Energy

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South Korean state-owned Korea Gas Corp.’s LNG imports rose 3.8% to 33.064 million mt in 2017 from 31.846 million mt the year before, a company official said Thursday.

This marks the second consecutive annual increase in the country’s LNG imports after two years of declines, and comes as the country’s domestic LNG demand is expected to increase on the back of President Moon Jae-In’s push to reduce reliance on coal and nuclear for power generation.

The official did not disclose how much Kogas imported in the fourth quarter. But given its imports over January-September totaled 24.428 million mt, up 11.7% year on year, it imported 8.636 million mt in Q4, down 13.4% from 9.975 million mt in Q4 2016, according to S&P Global Platts calculations.

Most of the company’s LNG imports in 2017 came under 15 term contracts, which totaled 35.2 million mt/year, up from 33.3 million-34.3 million mt the year before.

Kogas has term contracts for 9.02 million mt/year from Qatar, 4 million mt/year from Malaysia, 4 million mt/year from Oman, 3.5 million mt/year from Australia, 2 million mt/year from Yemen, 1.7 million mt/year from Indonesia, 1.5 million mt/year from Russia’s Sakhalin and 1 million mt/year from Brunei, among others, the official said.

The company also started to import 2.8 million mt/year of LNG from the Sabine Pass terminal in Louisiana in June 2017 under a 20-year contract.

Its 30-year contract with Indonesia’s Badak project, under which Kogas has imported 1 million mt/year since 1998 expired, late last year. Two other long-term contracts will expire in 2018 — 2 million mt/year from Malaysia’s MLNG II project that began in 1995 and 1 million mt/year from Brunei’s BLNG that began in 1997.

This equates to a total loss of 4 million/mt, more than 10% of Kogas’ term contract volume.

Seven more long-term contracts, worth 17.28 million mt/year, are scheduled to expire before 2030, including 7 million mt/year from Qatar’s Rasgas, 4 million mt/year from Oman’s OLNG and 2 million mt/year from Yemen’s YLNG.

Kogas said it will seek to diversify its LNG supply sources to include Russia and the US to ease its dependence on the Middle East and Southeast Asia. Around 90% of its imports are currently sourced from five suppliers: Qatar, Australia, Oman, Malaysia and Indonesia.

“Kogas has started preparations for new term contracts and seeks to sign new deals at least five years before existing contracts expire,” the company official said.

The rise in LNG imports last year came as Kogas’ sales of the fuel have been on the decrease.

The state utility, which has a monopoly on domestic natural gas sales, sold 32.163 million mt of LNG in 2017, down 1.9% year on year.

Of the total, LNG sales to retail gas companies for households and businesses rose 5.8% year on year to 18.39 million mt, while LNG sales to power generators fell 10.5% to 13.773 million mt.

“The decline in LNG sales to power generators was attributable to the start of production at a newly coal-fired power plant and restart of several nuclear reactors shut for a major earthquake,” the Kogas official said.

Despite the 1.9% decline in LNG sales in 2017, Kogas’ revenue rose 5% year on year to Won 22.17 trillion ($20.49 billion) in the year, driven by higher retail prices, the official said.

The utility posted a net loss of Won 1.92 trillion for 2017, expanding from a net loss of Won 612.5 billion the year before. Its operating profit rose 3.6% to Won 1.03 trillion over the same period.

The expanded net loss was attributable to losses in exploration and development projects overseas, such as in Iraq, Australia and Indonesia. Kogas is involved in 25 overseas projects in 13 countries, including 10 under development and production and four at the exploration stage.

Kogas saw its debt decrease to Won 29 trillion at end 2017 from Won 30.57 trillion a year earlier. But its debt-to-equity ratio rose to 356.2% from 322.7% over the same period.

The state utility’s LNG imports and sales are likely to keep rising in 2018 as Moon, who took office last May, has vowed to increase power generation by LNG to reduce the country’s heavy reliance on coal and nuclear.

Under the country’s long-term Basic Blueprint for Power Supply released last December, the percentage of electricity production from LNG would climb to 18.8% in 2030 from 16.9% in 2017.

The share of coal would fall to 36.1% in 2030 from 45.3% in 2017, of nuclear would fall to 23.9% from 30.3%, and of renewables would rise to 20% in 2030 from 6.7% in 2017.
Source: Platts

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A new container terminal at Duqm port, which will have an annual capacity to handle two million twenty-foot equivalent units (TUEs), will be ready by the end of 2019, according to a top-level port official.

“We are now building the platform, rail, and warehouses. By the end of 2018, we will order the big equipment, including cranes, for the port,” Reggy Vermeulen, chief executive officer of the Port of Duqm, told the Times of Oman in an exclusive interview.

Turkey’s Serka Taahhut Insaat is building the container terminal, which will have a length of 1.6 km. “The master plan for the Port of Duqm has been slightly changed. We have added capacity in mineral and roll on/roll off terminals. So, the container terminal will be 1.6 km long, extendable to 2.2 km,” Vermeulen remarked.

He said three major shipping lines, MSC, CMA CGM, and Balaji Shipping have listed Duqm as a final destination. Most of them use Duqm as the last leg of Oman Shipping’s feeder lines.

Vermeulen further explained that the port would focus on Sebacic Oman, which is expected to start commercial operations for the containerised export business soon. “There will be a big requirement for containerised shipment for the planned refinery as well,” he added.

Also, port authorities will try to attract containers going to the Al Wusta region via the Duqm port. Vermeulen noted that project cargo imports via Duqm were now showing a growing trend. Also, there was growth in operational cargo for the oil and gas industry.

Duqm port has witnessed tremendous growth in mineral exports last year. As many as 600,000 tonnes of minerals were exported through Duqm port last year. “This is a new market for the Port of Duqm and we will continue to encourage mineral exports because we believe that with efficient logistics support in Duqm, we will be able to eventually attract the industry link to the mineral business,” he said.

He added: “Mineral is the new oil of Oman. It is a big resource for the country and is barely tapped. To start with, the country needs to strengthen mineral exports and make a name. Then, we have to attract mineral processing industries for value addition.”

The major export markets of Oman’s minerals are India, Qatar, and the United Arab Emirates.
Source: Times of Oman

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In an exclusive interview with The National a week ago, UAE energy minister Suhail Al Mazrouei, who currently presides over Opec, said that plans to formulate an “Opec supergroup” are in the works. The new group would aim at longer-term cooperation with the 24-member “Vienna group” of Opec countries and allies, beyond the expiry of their production cut deal at the end of 2018.

If efforts succeed and such a group is indeed formalised, what should it do?

The current grouping includes the Opec countries plus Russia, Oman, Mexico, Kazakhstan and some smaller oil producers. Since their December 2016 accord, they have agreed to limit their oil production to reduce over-stocked inventories, an implicit effort to raise oil prices that had languished since the mid-2014 crash.

The progress was frustratingly slow at first, but most countries have complied closely with their targets and, helped by strong demand in the second half of last year, crude prices have indeed risen and inventories are falling closer to the group’s target levels.

The deal to curb output is set to expire at the end of 2018. However, Mr Al Mazrouei and the deal’s other two leading lights, Saudi energy minister Khalid Al Falih and his Russian counterpart Alexander Novak, have increasingly talked of a framework for future cooperation.

This super-Opec faces essentially four challenges:

Firstly, it needs to wind down the current deal before a damaging spike in prices, but without a disorderly exit that would lead to a new price crash. As Reuters analyst John Kemp observes, Opec has historically failed to do this well, usually acting too late and setting off a new boom-and-bust cycle.

Secondly, the group has to avoid encouraging too much competing production, particularly North American shale but also from Brazilian deepwater, and the possibility of the shale revolution spreading into other countries such as Argentina.

Thirdly, it has to guard against competition within its own ranks. Iraq has the most tangible and realistic plans for major production expansion, and has already been one of the least compliant of the deal’s members. But Iran, Russia, the UAE, Kuwait, Kazakhstan and Mexico all have their own plans for growth. Of course, new production will be needed to meet growing demand and compensate for declines elsewhere, but this means some members will lose market share to their peers.

Fourthly, the long-term outlook for oil demand is uncertain, due to growing efficiency, maturing demographics in some key markets, environmental pressures and the rise of electric vehicles. Demand will keep growing for now, but with many forecasters seeing a peak in the 2030s or 2040s, the super-Opec may at some point have to manage competition between its members over a shrinking or at least stagnant market.

The International Energy Agency (IEA), representative of the wealthy OECD countries, has not been standing still either. India and China, the two most important countries for future demand growth, have become associates of the IEA, and last Monday, Mexico became a full member – putting it in the anomalous position of being a member both of the Vienna-Opec pact and the IEA.

Faced with these pressures, some Opec members might chose to expand production more rapidly, hoping to make up on volume what they lose on price, forestall other competitors and ensure that they produce as much as possible from their resources before demand dries up.

Others might decide to expand production only gradually, to keep prices relatively high but accept a shrinking market share. And yet others, such as Venezuela, Algeria or Ecuador, would find that they are not able to play either game – because of domestic political instability, a lack of resources or high production costs.

So the super-Opec’s most important task would be to manage these tensions.

The key is Russia: no other really large producers, such as Brazil, are likely to join, and the inclusion of more smaller producers, mostly from Africa, does not help the framework much. They add to complexities, slow down the decision-making process, and their cooperation makes little difference to overall production. If one of them should be lucky to make a large discovery, it will probably exit the pact or at least cease complying.

Some of the second-tier producers, such as Oman and Azerbaijan, which each have output a little under 1 million barrels per day, could become members without affecting the group’s strategic balance or politics very much.

But Russia is a completely different beast. Its oil output is about equal to that of the US and Saudi Arabia as the world’s three biggest producers. It is also the world’s largest gas exporter by a long way, with exports twice that of second-placed Qatar.

Though its economy is rather moribund, its GDP is still twice that of the largest Opec member, Saudi Arabia. It is a nuclear-armed power with a permanent UN security council seat, which can exert control through diplomatic and military channels, not just through the functioning of the oil market. It was invaluable in roping Iran and some former Soviet countries into the Vienna deal.

Cooperation with Russia is essential if the super-Opec is to have enough power and market share to execute a meaningful strategy. But Russia’s interests extend beyond just oil. As in the popular fake photo of Vladimir Putin riding a bear, Opec may find that it is easier to get on than to dismount.
Source: The National

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News

Monday, February 26, 2018 20:59

By ELVIS MBOYA |

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Port of Salalah, one of the largest multi-purpose ports in the Middle East region, recorded significant growth in both container and general cargo volumes during 2017.

‘Despite uncertain global economic circumstances, the year 2017 ended on a positive note with both container terminal and general cargo terminal showing a growth over the previous years’, Salalah Port Services Co (SPSC) said in its directors’ report submitted to the Muscat Securities Market.

The port’s container terminal handled 3.94mn twenty-feet equivalent units (TEUs) in 2017 compared to 3.32mn TEUs in the previous year, recording a growth of 19 per cent. SPSC said it has retained all its major customers while a major customer’s share of business increased by 22 per cent compared to year 2016.

Port of Salalah’s general cargo terminal handled 13.58mn tons volumes during 2017, a growth of four per cent over 2016. ‘The general cargo terminal continues to grow, albeit at a slower pace as compared to the previous years, driven by the growth of aggregates business’, SPSC said.

SPSC’s consolidated revenues rose 3.9 per cent to RO57.03mn for the year ended December 31, 2017. Its consolidated net profit was recorded at RO5.21mn for 2017 as compared to RO5.72mn during the previous year.

‘The drop in profit is attributable mainly to changes in Oman tax laws requiring the company to provide a higher tax liability of RO1.7mn, higher costs arising from withdrawal of fuel subsidy by the government, higher staff costs and repair and maintenance costs to attend to ageing equipment’, the company said.

SPSC said the container shipping industry has been through very turbulent times in past three years, but it does appear that things are settling down and will be calmer in 2018. ‘Although we have seen a slight reduction in volumes from the peaks in 2017, the volume development is expected to be more stable in 2018 due to commitments from our shipping line partners’.
Source: Muscat Daily

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Iran’s LPG shipments eased to between 358,500 mt and 402,500 mt in February after recording a post-sanctions high of 520,000 mt in January, sustaining robust exports after normal production resumed in mid-November following maintenance at the South Pars gas field, fixtures from shipping sources showed this week.

The February shipments are destined for China, Taiwan, Africa and possibly India, according to shipping sources and S&P Global Platts trade flow software cFlow.

Unlike in previous months, no vessels were seen bound for Indonesia, as Iran and Indonesia are still negotiating the renewal of their term contract. Naftiran Intertrade Co., or NICO, a subsidiary of National Iranian Oil Co., lifted a 44,000-mt evenly split cargo from Iranian Gas Commercial Co., or IGCC, at Assaluyeh on February 17, aboard the VLGC BW Elm, cFlow showed. The vessel is now off southwestern Sri Lanka, cFlow showed.

According to shipping sources, NICO was also due to lift an IGCC cargo comprising 33,000 mt of propane and 11,000 mt of butane on a second trip aboard the BW Elm. cFlow showed that the vessel is destined for Mailiao in Taiwan.

NICO had also lifted in January a 44,000-mt evenly split cargo from IGCC for delivery to Mailiao aboard the LPG Capricorn which was at the Taiwanese port between February 7 and 13, cFlow showed.

Thai trader Siam Gas lifted at Assaluyeh on February 5 aboard the VLGC Ming Long, a cargo comprising 33,000 mt of propane and 11,000 mt of butane from IGCC. The vessel is due to arrive at Shantou around February 25, and is currently off the southeast Chinese coast, cFlow showed.

Trading firm Pacific Petrochemical has lifted at Assaluyeh a 22,000 mt evenly split cargo from Kharg Petrochemical aboard the Pacific Rizhao, as well as a 20,000-mt propane lot from Persian Gulf Petrochemical Industry Commercial Co., or PGPICC. The vessel, which is currently in the Gulf of Oman, is due to arrive at Qinzhou around March 10, cFlow showed.

SOCAR, PETREDEC AMONG LIFTERS

Pacific Petrochemical lifted a 44,000-mt evenly split cargo from PGPICC aboard the Sea Dragon, which is due to arrive in Ningbo on March 5. It is currently in the Indian Ocean, according to cFlow.

Pacific Petrochemical also lifted a cargo comprising 33,000 mt of propane and 11,000 mt of butane from IGCC aboard the Gas Courage, which is due to arrive in Ningbo on March 3, cFlow showed. The VLGC is currently off Singapore.

International trading firm Petredec is lifting a 44,000-mt propane cargo aboard the BW Orion from IGCC. The vessel is currently off Fujairah though its destination is not immediately known. BW Orion had been in Ningbo around end-January, cFlow showed.

Azerbaijani trading firm Socar is lifting from PGPICC a 44,000-mt evenly split cargo aboard the EverRich 10, shipping sources said. The VLGC is now in the Strait of Hormuz. The vessel was last in Zhangjiagang in late January, cFlow showed.

Iranian trading firm Triliance is lifting aboard the Gas Crystal a 44,000 mt propane cargo from PGPICC, shipping sources said. The vessel is currently near the Gulf of Oman, cFlow showed.

International trading firm Glencore is lifting an 8,500-mt butane parcel from PGPICC aboard the SeaSpeed, shipping sources said. The vessel is currently near Fujairah, cFlow showed.

The SeaSpeed was last in Mombasa, Kenya in early February and had also been at Beira in Mozambique before that, cFlow showed.

So far, only one fixture is seen for March lifting from Assaluyeh, shipping sources said. Siam Gas is lifting a 44,000 mt propane cargo from IGCC aboard the VLGC Ming De, which is first due to land at Jebel Ali in the UAE on Saturday, cFlow showed. The Thai-flagged vessel was last seen in southern China around end-January, cFlow showed.

Iran’s LPG shipments in 2017 totaled around 3.5 million mt, with the highest monthly volume last year seen in August at 423,000 mt before the South Pars gas field maintenance, which started in September and sharply reduced exports.
Source: Platts

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The LNG market is holding its breath over a price review arbitration case between South Korea’s Kogas, the world’s second biggest LNG buyer, and North West Shelf, Australia’s first and biggest LNG exporter.

The deal at stake, a 500,000 mt/year legacy contract that expired in March 2016, would seem insignificant given the size of the companies: the equivalent of 3% of NWS capacity of 16.9 million mt/year, and only 1.3% of South Korea’s total imports of 37.2 million mt in 2017, according to S&P Global Platts Analytics.

The parties hold no other LNG contracts with each other, their current bilateral trade is marginal — Platts trade flow software cFlow shows about one NWS cargo a month was delivered to South Korea in 2017 — and the prospects of closer ties are low as Kogas seeks to diversify its portfolio away from oil-linked prices.

Therefore, the impact of the contract price review on the companies’ cash flows would probably be small, while the LNG supply portfolios at either side of the dispute are unlikely to be significantly affected by any potential damage to bilateral trade relations.

THE BIGGER PICTURE

However, this arbitration case, the first to settle an Asian LNG contract dispute, is much more than a disagreement about pricing, with plenty at stake, not only for Kogas and NWS, but for the LNG industry as a whole.

First, it comes at a time when structural oversupply, growing market flexibility and downstream liberalization are threatening the traditional LNG business model — based on long-term contracts, oil-linked prices, destination restrictions and take-or-pay clauses — and gradually shifting risk up the supply chain from buyers to sellers.

Second, it has arisen ahead of the expiry of several legacy long-term LNG contracts. Approximately 15% of global contracts — about 43 million mt — are set to expire in 2018-20, and another 42 million mt in 2021-23, according to a recent report by Macquarie Research.

With the global supply glut likely to continue into the 2020s, this will give buyers more options. They can either replace contracts with spot volumes or re-contract under more favorable conditions, such as shorter duration, smaller volume, more flexibility or different indexation. But a continuation of the old supply model seems unlikely.

The Macquarie report pointed to an additional layer of risk, the contractual volumes up for pricing review. These include 187 million mt due for re-pricing before 2020 — around half of the estimated global LNG supply for that year — and another 146 million mt between 2021 and 2023.

Therefore, the NWS-Kogas pricing dispute could set an important precedent and open the floodgates for future contractual renegotiations and pricing reviews in the global LNG industry, with potential implications for all its stakeholders.

“Given the evolution of arbitration in pipeline gas contracts, we would not be surprised to see further buyers of LNG aiming to renegotiate their long-term contracts,” head of LNG Analytics with S&P Global Platts Frank Konertz said. “We clearly see a shift in the market to more spot, or gas-to-gas pricing, and a desire of importers to have this reflected in long-term contracts.”

Publicly available arbitration decisions over the past few years have all been in favor of the buyers, the Macquarie report said, with spot prices judged to be at least part of the market price.

WHAT’S AT STAKE FOR NWS?

More than half of NWS’ combined contracted portfolio of nearly 14 million mt/year is due to expire before 2024, according the International Group of Liquefied Natural Gas Importers’ 2017 report.

In addition, Woodside Petroleum, the operator and majority stakeholder of NWS, and Shell, its second largest investor, are, together with Malaysia’s Petronas, the world’s LNG sellers with the highest pre-2020 exposure to pricing review risks, the Macquarie report said.

“Using recent examples of slopes falling to approximately 11% from more than 14%, we see a substantial risk for sellers’ earnings,” the report added. The other stakeholders of NWS are BHP Billiton, BP, Chevron and Japan Australia LNG.

NWS’ ability to mitigate risk in a changing LNG business landscape is further weakened by the heavily concentrated nature of its supply portfolio, with nearly 80% of its LNG portfolio– more than 10 million mt/year — contracted with Japanese power and gas utilities, which are following the NWS-Kogas dispute very closely.

Japan, the world’s largest LNG consumer, has been at the forefront of global efforts to increase flexibility and improve LNG contractual terms for its buyers to mitigate the new risk emerging from a deregulating downstream market.

The first phase of Japan’s LNG liberalization saw it open up its domestic power and gas retail sectors in April 2016 and April 2017, respectively.

Further liberalization is on its way, with the division of former regional monopoly power-generation plants and transmission and distribution systems by 2020 and the unbundling of gas pipeline operations by 2022.

This is pushing Japan’s incumbents in new directions where managing price risk and ensuring profitability take priority over security of supply.

WHAT’S AT STAKE FOR KOGAS?

The inherent risk of pricing long-term LNG against a different commodity — which creates a disparity between expected delivered prices when the contracts are signed and market prices when deliveries begin — and the difficulty of placing those volumes in an increasingly competitive downstream market are becoming all too familiar for Kogas too.

In South Korea, the emergence of new importers unrestricted by long-term contracts, and increased access to import terminals are encouraging more competition in downstream markets.

SK E&S, a city gas company that has expanded into gas and renewables power generation, has been active in buying spot cargoes, after its own LNG receiving terminal in Boryeong started in 2017. The facility, which SK E&S owns with GS Energy, is the second private LNG terminal after Gwangyang. More importers mean more competition for Kogas.

Seoul’s move to allow private companies to import LNG directly and resell in the domestic market from 2025 coincides with the expiry of two large contracts by Kogas — a 4.1 million mt/year contract with Oman and a 4.9 million mt/year contract with Qatar.

“Kogas’ case for arbitration seems more aimed at winning better terms for future contracts, such as price, ‘take or pay’ clauses and ‘destination’ restrictions,” a South Korean source familiar with the arbitration case said.

WHO OWES WHOM?

A Kogas spokesman Monday told S&P Global Platts NWS owed the former money over a mid-term contract price dispute that has recently ended in court-administered arbitration.

The comments came after remarks last week by Peter Coleman, chief executive of NWS operator Woodside Petroleum, saying it was the South Korean buyer that owed money to the Australian joint venture.

“The contract allowed Kogas to call for price renegotiation to reflect major changes in the LNG markets,” the Kogas official said, adding that the two sides failed to reach an agreement before contract expired in March 2016. In a statement last week, Coleman said it was the NWS joint venture that had taken Kogas to arbitration.

“This was an old legacy contract that was at actually very low slopes,” he said. “The North West Shelf view is that Kogas owes the North West Shelf money, not the other way around.”

In the early years of this century oil prices were very low, with Brent averaging $18.65/b in late 2001, and a weak LNG market, independent oil and gas consultant and managing director of DataFusion Associates Tony Regan said.

China’s first LNG importer CNOOC was able to capitalize on this in its first LNG deal with NWS, concluded at a 5.25% linkage to the three-month average of the Japan Crude Cocktail plus a $1.55/MMBtu constant, and a ceiling of $25/b JCC, Regan said.

The NWS-KOGAS deal was done just after the NWS-CNOOC agreement and it was reported at a slope of 6.4% at the time, with a first price review after approximately five years, he added.

“The price would have been reviewed up considerably as we moved back into a sellers’ market, and the dispute suggests there was a loose end regarding future pricing that they were unable to resolve at the time. Volumes under the contract were heavily skewed to winter months so this back-end loading may also have created a pricing issue,” Regan said.
Source: Platts

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