projects. This latest announcement is likely a positive for Chinese solar development. Although declining costs are making solar photovoltaics more appealing, it’s still unclear how the new regime will impact the development of unsubsidized projects. That means continued uncertainty around annual PV additions in the near future. Meanwhile, headwinds have also been emerging in another important market for solar additions, India. While an ambitious solar target of 100 GW by 2022 has been set under the Jawaharlal Nehru National Solar Mission (JNNSM), a government initiative, there are nonetheless uncertainties related to the implementation of a 25% safeguard duty for imported modules, and other taxes have further dampened the enthusiasm around solar. Tariffs on imported PV modules also took effect in early 2018 in the US, adding 30% to the cost of a module in the first year of implementation. The tariffs are set to decline by 5 percentage points each year over the next four years, and so will equal 25% in 2019. Module prices have, however, declined by over 30% over the past year, offering support to growth. The pipeline of utility-scale projects in the US totaled 38 GW as of January 2019, according to the S&P Global Market Intelligence World Electric Power Plants Database. Corporate-backed renewable projects remain a positive driver of installations, along with utilities’ procurements under state-level renewables mandates. Interest in offshore wind grows In the wind sector, capacity additions globally last year are estimated to have totaled around 44 GW, about 3% below 2017. Almost half of this capacity was added in China, with wind additions trending higher, in spite of uncertainty around its renewable supporting mechanism. While feed-in tariffs for onshore wind have been progressively lowered, China also took the decision in 2018 to switch to an auction mechanism, with gradual elimination of government subsidies. China has a strong pipeline of projects that will still be able to benefit from the prior or current support mechanism and will still be largely unaffected by the switch to auctions in the near term. However, Europe has seen a significant decline in newly added capacity. Among the major markets, Germany installed over 3 GW in 2018, the UK about 2 GW and France around 1.8 GW. But overall, wind additions were well below 2017 and previous year levels, and were mostly in the onshore segment. To put this in perspective, there is rising interest in developing offshore projects, where Europe is already a leader. This is the result of a significant decrease in the overnight costs in recent years, while financial institutions are now comfortable with the technology. Some 2.7 GW of offshore plants were connected in 2018, with the pipeline of offshore projects much larger, in the order of 27 GW, and Germany and the UK lead the way. The UK will see a third contracts for difference auction in May 2019, with offshore wind projects widely expected to capture most of the available funds. Up to 6 GW of offshore wind capacity may be awarded in this round. Also, a number of offshore projects in Europe are not relying on public support – other than grid connection – which suggests an increasing confidence that wholesale prices will be sufficient to cover installation costs. Also worthy of note is the widening pipeline of offshore projects in the US East Coast – now totaling over 25 GW. Onshore wind is already the largest non-hydro, renewable source of power in the US, but development of offshore projects is gaining momentum. The 800 MW Vineyard Wind project, being developed off the coast of Massachusetts, signed a power purchase agreement starting in the early 2020s at $65/MWh, a recent indicator of where US offshore wind costs may be in this early stage. With the supply chain now just being developed, this is already comparatively low, considering that UK projects will be allowed to bid in the upcoming May 2019 CFD auction for up to £56/MWh (equivalent to $73/MWh) with completion set for 2023/24. Beyond the costs, a more critical issue to watch for offshore wind is the timing of development of these projects, especially the permitting phase, which has been particularly lengthy. Coal projects deferred, canceled Although China remains the leader in clean energy installations and manufacturing, it may seem ironic that the country is also bringing online a large amount of coal capacity – 38 GW alone in 2018, just a few gigawatts below China’s annual PV solar additions. The World Electric Power Plant database indicates that about 45 GW of coal-fired projects are still in an active construction stage, although a growing number of projects face a more uncertain fate. It should be noted that Chinese power demand continues to grow, with a 49 GW increase reported in 2018. Last year’s additional renewable capacity (solar, wind and hydro) would meet only a quarter of this demand increase. But the central government is getting more cautious and it recently started restricting the coal-fired capacity to be connected to the grid, in an effort to address growing overcapacities in certain provinces and air-quality concerns in major cities. Similar trends have also emerged in India. According to the Central Energy Authority, India’s net coal capacity has increased to 197.4 GW as of the end of 2018, up by only 4.5 GW on the year, with 6 GW of capacity commissioned offset by about 1.8 GW of retirements. To put things in context, India had been installing some 20 GW/year of coal in the prior five years. Increasing renewable generation, together with fuel availability problems, have undermined utilization of the existing coal assets – now in the 50-60% range, whereas load factors were at 70-80% earlier this decade. India has 13.8 GW of solar in construction and 22.8 GW is already tendered, with bids in 2018 as low as Rupee 2.4 /kWh (equivalent to about $33.60/MWh), making coal newbuilds a considerably more difficult proposition, especially in a context of elevated imported coal prices. While Asia continues to bring coal plants online – albeit at a slower rate – gas-fired capacity is increasing mostly in the US and Middle East. In fact, out of the 35 GW of gas generation connected in 2018 across the globe, the US accounted for about half, with another 20% in the Middle East. Cheap gas is clearly a major driving force in these regions. In the case of the US, lower gas prices have had a major impact on the erosion of coal-fired capacity. Over 70 GW of capacity with coal as the primary fuel has been retired over the past seven years. A further 20 GW of retirements have been announced, with much more capacity at risk. As many as 150 GW of coal units have been operating for more than 40 years. In addition, Platts Analytics sees another 16 GW of nuclear capacity at risk of retiring within the next five years, in spite of states in the Northeast implementing policies to aid at-risk nuclear generation. The appetite to invest in large-scale gas-fired units has been fairly limited in other regions, especially in Europe. Baseload retirements in Europe are not expected to be as large as in the US, at least within the next 10 years. Platts Analytics forecasts that 20 GW of nuclear and 56 GW of coal/lignite will be closing in the upcoming decade in the major European markets. But uncertainties over competing renewables and operating hours are dampening power generators’ interest in large-scale CCGT investment, while relatively high imported gas prices have hurt the margins of existing gas units. Even in countries where capacity mechanisms are in place, such as the UK, large-scale gas units were unable to secure long-term contracts, as distributed resources were more competitive. Instead, there have been a lot more small-scale OCGTs, which have low capex and considerably higher operational costs, with their flexibility matching the intermittency of renewables. Gas-fired projects in Russia appear so far to be limited, considering that a large portion of the country’s operational fleet is more than 40 years old. However, things will likely change as the Russian government recently approved a new capacity mechanism under which long-term contracts will be awarded for the upgrade of some 40 GW of aging thermal units. The first tender will be held in April-May for 11 GW that will have to be available from 2022-24. Pace of nuclear build lifts Nuclear remains a more marginal technology, although nine nuclear units were connected to the grid during 2018, representing some 10.4 GW, making 2018 one of the best years for nuclear in terms of capacity growth. Worthy of note is the fact that all of the Western-designed generation III+ reactors under construction in China – the French-designed EPR at Taishan and the AP1000 projects in Sanmen and Haiyang – have been connected to the grid. The pace of nuclear restarts in Japan has also picked up, with four reactors reconnected. However, the pace of global nuclear growth remains largely tied to China too, since the country has the largest capacity under construction globally. At present, there is only about 60 GW of nuclear capacity in construction worldwide. Although the relatively limited investments in nuclear energy globally are in part driven by local opposition and national policies, the technology is another victim of the conundrum currently facing the power industry. Platts Analytics’ long-term scenarios clearly show that the world will need more generating capacity, yet there is not enough investment in non-emitting (or even low-emitting) technologies. Current renewables and nuclear yearly additions could at most meet annual global power demand growth, but what about the gap opening up as a result of coal retirements? Even investments in flexibility appear to be lagging behind, with batteries accounting for only up to $1 billion/year, with less than 2 GW of batteries currently added each year. Reform of market design and the introduction of carbon pricing more widely across the globe could address some of these concerns going forward. The post Tracking global power capacity: Renewables growth outpaces fossil fuels appeared first on The Barrel Blog. from https://blogs.platts.com/2019/03/25/global-renewables-growth-outpaces-fossil-fuels/ Spring 2019 is ushering in important political changes that are being watched for their impact on oil and other commodities. In Algeria new leadership was promised recently, following widespread protests. That’s fuelled discussion about the future of the country’s oil and gas industry. Then on March 19, Kazakhstan’s president, Nursultan Nazarbayev, announced his resignation after nearly 30 years in power. The surprise announcement has similarly prompted questions about the direction oil and gas policy will take, after changes to tax legislation started to show signs of success in attracting new investment. Away from politics, Australian commodity producers and infrastructure operators were bracing for disruption as Cyclone Veronica headed towards Western Australia. Port Hedland and Port Dampier were cleared of commercial vessels, which could put a hold on iron ore exports for several days. Oil trade through both ports is also likely to be affected, as well as LNG, which is exported from Port Dampier. GRAPHIC OF THE WEEK Go deeper: Factbox on Kazakhstan’s commodity sector transformation VIDEO: LNG IN EUROPE European LNG Chronicles: The Russia question One year ago, markets were uncertain if Europe would, or even could, absorb the record levels of LNG forecast by Platts Analytics to be coming its way. Today, with total LNG imports into Northwest Europe more than doubling and expected to remain elevated through the rest of the year, Senior LNG Analyst Samer Mosis says the question is no longer if, but for how long Europe will be able to continue importing this level of LNG. WOMEN IN ENERGY AFPM: US refiners woo women to diversify workforce, add to bottom line Gender diversity – and what US refiners are doing to get there – was a main theme in this year’s annual meeting of refiner trade group, the American Fuel & Petrochemical Manufacturers, held in San Antonio. SHIPPING Sanctions push trans-Atlantic product freight to Venezuela to huge premium US sanctions on Venezuela are driving freight rates for clean oil products heading across the Atlantic to the country to enormous premiums, according to shipping reports. AGRICULTURE UK launch of E10 won’t be until 2021: government official The UK government will not be rolling out use of E10 gasoline before 2021, a representative of the Department for Transport said March 21. THE LAST WORD “There are vulnerable customers and France has shown us you need a social perspective. If we move too fast, and the transition is too costly you risk a backlash like the yellow vest movement.” – E.ON CEO, Johannes Teyssen, speaking about the challenges of decarbonizing heat systems at the Aurora Spring Forum in Oxford, March 19. The post Energy and commodities highlights: Political change in oil states, LNG in Europe, trans-Atlantic freight appeared first on The Barrel Blog. from https://blogs.platts.com/2019/03/22/highlights-political-change-lng-freight/ An impasse has emerged between key operators on the Houston Ship Channel, a critical lifeline for growing US energy exports, as thriving activity in both tanker and container shipping has exacerbated competition for space. Before August 2018, fog shutdowns were the main hindrance to ship traffic in and out of Houston, the second-largest petrochemical port in the world. However, that month the first container ship to exceed 1,100 feet in length traversed the 23-mile stretch between the entrance to the channel and one of the port’s two container terminals, facing no oncoming traffic, while outbound tankers were forced to sit and wait until it docked. It was the first of 10 such ships with length and width too large to safely allow two-way traffic. All ships normally flow freely toward each other in the channel and veer around one another in a carefully orchestrated move dubbed the “Texas Chicken” to maintain consistent two-way traffic. According to the Houston Pilots, who oversee ship traffic safety in the channel, the bigger container ships cannot safely veer around tankers because they essentially become 54% wider when at an angle. All other oncoming traffic – whether waiting to get in or leave the channel – must stand down for up to 10 hours or more until the container ship passes. For companies that load and unload crude, refined products and liquid chemicals – as well as those who produce natural gas liquids – such traffic interruptions resulting from container ship arrivals are unacceptable. They say it could jeopardize export growth and chill investment throughout the entire 52-mile-long channel to Galveston that is home to nearly 300 facilities, including refineries, chemical plants, storage tanks and support infrastructure like pipelines, rail, import/export terminals and trucks. “Reliable exports are absolutely critical to the energy value chain – and maintaining two-way traffic is essential to that reliability,” Enterprise Products Partners CEO Jim Teague told a Texas Senate committee in early March. Port officials concede the importance of two-way traffic and insist that larger container ships will not cause frequent interruptions because they expect only about 19 to arrive in 2019. However, that estimate could change. The port authority has also rejected proposals from liquids operators for a moratorium on larger container ships until all sides have more time to study the issue, and a limit of one per week because two could possibly show up at the same time. “We have container folks saying if we put a restriction on it, they’ll stop sending larger ships to Houston. That’s great for energy, but not necessarily for containers,” Both sides agree the ultimate solution is widening the of the 530-foot-wide channel to at least 750-800 feet to accommodate two-way traffic that includes larger container ships. However, such a project would likely cost billions of dollars and require Congress to provide federal funds – which can take years, if not decades. The US Army Corps of Engineers is in the fourth and last year of a $10 million study examining whether it would be feasible to deepen and widen the channel, but it could be just an incremental step in a years-long process while two-way traffic interruptions continue. Even if channel operators try to pool resources to widen the channel without federal funds, the Army Corps must first deem it a valid project, and it could take up to five years. Steve Kean, CEO of Kinder Morgan, said liquids operators need a solution now. “It’s a little bit like there’s a fire in the house,” Kean said. “We don’t want to let the entire house burn down before we do something about it.” So both sides are at impasse without a short-term solution that satisfies all, and the liquids operators have turned to the Texas Legislature to intervene. Multiple bills are pending that could limit or block arrivals of larger container ships, as well as address what the coalition sees as a conflict of interest with the port authority’s dual role as owner of the container terminals – benefiting from their cash flow – and regulator of the entire channel. Enterprise and Kinder Morgan, both major ship channel operators, with millions of barrels of liquids storage, export capabilities, pipelines and production facilities, are among 13 companies that banded together to form the Coalition for a Fair and Open Port, which wants certainty of consistent two-way traffic to ensure that all Houston Ship Channel exports can grow in tandem with onshore production growth. Campo agreed that uncertainty “kills business,” but said new laws could lead to unintended consequences from restrictions in the future, and port officials fear a moratorium could prompt bigger container ships to bypass Houston permanently. Growth all around Houston is the top US crude oil exporter, shipping out about 2.5 million b/d. The Energy Information Administration expects US crude production to average 12.3 million b/d in 2019 and 13 million b/d in 2020. Most of that growth will be in the vast Permian Basin in West Texas and Southeast New Mexico, where projected output of 3.9 million b/d in 2019 could double by 2025. The EIA also expects the US will be a net crude and petroleum product exporter by late 2020. “All that stuff needs to get from where it is to a place where it can get on a vessel,” Kean told the Texas Senate committee. “If the Permian doubles, we need the Houston Ship Channel to be able to take on more. There’s a conflict of interest when you have a port that is regulating us, but also is in business and competing for the scarce resources of access to the Houston Ship Channel.” The port also is the top US polyethylene resin exporter, alongside startups of more than 13.67 million mt in PE capacity from 2017-2027, more than 76% of which is or will be in Texas and Louisiana. Of the total, 23% is in operation – most of that at or near the ship channel. Both sides in the Houston Ship Channel dispute also have strong competition from other ports to handle growing crude and resin output. The Port of Corpus Christi has spent years marketing itself as an alternative to Houston for energy exports, highlighting its proximity to the Eagle Ford shale in South Texas as well as the Permian Basin. While the port exports less than 1 million b/d currently, Carlyle Group is investing $400 million in a project awaiting regulatory approval to deepen the Corpus Christi Ship Channel to accommodate Very Large Crude Carriers that can hold up to 2 million barrels of oil. Industry sources note that, unlike Houston, Corpus Christi offers primarily exports and few other options for crude. Houston offers exports, more storage and refineries, as well as pipelines that can move oil further east to plants in Beaumont and Port Arthur, Texas, and to Louisiana. Channel operators want to boost their export market share on the back of crude production growth, and they say they need consistent two-way traffic to do it. Container competition too On the container side, ports in Charleston, South Carolina; Savannah, Georgia; New Orleans and Los Angeles are enticing PE producers and traders to send some plastic pellets their way for export. Of 4.3 million mt PE exports in 2018, 2.67 million mt were waterborne, with most shipped out of Houston and those ports. Of volumes exported by these five, Houston’s share fell to 74% in 2018 from 87% in 2017 while flows from the other four showed gains, according to US International Trade Commission data. Houston exported 308,270 containers packed with resins and plastics in 2018 – nearly 30% of all containers and up 20.7% from 2017 – mostly on ships that did not disrupt two-way traffic, according to port data. And pressure has been on for Houston’s container terminals to compete. The port answered concerns about a lack of consistent empty container availability by soliciting more imports, bringing loaded import containers to parity with loaded exports. The competitors, particularly Los Angeles and ports on the East Coast, are primarily import centers and can accommodate even larger container ships, which are growing in size amid ocean carrier consolidation. “We know ultimately that we are going have more of those ships and we know ultimately we’re going to have more petrochemical exports and those exports are going to require bigger and more ships as well,” Campo said. Growth at stake However, the coalition contends that the vast majority of ship channel business involves liquids and natural gas, and those interests cannot be jeopardized by two-way traffic disruptions. In 2018, 71% of 18,790 ships that traversed the channel involved energy – 55% tankers, 10.5% natural gas and 5.6% barges. Of the rest, 11.1% were container ships, according to Houston Pilots data. The US’ recent shale boom sharply accelerated the channel’s importance to the emergence of the US as a global energy supplier. In 2011, the US started moving out more refined products than it consumed. The lifting of a decades-old domestic crude export ban in 2015 allowed US oil to flow freely into global markets. And seemingly boundless cheap feedstock ethane reversed the once-downtrodden US chemical industry’s fortunes, spurring tens of billions of dollars in new infrastructure to turn that overabundant feedstock into export-bound resins and other petrochemicals. But bottlenecks caused by larger container ships could send more outflows to competitors. “It’s the biggest sponge,” Enterprise’s Teague said. “You have water access through one of the most important waterways in the world – unless we screw it up.” The post Houston’s shipping bottleneck could curb expansion of major US oil and petchems hub appeared first on The Barrel Blog. from https://blogs.platts.com/2019/03/21/houston-shipping-bottleneck-oil-petchems/ Oil companies want to become power utilities to meet rising demand from electricity in transport and from growing populations. The strategy makes sense, but would also bring risks for regulators and consumers if it were to create a new breed of gigantic energy-controlling monopolies. On one hand, watchdogs in developed markets such as the UK should welcome the introduction of relatively new players like Shell and BP to challenge the Big Six conventional utilities. On the other, electricity markets are politically sensitive and oil majors would make easy targets for politicians keen to be seen protecting consumers if profits are put too far ahead of the public good. The Labour Party has threatened to nationalize parts of the electricity industry if it gains power in Britain. Meanwhile, regulator Ofgem was forced last year to introduce price caps to reduce household energy costs in response to political pressure. Introducing big oil into the debate could fan the flames. There is also the question of shareholder value for oil industry leaders to consider. Can Shell and other international oil majors afford to increase spending in their embryonic electricity businesses and still maintain adequate levels of expenditure on their conventional oil and gas divisions, which remain the main drivers of profits and investor returns? The decline in capital expenditure in new oil production has been flagged as a major concern for policymakers seeking stable crude prices. The world could require at least another 30 million barrels per day of new crude capacity by 2040 to meet demand, replace ageing reservoirs and keep prices affordable. Diverting capital into electricity markets could be a distraction. Despite these concerns, international oil companies such as Shell are ramping up their investments in electricity. The largest international oil major in Europe expects the market for power to be the fastest growing area of the energy industry as pressure builds to cut global pollution and carbon emissions, according to a recent Bloomberg television interview by Shell executive committee member Maarten Wetselaar. “We believe we can be the largest electricity power company in the world in the early 2030s, because this part of the energy system is going to be the thing that grows fastest,” said Wetselaar, who also heads up Shell’s gas and new energies division. Wetselaar’s vision is understandable given the rapid growth in electric vehicles (EVs). S&P Global Platts Analytics forecasts that plug-in EVs – including rechargeable hybrids – will account for nearly half of global auto sales by 2040, displacing some oil demand as a transport fuel and expanding the role of the electricity sector. Shell has said it plans to avoid investing in conventional transmission and power station assets to focus instead on distributed renewables and supply, making its goal to become number one in the power sector a complex and risky bet on emerging technologies and markets. The company beefed up its UK electricity supply business by buying First Utility in late 2017. It has since struggled to compete with cheaper start-ups in a fiercely competitive market that has seen a slew of supplier bankruptcies in recent months. Energy majors in new battleground To become the world’s biggest renewable generator, meanwhile, would require an annual expenditure in the region of $2 billion initially, according to a report by S&P Global Platts. By comparison, Spain’s Iberdrola – a European sector leader – ploughed over $5 billion into green power generation growth last year. Iberdrola has 29 GW of renewable electricity capacity installed worldwide. Shell has 1.6 GW of solar and will have 5 GW of wind on completion of committed investments. And Shell isn’t alone in wanting to forge into these new markets. BP claims it is now generating enough power from wind renewables to feed 400,000 homes. Meanwhile, some international oil companies are being even more aggressive, posing a direct challenge to incumbent conventional utilities in their domestic markets. In France, Total recently acquired Direct Energie. The deal pits it against the state-owned market giant EDF. By 2022, Total aims to be supplying electricity to 6 million customers in France and 1 million in Belgium. However, utilities can’t match the financial muscle of big oil. NextEra Energy, the world’s biggest renewable generator in the US, had a turnover of around $17 billion last year, which is less than Shell made in actual profits over the same period. Gobbling up rivals in the power sector is relatively cheap when armed with an oil company’s gigantic balance sheet. Globally, it’s not just international oil majors going electric. State-owned fossil fuel producers are increasingly looking at the sector for growth. Saudi policymakers have for the last decade harboured dreams of the kingdom being the biggest exporter of solar-generated electricity in addition to crude oil. Elsewhere in the oil-rich Gulf, petrodollar sheikhdoms are pumping billions into renewables. US oil companies are also coming under more pressure to diversify. Rising star US Congresswoman Alexandria Ocasio-Cortez has America’s most powerful business lobby in her sights. Ocasio-Cortez wants 100% of the country’s power to come from renewables and fossil fuels to be phased out in the world’s biggest economy, in just a decade. In its defence, big oil is stressing that EVs are no magic bullet for climate change and won’t spell the end of petroleum. EVs still account for a small share of the total global passenger vehicle fleet. Global sales of light duty plug-in EVs saw double-digit year-on-year growth in January, but still only totalled 155,000 units, according to the latest S&P Global Platts Analytics monthly report. Of course, declines in consumption by motorists will be compensated by growth in petrochemicals and industrial transport like shipping. Rapidly growing developing economies in Asia will also increasingly play a more important role in supporting crude demand. In tilting from hydrocarbons to electrons, oil companies will have to find a balance between serving their fossil fuel past while investing in their electric future. This article previously appeared as a column in The Telegraph The post Big oil’s electric dreams could create new energy cartels appeared first on The Barrel Blog. from https://blogs.platts.com/2019/03/20/big-oil-companies-electric-dreams-energy/ Louisiana Offshore Oil Port continues to load on average one VLCC crude tanker per month for export and logged its third such export of the year late last week. The 2 million barrel-capacity VLCC Dilam loaded at LOOP and set sail for South Korea on Wednesday, according to cFlow, Platts trade flow software. Dilam marks the third VLCC export from LOOP so far this year. All of the LOOP-loaded tankers have been taken to South Korea. New Caesar departed LOOP on February 1 and was observed in South China Sea on Monday. The tanker is expected to arrive at the Port of Yeosu in South Korea on March 26. The 2 million barrel-capacity Amad set sail from LOOP on January 6 and also made a trip to the Far East. The vessels’ destination of Yeosu is home to the 785,000 b/d GS Caltex refinery, which runs mainly light and medium sour crudes. South Korea continues to be a popular destination for US crudes. The country has taken on average, 2 million barrels/week during the past five weeks, according to Platts data. LOOP, which is only facility in the US that can directly load a VLCC without using ship-to-ship transfers, first started exporting crude on VLCCs in February 2018. The facility averaged loading about one tanker a month for the remainder of the year. Go deeper: On the heels of CERAWeek, Capital Crude podcast dives into the biggest topics in US oil LOOP exported 1.94 million barrels of crude oil in February 2018, which was the first month of LOOP exports, according to data from the state of Louisiana. In December, the most recent month for which data is available, LOOP exported about a record-high 6 million barrels. That same month LOOP reported loading three VLCCs. US crude exports have exploded in the past year, reaching or exceeding 3 million b/d twice in 2018. US crude exports reached a record high of 3.6 million b/d for the week ending February 15 and the four-week crude export average is about 3 million b/d, according to data from the Energy Information Administration. The US exported around 2.3 million b/d for the week ending March 15, according to S&P Global Analytics. The post In the LOOP: Third VLCC of the year departs Louisiana, bound for South Korea appeared first on The Barrel Blog. from https://blogs.platts.com/2019/03/19/loop-third-vlcc-crude-tanker-departs/ Trade in polyethylene resin and finished products slowed in the fourth quarter of 2018, becoming a casualty of the US-China trade war. Last year, the Trump Administration launched a full-scale trade war with China, imposing three rounds of tariffs worth a cumulative $250 billion on Chinese products. The move was intended to counter China’s practice of requiring US companies to turn over intellectual property as a condition for gaining access to the world’s second-largest economy. China responded with $110 billion in tariffs on US products, also in three rounds, signaling a commitment to protecting its interests and economic growth. The petrochemical-heavy second and third rounds of these tariffs came as the US chemical industry started up the first wave of more than $200 billion in new and planned infrastructure. US gas boom drives petchems ramp-up This industrial build-up emerged from the domestic natural gas boom and its seemingly endless bounty of cheap feedstock, namely ethane. That feedstock advantage, shared only by the Middle East, prompted chemical producers to turn the US into a global supplier of raw materials and resins. Asia, and more specifically China, were the target markets, given the region’s projected demand growth that far surpasses the rest of the globe. Much of the new US chemical infrastructure focuses on making polyethylene, a precursor to the most-used plastics in the world. Natural gas transmission pipes, opaque milk jugs, toys, grocery bags, buckets, cookie packaging and cellophane wrapped around meat at the grocery store are among the hundreds of products made with PE. Accordingly, PE manufacture dominates the petrochemical infrastructure currently starting up, under construction or planned in the US. China originally announced in 2018 that its tariffs would target low density polyethylene (LDPE), which makes up about 7% of 13.7 million mt/year of new PE US production that is operational, under construction or planned from 2017-2027. However, China replaced LDPE with linear low density (LLDPE) and high density PE (HDPE) shortly before imposing its retaliatory tariffs in August. Those grades make up more than 90% of that new US output, 29% of which is operational – suddenly making it a significant concern to US producers. Overall, US PE exports reached a record 4.3 million mt in 2018, up more than 24% from 2017, US International Trade Commission data shows. The share sent to China declined while some flows shifted to other markets, notably Europe and Vietnam. Go deeper: S&P Global Platts Americas petrochemicals outlook H1 2019 Chinese Customs data show China’s Q4 2018 imports of US-origin PE resin nosedived 57% to 98,000 mt compared with the third quarter, with new inflows seen from Saudi Arabia, UAE, Taiwan and Singapore, according to China customs. Total PE imports to China in Q4 actually rose 0.5% to 3.8 million mt from Q3, according to the data. Data from Chinese firms who typically imports large quantities of US PE details this pullback. Tetra Pak Hohhot, part of the multinational food and beverage packaging company Tetra Pak, saw its LLDPE resin imports from the US drop by 74% to about 600 mt in Q4 compared with Q3, as compared with its overall LLDPE resin imports, which fell 26%. Weihai Lianqiao International, a textiles and garments company that lists US stores such as Walmart, Forever 21 and Macy’s on its website as clients, saw its US-origin HDPE resin imports fall by 93% to about 400 mt in Q4 compared with Q3, while its overall HDPE imports fell by about half. This does not mean China has stopped buying PE from US companies altogether. US PE producers with global footprints have the option to reroute supply from their international operations. DowDupont, for example, can supply Asia from its Canadian assets as well as its Sadara joint venture in Saudi Arabia. ExxonMobil also can supply China via its Singapore operations, minimizing tariff fallout. Bag trade blighted Meanwhile, China’s petrochemical finished goods products were caught in the middle of the trade tensions as well. US imports of Chinese PE bags and sacks began declining last September, targeted by the US’ $200 billion in tariffs implemented the same month. These imports fell 19% in Q4 2018 from Q3, according the data, reversing 2017 year-on-year growth of 35%, according supply chain data from Panjiva. The growth decline is accelerating in 2019, with import figures plunging 38% in January and 45% in February compared with same month last year, according to the data. The chief fallout from ongoing trade tensions between the US and China is uncertainty. No one knows how long tariffs will last. Building a new plant can take up to five years from initial planning to startup, and companies make such investments based on long-term forecasts of supply and demand, not market volatility or geopolitics. Tariffs could be gone by the time a plant under construction in 2019 starts up in 2021 – or by the time one starts up in late 2019. In addition, changing long-established supply chains can take up to 18 months or more, to conduct due diligence for quality control before a the arrival of a new supplier’s first shipment of key ingredients, for anything from medicines and cosmetics to flame retardants or packaging. That complex, expensive process could be rendered moot if the tariffs are suddenly lifted. Conversely, if the trade war drags on, China could keep finding alternate sources for raw materials and plastics, siphoning market share that the US may not be able to retrieve – just as the shale revolution is offering it a competitive edge. The post Tariffs frustrate US-China trade in plastic resins and finished products appeared first on The Barrel Blog. from https://blogs.platts.com/2019/03/19/tariffs-us-china-trade-war-plastic/ |
About MeHi I am Robert Keasler 35 years old, I am mine Engineer currently attached with local petroleum exploration company. In free time mostly search for some better opportunity online. ArchivesNo Archives Categories |