Trump wants to expedite a Texas pipeline project, but no one seems to know what it is

“I’m baffled,” one US government official said last week.

“I have no clue,” said another.

“I have absolutely no idea what he’s talking about,” one frustrated analyst said after an hour of phone calls. “I’m not sure anybody does.”

On October 9, President Donald Trump told reporters aboard Air Force One that he was getting “expedited approval” for a Texas pipeline project.

According to a press pool report, Trump gave no additional details.

“It’s unclear exactly what project he was referring to,” the report notes.

As the week wore on, the Trump administration offered no additional information.

Officials with the US State Department, which can issue permits for cross-border liquid pipelines; the Pipeline and Hazardous Materials Safety Administration, which regulates interstate pipelines that cross state boundaries; the Federal Energy Regulatory Commission, which approves the siting of natural gas pipelines; and the Department of Energy all referred questions to the White House.

The Railroad Commission of Texas, which regulates the state’s roughly 467,000-mile pipeline infrastructure and permits all new intrastate pipelines, declined to comment.

“Any question regarding comments by the President should be directed to the White House or the President’s representatives,” Ramona Nye, a commission spokeswoman, said in a statement.

The White House did not respond to multiple requests for comment from S&P Global Platts and other media outlets.

Analysts speculated that Trump may have misspoke, claiming that the president may have been briefed on Permian oil midstream constraints and thought the federal government could hasten approval of a pipeline project there.

But, as analysts noted, those permitting decisions would likely all be made at the state level.

“How would Trump expedite a Texas pipe?” asked Rusty Braziel, president and CEO of RBN Energy.

Permian oil production is expected to average about 3.5 million b/d this month, up about 843,000 b/d from a year ago.

Platts Analytics forecasts Permian production to grow to about 4.5 million b/d by the end of 2019 as midstream companies add about 3 million b/d of new pipeline takeaway capacity.

Most recently, EPIC Midstream announced earlier this month that it will temporarily move Permian crude oil to the Gulf on its NGL pipeline before its 825,000 b/d pipeline between the Permian and Corpus Christi comes in service.

Trump’s comments on the Texas pipeline project came amid his recent criticism of OPEC for, he claims, driving up global oil prices, an attempt to show he’s addressing rising energy prices ahead of next month’s congressional elections.

For Trump, $80/b Brent and $3/gal retail regular gasoline is a “red line,” according to Bob McNally, founder and president of Rapidan Energy Group and a former White House international and domestic energy adviser.

“It’s binary,” McNally said in an interview with the Platts Capitol Crude podcast. “Below that level, he really doesn’t care too much, he doesn’t tweet much, he doesn’t really talk much about OPEC or oil prices. But everything switched on the approach and then above $80/b Brent, $3/gallon retail gasoline. Oil can quickly become the most important issue.”

Which likely means that if Brent prices fall below $80/b and US drivers are, on average, paying less than $3/gal for gasoline, last week may be the last time we hear about this mysterious Texas pipeline project Trump wants to expedite.

But if prices climb, the project may come up again, even if no one is entirely sure just what it is.

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In the LOOP: China export cargoes from Louisiana dry up

September was the second month of halted US crude exports from Louisiana to China due to higher VLCC freight rates, a narrower Dubai/LOOP Sour spread and uncertainty over possible trade tariffs imposed by China on US crude.

In September, no cargoes departed Louisiana for China, according to cFlow, S&P Global Platts trade-flow software. Additionally, no cargoes left Louisiana for China in August, according to export data from S&P Global Platts Analytics and US Customs.

Rising VLCC freight rates from the US Gulf Coast to China may have contributed to the lack of cargoes flowing that way. Average VLCC rates for October to date reached $3.39/b, up from an average rate of $2.45/b in September and $2.37/b in August, according to Platts data. In contrast, VLCC freight rates from the USGC to Singapore have also increased in recent months, but have not hit the high levels of the China route. Average VLCC rates for October to date on the Singapore route reached $2.91/b, up from an average rate of $1.98/b in September and $1.89/b in August.

Freight rates for VLCCs carrying cargoes from the USGC and Caribbean have soared over the past two weeks on a combination of increased interest from Asian crude buyers and a very tight global VLCC market. Rates have climbed over 43%, or $1.9 million, for the USGC-Singapore route since September 27, the day before rates climbed $800,000 in one trading session.

A narrower Dubai/LOOP Sour spread has made exports to Asia in general less competitive in recent months. For October to date, Dubai’s premium to LOOP Sour fell to $2.29/b, a decrease of 21 cents/b month on month and a decline of $1.02/b from August.

In August, only one cargo bound for South Korea, one for Japan and two for India departed Louisiana, according to data from Platts Analytics and US Customs. September data from cFlow showed only one cargo headed to Asia. The Australian Spirit, bound for Ulsan, South Korea, departed Louisiana September 13, with delivery scheduled for October 28.

US crude oil exports have bounced back in recent weeks, after reaching a five-month low of 1.31 million b/d at the end of June, according to data from the US Energy Information Administration. Crude exports reached 2.576 million b/d for the week ended October 5, representing a week-on-week increase of 853,000 b/d.

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Saudi Arabia’s power play will unleash crude oil supplies: Fuel for Thought

Saudi Arabia’s energy strategy could put to bed questions over its spare oil capacity in the coming years.

The kingdom’s plan is two-pronged: Expand and develop oil fields to offset production decline, and diversify away from crude for power generation. It is this latter move that is key to unlocking further oil exports.

The OPEC doyen plans to burn less crude as it pushes ahead with a swathe of important gas and high-sulfur fuel oil power plants to drive its economy and keep homes cool.

S&P Global Platts Analytics sees high-sulfur fuel oil displacing 200,000 b/d of crude burn by 2020, as Saudi Arabia ramps up use of the cheap and undesirable by-product of the refining process rather than its precious black gold.

The International Maritime Organization’s regulation that will cut the sulfur limit from 3.5% to 0.5% from the start of 2020 and see shipowners scramble to find cleaner alternative energy sources is likely to play into the kingdom’s hands. The UN agency’s ruling will see a probable global glut of fuel oil that could find a home powering much of the Persian Gulf.

In 2016, Saudi Arabia became a net consumer of fuel oil, especially during the summer months when more is needed to meet peak electricity demand, and that trend is likely to become entrenched with fuel oil set to be a key substitute for crude.

“As IMO regulations come into effect, Saudi Arabia will not only be able to consider the option of supplying more diesel due to its complex refineries, but also divert fuel oil towards the power sector,” APICORP stated in its September energy research.

“Over the next four years, Saudi Arabia is expected to add more than 25 GW of generation capacity, of which around 9 GW of oil-fired capacity will come on line in the next two years,” it added.

Saudi Arabia's oil and gas infrastructure


Gas is also playing a much bigger role in Saudi’s energy mix in synch with its Vision 2030, making up almost half of its 90 GW of total Saudi capacity and with an extra 9 GW coming online by 2020.

The recent commissioning of the 1.2 GW combined-cycle gas turbine Waad A-Shamal plant will mean gas and fuel oil will make up the lion’s share of Saudi’s power generation and allow the country to maximize its profits from lucrative crude exports.

Saudi Arabia has often waxed lyrical on renewables but has now started to back these lofty goals with solar projects. The Skaka 300 MW solar PV plant and a 600 MW Green Duba plant in the works aim to utilize the sun-blessed kingdom’s natural resource.

The benefits of nuclear have also been talked up, with plans to build the kingdom’s first two nuclear power reactors this year with a goal that 15% of Saudi power comes from the radioactive energy option by 2032.


But for Saudi Arabia to truly take advantage of this diversification, the OPEC stalwart needs its oil industry to thrive.

Saudi Aramco is bidding to bring on 300,000 b/d of Arab Light from its Khurais field, has awarded offshore drilling contracts to boost output at Berri and wants to boost the capacity of the Zuluf offshore field by 600,000 b/d.

Moreover, the national company is dusting off the mothballs from its Damman onshore oil field, and production at the Sheybah field has already been ratcheted up.

There is also the potential to add up to 500,000 b/d from the so-called neutral zone, an area of oilfields between Saudi Arabia and Kuwait that has been in limbo since 2014. The Gulf states are close to settling their issues but it could take time to get production back up to speed if production is brought online early next year.

Saudi Arabia produced 10.60 million b/d in September, according to a S&P Global Platts survey, which is one of the secondary sources OPEC uses to monitor compliance to the production cut deal. There are doubts whether the kingdom can produce its 12 million b/d capacity over the long term to plug any shortfalls in the market, with some analysts seeing limits being tested at closer to 11 million b/d for any sustained period of time.

With around 1.7 million b/d set to come off the market due to sanctions on Iran, according to Platts Analytics, risks that Venezuela output could fall further and with Libya production extremely fragile, the market is looking to Saudi Arabia to flex its muscles.

If Persian Gulf powerhouse wants to maintain its considerable strength, then freeing up crude from power generation will be as important as developing and expanding its oil fields.

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Vietnam’s plastic end-users set to gain as US-China trade spat intensifies

The global plastics supply chain is changing as the US-China trade war intensifies, and Vietnam’s plastic resin end-users are poised to benefit.

While Vietnam is already a manufacturing hub for plastic finished goods due to its low labor costs and business-friendly environment, the recent trade war between global giants is providing an additional boost as key resin costs decline.

US polyethylene, which was slapped with a tariff by China in the opening shots of the trade war, is now heading to Vietnam at a rate of around 20,000 mt/month, up from 3,000 mt/month in 2017, according to distributors.

The Chinese tariff on US PE was part of a $110 billion retaliatory tariffs package imposed in response to the US’ $250 billion tariffs on Chinese products.

Related special report: US Chemical industry caught in US-China trade war

US polyethylene diverts to Vietnam as China's tariffs on US PE kicks in

As the industry gathered in Ho Chi Minh City for VietnamPlas 2018 in October, the impact of the trade war was just beginning to be felt.

Vietnam-based polymer traders with extensive local distribution channels were the first to take advantage of cheap US PE.

Nguyen Dang Quang, General Manager Middle East of OPEC Plastics

Nguyen Dang Quang, General Manager Middle East of OPEC Plastics

“We now buy direct from US [producers] such as Dow Chemicals, Westlake Chemicals, Chevron Philip, LyondellBasell US, and others. Chinese companies used to do this business, but after the trade war began, we took their allocations,” Nguyen Dang Quang, General Manager Middle East of OPEC Plastics, said during VietnamPlas.

“Our connection with end-users is the key and we can buy in bulk — 10,000-20,000 mt [per order],” he added.

US PE imports in Vietnam are currently $80-$100/mt cheaper than Middle East origin PE cargoes of the same grade, undercutting traditional suppliers to the region — even after accounting for unfamiliarity with US material and unfavorably long voyage times.

Industry participants at VietnamPlas expected ample US imports to continue to tip the scales towards oversupply in Vietnam for the duration of the trade spat, and no one volunteered a prediction on how long that would be.

Nguyen Thai Mai Anh, Chemical Department of Mitsubishi Corporation Vietnam

Nguyen Thai Mai Anh, Chemical Department of Mitsubishi Corporation Vietnam

“In the short term, because of the US-China trade war, we forecast that the local polyethylene market price will be on a downward trend because of supply [outpacing] demand,” Nguyen Thai Mai Anh from Mitsubishi Corporation Vietnam said.

Meanwhile, local polymer end-users see opportunities as supply chains begin to reroute from China to Vietnam, but are cautious about rushing to commit to expansions.

“Walmart is looking to move orders to Vietnam to avoid [US] duties on finished plastic products [from China], but I don’t see a big increase [in resin orders] from my customers supplying Walmart yet,” Nguyen Dang Quang from OPEC said


Supply chains impacted by the US-China trade war will move into Vietnam in three distinct phases, according to David Hsu, General Manager of Kim Hoang Long, a major PS and ABS distributor for Taiwan’s Chi Mei Corporation in Vietnam.

David Hsu, General Manager of Kim Hoang Long

David Hsu, General Manager of Kim Hoang Long

“First, [plastic finished goods] orders will move to Vietnam and other Southeast Asian countries, and we’re beginning to see that,” he said.

“Secondly, next year, companies with capacity in both countries will expand Vietnamese capacity while Chinese capacity will [be relegated to] serve mostly domestic demand. Thirdly, companies with no footprint in Vietnam may open new factories [there], but that will take time,” he said.

On the polystyrene front, he predicts the trade war will bring 5%-10%/year extra resin demand into Vietnam on top of the base growth rate of 15%-20%/year.

Vietnam’s auto sector will also likely see a surge if the trade war persists, both from automakers feeding into Vietnam to avoid duties and from startups. New automotive factories would bring with them demand for automotive plastic parts, and in turn for PS and ABS.

Experts say modern global supply chains will inevitably find a path around the US-China trade tension.

“Persistent trade tensions could lead companies to move part of their operations, provided their adjustment costs are lower than the benefit resulting from avoided tariffs,” said Vishrut Rana, Asia-Pacific Economist at S&P Global Ratings.

“Southeast Asian economies, including Vietnam, offer favorable cost propositions and a good track record in attracting export-oriented foreign direct investment,” he added.

Related articles:
** More US polyethylene to hit Vietnam’s shores in Q4 as US-China trade war intensifies
** Vietnam’s polyethyelene prices seen set to weaken in early 2019 as imports outpace demand
** Vietnam’s polypropylene capacity set to exceed domestic demand by 2023
** Vietnam 2019 polystyrene demand to get a boost from trade war, auto sector – distributor

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Insight: Libya’s oil production faces political litmus test

Predicting what Libyan crude production will be in a few months’ time can be even trickier than forecasting the oil price itself. And the risks it faces could multiply as the country – which holds the largest oil and gas reserves in Africa – moves towards critical elections in December.

Libya’s recent rise in production has confounded even the most pessimistic of analysts. In mid-September, Libyan oil production surged to more than five-year highs of 1.28 million b/d, according to Mustafa Sanalla, chairman of the state-owned National Oil Corporation.

Libya's production recovery


Most independent observers would see that as on the high side, but estimates show production late summer reached just above the 1 million b/d mark. Libya’s oil output hit 1.05 million b/d in September, its highest level since June 2013, according to the latest S&P Global Platts OPEC production survey.

Libya’s oil sector has been unfortunately synonymous with turmoil since the toppling of leader Muammar Gaddafi in 2011. Since then, production sank to around one-third of a total capacity of 1.6 million b/d, until the recovery began to show signs of promise in early 2016.

Despite the slight progress, uncertainty over Libya’s political future and a worrying security situation continue to cast a shadow over prospects for its oil industry.  With the ever-present threat of attacks by rival militias and the Islamic State group, it is tough to forecast the country’s mercurial production swings.

Security in focus

The progress in crude output can be attributed to the efforts of NOC, ably led by Sanalla, a relentless, hardworking man who runs the 1 million b/d oil corporation on a shoestring budget.

All the good work could be undone if the core issues – a lack of security and money – do not improve. As the de facto head of the country’s beleaguered oil industry, Sanalla is doing all he can, but one man and one company is never enough. This is why the elections planned in December will test the country’s unity and be crucial to the outlook for its oil industry.

The past few months have been a painful reminder that rivalry between different factions and militias continue to threaten the stability of the country and its beleaguered oil sector.

Tensions reignited in Tripoli in September, which also saw an attack at the NOC headquarters by IS militants, but production was left unaffected. In June, crude output halved as the key eastern ports of Es Sider and Ras Lanuf were shut-in due to violence followed by blockades.

In an interview with S&P Global Platts in late September, Sanalla admitted security concerns and a lack of foreign investment would continue to weigh on attempts to increase output. He added there had been progress with some international oil companies on increasing production, staffing and investment across the country.

Almost two weeks after that interview, BP and Eni announced their intention to resume exploration activities in the war-torn country alongside NOC. Russia’s Tatneft also said it was working on restarting operations in Libya. This bodes well for the North African producer, but history tells us the road could be a bumpy one.

Libya’s critical oil infrastructure is protected by a complex patchwork of security agreements between NOC and local militias, leaving production vulnerable to sudden disruptions. One such event happened in June, when the self-styled Libyan National Army, controlled by General Khalifa Haftar, took control of the eastern ports and prevented any crude from being loaded.

Most analysts believe almost 500,000 b/d−700,000 b/d of Libyan output remains at risk during the next few months. But they expect these outages to last only days to weeks, as stable oil output will be essential to any political solution in Libya.

Libyan crude oil output is expected to have dipped slightly this week due to the deteriorating security situation around its largest oil field Sharara. Sources said an increase in local militia activity had led to some oil workers evacuating fields. Sanalla’s own life has come under threat and he was forced to flee NOC’s headquarters in Tripoli last month after the building came under attack from gunmen.

Power plays

It is still not known whether the December election will occur on time. The UN-backed Government of National Accord is gradually losing its clout and remains under pressure due to the lack of security and economic reforms. Disunity in the country has created space for the rise of the LNA under General Haftar. Some of Libya’s key oil terminals and infrastructure are controlled by Haftar’s LNA, and his role ahead of the elections, along with the result of those polls, will define the future of Libya.

Haftar’s recent moves in the country resemble those of a chess grandmaster. With elections around the corner, Haftar will be thinking of his next move. Since he called off his surprise blockade at the ports of Es Sider and Ras Lanuf, he targeted the removal of the central bank governor.

Most analysts expect oil infrastructure to be used as leverage as the December elections loom. If elections results go Haftar’s way, exports could remain stable. If not, his influence at key oil ports could push output down.

Meanwhile, Russia is quietly building a presence in the North African country and this alliance is worrying the West. France and Italy are also competing for influence.

The rise of IS is a huge worry for the country, and for the wider world too. Haftar’s LNA has been facing off rival militant groups, especially IS, as it tries to stymie opponents in the east of the country.

In addition, Libya has emerged as a hub for people smugglers, serving as a portal into Europe for migrants from Africa and the Middle East.

This is why the future of Libya is of deeper, global significance. The recent oil output recovery is just the catalyst Libya and the West needs. As the country faces a political litmus test in the form of its December elections, the recovery needs to be maintained – otherwise Libya will be going nowhere.

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US jet fuel soared in Q3 on sagging RVO, record demand

The summer months always constitute the peak travel season for US airlines, making the third quarter traditionally the heaviest sustained demand portion of the year.

But Q3 2018 was something the industry had never seen.

Record demand for jet fuel in both the US and Latin America, combined with sagging Renewable Volume Obligation (RVO) values, led to unprecedented strength in prices during Q3.

US jet fuel demand reached an all-time high this summer.

Seven percent airline year-on-year growth on average across the US,” said a Gulf Coast jet fuel trader.

Added to the domestic strength, Q3 demand for jet exports to Latin American demand also reached record highs. Latin America takes around 50% of US jet exports, and Mexico is the region’s top importer. Jet fuel imports now cover around 63% of Mexico’s domestic demand, compared with 53% in 2017, 44% in 2016 and 33% in 2015.

In July 2018, USGC jet exports averaged 236,625 b/d, up from 164,888 b/d over the same month in 2017 and 146,665 b/d in 2016, according to US Energy Information Administration data. Mexico led the way in July with 1.45 million barrels imported from the US, followed by Brazil at 932,000 barrels.

US refiners were forced to run maximum jet fuel output to try to keep up with all the demand, setting new records for all-time jet output five times this summer, EIA data showed.

Still, demand outpaced the record production and prices took off.

S&P Global Platts assessed benchmark USGC jet fuel on Colonial Pipeline at an average of $2.1843/gal in Q3 2018. That was significant jump from Q3 2017’s average of $1.6353/gal and 2016’s Q3 average of $1.3410/gal.

Q3 jet fuel prices were so strong that USGC jet, traditionally at a discount to USGC ultra-low sulfur diesel, flipped to a premium to its distillate neighbor in early July. It held that premium to ULSD for 31 of the next 35 days.

Plunging costs for RVO compliance also played a role in jet fuel’s Q3 strength.

The renewable volume obligation — a calculated value based on Renewable Identification Number prices and EPA-published mandates — dropped to multiyear lows during the quarter.

Lower RVO values incentivize refiners to produce more ULSD, since their compliance cost is lower. If they are making more ULSD, they are necessarily making comparatively less jet fuel. Thus, jet supply is tighter, supporting prices.

On the Atlantic Coast, tight supply due to intermittent problems at key Northeast refineries, as well as lower shipping volumes coming up Colonial Pipeline, kept regional jet prices high during the quarter.

Platts assessed benchmark jet fuel on Buckeye Pipeline in New York Harbor at an average of $2.1862/gal during Q3 2018, compared to $1.6605/gal during Q3 2017.

In the US Midwest region, Q3 was relatively subdued. Chicago jet traders are wary of jet fuel thermal oxidation testing, or JFTOT. From time to time, jet barrels arrive in the Chicago area and fail this test, requiring 5-10 days of treatment before being released onto the various pipelines in and around the city. This can cause Midwest prices to spike suddenly.

However, the Chicago area pipelines seem to have gotten this situation under control, keeping wild price fluctuations seen in past years to a minimum in Q3.

The US West Coast jet fuel market is balanced by imports coming over from South Korea and Japan, sources say. If any of the volatile USWC refineries is having trouble, incoming Asian jet cargoes can fill in with supply and mitigate price movement.

However, if the flow slows down due to a closed arbitrage and barrels staying in Asia to meet demand there, USWC jet prices can rise dramatically.

An example of this happened in April, when the Los Angeles jet fuel differential reached a three-year high after the longest stretch without an Asian jet cargo since February 2016.

The Asian jet flow did indeed slow in Q3, continuing a trend seen throughout 2018. There were 21 jet cargoes into California between July and the end of September, delivering 4.91 million barrels of jet fuel. That was quite a drop from Q3 2017, which saw 39 cargo vessels delivering 7.54 million barrels of jet.

US airlines absorbed the impact of higher Q3 jet fuel prices and responded immediately. Underperforming routes were either cut entirely, or had their frequency curtailed. Industry analysts said jet fuel went from just under 20% of airline expenses before summer 2018 to as much as 25% in some cases.

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In the LOOP: Imports of Kuwaiti crude fall 60.5% year on year

Imports of Kuwaiti crude into the Louisiana Offshore Oil Port have fallen by 60.5% year on year as of September, with rising Iraqi crude imports failing to make up the full loss.

For the first nine months of 2018, only 8.347 million barrels of Kuwaiti crude were imported into Morgan City, Louisiana, the delivery point for LOOP, according to data from S&P Global Platts Analytics and US Customs data. This marks a steep fall from a total volume of 21.128 million barrels for the same time period in 2017.

In September, Kuwaiti crude imports into LOOP fell to zero, with July and April also failing to see any similar imports into Morgan City. By comparison, September 2017 saw about 994,000 barrels of Kuwaiti crude brought into the port for domestic consumption.

As imports of Kuwaiti crude have dropped, volumes of Iraqi crude, including Basrah Light, have increased by about 26% year on year. For the first nine months of 2018, Morgan City saw 50.67 million barrels of Iraqi crude imported, compared with only 40.09 million barrels for the comparable time period in 2017.

The impending shortage of Iranian crude barrels in the market due to the looming implementation of US sanctions has led to an increase in demand from Asian buyers for comparable barrels, according to market sources. As a result, more Kuwaiti barrels have been diverted away from the US Gulf Coast and toward markets in Asia.

A wider swap spread between second-month Dubai futures and front-month WTI futures has also served to push higher volumes of domestic medium sour grades such as Mars that way. With US crude exports remaining strong in recent months, domestic supply is becoming somewhat tight, according to an industry source.

As the arbitrage east has opened up, the assessed value of medium sour domestic grade Mars has rebounded from a 21-month low of WTI cash minus $2.90/b on July 23 to $5.40/b Friday, with domestic buyers forced to pay higher prices to prevent foreign buyers from securing increasingly larger volumes.

Kuwait Export Crude, along with Basrah Light and Arab Medium, are delivered into LOOP’s Segregation 17 crude blend. Segregation 17 is blended with Mars and Poseidon to form the LOOP Sour crude stream. LOOP Sour has averaged 29.5-30.5 degrees API gravity and 2.11%-2.9% sulfur content over the past 12 months, making it most similar to Mars in terms of API gravity and Arab Medium in terms of sulfur content.

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African upstream recovery raises funding dilemma: Fuel for Thought

Chinese President Xi Jinping last month announced a new $60 billion financing package in aid, investment and loans to Africa, as the world’s biggest energy importer continues to expand its global influence.

Part of that pledge will further underpin efforts by China’s state oil giants to help develop the region’s sizeable oil and gas resources.

For many existing and would-be African oil and gas producers, the promise of new funds to
kick-start upstream activity after years of shrinking spending will be a welcome breath of
fresh air.

Africa upstream recovery raises funding dilemma:: Oil majors head back to NamibiaFrontier African exploration was one of the main casualties of the oil price slump. When the
returns from $100 oil evaporated, industry concerns over the region’s political instability, local disputes and legal uncertainty soon resurfaced.

With oil prices now hovering around $85/b, the region is eager for a fresh wave of upstream
investment, and many governments are asking which kind provides the swiftest returns with
the fewest strings attached.

Speaking at an Africa Oil and Power event in Cape Town in early September, some regional
oil ministers—many of whom had just returned from Beijing’s triennial African investment
forum—voiced cautious optimism that more Chinese investment is the best option.

“We are open to all offers but they [the Chinese oil majors] are offering the best prices, the most money. It’s that simple,” said the oil minister of one sub-Saharan oil and gas producer.

But not everyone will be happy to hear of China’s latest push to boost its control of the continent’s energy resources. Some industry players question the rationale of giving China’s state oil majors even more access to upstream resources.

The head of one independent oil explorer operating in Niger, where Chinese state oil major CNPC already dominates oil finds in the Agadem basin, voiced concerns that Chinese oil firms are “just sitting on” discoveries, happy to pay license fees and meet local content commitments to control the assets but with little motivation to actively develop the finds.

CNPC also controls most of South Sudan’s oil and inked agreements to expand its upstream footprint there as well as in Uganda and Kenya in the days before of the Beijing investment forum.


Without doubt, Africa’s remaining oil and gas potential across its little-explored resources basins remains vast.

Under a conservative scenario, a US Geological Survey report in 2016 estimates a 95% chance that at least 41 billion barrels of oil and 319 trillion cubic feet of gas are still up for grabs in sub-Saharan Africa.

Time may also be running short to get these resources to market. Like the oil industry itself, regional governments are acutely aware of the narrowing window of opportunity to develop and monetize their resources as climate change concerns cloud the future of fossil fuel demand.

With oil prices recovering, concerns that cash-flush oil companies will snap up control of new acreage on offer is not confined to China’s state-backed giants.

Speaking in Cape Town, Equatorial Guinea’s energy minister Gabriel Mbaga Obiang warned the return of western oil majors to African exploration projects as upstream spending bounces bank threatens to slow down, rather than accelerate, the pace of new finds in the region.

“Majors are like big elephants, they are very slow. That means that the development of fast-tracking initiatives will slow down,” Obiang said on the sidelines of the event.

Acknowledging that deep-pocketed global oil majors are well suited to developing existing
discoveries, the minister said the swift return of oil and gas “superpowers” to African exploration plays can make less sense for countries keen to quickly locate new resources.

Oil majors can often take longer to assess, prioritize, execute and appraise frontier exploration drilling compared to more nimble, tightly-focused independent explorers, Obiang said.


His concern is sharpened by the pace at which energy majors are rushing back to Africa as oil prices firm. While the big players have successfully conserved cash and slashed costs during the downturn, many less project-diverse independents are still laboring under heavy debts and meager cash flows.

As a result, more agile, less risk-averse independent explorers are being outgunned in the competition for new quality exploration acreage to rebuild resources depleted during the spending slump.

Last October, Total took a majority stake in a Namibian block, and one in South Africa, from
UK-based independent Impact Oil and Gas.

Shell secured its first exploration acreage off the coast of Mauritania in July, while ExxonMobil acquired stakes in Namibian fields from both Portugal’s Galp in February and from minnow Azinam in August.

Clearly, as the appetite for African exploration heats up, regional leaders appear to be facing tough decisions over whether to favor hard cash or more operational focus and resolve.

For Equatorial Guinea, at least, the answer lies in prioritizing exploration activity on the ground.

“We need to drill, that’s the only way and we want companies that are willing to do that,” Obiang said. “If you want to be in Equatorial Guinea, you drill. If you don’t want to drill, we’ll look for someone else.”

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IBTX client @UlterraBits is bringing in pink drill bits for Breast Cancer Awareness Month! Anyone else showing their support in creative ways?

IBTX client is bringing in pink drill bits for Breast Cancer Awareness Month! Anyone else showing their support in creative ways?


Insight: US natural gas, coal markets calm about low inventories … for now

The growth of low-priced natural gas supply from Appalachia and Texas appears to be changing the market calculus on winter heating demand this year.

With pre-winter gas inventories sitting at their lowest levels in over a decade, prices remain near historic lows. In the coal market, inventories are also at their lowest level in more than a decade, but prices have shown little reaction.

For both commodities, an early or colder than normal winter could have a significant impact on pricing. Winter gas prices in some parts of the US suggest squeezes lie ahead. But until demand shows up, the markets for both fuels seem to believe supply will be available when it is needed.

In general, the market seems to be saying, “what’s the rush?”


US natural gas storage history and forecast


Despite low inventory levels in the gas market, recent supply growth has led traders to believe that flexible production should be sufficient to meet residential-commercial heating demand this winter in most areas.

Through late September, US gas production has averaged more than 83.3 Bcf/d for the month, according to a modeled estimate from S&P Global Platts Analytics. In the past 12 months, production is up 13%, or about 9.7 Bcf/d, with more than half of that growth coming from Appalachia and one-quarter from Texas.

In late September, the US Energy Information Administration reported total gas stocks at 2.77 Tcf, down 18.3% from the five-year average. Gas in storage should end the injection season in early November at less than 3.3 Tcf, which would be the lowest level since 2005.

Meanwhile, gas demand is expected to rise. Demand is forecast to average 79.6 Bcf/d in 2018, according to EIA data. That would be a 5.4 Bcf/d, or 7.3%, increase from 2017.

So far, strong production growth has kept a tight lid on benchmark US gas prices this year. At the Henry Hub, the cash market has traded at an average $2.91/MMBtu from January 1 to date. The prompt futures market has been even weaker, with NYMEX Henry Hub natural gas futures averaging just $2.84/MMBtu over that same period, S&P Global Platts data shows.

The forwards market appears to reflect a similar price outlook. As of late September, the 12-month forward curve at the Henry Hub was priced at an average of just $2.87/MMBtu.

Coal stockpiles

Coal prices also remain subdued despite low inventory levels, but could rally quickly if winter weather and rising gas prices lead to a shortage.

Powder River Basin coal, largely mined in Wyoming, makes up roughly half the market for thermal coal in the US. Stockpiles have shrunk in the last two years, and are now at levels not seen since 2006, when rail issues in the Powder River Basin led to a precipitous decline in inventories.

According to the most recent EIA data, utility coal stockpiles at the end of July stood at 110.5 million st, down 27.1% from the five-year average. S&P Global Platts Analytics estimates stockpiles stood at 107 million st as of last week.

The price for physical CSX coal has shot up in recent months to more than $70/st, but that has largely been due to export demand fueled by higher pricing in Europe.

For PRB 8,800 Btu/lb coal, however, which is not subject to export demand due to its relatively low heat content and distance from port, the price has remained stable. Since May, the price for PRB 8,800 for prompt-month delivery has averaged $12.44/st.

This stability despite low stockpiles is the result of a lack of demand, driven by both low gas prices and fears of over-contracting for coal. Coal buyers believe that if coal demand increases due to cold weather, there will be plenty of supply.

Coal producers, however, are warning that should gas prices rise this autumn or winter due to cold weather, utilities may find themselves with too little inventory, sparking a rally in prices.


Midwest winter basis averages


In contrast to the broader US gas market, elevated winter prices in the Midwest suggest that traders are concerned that the recent growth in aggregate US gas supply may not be enough to meet demand there — especially on the coldest winter days.

In recent trading, the January-2019 and February-2019 forwards contracts at Chicago city-gates have climbed to nearly a 30 cent/MMBtu premium to Henry Hub. As recently as June, those same forward contracts were trading at a discount to the benchmark price.

Other regional hubs have seen a similar price trajectory.

At the Northern Ventura hub in Iowa, the two winter forwards contracts were trading recently at nearly a 70 cent/MMBtu premium to the benchmark. At Dawn Hub in Ontario, January and February forwards were recently priced at an average 24 cent/MMBtu premium.

Midwest forwards markets’ premium to Henry Hub could provide an opportunity for coal to regain some share of the generation mix, at least this winter. If prices remain stable, PRB 8,800 coal should stay competitive throughout the fall and winter and could even add some market share due to relatively low delivered costs.

Nationwide, the average delivered cost year to date for PRB 8,800 coal was $1.92/MMBtu through June of this year, according to EIA data.


US natural gas storage by region


Even with new pipelines bringing more gas from Appalachia to the Midwest, the risk of regional supply shortages seems to be driving prices in some locations.

Established supply arteries like Rockies Express Pipeline will move much of this gas west. But increasing volumes on Rover Pipeline and later this fall, Nexus Gas Transmission, will provide additional volumes, most notably to the Michigan and Dawn markets.

Aggregate flows from Appalachia to the Midwest should average about 5.3 Bcf/d from December 2018 to February 2019, according to S&P Global Platts Analytics.

On the coldest winter days, though, high utilization of the region’s supply pipelines means that certain Midwest hubs may be more dependent on gas in storage to meet demand. Midwest gas storage is currently sitting at 800 Bcf, about a 15% deficit to the prior five-year average.

The post Insight: US natural gas, coal markets calm about low inventories … for now appeared first on The Barrel Blog.