North Asian refiners are set to test a new US crude oil grade that some have touted could be a replacement for Iranian barrels, traders said.
Samples of US West Texas Light crude or WTL, which has an API of between 45 and 55, were heard to have been sent out to North Asian refiners, they added. Depending on results, and global appetite, the US Gulf Coast will be exporting many more cargoes of WTL in the future.
WTL is the name for production in the Permian basin that exceeds the API spec range for a barrel of West Texas Intermediate delivered at the Magellan East Houston (MEH) Terminal at the Gulf Coast. A barrel of traditional WTI typically ranges between 38-44 API and the BridgeTex and Longhorn pipelines cap WTI specifications at 44 API.
However, as new production in the Delaware section of the Permian Basin ramps up, the overall quality of domestic crude is getting lighter and sweeter and the opportunity to begin marketing the lighter crude coming out of the Permian has evolved.
“This crude can be considered for both splitter and CDU and it could be an alternative for Iran [barrels] with the US sanctions,” said a trader with a South Korean refinery.
South Korea is among eight countries to have been granted a 180-day waiver by the US to the sanctions on Iran last November, enabling them to continue to import Iranian oil through May 4.
South Korean companies looking to procure cargoes after this period have to seek replacement barrels elsewhere until further clarity is given on whether there will be an extension.
Some market sources in Asia, however, have noted that the uncertainty around the API of the crude would mean that it is unlikely suitable for condensate splitters, which typically process condensates with an API of over 55.
“The API gap is wide, and I don’t think it can be directly replaceable for condensates,” said another trader. Iran’s South Pars condensate, a favorite of many Northeast Asian condensate splitters, has an API of 61.6, while Australia’s North West Shelf condensate, Asia’s most liquid condensate grade, has an API of 63.
However, the US and Australia are producing slightly “heavier condensates” that could possibly substitute for Iranian barrels. Asian buyers have been familiarizing themselves with this “heavier” condensate and some companies have cited plant modifications to run heavier feedstocks coming out of the US and Australia.
South Korea has already emerged as a major buyer of US crude, and that is expected to continue. According to the US Energy Information Administration, South Korea is the second-largest importer of US crude behind Canada and has outpaced China’s imports of US crude. South Korea took 86.15 million barrels of US crude in 2018, compared to about 64 million barrels in 2017 and 39 million barrels in 2016.
Lighter, sweeter US crude
In the Delaware, the percentage of WTL has remained fairly constant over the past five years, averaging about 25% of overall production, according to S&P Global Platts Analytics. After combining production from the different parts of the basin together, WTL likely made up 6%-10% of the nearly 4 million b/d Permian production during 2018.
While the percentage of WTL production is still rather small, it is expected that more of the grade will soon begin to hit the market. As new and expanded pipelines begin to come online later this year and into next, there will be added takeaway capacity and the ability to begin batching separate crude qualities that are flowing form the Permian.
Most of that new flow will be piped directly from the Permian Basin to the US Gulf Coast, where it can be consumed by domestic refineries or condensate splitters. However, much will be exported. The ability to batch certain quality bands straight to the water for export will allow global refiners to select certain barrels that best meet their needs.
WTL has been heard priced at a $1.50/b discount of WTI Midland in the Permian Basin. Sources said that they have yet to see if that discount is carried down to the Gulf Coast. One crude trader said he expects that WTL’s “new crude” discount will eventually shrink as more refiners test and become familiar with it, but it is expected to remain at slight discount to WTI at the Gulf Coast.
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Saudi Aramco is by far the most profitable company on the planet and produces more oil than any other single entity, but there are still doubts about the viability of its stalled initial public offering.
The problem for Aramco is that its weaknesses are as obvious as its strengths.
Riyadh’s dream of raising $100 billion by selling a 5% stake in the state-owned oil giant had seemed entirely dead until the company opened its books.
Just over a week ago, Aramco gave a rare glimpse into its financial treasure chest and revealed a pot of gold, which has reawakened interest in its potential listing. At $224 billion, its earnings before interest, tax, depreciation and amortization are three times the size of Apple.
The $111 billion the company made in net profit last year makes it bigger in sheer earnings power than ExxonMobil, Shell and BP combined.
Financial analysts and bankers may still question the lofty valuation of $2 trillion desired by Saudi Arabia’s Crown Prince Mohammed bin Salman, but they can no longer question Aramco ’s gigantic balance sheet.
At the wellhead, Aramco is also insanely efficient when compared to international oil companies.
According to this week’s disclosure, it is producing crude for as little as $3/b, compared with around $40/b in the North Sea. The company also has no shortage of black gold to produce. Its daily capacity can reach 12.5 million barrels in a total global oil market of around 100 million b/d.
Saudi Arabia’s oil reserves, which it has almost exclusive access to, are also vast.
The country holds over 263 billion barrels of proven oil underground. Compare this to Britain, which is down to its last 20 billion barrels as it squeezes every last drop from the North Sea.
There is also no shortage of buyers for Saudi Arabia’s crude, despite the rise of US shale and growing buzz around electric vehicles. World oil demand averaged 100 million b/d last year, and even the glummest forecasts see this trend continuing to at least 2040.
Although Saudi has lost ground in the US, it has increasingly focused on China and India, where demand for hydrocarbons is growing at a faster clip.
Aramco is not just about pumping oil. It is buying petrochemicals giant SABIC from the Saudi government for almost $70 billion, giving it a dominant position in the global supply chain for plastics . The company’s executives are embarking on a global roadshow of meetings with bankers to raise debt for the deal, which welds Aramco’s future to Asia’s giant manufacturing economies.
“With petrochemicals demand expected to grow faster than traditional refined products, such as transportation fuels, both IOCs [international oil companies] and NOCs [national oil companies] are likely to continue to invest in petrochemical infrastructure to diversify their portfolios and align their long-term financial prospects with anticipated product demand,” said Jennifer Van Dinter, global head of petrochemicals at S&P Global Platts Analytics.
But despite all these strengths, Aramco is potentially a risk for investors.
The international financial community’s nerves have been shaken by the kingdom’s response to the alleged assassination last year of dissident journalist Jamal Khashoggi. His death followed a year of turmoil and intrigue in Riyadh after the crown prince ordered the arrest of hundreds of his own family in a sweeping corruption probe.
Mohammed bin Salman is the architect of Aramco’s IPO plan. He wishes to use the proceeds from the sale to fund ambitious economic development plans to diversify the kingdom’s economy away from oil. However, his alleged role in the Khashoggi scandal and rapid rise as heir apparent to the Saudi crown has caused anxiety both within the kingdom and outside.
All this uncertainty has fed doubts about the long-term plan for Aramco.
Oil companies have also become less appealing to institutional investors. Norway’s $1 trillion sovereign wealth fund said last month it would divest its holdings in oil and gas explorers, excluding BP and Shell due to their sizeable renewable energy divisions.
Despite the size of its earnings, Aramco is a hard sell with funds that are increasingly weighing environmental, social and governance (ESG) in their investment decisions.
Then there is the issue of Aramco’s independence and its inextricable link to the kingdom’s oil policies.
As the de-facto leader of OPEC , Saudi Arabia is bearing the brunt of US President Donald Trump’s complaints about oil prices climbing too high for the global economy to take. Prices are now pushing $70/b after the cartel and its allies, led by Russia, have continued to hold back supplies despite warnings of damaging global growth.
Accounting for about a third of OPEC’s total production, Aramco could easily find itself at the center of any future political storms surrounding the cartel’s policies. The group could still be effectively outlawed by US politicians if so-called “NOPEC” legislation is passed.
Support for the bill is mixed, but made law, it could make Aramco look too toxic for squeamish Wall Street investors to touch.
Despite these worries, money talks. Aramco’s recent bond prospectus disclosure proves the company has no shortage of cash, but that won’t necessarily be enough to win the hearts and minds of increasingly picky investors.
This article previously appeared as a column in The Telegraph
The post Saudi Aramco’s riches disguise its risks: Fuel for Thought appeared first on The Barrel Blog.
Oil markets had their eyes trained on North African politics this week, and developments in Libya and Algeria in particular.
Algerian President Abdelaziz Bouteflika’s resignation on April 2 threw the state’s long-delayed oil and gas reforms into doubt. Bouteflika had just a few days earlier appointed Algeria’s fourth energy minister in three years.
In Libya, eastern military leader General Khalifa Haftar looked to be pushing for greater control over the country, adding to other supply-side concerns that have recently driven sentiment in crude oil markets.
Further south in the continent, industry members gathered in Malabo, Equatorial Guinea, for the APPO Cape VII conference. At the event, OPEC’s secretary general said the group and its allies would not ease recent output cuts despite recent price increases.
GRAPHIC OF THE WEEK
The aging US coal fleet is being squeezed from all sides, with policy, cheap domestic gas supply and developments in clean energy generation all contributing to fast-paced closures. S&P Global Platts Analytics data show that since peaking at 317 GW at the end of 2011, US generating capacity with coal as the primary fuel fell by 73 GW, or 23%.
PODCAST: BIG THEMES IN AMERICAS CRUDE AND PRODUCTS
S&P Global Platts oil market editors Seth Clare, Laura Huchzermeyer, Maria Eugenia Garcia and Daron Jones discuss the most talked about topics at the American Fuel and Petrochemical Manufacturers’ Annual Meeting in San Antonio, one of the largest energy industry events in the US.
Topics include a new grade of US crude oil, challenges in Venezuela, the US-Mexico jet fuel relationship, and two fires that erupted near Houston during AFPM.
The automotive sector could be the main driver of any recovery in steel demand in Brazil if the construction sector does not pick up, said Diego Ocampo of S&P Global Ratings.
OIL AND PETCHEMS
A new breed of plastic recycling plants capable of recovering crude and fuels from plastic waste is piling more pressure on global oil demand forecasts. The growing backlash against single-use plastics has seen a number of companies looking to launch these new plants at commercial scale.
China’s mine safety watchdog ordered inspections at “high risk” mines after recent industry accidents, stoking fears that thermal coal availability might be affected in the near term. The checks will start with immediate effect and run until June.
Corn planting in some areas of the US is likely to be delayed after recent floods led to saturated fields, but the effect on the market will be limited because of plentiful carryover stocks, sources said.
THE LAST WORD
“No one has the right answer as to which fuel to use. Look for where you need fuels for your particular ships. Pick for individual vessels. Companies that pick the right fuel will win.”
– John LaRese of ExxonMobil Marine Fuels, on the conundrum facing bunker buyers as IMO 2020 nears.
The post Energy and commodities highlights: Algerian politics, Brazilian autos and plastics-to-fuel tech appeared first on The Barrel Blog.
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. In this last post of the series, Steve Piper analyzes S&P Global Market Intelligence data to show that renewables are increasingly able to compete with conventional generation.
Wind and solar photovoltaic (PV) electric facilities only account for an estimated 11% of US generation, but they are fast closing on a tipping point where they may outperform conventional generation as an asset class.
Several factors have come together to drive this result, starting with a rapid decline in costs for new renewable facilities, both wind and solar, that has offset the advantage to natural gas generation brought about by abundant and economical supply.
Improved efficiency of renewables also means every facility can generate more power, delivering greater value and revenue to the off-takers. Declining cost and increased output drives a cycle of improving competitiveness and returns when compared to conventional generation.
Supportive economic policies such as Investment Tax Credits (ITC) and tradeable Renewable Energy Certificates (RECs) also provide a source of financial support to green energy, although both are expected to be reduced in the future.
Finally, the progressive restructuring of wholesale electricity markets, while traditionally viewed as providing principal support to conventional merchant generation, has also facilitated the spread of green energy. It has enabled multiple points of interconnection, and broad integration of both the green electricity markets and the markets for their environmental attributes.
The ability to plug into the grid and realize a backstop price and secure marker for value, at a time when per-MWh costs of production are falling, has further allowed renewable projects to proliferate. S&P Global Market Intelligence has examined the revenue generation attributes of wind, solar, and natural gas generation across three major US investment markets to illustrate the respective drivers of value as well as the enormous potential for green energy to disrupt generating fleets well into the future.
Federal subsidy phase-out
Federal subsidies for renewable energy have fluctuated in recent years, with current law phasing subsidies out over the next two years. The current landscape for federal renewable incentives is as follows:
The lapse of federal subsidies will drive up the effective cost of wind and solar facilities beginning in 2021-2022, although some of this increased cost will be offset by falling costs on installation and technology improvements that boost output. Unlike in Western Europe, only about 25% of US electric load in California and the Northeast is subject to taxes on CO2 emissions, and the Northeast program is directed solely to electric sector emissions.
Instead, states increasingly focus on mandates to expand zero carbon generation. In 2018 California followed Hawaii’s lead to mandate 60% of electricity come from renewables by 2030, with a 2045 goal of 100% carbon emissions-free generation.
Many Western US states are introducing similar targets, with Arizona and Nevada pushing a 50% target by 2030. In the East, New York recently issued an executive order bumping its 2030 target from 50% to 70%.
The emphasis on mandates over prior tools such as Renewable Energy Certificates (RECs) and tradeable carbon emission credits reflects a growing consensus on commitment to the infrastructure aspects of the US generating fleet transition, much of which is expressed in early congressional proposals for the “Green New Deal”.
The charts below present 10-year forecast merchant development returns to natural gas, wind, and solar PV in three key US markets: the Electric Reliability Council of Texas (ERCOT); the PJM Interconnection (PJM), and the California Independent System Operator (CAISO). As a whole, low load growth and generation oversupply ensures that none of these asset classes is forecast to achieve a full return (estimated at 9.7%). What is noteworthy, however, is the relative consistency of returns to all classes and the narrowing of spreads between renewable asset classes and new natural gas plants.
ERCOT: King of the hill in energy
If you were going to choose a market with the best odds of success for a natural gas power plant, you could hardly do better than Texas, where industrial-zoned land is cheap, electricity demand is growing, older coal plants have retired, and natural gas produced here may just be the lowest-cost on the planet.
Thanks to burgeoning unconventional oil production, especially that coming out of West Texas, the supply of natural gas that comes along for the ride has expanded faster than generators (or anyone else) can use it. But Texas is also blessed with high levels of wind, be it from the wide flat plains of the West or from the steady coastal breezes. Texas is also at a favorable latitude for solar resource. Furthermore, the Electric Reliability Council of Texas (ERCOT) market only pays for peak generating capacity on an hour-to-hour basis, a situation independent merchant power developers have long decried. With last year’s improvement in prices, Market Intelligence estimates spark spreads sufficient to deliver returns to generation equity owners this summer, with growth into the future as the market stays tight on generation.
Compare the struggle for returns of a gas-fired combined-cycle (CCGT) plant in ERCOT to a new solar facility. Although solar facilities can’t avail themselves of hour-to-hour capacity payments, solar PV drives value during the peak times of the day, receiving arbitrage between the fluctuating price of coal and natural gas and their own marginal cost of zero. Solar PV plants also receive at least a nominal contribution from ERCOT’s REC market. While low power prices in ERCOT mean solar PV owners must accept less than a full 9-10% return on capital, Market Intelligence estimates superior returns to solar than those for natural gas.
Wind clean spreads look better still. With modern wind turbines operating close to 45% of the year, the long-cited deficiency in summer peak contribution becomes less relevant. Wind captures more value in winter months than solar PV does, driving a higher overall estimated return.
Pennsylvania: Renewables close in on gas
If the Permian Basin of West Texas produces the cheapest natural gas on the planet, the Marcellus Shale centered in western Pennsylvania, eastern Ohio, and West Virginia may come in a close second. Combined with a more stable revenue stream for generating capacity via the PJM Interconnection’s capacity auctions, this region has been targeted for merchant CCGT investment.
Market Intelligence estimates 16.7 GW of new CCGT capacity will come on-line 2018- 2020, offsetting the impact of recently retired coal and nuclear capacity. Together with a robust capacity payment, Market Intelligence estimates that a new CCGT will generate a solid return, exceeding that of ERCOT gas plants, over the next 10 years.
But states in the PJM region also support renewable facilities, using Renewable Portfolio Standards (RPS) backed by tradeable RECs. Utilities in Pennsylvania, Maryland, and New Jersey in particular can contract with green facilities or purchase RECs created by a facility potentially anywhere within PJM’s 14-state footprint. As in ERCOT, typical wind plants in PJM generate substantial value for their owners, with REC contributions driving comparable returns for wind compared to those estimated for a natural gas plant.
California: Gas out of favour
In efforts to modernize its natural gas generation fleet, California has mandated replacement of once-through cooling systems with zero-discharge water towers. Many plants are instead opting to decommission. At the same time, the aggressive build out, especially of solar PV, both distributed and wholesale, has depressed power prices substantially and will continue to do so.
This is essentially the wholesale price version of the infamous ‘duck curve’ for hourly load, resulting in very low prices when solar PV generation is highest. As a result, a new CCGT stands out as a higher-performing asset in our forecast than wind or solar, as the state’s enthusiasm for these resources saturates the market. Importantly, however, the hourly wholesale electricity market supported by CAISO has expanded to cover multiple states of the Western US, allowing developers to site plants in areas less picked-over and still serve California’s RPS standard. While total returns in California appear low, stronger returns are achievable elsewhere in the Western US.
Bottom line: Tilting towards renewables
The revolution in US shale gas seemed destined to drive most future generation investment toward natural gas power plants. And indeed it did – for a few years. As costs have fallen for wind and solar PV facilities, Market Intelligence forecasts indicate returns are converging with new natural gas, even in markets where natural gas competes best.
This begs an important question: how competitive is green electricity today in parts of the world where fossil supplies are lagging? With just modest additional improvements in technology, we could see capital begin to tilt even further towards renewable energy, and further away from conventional generation.
The post Forward spark spreads suggest rising profitability of US renewables as sector matures appeared first on The Barrel Blog.
Russia’s planned 55 Bcm/year Nord Stream 2 gas link to Germany has prompted heated political debates, changes in EU law and threats of US sanctions, but its fate in the end may be decided by Danish civil servants enforcing local planning rules.
The latest development is that the Danish Energy Agency has asked the Nord Stream 2 project company to provide information on a third possible route for the Danish section of the two 1,200 km parallel pipelines, while it is still assessing two pending permit requests for other routes.
The problem for Nord Stream 2 is that it cannot complete the pipe-laying without a permit from Denmark, and there is no legal deadline for approving or rejecting such permits, creating uncertainty about when gas will start flowing through it.
The project company wants to bring Nord Stream 2 online by the end of this year, before Russian gas pipeline export monopoly, Gazprom, reaches the expiry of its transit contract to Europe with Ukraine’s Naftogaz. Gazprom has not said yet what it will do if that date slips.
Naftogaz officials have said Gazprom could meet its minimum contractual commitments to European customers without Nord Stream 2 or Ukrainian transit from January 1, 2020, as long as its 31.5 Bcm/year Turk Stream pipeline to Turkey starts by the end of this year as expected. That could see European gas prices spike in 2020, as customers make up any shortfall from storage and more expensive LNG sources.
But the more likely outcome, according to Naftogaz CEO Andriy Kobolyev, is that Gazprom will continue to use the Ukrainian route during any Nord Stream 2 delay. Gazprom sent 87 Bcm through Ukraine to Europe in 2018, and has said these volumes would likely drop to less than 20 Bcm/year once Nord Stream 2 and Turk Stream are available.
The European Commission and Naftogaz are keen for Gazprom to sign a long-term capacity commitment for the Ukrainian route after 2019 at volumes high enough to keep it viable. EC vice president for energy union Maros Sefcovic has reportedly suggested Gazprom commit to a minimum 60 Bcm/year capacity contract for 10 years, on a ship or pay basis, with Naftogaz ensuring another 30 Bcm/year capacity is available to cover any short-term extra needs.
But Gazprom and Naftogaz are locked in a protracted legal dispute over the current transit contract that will not be resolved till the middle of 2020 at the earliest. Gazprom has said it will not sign new terms before that dispute is resolved.
That approach works for Gazprom as long as Nord Stream 2 comes online by the end of the year. Everything that puts that in doubt – such as uncertainty over when Denmark will grant the permit – puts pressure on Gazprom to come to the negotiating table to agree new transit terms before the end of this year.
Kobolyev has said Gazprom could also book short-term entry and exit capacity, for example for a year, under Ukraine’s current tariffs and capacity booking products. Such short-term tariffs would be higher than those possible with a long-term contract, he said.
Nord Stream 2 already has all the other planning permits it needs from Finland, Germany, Russia and Sweden on its route across the Baltic Sea, and it has laid more than 800 km of pipe. The project company has said the Danish section can be filled in last if needed, so the project could stay on schedule even if the final permit is not granted until August.
Gazprom’s gas sales to Europe are on the rise, meanwhile, despite stable European gas demand. Sales hit a record 201 Bcm in 2018, using Russian measurements, as lower domestic European output boosted demand for imports.
The US continues to warn Europe against becoming more dependent on Russian gas, even while recognizing that it is currently cheaper than the alternatives, including US LNG. It is also a consistent, vocal critic of Nord Stream 2 for the negative impact it will have on Ukraine’s Russian gas transit revenues.
The EC sympathizes with the US view on Nord Stream 2, but there is no legal way to stop the pipeline being built as long as the project company complies with all EU rules. The US President has the power to impose financial sanctions on the companies helping to build Nord Stream 2, which could disrupt or delay the project, but the current incumbent, Donald Trump, has shown no sign of using them.
Meanwhile, the EC has been courting the US and its potential to increase LNG exports to Europe. It is planning a high-level EU-US industry meeting on May 2 in Brussels to discuss “competitive pricing,” among other things, with US secretary for energy Rick Perry due to give a keynote address.
But LNG imports from the US remain tiny compared with Russian pipeline gas, at just 3.3 Bcm in 2018, or less than 1% of total EU gas demand. The EC wants this to more than double to at least 8 Bcm/year over the next four years, and European demand for US LNG is growing rapidly – but from a very low base.
For example, US LNG exports to Europe, including Turkey, surged 75% on the year in February to 411.5 million cubic meters, but were still eclipsed by Russian LNG exports of 1.4 Bcm, up 67%, according to S&P Global Platts Analytics data.
The post Insight from Brussels: Start of Russian gas flow via Nord Stream 2 hangs on Danish permit appeared first on The Barrel Blog.
Mexico’s new president Andres Manuel Lopez Obrador, popularly known as AMLO, has said there will be no fracking during his six-year term, igniting a debate about Mexico’s energy security amid rising gas consumption. But mixed signals on the issue have emerged from elsewhere in the government.
So what is all the fuss about? Saying no to fracking will mean leaving more than half of Mexico’s total natural gas reserves in the ground. This could be risky for Mexico, since the country’s natural gas production has fallen dramatically in recent years, descending to 2.6-2.7 Bcf/d in 2018 from a historical high of 5.1 Bcf/d in 2010, according to S&P Global Platts Analytics.
The decline in production coincided with rising domestic gas consumption off the back of growing gas-fired power generation, new factories, and favorable gas prices in the US. This combination of factors has caused a rapid increase in natural gas imports from the US through pipelines and as LNG.
Mexico’s gas imports now account for more than 70% of total demand. Pipeline flows amounted to around 4.2-4.5 Bcf/d in 2018, but insufficient pipeline infrastructure amid surging demand has led Mexico to become the second-largest buyer of US LNG, taking around 19% of the overall LNG exports from the country.
This growing reliance on imported natural gas from the US is fueling a debate on self-sufficiency goals, and energy security. Mexico is one of the few countries in the world that depend on a single other state for gas imports. That leaves its energy supply heavily exposed to US export strategy. What would happen if the US decided to liquefy more of its natural gas and sell it to other countries that pay more than Mexico?
Fracking could yield significant domestic gas output, alleviating the country’s dependence on natural gas imports. The technique dramatically altered the US energy balance, taking it from a country heavily reliant on the Middle East for its energy needs, to an oil and gas powerhouse. Oil production in 2018 reached around 11 billion b/d, and natural gas production reached 16.86 Tcf in 2017, a 39% increase over the last decade, according to the US Energy Information Administration. Furthermore, the US hydrocarbon bonanza has helped reduce energy prices, saving consumers billions of dollars and spurring economic growth.
In Mexico, fracking has been used for more than half a century, and has been applied to about one in five conventional oil and gas wells, according to former energy secretary, Pedro Joaquin Coldwell. This year, there were plans to start applying the technique in unconventional basins. However, AMLO cancelled a bidding round scheduled for February 2019, which involved nine unconventional onshore blocks.
Without the use of fracking for shale gas extraction, hydrocarbon production will depend on the country’s conventional basins. According to the National Hydrocarbons Commission (CNH), more than 50% of Mexico’s gas reserves are in non-conventional resources, and the only way to extract them is by hydraulic fracturing.
Furthermore, Mexico ranks sixth worldwide in volume of unconventional resources. It is estimated that the hydrocarbons contained in shale across all the oil provinces of the country are equivalent to 4.1 times the total historical production of oil and gas of the mega deposit Cantarell, according to Coldwell.
But despite AMLO’s blunt fracking ban, there is a twist: Pemex, the state oil and gas company, contemplates investing in fracking in its 2019 budget, devoting about Mexican Peso 3.8 billion to evaluating multiple areas with oil and shale gas. Additionally, the Energy Secretary, Rocio Nahle, mentioned in early 2019 that this government will use fracking, though she was careful to emphasize that she was not advocating a free-for-all. Strict conditions would apply, she said, including the use of the most modern and environmentally-friendly technology.
Furthermore, in February, CNH approved Pemex’s plan to test shale potential in up to eight exploratory natural gas wells in northwest Veracruz. This suggests the new administration has no clear position on fracking, and it is watching to see what happens with the exploratory wells to inform its next steps.
Politics aside, there are other obstacles to producing shale gas in Mexico. Firstly, there are the environmental concerns about water use, air and groundwater pollution and earthquakes that have drawn opposition to fracking in Mexico just as they have in other countries including the US.
There are also challenges more specific to Mexico, of land holding and mineral rights; a lack of knowledge on unconventional resource geology; a small service industry; a poor regulatory framework; lack of pipelines; and security issues.
Meanwhile, given the efficiency and abundance of US shale gas plays, and the resulting low prices, Mexico faces stiff competition in its bid to develop domestic resources. Given a green light for fracking, would Mexico be able to emulate US efficiency? To promote the production of natural gas in unconventional reservoirs, at least in early stages, the government would need to implement a comprehensive program including incentives and tax breaks, as was done in the US in the 1980s.
To frack or not to frack, is the dilemma that lingers. Either continue relying on the US to meet Mexico’s natural gas demand and let go of the country’s vast shale reserves, or start the exploitation of these deposits to attempt to reverse the significant fall of conventional deposits.
All oil and gas activities carry a risk, and what Mexico needs is to tighten regulation in all processes, not only for fracking, but also for traditional extraction, in order to reduce any possibility of damage to the environment. And before allowing or prohibiting fracking, there should be a deeper analysis and discussion that covers not only gas and oil output, but also the impact it might have on the petrochemical and electricity industry, employment, and national security.
The post Mexico’s gas dependence on US pushes politicians to consider fracking appeared first on The Barrel Blog.
Deliveries of LOOP sour crude dropped in March, one month after flows reached their highest level in half a year, a Louisiana Offshore Oil Port report showed Monday.
LOOP delivered more than 845,000 barrels of the sour crude from its storage in March. That is compared with the six-month record high of 1.135 million barrels of LOOP sour crude that was delivered in February.
US Gulf Coast refining activity hit its lowest point in about a year during March. The Energy Information Administration data showed that in the week that ended March 22, the USGC refining complex ran at 87% of capacity, the lowest level since the week that ended February 16, 2018.
Market sources said this was partly due to a fire at ExxonMobil’s Baytown refinery, one of the largest in the US, as well as other planned and unplanned repair work in the region. With regional refining appetite quelled, demand for LOOP sour may have been dampened.
However, March’s deliveries of LOOP sour still remained relatively strong, when compared with the six-month average of about 730,000 barrels delivered.
There has been strong demand for sour, heavier crude grades such as LOOP sour in recent months as there has been limited supply due to OPEC production cuts, in addition to dwindling supplies out of Venezuela.
LOOP also reported that the crude delivered ex-cavern in March maintained its density with an average API of 29.8 degrees. LOOP Sour’s sulfur content decreased to 2.06% in March, compared to 2.21% sulfur reported in February. LOOP’s six-month sulfur quality average is 2.18%.
Separately, LOOP will auction 7,200 capacity allocation contracts in its monthly crude storage auction on Tuesday, which collectively equal 7.2 million barrels of storage for the medium crude blend. The minimum bid price LOOP will accept during the auction is 5 cents/b. Monthly storage for LOOP Sour traded around 5 cents/b for all of 2018.
Auction co-host Matrix Markets said LOOP will sell up to 3,600 storage futures contracts and 3,600 physical forward agreements. The front-month contract of May will see 300 CACs put up for sale. LOOP and Matrix in March sold a total of 2.175 million barrels of storage capacity of the 7.4 million barrels that were offered.
The post In the LOOP: March LOOP crude deliveries drop on subdued demand appeared first on The Barrel Blog.
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, Morris Greenberg explores the drivers behind US coal generation retirements in recent years.
The aging US coal fleet is being squeezed from all sides, with policy, cheap domestic gas supply and developments in clean energy generation all contributing to fast-paced closures.
Since peaking at 317 GW at the end of 2011, US generating capacity with coal as the primary fuel fell by 73 GW, or 23%, due to retirement of 61 GW and primary fuel conversion – mainly to natural gas – of 16 GW. This was offset by additions of 4 GW.
Most of the additions were made early on in this eight-year period. Coal-fired generation has fallen even more steeply than capacity, with a decline of 33.5% between calendar years 2011 and 2018. The drop reflects a reduction in average capacity factor (utilization rate) from 62% to 52%.
While capacity factors have stabilized during the past three years, announced plans for retirement of around 20 GW and conversion of around 5 GW indicate that, without some form of policy support, capacity declines will continue.
Indeed, the announcements may only reflect the tip of an iceberg that includes many more GW of capacity at risk. To get a better handle on that number, it is useful to review first the economics of retirement and then factors that have driven the restructuring observed to date. These factors are: an aging coal fleet; stagnating demand; low natural gas prices; environmental regulation; and finally, cost declines and policy support for clean energy.
The decision to permanently retire a merchant coal unit, or really any merchant unit, is made by comparing the present value of future revenues from sale of energy, capacity and ancillary services to the present value of costs including fuel, non fuel variable operating and maintenance expense, fixed operating and maintenance expense, and required capital spending. For regulated units, the relevant measure is the present value of revenue requirements. The calculations are similar if replacement energy and capacity is acquired from the market. There are several factors that play into this calculation and have driven the restructuring seen in the US market in recent years.
Of the 317 GW of operable capacity in 2011, 125 GW exceeded 40 years of age and 50 GW exceeded 50 years. Older units are less efficient, require higher spending per unit of capacity to maintain availability, and tend to face higher capital requirements for environmental retrofits, leaving them more vulnerable to changes in market conditions.
Stagnating power demand
A combination of improving energy efficiency among consumers combined with rising behind-the-meter generation has led to stagnating demand, leaving US retail electricity sales virtually unchanged from 2011 to 2017. Weak demand depresses energy and capacity prices for all generation, but coal units were exposed due to the factors that follow.
Lower natural gas prices
Low natural gas prices have had a major impact on the erosion of US coal-fired capacity. The direct impact is the conversion of existing capacity from coal to gas. But there is also an indirect impact, as lower electric energy and capacity prices reduce the value of coal capacity and may boost operating costs due to operational changes.
Since 2011, rising gas supply associated with shale gas development has allowed US consumption of gas for power generation to increase by 38%, from 21 Bcf/d to 29 Bcf/d and accommodated higher net exports with no upward pressure on prices.
Accounting for permitting, financing and engineering, the development cycle for gas capacity ranges from about two years for fuel conversions, to five years for greenfield development. As a result, while gas prices have an immediate impact on energy prices, the impact on capacity prices and decisions to build or retire plants occurs with a lag of that duration.
A three-year moving average of Gulf Coast gas prices lagged by two years peaked in late 2010 near $8/MMBtu, fell to the $3.50 range in 2015-17, and to the low $3 range in 2018. It will fall below $3/MMBtu this spring and likely remain there for several years. That means gas markets will remain a drag on coal unit economics for years to come.
Coal units must comply with air, water and solid waste emissions standards. Air emissions include sulfur dioxide, nitrogen oxide, particulates, mercury and other air toxics, and carbon dioxide. Water standards cover plant effluents as well as cooling water intake structures and temperature impacts. Coal combustion residuals are also regulated.
The Mercury and Air Toxics rule, which took effect in April 2015, was the most important regulation to impact coal capacity during the 2011-18 period, driving units facing high compliance costs to retire. In some cases, units that remained in service faced increased costs associated with operating emissions controls or purchasing coal additives to improve mercury capture.
While the Obama administration’s Clean Power Plan proposed in 2014 was never implemented, the potential for future carbon regulations must be considered in a decision to retire or maintain coal capacity, particularly if capital infusions are required. In addition, while the federal regulatory role is currently limited, carbon emissions caps are in effect in California and the Northeast, through the Regional Greenhouse Gas Initiative (RGGI), and several other states have emission reduction targets.
Cost declines and policy support for clean energy
A combination of falling costs and state, as well as federal, policy has led to rapid growth in US wind and solar generation. Solar PV costs have declined from about $4,000/kW-AC in 2011 to about $1,200/kW-AC at present. During the same period, onshore wind costs fell from over $2,000/kW to about $1,500/kW. In addition, the cost of battery storage that can help integrate intermittent renewables, particularly solar, has fallen dramatically.
States have played a role in renewables growth primarily through renewable portfolio standards (RPS), which mandate a certain proportion of renewables in the energy mix. Twenty-nine states and the District of Columbia currently have mandatory RPS. Qualifying technologies vary from state to state – though solar and wind qualify everywhere – and percentage requirements vary over a wide range. Based on current law, renewable generation to meet RPS requirements of load serving entities – that is, companies that provide power on a retail basis, mainly utilities but also unregulated marketers – will more than double between 2018 and 2030. Corporations in pursuit of sustainability goals have also stepped up their purchases of renewable energy, signing deals for over 6 GW of capacity in 2018 alone.
State support for merchant nuclear units challenged by weak margins may come at the expense of coal capacity. Unlike intermittent renewables, nuclear units provide significant capacity value – meaning they can provide energy whenever needed. New York and Illinois are already providing support, with New Jersey and Connecticut also moving down this path. Pennsylvania, home to 10 GW of nuclear capacity, may follow.
The federal role in promoting renewables has mainly been through tax credits, including production tax credits (PTC) for onshore wind and investment tax credits (ITC) for solar. Under legislation enacted in late 2015, wind projects starting construction in 2016 are eligible for a PTC of $23/MWh for 10 years; the value of the credit steps down for projects started in subsequent years and is phased out for projects begun after 2019.
The ITC is 30% for projects started by the end of 2019 and then steps down over the following two years with the residential credit expiring for projects begun after 2021 while the ITC for non-residential systems falls to 10%.
The cost of wind generation (including ROI) from projects qualifying for the full PTC in areas with high average wind speeds is in the $15-20/MWh range, competitive with the variable cost of coal and gas generation. The cost of solar PV qualifying for the full ITC in areas with high insolation is in the $25/MWh range. Variable production costs are lower, and producers are often willing to sell at negative prices to capture tax credits (in the case of wind) and renewable energy credits (used for RPS compliance).
Due to lower variable production costs, rising renewables generation will displace both coal and gas generation and result in lower energy prices. In addition, more extensive cycling of dispatchable generation to balance supply and demand will result in higher operating costs.
Despite its impacts on energy prices and operating costs, growth in renewables output by itself has not been a major driver of coal retirements because the resources do not provide much capacity value, and lost energy revenues can be partially recouped in capacity markets. That may change, however, with additional investment and the ability of battery storage to add capacity value. According to the American Wind Energy Association, there are 35 GW of wind capacity in advanced development and the Solar Energy Industry Association report 27 GW of solar projects with signed PPAs and another 37 GW announced.
While this discussion has been focused on US developments, the same factors apply elsewhere in the world as well, though their relative importance may vary. Europe, for example, is expected to see a significant reduction in coal-fired generating capacity during the next two decades. Slow demand growth, policy support for renewables, and explicit coal shutdown plans play a role. As a gas importer, gas prices tend to be higher in Europe, but the impact is offset by carbon allowance prices that boost the effective cost of burning coal relative to gas.
In Asia, the picture for coal is a little brighter thanks to high gas prices, faster load growth and looser environmental regulations. However, renewables are making inroads, particularly in China, causing growth in coal to slow.
Read more articles in this series:
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Fuel quality is the great unknown for the shipping and oil refining industry. The International Maritime Organization’s (IMO) January 2020 deadline could see the majority of vessel owners switching to cleaner marine fuels incompatible with each other. Other solutions look similarly haphazard.
The IMO’s global sulfur limit for marine fuels drops to 0.5% next January from 3.5%, and the industry is developing a wide range of very low sulfur fuel oils, which may be compliant but also vary in other qualities.
The specifications of the new fuels matter because marine engineers need to know how they will interact with their vessels, and bunker purchasers need to start planning which fuels they will be able to buy, at which ports and in which combinations. Imagine a driver in a car pulling up outside a filling station uncertain as to whether the gasoline at the pump would cause their car to break down.
But this unthinkable scenario looms large at sea. There is at present no guarantee any of the new bunker fuels will be compatible with each other — when mixed in a single bunker tank, they may separate and form sludge that will block filters and ultimately damage the engine.
Viscosity differences could be vast, the fuels could have much higher presence of substances like silicon or aluminum compounds or there could be questions over fuel blends when mixing aromatic and paraffinic refinery streams.
“We’ll have to learn on the behavior of these fuels, it will take quite some time to find the right balance and understanding across the global market,” said Damien Valdenaire, science executive at oil industry research body Concawe.
A buyer with ships travelling between Fujairah and Singapore – the two biggest bunkering hubs – may have no idea whether the fuel bought at the Middle East hub will be compatible with any of the products available in the Far East.
The cost could be huge, and not confined to a handful of credit-starved shipowners. Higher oil prices, slower-sailing ships, bankruptcies and squeezed margins across many connected industries, along with risks to world trade, could all define the years that follow.
And then there’s the danger of high-profile engine failures in shipping arteries such as the Strait of Hormuz, the world’s most important chokepoint that allows 30% of the world’s crude oil and other liquids as well as 30% of global LNG trade into the Gulf.
The message from the bunker industry has been unequivocal. “No co-mingling of fuels,” said Unni Einemo, the IMO representative at the International Bunker Industry Association, recently. And at the Fujairah Bunkering & Fuel Oil Forum, top executives said they expect most shipowners to switch to marine gasoil or marine diesel in the short term, and to 0.5% low sulfur fuel oil blends in the mid to long term.
Glander International Bunkering Chief Executive Carsten Ladekjaer said at Fujcon that the industry generally does not yet know enough about the 0.5% sulfur products of the future – including their origin, components, stability and not least their compatibility – to make longer-term plans.
The IMO has shown it won’t be backing down. But similarly, the United Nations’ body responsible for the safety and environmental performance of the shipping sector has left ownership of the issue up to the individuals concerned.
Some seafarers have rushed to fit scrubbers – kit to clean up the pollutants – so they can carry on burning fuel oil, while refiners are yet to come up with the goods on iron-clad specification-ready middle distillates.
The energy majors have been scrambling to be ready as the clock ticks down. BP said this month it was set to launch “a new very low sulfur fuel oil” with maximum 0.5% sulfur content following sea trials of product produced and supplied in Northwest Europe and Singapore. But details of specifications or when it plans to make the first sale were not given.
ExxonMobil announced in October that its range of 0.5% sulfur marine fuel blends will be compatible with each other. That could mean shipowners end up willing to pay a premium for Exxon’s products that are likely to be available at a wide range of ports. However, it still leaves open the question of whether shippers can mix Exxon’s fuel with other refiners’ brands.
Shell is conducting trials of its new 0.5% sulfur fuels with customers in Rotterdam, Singapore and New Orleans.
Meanwhile, the world’s largest consumer of bunker fuel is increasingly becoming a supplier of the product as well, as it takes back control of its supply chain ahead of disruptive changes to emissions regulation next year.
AP Moller-Maersk, the parent company of container shipping firm Maersk Line, signed a deal with New Jersey-based PBF Logistics last month to produce and store 0.5% sulfur bunker fuels both for its own needs and third-party customers on the east coast of the US. The agreement follows a similar one made with Vopak in Rotterdam in August, and its leasing of storage capacity in Singapore in October.
Individual solutions point the way forward until the industry is able to figure out compatibility.
At an S&P Global Platts industry event earlier this year, participants felt that mixing fuels was too big a gamble but that in time an answer will be found. After all, the industry has already had a wake-up call. Last year hundreds of tankers in Houston and Singapore suffered damage due to contaminants in fuel clogging filters and pumps. While it was a very different issue and didn’t lead to engine failures, it sparked panic after shipowners in Asia were reluctant to buy US Gulf Coast-origin fuel.
Time is running out and the whole value chain could benefit from a dose of collective responsibility rather than individual accountability. It could be in as short supply as the right sort of fuel come 2020.
Platts launched IMO 2020-compliant 0.5% sulfur marine fuel cargo assessments in Fujairah and Singapore at the start of this year.
Metals are playing a starring role in the transition towards renewables and electric vehicles, and the past week saw plenty of activity in the sector. There were also positive indicators pointing to strong demand ahead for a number of products.
In China, the announcement of a cut in subsidies for EVs signalled a further milestone in the industry’s development.
Construction of Australia’s largest lithium processing plant began in Kemerton, Western Australia, with approval to produce up to 100,000mt/year of battery-grade lithium hydroxide. While research is ongoing to refine battery chemistry, there is no real alternative to lithium for batteries in the transport sector, making future supply crucial to the EV industry’s development.
In terms of international trade flows, Japan and South Korea saw their imports of lithium carbonate and hydroxide soar in February. Japan’s imports of lithium hydroxide, for example, jumped 79% year on year to 2,687 mt. Chinese lithium imports declined, however.
According to the Japan Mining Industry Association, development in transport and telecoms should bolster demand for base metals, which include nickel, copper and zinc, despite economic headwinds. “With the EV and 5G coming, demand fall is unlikely in the longer term,” said association chairman Naoki Ono on March 27.
Away from EVs, development in conventional autos continues to bolster the price of palladium, used in catalytic converters to reduce emissions. Palladium is currently priced at around $1,600 per ounce, a rise of more than 50% since October.
GRAPHIC OF THE WEEK
The gas discovery off Cyprus announced in late February by US major ExxonMobil and its partner Qatar Petroleum has contributed to the fast-shifting dynamics of the East Mediterranean gas market.
PODCAST: BUYING FLURRY ON DATED BRENT
S&P Global Platts reporters Emma Kettley and Gillian Carr speak to Joel Hanley about the sudden strong buying interest in the North Sea Dated Brent crude complex, as well as the knock-on effect on grades such as Russia’s Urals.
Africa’s downstream sector has seen an injection of $30 billion in investment, as the continent is one of the few regions where oil demand is expected to grow steadily for the next two decades, the African Refiners and Distributors Association (ARA) said Thursday.
The 2019-20 sugarcane season will officially start April 1 in the Center-South, the world’s largest sugarcane- and sugar-producing region. The continued strength of ethanol prices has maintained a wide spot premium to sugar, which, coupled with higher-than-expected fuel consumption rates in 2019, is tilting the balance toward ethanol.
The role of bunker traders is undergoing a transformation as 2020 approaches, with many likely to play an increasingly vital role as harbingers of credit and information to a market which is dealing with the complexity of the International Maritime Organization’s global sulfur limit rule for marine fuels.
THE LAST WORD
“We’re not looking to trade battery metals in the short term, we are focused on the energy side of commodities.”
– Gunvor CEO, Torbjorn Tornqvist, lays out the limits of the Swiss trading company’s current strategy.
The post Energy and commodities highlights: Metals and EVs, Africa’s downstream boom, Brazil’s sugar season appeared first on The Barrel Blog.