Funding the main challenge for Indian steel growth

India’s steel production is expected to almost double by 2025 and M&A activity could result in a leaner industry, but headwinds remain, including tight credit lines and exposure to raw material prices.

S&P Global Platts spent a week in India in November, mainly to host our Steel Markets Asia conference in Mumbai, but also to meet with companies and visit operations. There was plenty of positivity about the state of the local steel market, as well as a few notes of caution.

S&P Global’s Indian subsidiary CRISIL predicts steel demand will grow around 7%-8% CAGR in coming years, driven by significant infrastructure investment, new affordable housing developments and strong auto sector growth. The industry consolidation process currently underway will make the steel industry more efficient and robust, and provide a more solid growth platform, most believe.

Once all of the bigger assets, such as Essar Steel and Bhushan Steel, have been acquired and integrated, another round of M&A among smaller “secondary” producers – which comprise at least 40% of the total industry in terms of output – is expected to take place.

This year Indian monthly crude steel production sneaked past that of Japan, making it the second-largest producer after China. India produced 88.4 million mt of crude steel over January-October, up 5.5% on last year, compared with 87.2 million mt from Japan over the same period, according to World Steel Association data.

Privately-owned JSW Steel expects India’s annual crude steel production to reach 195 million-200 million mt by 2025 on the back of large brownfield expansions by the larger steel producers. To meet the Indian government’s ambitious capacity target of 300 million mt/year by 2030 – the key plank of its National Steel Policy – would require the development of large greenfield projects, which have always proved troublesome in India due to a lack of access to land, red tape and difficulty in securing project approvals.

Financing conundrum

One of the major challenges that India faces is how to finance its infrastructure program. One speaker at the Platts conference estimated there would be a funding gap of around 30% over the medium term. GDP would need to grow at 8% to pay for all the bridges, roads, ports and smart cities planned by the government.

Credit remains tight in India. Indeed, there was a face-off between the Reserve Bank of India and the government on November 19. The government wanted to pry open the central bank’s purse and unleash more liquidity into the system – particularly with an election due in April. Meanwhile, the private sector is largely sitting on the sidelines, meaning the public sector needs to shoulder most of the funding burden. Prime Minister Modi had hoped that significant public investment in public works would entice the private sector to participate, but it hasn’t happened. Further, India’s government does not have the “deep pockets” enjoyed by China. As a result, nobody is quite sure how India will pay for its infrastructure plans and therefore project completions are likely to be pushed way beyond scheduled timelines.

New Delhi has sped up infrastructure development ahead of the election in early 2019. There is a 90-day moratorium on new project approvals before an election, which has also contributed to the urgency on view now. Work could slow slightly after the general election, which is expected in April or May, and there may be some easing of economic growth until momentum picks up again.

Therefore, while the growth trajectory is undoubtedly strong and long term, the curve may be slightly flatter than many in India would like.

On the raw materials side, India is still susceptible to coking coal price spikes, being almost wholly dependent on imports. The country is expected to import around 50 million mt this year, up around 5 million-6 million mt on last year.

Though India does have significant iron ore reserves, upcoming auctions in 2020 are expected to result in some supply shortages while licenses are renewed. This year, India could import around 10 million mt of iron ore, mainly from Australia’s Fortescue Metals Group. Some at the conference were tipping imports of around 20 million mt in 2019.

The post Funding the main challenge for Indian steel growth appeared first on The Barrel Blog.



Scrubbers under scrutiny by maritime industry as IMO 2020 nears

Looming 2020 regulations capping marine fuel sulfur at 0.5% have so far benefited manufacturers marketing scrubbers – or exhaust gas cleaning systems, as they are more formally known – but this solution is now being viewed with a more critical eye.

At the 12th annual MARE Forum on November 27 in Houston, one of the biggest topics debated by the maritime and shipping market delegates in attendance was the role of scrubbers, which have enjoyed increasing popularity with shipowners in 2018, in meeting the tightening environmental rules.

Go deeper: S&P Global Platts podcast on IMO 2020’s challenge and opportunity for shipowners

Scrubber manufacturers marketed their systems with the promise of ‘business as usual’, as the exhaust gas cleaning systems essentially scrub the sulfur from currently used 3.5% sulfur bunker fuel to the mandated 0.5% sulfur ceiling.

But this version of ‘business as usual’ also includes the not-so-usual neutralization and disposal of the sulfuric acid washwater, as well as the maintenance of the scrubber. Because the systems have not yet been tested widely on long-haul voyages, their reliability gives cause for concern.

Scrubber uptake quadrupled in 2018

Derek Novak, Senior Vice President of Engineering and Technology and the American Bureau of Shipping, explained at the forum that the total adoption of scrubbers as of October 2018 amounted to 1,509 units, with 665 to be installed on newbuild vessels and 844 to be retrofitted.

He expects that a total of 2,000 to 3,000 vessels will be outfitted with scrubbers to comply with the new regulations. Assuming the total merchant marine fleet amounts to close to 60,000 vessels, those 2,000-3,000 scrubbers make up only 3%-5% of the entire fleet.

According to S&P Global Platts Analytics, the number of scrubbers installed and ordered at the end of November amounts to 1,948 units, while the total number of systems installed and ordered by January 2020 is forecast at 2,278, consuming around 500,000 b/d of high sulfur fuel oil.

pace of vessel exhaust scrubber installations hastens ahead of IMO 2020 deadline

Environmental impact

Many speakers on the MARE panel expressed concerns about the use of scrubber systems as to power availability, vessel maneuverability in ports, and increased emissions through scrubber use. Novak suggested that scrubbers would present space challenges on retrofitted vessels due to funnel enlargement and potential issues of power availability, as vessels would require more power to run the scrubber while steaming.

Keynote Speaker Rear Admiral Paul Thomas expressed concern that the scrubber systems would not meet the goal of reducing the environmental footprint of the maritime industry as envisioned by the IMO’s 2020 sulfur level reduction regulation, but rather provide a short-cut road to compliance. “You choose to take sulfur out of the air and put it into the ocean or onto land,” Thomas said. He explained that open-loop scrubber systems were short-term at best and would likely be regulated, as they do nothing to reduce a vessel’s environmental footprint. Captain Anuj Chopra, Vice President of Rightship, a provider of maritime and environmental risk management systems, pointed out that the use of scrubbers would increase environmental emissions of up to 5% through additional energy used to power the cleaning systems.

These concerns have not escaped local regulators. The Singapore Port Authority announced on November 30 that it will ban the discharge of wash water from open-loop scrubber systems as of January 1, 2020, requiring the use of compliant fuel in the port.

Availability and bottlenecks

Additional concerns circled around the availability of 3.5% sulfur bunkers, which scrubber-installed tankers would continue to use after January 1, 2020. With most bunkering locations preparing to offer the new regulation 0.5% sulfur material, many of the forum’s speakers believed high-sulfur bunker availability would be difficult to come by in the less-trafficked regions frequented by the tanker tramp trade, in particular in South America, Africa and Southeast Asia.

Should 3.5% sulfur fuel be unavailable at a port, vessels with scrubber systems would have to use fuel with differing sulfur contents, including lower-sulfur fuels, dampening the economic benefit from the low/high-sulfur spread and thus extending the payoff period of the scrubber system, said Kathy Metcalf, president and CEO of the Chamber of Shipping of America. Pay-off is generally indicated at between 0.5-3 years, depending on the size of the scrubber, distances travelled, bunker consumption, and the price gap between high-sulfur bunker fuel and marine gas oil, which is currently forecast anywhere between $250-$400/mt.

Infrastructure can also substantially bottleneck high-sulfur fuel supply, as bunker suppliers have yet to determine how many fuel barges they should clean up and which to keep for higher sulfur fuels. Buffalo Marine Services’ General Counsel Thomas Marian mentioned that fuel barges take two to three weeks per wash, which, should the decision to clean the vessels continue to be delayed, could become another infrastructure bottleneck.

Short of time

Panelists warned that time was running out for shipowners to fully prepare for the IMO 2020 implementation in view of both equipment availability from top-tier scrubber manufacturers and shipyard capacity for installations.

Shipowner Scorpio Group and Pacific Green Technologies Group, owner of the ENVI-Marine Exhaust Gas Scrubbing System, alone announced the week of December 3 that they have agreed to purchase and manufacture 60 scrubbers in 2019 with an additional 20 units in 2020.

Shipowner planned scrubber installations

In addition Scorpio Tankers and Scorpio Bulkers have executed a framework agreement with Pacific Green Marine Technologies, a wholly owned subsidiary of Pacific Green Technologies Group, whereby Scorpio can elect for PGMT to design and engineer scrubbers for up to a further 28 and ten vessels, Pacific Green Technologies said in a statement.

While an increasing number of shipowners has decided to steam the scrubber way, others are less convinced by the benefits. Ardmore, Euronav, Odfjell and Teekay tankers have opted not to scrub as they view the systems as a stop-gap measure until compatible low-sulfur fuels become available.

The post Scrubbers under scrutiny by maritime industry as IMO 2020 nears appeared first on The Barrel Blog.


Tellurian-Vitol LNG deal signals shifting balance of power

The preliminary LNG offtake agreement announced on December 6 between export developer Tellurian and trader Vitol, marks a conspicuous shift in the balance of power in LNG contract markets.

The memorandum of understanding calls for Vitol to lift 1.5 million mt/yr, equivalent to nearly 70.1 Bcf/yr of gas, on an FOB basis from Tellurian’s Driftwood LNG-export terminal over a 15-year term.

What makes the otherwise routine supply agreement so consequential is that Vitol’s purchase price is actually linked to a destination market price in northeast Asia—the Platts JKM.

It is among the first, if not the only such agreement in the global LNG market.

For the buyer Vitol, the deal dramatically reduces market risk since its contracted LNG-purchase price effectively includes a built-in margin for profit.

While Vitol pays more for LNG as the JKM rises, it also pays less as the benchmark index declines.

If that destination-market linkage wasn’t compelling enough, the agreement also includes a shipping component, further reducing the risk imposed by fluctuating charter rates in the global freight market.

Export margin

In recent weeks, volatility in LNG-import and shipping markets, and even in the US onshore gas market, brings some perspective to those contract terms.

In Northeast Asia, flagging demand for winter LNG supply has seen the JKM tumble. On December 8, the index sank to just $8.75/MMBtu, down from a multi-year high at over $12/MMBtu in September.

At the same time, shipping rates have skyrocketed, recently hitting their highest on record $190,000/d in the Asia Pacific Basin. While prices have since declined modestly, a US Gulf Coast LNG offtaker is still paying nearly $3.60/MMBtu to reach Japan/Korea, and about $4.30/MMBtu to South China or Taiwan.

Meanwhile, the feedstock cost for US LNG exporters has climbed sharply in recent weeks, tracking the upward trend in NYMEX prompt-month futures, which were trading Friday at close to $4.50/MMBtu.

Under more typical, existing LNG-offtake contracts, recent market volatility has crushed the margin on US LNG delivered to northeast Asia.

LNG netbacks to Sabine Pass shrink in 2018

After paying gas feedstock and onshore transport costs, equal to 115% of the NYMEX Henry Hub, plus shipping, Panama Canal and related freight fees, the profit margin on US LNG delivered to Japan/Korea is actually negative, according to Platts Analytics.

What’s more, that calculation actually excludes the liquefaction fee, ranging from $2.25/MMBtu to $3.50/MMBtu since it’s typically considered by the industry to be a “sunk cost”.

Second-wave exports

In an interview Thursday, Tellurian CEO Meg Gentle said that the exact details of the offtake agreement with Vitol were still being ironed out, so it remains unclear what export-price floor Vitol might face, or whether a liquefaction take-or-pay fee or some more flexible option fee would apply for the buyer.

Regardless of the agreement’s exact terms, the announcement was likely unnerving to the US’ second wave of LNG export developers that are now in contentious pursuit of offtake contracts, particularly from buyers in Asia’s growing import market.

Go deeper: S&P Global Platts special report on LNG financing

While the offtake agreement was Tellurian’s first, making them more likely to accept contract terms generous to the buyer, it still speaks volumes about the shifting balance of power in LNG contracting markets.

If Gentle’s prediction is correct that the Platts JKM could become an index price for US LNG exports, the move implies much stiffer competition ahead for second-wave projects developers.

The US’ largest LNG exporter, Cheniere Energy, currently holds contracts linked to the NYMEX Henry Hub price, effectively shielding the producer from fluctuations in the cost of feedstock gas.

For second-wave producers, though, the ability to delink their feedstock gas cost from Henry Hub—and potentially source gas at a fraction of the benchmark price thanks to new investments—might be their best way to compete heading into the 2020s.

The post Tellurian-Vitol LNG deal signals shifting balance of power appeared first on The Barrel Blog.


In the LOOP: Three VLCCs depart LOOP for India, South Korea

Three VLCCs departed the Louisiana Offshore Oil Port over the week ended December 8, with the crude cargoes on board bound for India and South Korea.

LOOP did not release the names of the vessels that were loaded and it was unclear exactly which VLCCs departed the port for export. However, cFlow, Platts’ trade flow software, reported that three laden or partially laden VLCCs exited LOOP last week.

The Khurais set sail from LOOP on December 5 and is bound for Kochi, India, according to cFlow. It is expected to arrive at the west coast of India on January 12. Another vessel, Lulu, left LOOP on December 7 and is expected to arrive at India’s east coast port of Paradip on January 19. The third VLCC, Maharah, was loaded at LOOP and set sail December 2. It is expected in Daesan, South Korea, on January 23.

The three VLCCs were loaded with crude sourced from LOOP’s Clovelly Hub, including a light sweet crude grade, most likely either LLS or WTI MEH, according to industry sources. The remaining two cargoes could contain Mars, Poseidon or LOOP Sour crude. The three VLCCs were loaded one after the other, representing a reduced overall load time at the port, according to LOOP.

Both sweet and sour grades have made their way to India and South Korea in recent months, including WTI MEH, Mars and Poseidon grades. The month two Dubai and month one WTI swap spread, has widened 41 cents/b to $6.75/b since the start of the fourth quarter. As Dubai’s premium over WTI increases, WTI-based grades become more competitive with comparable Dubai-based grades in export markets.

On Monday, S&P Global Platts assessed LOOP Sour CFR North Asia at $60.76/b, falling below the comparable values for competing grades Dubai, assessed at $62.33/b, and Basrah Light, at $61.88/b. The assessed WTI MEH CFR North Asia value of $63.93/b, while higher than competing grade Murban at $63.35/b, was still slightly lower than the CFR value of Forties at $64.01/b.

US crude oil exports surged to reach a new all-time high of 3.2 million b/d for the week ending November 30, according to data released last Thursday by the Energy Information Administration. The total surpassed the previous record of 3 million b/d, which occurred the week of June 22. The record exports helped create a draw on crude oil inventories, which came after 10 weeks of builds.

The post In the LOOP: Three VLCCs depart LOOP for India, South Korea appeared first on The Barrel Blog.


Qatar’s OPEC exit could backfire on LNG superpower

Qatar’s reasons for exiting OPEC look muddled. The tiny Persian Gulf sheikhdom says it wants to concentrate on building on its position as the world’s biggest exporter of liquefied natural gas (LNG) instead of being a minor player in an oil cartel dominated by Saudi Arabia. Aside from saving on membership fees, leaving the group has few benefits and many risks.

Politics had nothing to do with the decision, which came as a complete surprise to OPEC and its allies, according to Qatar’s new energy minister Saad Al-Kaabi. At a press conference in Vienna on the sidelines of tense talks between the world’s most powerful oil men this week, he said Doha was a small oil producer and it had very little influence over OPEC’s decisions.

True, Qatar pumped daily just over 600,000 barrels of crude oil last month out of an ocean of over 33 million b/d produced by OPEC as a whole, according to a survey of output by S&P Global Platts. However, bringing to an end 60 years of membership comes as Doha is isolated by its powerful Gulf neighbors Saudi Arabia and the UAE. Both regional superpowers are leading an economic and diplomatic blockade after accusing the country’s rulers of supporting extremism in the region.

Map of Qatar's oil and gas fields

“I was behind the recommendation for this, and I have been known as the gas man for a long time,”  said Al-Kaabi. “So it just took time to go and get approvals from your leadership, because it’s a sovereign decision, not a ministerial decision, to leave OPEC.”

Al-Kaabi isn’t the first Qatari official to brand themselves a “gas man” but he is the first to turn his back on OPEC. His predecessor and mentor Abdallah bin Hamad al-Attiyah managed to build the country’s LNG industry from scratch and punch above his weight in the cartel. Al-Attiyah – who stepped down as energy minister in 2012 – was one of OPEC’s most influential presidents and was even invited to head the group as its secretary general.

Go deeper: S&P Global Platts factbox on Qatar’s withdrawal

In more recent history, Qatar played an active leadership role in 2015 building bridges behind the scenes with Russia. This early outreach eventually led to the formation of an alliance with OPEC to cut production and reverse the worst crash in oil prices in a generation. OPEC arguably gave Qatar a more influential voice at the world’s most important energy price setting table, which it has now voluntarily sacrificed. Under closer scrutiny the decision to leave looks flawed and even dangerous if it provokes retaliation in the Middle East.

Not all Qataris were as diplomatic as the country’s energy minister when justifying the surprise move. And who can blame them after two years of political and economic isolation. Saudi Arabia has threatened to build a canal between the two countries to create a physical barrier – such is the enmity and bad blood between the former allies. Meanwhile, Abu Dhabi has decreed showing support for Doha on social media is a crime in the emirates.

“This organization has become useless and adds nothing to us,” Sheikh Hamid bin Jassem, Qatar’s former prime minister and influential royal, tweeted soon after the decision to leave OPEC was announced. “It is only being used for purposes aimed at harming our national interest.”

Of course, Qatar isn’t the first country to grow tired of OPEC’s bickering and the costs of participating in its endless meetings in Vienna. Gabon, withdrew only to rejoin 20 years later. Likewise, Indonesia left, came back and resigned again in 2016 in disgust over production cuts.

For energy markets focused on fundamentals Qatar’s exit could mean more uncertainty and volatility. It also makes OPEC look increasingly like a duopoly between Saudi Arabia and non-member Russia, which has been given a seat at the table anyway. Their increasing domination over decisions on output and the influence of US President Donald Trump could gnaw away at unity within the cartel. Qatar’s withdrawal comes as OPEC has tried to recruit new members, including the Republic of Congo and Equatorial Guinea, to try to remain relevant in a world where the US is now a net exporter of crude and the biggest producer.

“The exit of Qatar is suggestive of growing dissatisfaction among OPEC nations with the Saudi’s leadership,” said Ashley Kelty, oil and gas research analyst at Cantor Fitzgerald. “We’d suspect that many of the members are wary of how much influence the US has over Saudi Arabia, and whether this leads to decisions that are not necessarily in the best interests of OPEC.”

Iran has gained from Doha’s withdrawal. Isolated by US sanctions aimed at restricting its oil production, Tehran has used the Qatari decision to strengthen its own negotiating position within OPEC and managed to squeeze a valuable concession on production cuts of 1.2 million b/d agreed Friday after days of arduous talks. Qatar and Iran maintain cordial relations despite traditional Arab political allegiances and both share access to the world’s largest offshore natural gas field in the Persian Gulf.

Although Qatar accounts for less than 2% of OPEC’s crude output its overall importance to global energy supply is much greater. Combine its near 80 million mt/year of LNG and significant output of gas condensates and the tiny sheikhdom has a total output equal to about 5 million b/d of oil equivalent. Its plan is to boost LNG output by 30% to 110 million mt/y, but it is unclear if this goal will be more attainable sitting outside OPEC.

If its new status outside the cartel adds to the growing risks and challenges of investing in Qatar then probably not. Leaving OPEC may serve as a snub to its rivals but it leaves Doha looking isolated and exposed when it needs friends the most.

This article was first published as a column in The Telegraph.

The post Qatar’s OPEC exit could backfire on LNG superpower appeared first on The Barrel Blog.


We are excited to announce @JayNovacek84 as the Keynote Speaker for the 2018 Kickoff Luncheon! The luncheon, presented by @AmericanAir and @OmniHotels Fort Worth, will be held on Friday, Dec. 21 Details & ticket info:

We are excited to announce as the Keynote Speaker for the 2018 Kickoff Luncheon! The luncheon, presented by and Fort Worth, will be held on Friday, Dec. 21 🏈👏 Details & ticket info: 


Insight: Nigeria’s oil sector looks for sweet spot amid power struggles

“We are ready to bring it down. It won’t drill a barrel of crude,” tweeted Mudoch Agbinibo, the leader of the militant group Niger Delta Avengers, which in 2016 brought Africa’s largest oil producer to its knees with brazen attacks on the Delta’s oil facilities.

The tweet referred to the floating production storage and offloading unit of the 200,000 b/d Egina field, which is due to start up later this year, pushing up Nigeria’s oil output by over 10%.

Mudoch’s tweet came in February, as the Egina FPSO first reached the shores of Nigeria via a South Korean shipyard. This also happens to be the last time Agbinibo appeared on social media. The Niger Delta Avengers, a group of which little is known, have basically been dormant since then, barring for some apocalyptic threats.

Despite this hibernation by the group, the din in the Delta is gradually growing and the chances are high that the Avengers, along with a handful of other militant groups, will plan attacks on oil infrastructure. The government has so far also pledged to prevent fresh outbreaks of militancy and violence in the Niger Delta. It has found ways to keep the militants quiet through a cluster of promises on money and development, and a shaky amnesty program.

The amnesty program began in 2009 by former President Umaru Musa Yar’Adua was meant to fight militancy in the Niger Delta by offering incentives to young people to give up on oil theft and sabotage. It briefly worked, but critics argue the program has now morphed into a money-for-peace model that is unsustainable. New militants have emerged over the past decade to replace the old ones, and the Delta remains just as fragile.

Nigeria’s oil industry can best be described as mercurial. It produces probably the best quality crude in the world, yet this oil has created deep fractures in its society fueling militancy, corruption and mistrust that has thrived in a country beset by economic and regulatory uncertainty.

2019 elections

Now, the country faces a fresh challenge as it heads into a volatile presidential campaign season ahead of its February 2019 elections. Popular export grades like Bonny Light and Forcados have been riddled with pipeline sabotage issues this year, but Nigeria has managed to restore some production after it fell to 30-year lows in 2016. Nigeria’s crude and condensates output, which plummeted to 1.1 million b/d in mid-2016 due to renewed militancy in the Delta, has been climbing gradually and averaged just over 2 million b/d in September.

Maintaining production at full capacity of 2.2 million b/d has been a struggle for any government in the past decade, and it isn’t going to get any easier. The quandary for President Buhari is that his political rivals have found common cause with militants in undermining Niger Delta security. Most analysts expect disruptions to Nigerian oil output of around 300,000 b/d leading up to the elections.

“While large attacks of oil infrastructure remain unlikely, the volume of oil theft and minor disruption is likely to increase… and may push IOCs to declare force majeure on Nigerian crude streams,” consultancy Rapidan Energy said in a recent note. The attacks are also likely to fan the flames between the Christian south and Muslim north, reinforcing a popular narrative that Buhari is doing more to grow the oil sector in the north rather than in the Delta, which remains the heart of the oil sector. This narrative has been supported by recent announcements by the Nigerian National Petroleum Corporation that it will start oil exploration in the Lake Chad basin, along with plans to build a new refinery near the Niger border

Despite the oil potential in the north, the region remains dominated by the Boko Haram insurgency, limiting these prospects. Supported by Vice President Yemi Osinbajo and oil minister Emmanuel Kachikwu, Buhari pushed for a 30% increase in amnesty program payments this year, along with a sizable increase to the budget of the Niger Delta ministry – part of a charm offensive to keep militants on side. In the past two years, President Buhari and his government have found ways to keep the militants quiet through promises of development, money and the amnesty program. But they face a stiffer challenge as the country heads into a volatile presidential campaign season.

Light and sweet

Despite all the unrest, the appeal of Nigeria’s crude, which is light and sweet, and of high quality, could face a brighter future. This crude is largely low in sulfur and yields a generous amount of diesel, jet fuel and gasoline, which are the profit-making products for global refineries. The Nigerian light sweet barrel – until almost a decade ago, every refiner’s most sought after barrel – was one of the biggest casualties of the US shale revolution. US shale oil is extremely similar in quality to light sweet Nigerian crude, and as more and more shale basins were discovered in its own backyard, the US, which used to be the largest buyer of Nigerian crude, did not need any more oil from Africa’s largest producer.

But the country’s light sweet crude could stage a comeback, as the International Maritime Organization’s 0.5% sulfur cap on marine fuels comes into effect in 2020. The regulation is expected to drive demand for lower sulfur products, triggering stronger demand and increasing the profitability of crudes that are low in sulfur. A big focus for Nigeria’s government and oil marketers is to broaden the popularity of Nigerian crude. Currently, the bulk of Nigerian crude goes to Europe and India. Europe’s oil demand is largely stagnant and it is awash with so many different types of crudes that it is tough to compete with cheaper, heavy sour varieties. So Nigeria needs to find innovative ways to market its crude to new buyers, particularly countries or regions where oil demand is on the rise, such as China, the world’s largest crude oil importer.

The West African country has taken some steps to broaden its customer base, but these are not enough. NNPC’s 2018/2020 crude oil term contracts, which came out earlier this year, were handed to more than 60 recipients – the largest list Nigeria has ever allocated. Officials have cited this as a demonstration of NNPC’s efforts to broaden its customer base and include more domestic companies, which may help Buhari ahead of the elections.

Many of the winners of the coveted contracts were domestic Nigerian companies that are new to the world of international oil trading. A lot of these firms have no experience in oil trading and will be transferring their allocations to bigger trading companies that have greater familiarity with end-consumer markets. The allocations might mean there is a larger pool of people involved in Nigeria’s crude oil term contracts, but it also means the murky oil business, already riddled with corruption, could get messier, especially ahead of the elections.

Reforms needed

Nigeria’s oil sector is in urgent need of a complete overhaul, but this looks unlikely to happen given the current political climate and February elections.

The Petroleum Industry Governance Bill is intended to bring order to the country’s oil sector. It seeks to change the way upstream agreements, fiscal terms and production sharing contracts are handled, while splitting NNPC into three different entities: an upstream and downstream company, as well as an independent regulatory commission.

Given the level of corruption in Nigeria, the passage of the PIGB has been looked on as the first step for the country to overhaul its industry and achieve its long-term oil production targets. However, it has been stuck in parliament for more than eight years, held up by political wrangling and objections from foreign oil companies that have said the significantly higher fiscal terms envisaged in recent drafts were unacceptable. Most recently, Buhari withheld his assent of the bill in August and sent it back to the National Assembly for review.

A provision of the PIGB includes curbing the powers of the Nigerian president and oil minister to award lucrative contracts on a discretionary basis and also to run the three new entities to be created from the state-owned NNPC. This is cited as one of the reasons Buhari has stalled the progress of the bill, showing how central oil is in Nigeria’s corridors of power. Some steps to address these issues will need to be a priority for the next administration.

Despite these challenges, Nigeria remains one of the key crude oil exporters globally, and the nature of its vast oil and gas reserves means it will continue to be a crucial player in energy markets.

This article is forthcoming in Oxford Energy Forum, the quarterly journal of the Oxford Institute of Energy Studies

The post Insight: Nigeria’s oil sector looks for sweet spot amid power struggles appeared first on The Barrel Blog.


Insight: Politics, not economics, drives decision-making in European gas

While politics have always played an important role in the energy sector, over the past few years a trend toward a new class of energy-related decision-making seems to have emerged, with non-economic or sub-economic policies increasingly in evidence.

European gas in particular is likely to be impacted by more protectionism-driven policies – from the US, the UK, Russia and others – as the application of national security goals in energy policy increases in significance, which in turn is having an impact on gas infrastructure investment, trade flows and prices.

The increasing politicization of European gas will inevitably lead to decisions on infrastructure – especially around LNG import facilities and pipelines – that will see shifts in European gas flows and gas price evolution, with infrastructure costs passed on into gas network charges and energy bills.

German LNG ambition

One country currently in the center of the politics-economics dichotomy is Germany. Europe’s biggest gas consumer with demand at around 90 Bcm/year, Germany has found itself in the middle of a political quagmire, with the US and Russia pulling at Berlin on either side and even Qatar making a play to impact Germany’s gas supply.

The German government’s support for an LNG import terminal, in particular, is questionable. Germany is possibly the best connected country in Europe in terms of gas supply, with direct links to Norway, Russia, the Netherlands and now southern Europe after Italy completed its reverse flow initiative in September. In addition, it can access LNG imports easily through northwest Europe’s chronically under-utilized facilities – such as Gate in the Netherlands, Zeebrugge in Belgium and France’s northern terminal at Dunkirk.

German LNG project plans

Germany’s economy minister Peter Altmaier in September went as far as to say that a German LNG import terminal would be a “gesture” to the US, which wants to help Europe wean itself off Russian gas by turning instead to US LNG. This is tantamount to admitting that Germany does not need an LNG import terminal when Europe’s existing plants are used at just one quarter capacity, according to S&P Global Platts Analytics.

European LNG imports vs. capacity

It could be argued that Germany would be better off with its own LNG import facility, giving German companies increased flexibility around renegotiating pipeline gas supply contracts with Russian gas giant Gazprom. And it might mean Germany can say it has a more diversified import mix following criticism from US President Donald Trump that Germany is “captive to Russia.”

Enter Qatar, which said it would be interested in supplying a future German LNG import terminal, perhaps in an attempt to find a foothold in Europe’s most important gas market.

Jonathan Stern, leading gas analyst from the Oxford Institute for Energy Studies, sees limited value in having an LNG import terminal in Germany. “The economic value is dubious,” he said. Germany had decades-old plans for an LNG import facility at Wilhelmshaven, which Stern said was arguably a much more commercially justifiable project at that time than the current scheme. “If it didn’t make economic sense then, I don’t see why a new project should now,” he said.

Poland’s plans to build the Baltic Pipe to import Norwegian gas via Denmark are also “economically crazy,” Stern said, and are solely based on Warsaw’s determination to become independent from Russia. Poland’s PGNiG has also signed a number of deals with US LNG suppliers to boost its import portfolio.

But just because you have an LNG import terminal doesn’t mean cargoes will come. In fact, European gas prices do not seem to be attracting US LNG despite low Henry Hub prices, with the increase in European gas demand met mainly by Russian gas imports over the past two years. LNG flows instead are following price signals from China and other Asian buyers, which are likely to have incrementally higher demand in the coming decades.

Spy story

The Russian “threat” has also led the UK to make some uneconomic noises with regard to gas supplies. Prime Minister Theresa May said the UK was “looking to other countries” for gas supply amid worsening relations with Russia triggered by the poisoning of ex-spy Sergei Skripal in the UK in March this year.

Estimates of Russian gas sales in the UK vary, but a closer look at import flows suggest that the UK needs Russian gas to some extent – physical flows are estimated at around 6 Bcm/year, all centered on the winter months, according to S&P Global Platts Analytics.

“There is a lot of geopolitical argy-bargy around Russian gas, with a lot of people trying hard not to say the real reason, which is that they don’t like or trust president Putin and therefore they don’t want Russian gas,” Stern said.

In the meantime, the UK almost fell foul of US sanctions against Iran given that one of the UK’s key gas-producing assets, Rhum, could have come under the renewed measures from Washington. As it happened, the US gave the BP-operated field – co-owned by Iran’s state-owned NIOC – an exemption from sanctions through to October 2019.

Russia also remains a target of US foreign policy, with the recent accusations of meddling in the 2016 US presidential election leading to the threat of further sanctions against Moscow. There is a risk that if more evidence comes to light of Russian political interference abroad, or if Moscow makes any more aggressive moves toward its neighbors, that the US – and the EU – would be forced to act to penalize Moscow’s energy sector further.

BP CEO Bob Dudley warned in October that any escalation of sanctions targeting Russia’s major oil and gas companies – such as Rosneft, Lukoil or Gazprom – would “shut down” Europe’s energy systems. Given the interdependence between Russia and Europe on gas supplies, it might require a serious shift in the political relationship to trigger any action, but anything is possible.

The role of the US is more nuanced. Washington – as it has done for decades – continues to attempt European gas market interventions with regard to Russia, with the difference that now it has its own LNG to sell. When it threatened sanctions against the Nord Stream 2 pipeline it prompted a particularly strong reaction from Germany and Austria, whose governments urged Washington to basically mind its own business.

The issue of Nord Stream 2 – the planned 55 Bcm/year pipeline from Russia to Germany bypassing Ukraine – has become extraordinarily political and has effectively divided Europe. Brussels and most of the countries of eastern Europe are dead against the project, while the home nations of its western European financial backers – Anglo-Dutch Shell, France’s Engie, Austria’s OMV and Germany’s Uniper and Wintershall – have been more tight-lipped on the issue.

The European Commission has also urged Moscow to commit to continuing transit via Ukraine to retain gas source and route diversity.

Russia remains intent on sidelining Kiev from its European gas transit arrangements, while the recent arbitration awards from the Stockholm court left Ukraine’s Naftogaz $2.6 billion better off. Not that Gazprom believes it should have to pay up. In the meantime, talks are being held at technical level between the energy ministries of Russia and Ukraine, and the EC, about what future Russian gas transit via Ukraine to Europe would look like.

It seems inevitable that some kind of deal will be reached – not least if Nord Stream 2 is delayed past its planned end-2019 startup – given how high the stakes are for both players. Ukraine has a good negotiating position – Gazprom has legally binding supply contracts in place with customers and if it cannot get the gas to them, it would be in breach of those contracts and face stiff penalties.

Italian job

Pipeline politics are also being played out elsewhere, with Italy at the center of the most recent controversy. Against all expectations, Rome has emerged as an unlikely stumbling block to the completion of the Southern Gas Corridor to bring Azeri gas to Europe.

There have been question marks over whether the new Italian government, which came to power in May, would look to block the TAP project, with environment minister Sergio Costa dismissing the pipeline as “pointless” and questioning its economic viability. Any delays to the construction of the pipeline infrastructure off- and onshore Italy could push back the timeline for TAP past its 2020 start date.

Shah Deniz links in with Southern Gas Corridor infrastructure

Political moves of a different kind are under way in Romania, meanwhile, where the ruling Social Democratic Party (PSD) is trying to push through new legislation that would see at least 50% of new Romanian offshore gas production reserved for the domestic market.

Producers – including ExxonMobil and Austria’s OMV which are hoping to develop the 84 Bcm Neptun gas field in the Romanian sector of the Black Sea – have said they would find it difficult to move to final investment decision under such conditions.

The PSD wants Black Sea gas output to predominantly be used for Romania’s “re-industrialization” and economic development. But Bucharest could be cutting off its nose to spite its face if it doesn’t give companies enough incentive to invest – no gas production at all is no good for anyone.

European gas prices and demand are also to some degree at the mercy of developments in other commodities – and politics and oil go hand in hand. Higher oil prices, in particular, tend to filter through to the broader energy complex and LNG prices in particular. The emergence of President Trump’s use of social media in a bid to put pressure on oil producers, especially OPEC, is a staggering development. And the recent bull run in oil is due mainly to the US reimposition of sanctions against Iran.

Other political decision-making is making its impact felt too: the US-China trade war is expected to have a dampening effect on global energy demand, while the specific move by Beijing to impose a 10% tariff on US LNG is expected to lead to more inefficiencies in the global LNG market, dragging up prices and raising questions over the economics of the second wave of US LNG projects.

Government policy on nuclear power is also a key factor in gas demand evolution. In the UK, the government’s decision to back the mega-expensive Hinkley Point nuclear power station despite strong opposition and limited economic value raised many eyebrows given the 3.2 GW project is expected to cost more than £24 billion ($31 billion) through its lifetime.

Meanwhile, the possibility of a rise to power in the UK of a Labour government – which has pledged to renationalize the UK energy sector – would be representative of politics outweighing economics in the most extreme of examples.

Environmental motivation

Other political decisions on energy are driven by more reasonable aims – such as environmental protection or supply security. The Dutch government has forced Shell and ExxonMobil to halt production at the giant onshore Groningen field by 2030, but likely much before then, leaving some 450 Bcm of gas in the ground.

Gas demand will also be buoyed in the future once the phase-out of coal in power generation across numerous countries in Europe takes full hold later in the 2020s. France’s plans to reduce dependence on its huge nuclear fleet could be revised with the country’s energy future linked to whichever administration is in power. A pan-European carbon price would also incentivize gas over coal, while renewables subsidies across Europe would impact gas demand to the downside.

So what of the future? It seems clear that the shift toward political decision-making in energy policy is here to stay for a while yet. New infrastructure – even if it is arguably in the wrong place or with questionable motivation – would likely be bearish for wholesale gas prices as it adds flexibility and optionality, but the costs will be passed on into network charges and energy bills.

Trade flows will shift – particularly on the back of increased LNG import capacity and a pick-up in US LNG imports – while the routes taken by Russian pipeline gas to Europe may look very different in a couple of years depending on political decisions.

Energy policy remains an important issue for voters, and with the rise of the populist governments in key countries, it is not altogether surprising to see such a change. It may require a change in the current state of global politics before economics can again take its place as the key driver of energy markets.

The post Insight: Politics, not economics, drives decision-making in European gas appeared first on The Barrel Blog.


In the LOOP: LOOP Sour deliveries rebound in November from multi-month low

The Louisiana Offshore Oil Port said Saturday that about 17,670 b/d of LOOP Sour was delivered ex-cavern from the US Gulf Coast crude terminal in November, which was over a 40% increase from the month before.

LOOP said 520,000 barrels of the medium sour crude blend were pulled from the Louisiana cavern last month. That was an increase from the 370,000 barrels delivered in October, which marked a more-than-one-year low. Deliveries dipped in October as the market shifted from backwardation to contango, making storing crude more attractive. However, that contango has eased and the market has become slightly backwardated, a trend that would make crude storage less favorable.

LOOP Sour delivered ex-cavern in November had an average API gravity of 29.6 and sulfur content of 1.94%, LOOP data published Saturday showed. LOOP Sour comprises US Gulf of Mexico grades Mars and Poseidon and a crude blend called Segregation 17, named after a cavern into which the Middle Eastern grades Arab Medium, Basrah Light and Kuwait Export Crude can be delivered. The grade has been most similar to Mars in terms of API gravity over the past 12 months, averaging 0.33 degree off Mars’ typical 29.44; and to Arab Medium from a sulfur standpoint, averaging 0.02 percentage point off Arab Medium’s typical 2.53%.

The post In the LOOP: LOOP Sour deliveries rebound in November from multi-month low appeared first on The Barrel Blog.