Insight, news and analysis from the European markets ...€¦ · Hungarian exports to Ukraine open price arbitrage between MGT and AVTP this summer Inside Story 5 Reverse flow project

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Gas in Focus 25.12 | 29 June 2018 | www.icis.com/energy | 1

25.12 | 29 June 2018 | Published by ICIS | www.icis.com/energy

Insight, news and analysis from the European markets

GasInfocuscoNTENTs

British gas industry rebuffs tariff change 2Producers and utilities unite against short-haul tariff modifications

PEG Nord premium builds ahead of French hub merger 4Traders price French winter contracts above TTF as Trading Region France launch approaches

Gas-fired power demand set to rise even without carbon surge 4Gas share of German power output dropped to 7.5% this year, but spark spreads promise a rebound

Ukrainian demand to support Austrian flows to Hungary 10Hungarian exports to Ukraine open price arbitrage between MGT and AVTP this summer

Inside Story 5Reverse flow project completion bolsters Italy’s export ambitions

Comment 20Russia-US gas competition comes to a head in battle for Nord Stream 2

spot marketsTraded hubs 16

LNG spotlight 8

Emerging Markets 9, 10

prices & DataLong-term contracts 15

Monthly cumulative indices 16

Spot gas price assessments 16

Month+1 price assessment graph 16

Traded ranges – key gas contracts 18

Storage comment 19

The European Commission has opened an investigation into the continent’s largest LNG supplier, Qatar Petroleum, on the basis that supply agreements

with European importers may contravene EU anti-competition laws.

The Commission will investigate whether Qatar’s long-term agreements to supply LNG into Europe, which typically run for 20-25 years, contain territorial restrictions.

“Certain clauses contained in these agree-ments appear to, directly or indirectly, restrict [European] importers’ freedom to sell the LNG in alternative destinations within the Europe-an Economic Area,” the Commission said in a statement on 21 June. The clauses allegedly prevent the diversion of LNG cargoes to other destinations inside Europe, or restrict diver-sions to certain locations, or contain volume restrictions.

A Commission spokeswoman could not disclose which countries the clauses refer to. Qatargas, the LNG and gas arm of Qatar Pe-troleum, has long-term LNG supply contracts with many of the world’s major importers and supplies around 40% of Europe’s LNG.

The Commission’s investigation into Qatar Petroleum marks the latest step in the fight to break down trade barriers and complete Europe’s internal energy market.

The most likely outcome of the case will see Qatar being forced to remove offending clauses in contracts, although a fine may also be enforced.

The case will not change Qatar’s position as Europe’s principal LNG supplier, but it should further entrench the global gas and LNG industry’s drive towards transparency, commoditisation and greater contract flex-ibility.

The crux of the case, which came to light last week, is the Commission’s accusation that Qatar breached EU anti-competition law by imposing certain clauses in its 20-25 year supply contracts with European importers.

“Certain clauses contained in these agree-ments appear to, directly or indirectly, restrict [European] importers’ freedom to sell the LNG in alternative destinations within the

european commission probes Qatari LNG deals

European Economic Area,” the Commission said in a statement on 21 June.

The clauses allegedly prevent the diversion of LNG cargoes imported from Qatar to other destinations inside Europe, or the resale of the gas and LNG to other markets, or contain volume restrictions.

“Energy should flow freely within Europe, regardless of where it comes from,” said Mar-grethe Vestager, European Commissioner for Competition.

What does the eU legislation say?The parts of the EU legislation that may be in breach are articles 101 and 102 of the Treaty on the Functioning of the European Union (TEFU).

Article 101 governs “anti-competitive business practises” which may “prevent, restrict or distort competition within the inter-nal market and affect trade between member states.” Article 102 regulates market abuse by dominant players.

The Commission may find it particularly problematic to prove that Qatar has contra-vened article 102, according to a source at a law firm.

Despite being Europe’s largest LNG sup-plier, Qatar’s share of the European gas mar-ket is much smaller. This raises questions over whether Qatar holds a “dominant” position in the European market.

In any event, given that Qatar is Europe’s For the latest key oil and gas prices click here coNtiNUeD oN paGe 3

competition commissioner targets territorial restrictions in long-term deals

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price Data

icis Heren NBp Jul '18 20.744 7.053

icis Heren ttF Jul '18 21.913 7.450

icis Heren rU-De contract Jul '18

19.812 6.889

icis Heren No-De contract Jul '18

21.288 7.402

icis Heren NL-De contract Jul '18

22.717 7.899

icis Heren aL-sp LNG contract Jul '18

21.406 7.443

NymeX Henry Hub aug '18

8.748 2.981

icis Brent aug '18 39.413 13.431

NymeX Wti aug '18 36.922 12.582

icis Gasoil 0.1% 47.662 16.205

icis Fuel oil 1% 32.803 11.153

contract €/mWh $/mmBtu

key oiL aND Gas prices 28 JUNe 2018

0 10 20 30 40 50

ICIS Fuel oil 1%

ICIS Gasoil 0.1%

NYMEX WTI Aug '18

ICIS Brent Aug '18

NYMEX Henry Hub Aug '18

ICIS Heren AL-SP LNG Contract Jul '18

ICIS Heren NL-DE Contract Jul '18

ICIS Heren NO-DE Contract Jul '18

ICIS Heren RU-DE Contract Jul '18

ICIS Heren TTF Jul '18

ICIS Heren NBP Jul '18

KEY OIL AND GAS PRICES 28 JUNE 2018 €/MWH

British natural gas stakeholders resound-ingly rejected a proposed change to a key network tariff.

The industry’s largest producers and utilities led the way in their dissent against a modification to the uniform network code (UNC) proposed by Canadian producer Ver-milion Energy in october 2017.

Vermilion’s proposal changes the way in which the optional commodity charge (oCC) is calculated.

Some shippers are able to avoid paying a number of commodity fees – levies on vol-umes entering or exiting the grid – by using the oCC. The industry more commonly refers to the option as the short-haul tariff.

Network operator National Grid estimated that the oCC provides a total subsidy of around £146m (€165.5m) to its users, at the expense of shippers who cannot use it.

But some shippers were delaying the pas-sage of this modification.

Three stakeholders put forward alternative modifications to the Vermilion’s proposal. Swiss merchant trader Vitol, British utility SSE, Irish industrial Aughinish Alumina and Russian Gazprom Marketing and Trading all proposed different changes to the way the oCC was calculated.

over 30 participants submitted responses to all the original modifications and its four alternates.

British gas industry rebuffs tariff changeA key concern was the timing of the modi-

fication, running in tandem with an overhaul of the British tariff regime – itself already under severe time pressure.

The gas market’s largest upstream produc-ers – Anglo-Dutch Shell, Gazprom Marketing and Trading, and Italy’s Eni – rejected all proposals.

Storage operators – unable to benefit from the oCC – submitted zero responses. Large utilities, who firmly rejected most proposals, own all British stores.

Analysis from National Grid showed that gas-fired power stations were the largest us-ers, in monetary terms, of the oCC.

Vermilion’s original proposal received the most support votes, with all four coming from distribution system operators (DSos) and Vermilion itself. DSos do not benefit from short-haul subsidies.

The other four alternatives failed to garner more than two supporters. Aughinsh Alumina only gave ‘Qualified Support’ to its own pro-posal.

The industry workgroup developing the modification will submit final modification reports with recommendations.

The UNC panel then votes as whether to accept or reject the modification or an alter-native. Regulator ofgem has the final say on all modifications. Thomas Rodgers

SHORT-HAUL HISTORY

The industry introduced the OCC in 1998 to provide an option for shippers nominating a point-to-point path for volumes from a transmission system entry point to a grid offtake point.

Shippers are able to avoid the exit and entry commodwity charges by electing to pay the OCC, which calculates estimated cost of the theoretical laying and operating of a dedicated pipeline between the two points.

Short-haul has become increasingly attractive to shippers as commodity charges have risen in recent years.

Short-term capacity discounts have left network operator National Grid with little choice but to collect revenue by increasing the commodity charge.

The OCC calculation has seen little change; it still uses the 1998 costs of building and operating a dedicated pipeline.

Shippers are able to short-haul volumes across the network using the OCC, going far beyond the intention of the charge – designed to be used in very select cases.

https://www.icis.com/Dashboard/MarketUpdate/LoadGeneral/10220618




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major provider of LNG, there is a great deal riding on the case on both sides.

Qatar provides about 40% of Europe’s total LNG imports according to the Commis-sion. While the Uk, Spain and Italy have his-torically been large importers of Qatari LNG, according to LNG Edge data.

Why include clauses?The motivations behind Qatar’s contractual restrictions could be to avoid competing with its own supply in other regions, a source at a trading house said.

“Given that Qatar has so much market share in Europe, it has previously prevented companies diverting volumes to other EU markets,” he said.

“The motivation for restrictions is always to prevent competition from diverted cargoes and support prices,” said another source.

He said it was unlikely that Qatar would deliberately intend to contravene the EU’s ban on territorial restrictions, nor would EU buyers be willing to sign contracts with these restric-tions in place.

The legacy of Qatar’s status as the first country to export LNG on a mass scale could be another reason why some clauses could remain, according to Wolfgang Peters, Managing Director at The Gas Value Chain Company.

“Remember Qatar was the first region which really massively proliferated LNG. Those were the late 80s/early 90s and Qatar’s mind-set was pretty much the ‘seapipe’ (i.e. featur-ing a pipeline type A to B scheme),” he said.

“When, for example, Trinidad and Nigeria came up (who did not care so long as they made some money), it strengthened Qatar’s resolve to keep their markets clean (and prices in their long-term contracts high). only lately have we seen Qatar also engaging in spot deliveries,” he added.

Which buyers have been affected?The Commission declined to comment on the specific contracts it is investigating, but some commentators have speculated that contracts to deliver to Spain or certain parts of northwest Europe may be being looked at.

“I wonder if there are some contracts that predate the [EU] ruling and which were not changed? Gas Natural Fenosa in Spain has a supply and purchasing agreement for 2005-2025 with Qatargas 1 and Endesa has one with RasGas 2 that started in 2005,” one source said.

A number of buyers did not respond to requests for comment by the time of publi-cation and it remains unclear exactly which parties have been affected by the clauses.

“Spain does not exactly strike me as the predominant ‘problem area’: there have been

QATARI LNG - A DOMINANT PLAYER IN THE EUROPEAN GAS MARKET?

SOURCE: Grid operator data collated and normalised by ICIS

Russia(piped)187.45

Norway(piped)124.73

Algeria(piped)36.19

LNG excl. Qatar(regasi�ed equivalent)

25.62

Domesticproduction

117.94

Qatari LNG(regasi�ed equivalent)

23.17

Libya (piped)4.87

Chart shows the share ofEuropean gas marketsupply in 2017 by source

SOURCE: LNG Edge

million cubic metres of LNG/year

QATARI LNG EXPORTS TO UK FALL OFF A CLIFF

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PolandPortugalItalySpain

TurkeyGreeceFranceBelgiumUK

Netherlands*Chart shows Qatari LNG exports toEurope by year since 2012**2018 �gure includes exportbetween 1 Jan - 26 Jun

so many re-loadings (of DES delivered LNG stored in tanks) in the past that I doubt there is much meat on the bone,” said Peters.

“It cannot be excluded however that the extra costs of re-loading (as opposed to diverting the original cargo in the first place) might be a bone of contention.”

“Italy and France appear the more likely candidates,” he said.

“You can safely assume that all agree-ments with Qatar Petroleum are under scru-tiny,” said the law firm source.

eU enforcementIf unlawful restrictions are included in Qatari contracts then this is “a big issue,” according to Thierry Bros, senior research fellow at the oxford Energy Institute.

“Let’s be a bit more reactive on the Eu-ropean side. The Directorate-General for Competition needs to enforce and defend the European market a bit faster than they have done so far,” he added, referring to the conclusion of a recent case involving Russia’s Gazprom, case which took six years to con-clude.

He added that the clauses could have pre-vented the most competitive gas price from being realised and ultimately cost European consumers.

The conclusion in May 2018 of a major an-titrust investigation into Europe’s largest pipe-line gas supplier, Gazprom, may provide some

clue into the outcome of the Qatar case.This case saw Gazprom accused of market

abuse against Bulgaria, Estonia, Latvia, Lithu-ania and Poland.

Gazprom ultimately avoided a fine, but agreed on new measures to increase gas market competition in central and eastern Eu-rope, including removing destination clauses in its contracts.

A fine in the region of 10% of its annual global portfolio had been mooted, and some observers have suggested Qatar may be sub-ject to this kind of penalty if found guilty.

“Destination clauses fall under the hard ‘no-no’ of the TEFU, and can be punished with up to 10% of your global turn-over,” Peters said.

“I would find it hard to see Qatar facing harsher treatment than Gazprom, but lifting the clauses is the minimum punishment,” said the law firm source.

Historic precedentsIn addition to Gazprom, the Commission has concluded similar antitrust cases with other state-owned gas and LNG suppliers during the past two decades, including Nigeria’s NLNG, and Algeria’s Sonatrach.

Although the Sonatrach case was con-cluded in 2007 and the gas and LNG markets



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peG Nord premium builds ahead of French hub merger

Deals for winter-delivery gas at PEG Nord were concluded at a growing premium to the TTF market during June, based on traders’ concerns

that the upcoming single French market will be prone to price spikes despite investment in infrastructure.

on 21 June, the Winter ’18 contract traded at a €0.32/MWh premium to the TTF. Meanwhile, the Q1 ’19 contract traded at a premium of €0.23/MWh to the TTF.

These price differentials are in line with five-year averages and mark a return to levels before France’s first ever storage auctions in March when a surge in liquidity pressured PEG spreads to the TTF lower.

Traders said the growing premiums reflect a concern that a single French price quotation will be more expensive than initially antici-pated.

“The market is seeing that the merger will impact a bit on the PEG making it higher, and not just the TRS cheaper,” one France-based trader told ICIS.

New capacityThe unified French market will be known as Trading Region France (TRF), and launches on 1 November.

A new pipeline is being built at Val-de-Saone that will add 23mcm/day of south-bound capacity on the north-south link, the virtual interconnection point connecting the two existing French gas hubs. Another pro-ject, Gascogne-Midi, will reinforce the grid in the south-west of France. The country cur-rently suffers from bottlenecks that depend on the combination of different flows in and out of the grid.

Earlier this month, CRE proposed the use of locational spreads to manage congestion-related price spikes in the event the two key infrastructure projects are not completed by the time of the merger on 1 November.

The trading tools would allow shippers to buy gas downstream of a congested area and sell it upstream of the affected point, thereby ensuring gas flows around the grid.

Even if the infrastructure is available on time for the launch of TRF, ICIS analysis earlier this year found that the additional capacity would amply cover average demand but might still not be enough to satisfy peak winter needs.

“Regardless of the locational product be-ing implemented the reality is no one knows how that stuff will behave, not even [French system operator] GRTgaz,” a trader said.

the LNG factorRegasified liquefied natural gas is a key source of supply to France’s natural gas network. TRS

is particularly dependent on it and has two LNG terminals. An increase in LNG cargoe arrivals tends to have a bearish impact on TRS prices.

Currently, higher prices in Asia are drawing LNG cargoes away from northwest Europe. And the subsequent shortage of supply for the region is pressuring European gas prices upwards.

According to ICIS assessments based on LNG swap values, the arbitrage opportunity

for LNG into Asia could continue until next summer.

This would negate CRE efforts to dampen price increases.

In this scenario, PEG premiums to TTF con-tracts would likely remain stable, but outright prices for natural gas could rise.

“CRE is creating a single zone hoping to have the PEG index as close to TTF as possible. In reality, they might achieve the opposite in stressed periods,” a trader said. Kelly Paul

The unified French market, known as Trading Region France (TRF), launches on 1 November

Gas-fired power demand set to rise without carbon surge

Gas demand for power generation is set to return to high levels over the next year and a half, an ICIS analysis indicates.

Use of gas for power generation will not depend on weather carbon prices remain in their current range or hit €20.00/tonne Co2 equivalent (tCo2e).

ICE EUA futures, which European power generators must purchase to emit carbon, have more than trebled in price over the past year as the EU agreed post-2020 carbon mar-ket reform.

The reform will double the rate of with-drawal of EUAs from the market stability reserve (MSR), which is set to cut auction volumes short when the market is over-supplied from 2019 onwards.

A surplus of EUAs has built up since 2009, when the economic crisis unexpectedly reduced European carbon emissions.

icis viewThe long-term visibility that the reform’s passage provides has attracted hedge funds and other financial players to enter the carbon market, according to ICIS senior EU power and carbon markets analyst Stefan Feuchtinger.

In addition, utilities expecting the market to be short next year have stepped up their reserve buying too, according to Feuchtinger.

Carbon prices have lost some momentum since settling above €16.00/tCo2e in late May and early June.

The EU raised its 2030 target for energy consumption from renewable sources to 32% on 13 June, up from the previous goal of 27%.

As an overlapping policy, this may render the carbon market less effective, and could deter fuel switching from coal to gas.

Nevertheless, multiple traders and analysts contacted by ICIS agreed that carbon prices would reach €20.00/tCo2e eventually. ICIS analysts’ mid-range carbon price forecast has this occurring in the third quarter of the year.

“Southern and eastern utilities have not yet bought additional allowances for the most part,” said Feuchtinger. “We see demand ramping up again from July.”

power sector demandCoal made up 15% of German power generation in 2017, with gas at 9%,


SOURCE: ICIS, Fraunhofer ISE

mcm/day

Demand Current outlook €20.00/tCO2e carbon

ANNUAL GERMAN GAS DEMAND FOR POWER GENERATION AND OUTLOOK

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a reverse-flow project that looked wildly speculative to shippers five years ago now holds more promise, as europe’s supply-demand balance shifts and italy awaits new volumes from azerbaijan in 2020

Uphill, downhill

ALA

MY

Italy will have the technical ability to export up to 40 million cubic metres (mcm)/day to northern Europe via the Swiss Transitgas pipeline by 1 october 2018, once the Al-

pine reverse flow project is completed. Physical flows from Italy to France’s PEG

Nord zone, through Switzerland, are already technically possible. Flows to Germany’s NCG area will be possible from the start of the coming gas winter, Swiss operator Fluxswiss said in May.

An auction of the German leg of the new south-north capacity on 2 July should give an indication of shipper interest, but price spreads and the price history of the hubs concerned suggest significant south-to-north flows are unlikely until additional supply en-ters the Italian system. The major change to Italy’s supply profile will come in 2020 with the realisation of the Trans-Adriatic Pipeline (TAP) project.

For the next two years, historical data show that reverse flows are likely only when exceptional fundamentals boost north-west European supply margins, as happened in March 2018.

The reverse-flow project was realised in order to increase the security of supply of cen-tral and north-European hubs, giving them access to supply sources such as Algeria, Libya and Azerbaijan and therefore making them less dependent on Russian supply.

It will also give Italy the chance to switch from net importer to transit hub, as the country could take advantage from its wide

portfolio of sources of supply and its key geo-graphical position.

The evolution of Italy’s supply mix will be one of the deciding factors: long-term contracts covering some 30bcm/year will expire by the time TAP comes online, mostly between Italian companies and Algerian Sonatrach or Russia’s Gazprom.

Therefore while short-term price dynamics do not back up regular use of reverse flows, the landscape could change significantly in the space of two years.

italy looks northThe reverse-flow project involves five grid operators: the Swiss Fluxswiss, Fluxys and

open Grid Europe on the German side, GRT gaz on the French side and the Italian Snam Rete Gas.

The rationale behind the project is to en-hance diversification of sources of supply and thus the security of supply for Switzerland, France, Germany and onwards. The range of sources currently available in Italy includes gas from north Africa and also LNG terminals, which are currently severely underused.

The expansion of the Southern Gas Corri-dor will also provide access to gas from more sources, such as Azerbaijan. And gas flows

from Italy and from the connected sources could support the conversion from L-gas to H-gas in Germany precipitated by declining production from the low-calorific Groningen field in the Netherlands.

Making the TENP and Transitgas systems bi-directional is also expected to increase spread trading between Italian PSV, the French PEGs and the German NCG, and liquidity on the hubs, according to Fluxswiss and the three grid operators GRT gaz, Fluxys and Snam Rete Gas.

According to data published by the Italian ministry of economic development and the European Network for Transmission System operators for Gas (ENTSoG), by 1 october

2018 Italian export capacity will increase up to 40mcm/day. These volumes could all transit through the Gries Pass entry point on the border between Italy and Switzerland, or 18mcm could transit through Tarvisio on the border between Italy and Austria and the remaining through Gries Pass. Gas that flows through Switzerland could then be exported towards France and Germany.

South-to-north physical reverse flow capacity from Italy to France has been avail-able since 1 June, when around 20mcm/day export capacity from Switzerland to the

Long-term contracts covering some 30bcm/year will expire by the time TAP comes online

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French PEG Nord hub became marketable at the oltingue interconnection point.

Investments for bidirectional flows were also made on the German TENP pipeline, in order to allow flows from Italy to transit Germany and reach the Netherlands and Belgium.

operator Fluxys will offer capacity for the first five gas years starting from 1 october 2018 as a restricted firm capacity product at the Wallbach entry point on the German-Swiss border and Eynatten exit point to the Netherlands or Bocholz exit point to Belgium.

Shippers will be able to submit their bids for yearly capacity on the pan-European PRISMA booking platform on 2 July. The first yearly auctions for export capacity from the Italian Passo Gries to Switzerland are also scheduled for 2 July.

As for capacity on the Swiss borders, mar-ket participants are able to book reverse flow capacity as of 18 May 2018. Switzerland is not part of the European Union, therefore the Transitgas operator Fluxswiss does not have to comply with the EU transparency rules.

It is not certain how much take-up of the products there will be in the short-term, as the Italian curve has always been a premium hub compared to north-west European markets.

price spreadsItalian gas curve prices are among the most expensive in Europe and they traditionally trade at a premium to all other hubs except occasionally the Spanish PVB.

This is because Italy is a net importer from

LONG-TERM CONTRACTS VIA TAP

Azeri gas producer SOCAR has a number of deals with European suppliers:

Edison - 1bcm/year*

Shell - 1bcm/year

Hera - 0.3bcm/year

Uniper - 1.6bcm/year

ENGIE - 2.6bcm/year

Bulgargaz - 1bcm/year

DEPA - 1bcm/year

Enel - undisclosed

Axpo - undisclosed *Edison bought Gas Natural Fenosa’s 1bcm/year long-term contract in October 2017

the surrounding countries, and therefore a price-taker. The benchmark for PSV contracts is the Dutch TTF hub, the most liquid Euro-pean market.

This is also because gas flowing from the Netherlands through Germany and France to Italy is the country’s marginal source of sup-ply, which is why the PSV premium to the TTF generally reflects the cost of importing gas from north Europe through Switzerland.

This is estimated to be around €1.80/MWh,

based on documents published by the Italian ministry of economic development in 2017.

In the past three years, PSV prompt prices were assessed at a premium to their French, German and Dutch equivalents, except for a handful of days in which exceptional weather-related circumstances pressured supply mar-gins in northern Europe in the first quarter of 2018.

Between 1 April 2015 and 21 June 2018 the PSV Day-ahead product was assessed at a discount to the German NCG hub only on seven days.

These were all during the first quarter of the year, when cold temperatures typically pressure supply margins in northern Europe, while higher storage withdrawal allowances in Italy quarter on quarter boost supply in the country.

Five of the seven days were in March 2018, when a cold spell in northern Europe caused north-west European gas prices to spike. The Italian system was well-supplied in March thanks to high Russian and Algerian flows, which made flows from northern Europe superfluous.

Between 14-19 March 2018, this even pushed the Italian system to switch to net exports from Italy to Switzerland for the first time. If bidirectional flows had been possible on Transitgas at the time, it would have been the only time in the PSV’s history that shippers would have profited from exporting to north ern Europe for more than one day.

The PSV Day-ahead had a discount of around €1.80/MWh to the NCG over the period. This compares to an average PSV Day-ahead premium to the NCG of €1.70/MWh in 2018 so far, based on ICIS assessments. The PSV Day-ahead premium to the French PEG Nord hub was around €1.60/MWh on aver-age in the same period.

As for France, the PSV Day-ahead was as-sessed at a discount to PEG Nord only on 14 days in the past three years, seven of which were in March 2018. This indicates that ex-ports to the PEG Nord area are also unlikely in the years ahead.

Except for a few days in which exceptional circumstances boosted north-west European prices, Italian supply margins do not allow the country to switch to a net exporter towards north Europe. on the contrary, supply from north Europe has a key role in balancing the system as the marginal source of supply.

But the Alpine reverse flow route could prove a useful safety net in crunch situations like that seen in March.

While Italian shippers have said they are not paying attention to the upcoming auctions for annual capacity at Wallbach, shorter-term capacity will also be available. This means they could pick up transport rights if price differentials make it worthwhile, at specific times of year.

Looking further ahead, spreads between the PSV contracts with delivery after sum-mer 2018 and the European benchmark TTF

SOURCE: Snam Rete Gas

MILLION CUBIC METRES

Austria (Tarvisio) Libya (Gela) Algeria (Mazara)

ITALIAN IMPORTS VIA PIPELINE (2016-2018)

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SOURCE: ICIS, SNAM RETE GAS

€/MWh million cubic metres

PSV Day-ahead premium to NCG Italian imports via Switzerland

ITALY-SWITZERLAND FLOWS RESPOND TO PSV-NCG SPREAD IN 2018

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SWITZERLAND

FRANCE

GERMANY

ITALY

TENP

TRANSITGAS

TRANS ADRIATICPIPELINE

Wallbach

Passo Gries

Oltingue

TO GERMANY: Up to 22.3mcm/day

from 1 October 2018

TO FRANCE: Up to 18.6mcm/dayfrom 1 June 2018

TAP expected to deliver8.8bcm/year from Q1 2020

ITALY GEARS UP FOR REVERSE FLOWS

also show that Italian gas products have not factored in the possibility for Italy to export even after the reverse flow project will be fully online.

The Calendar ’19 product traded at an average €2.025/MWh premium to the Dutch TTF in the first 20 days of June, while the Cal-endar ’18 held a €2.15/MWh to the TTF at its expiry, ICIS assessments show.

Similarly, the Winter ‘18 contract traded in the past few months at a €1.99/MWh premium to the TTF, above the €1.90/MWh premium at which the Winter ’17 contract traded to the TTF ahead of expiry.

The spreads between the PSV Winter ’18 and the PEG Nord and NCG equivalents signalled the same trend, as the Italian front season was assessed at a premium of €1.663/MWh to PEG Nord and €1.925/MWh to the NCG.

tap and the long-termThe pricing scenario is unlikely to change at least as long as Italy’s supply portfolio stays the same.

Additional volumes from Azerbaijan through TAP and contracted to a number of European companies (see box) could change the trend in the future.

The TAP project is part of the Southern Gas Corridor (SGC), a series of gas pipelines planned to connect the Shah Deniz gas field in Azerbaijan to Italy via Turkey, Greece and Albania. The pipeline will have an initial ca-pacity of 10 billion cubic metres (bcm)/year, which may be doubled in future. The first

volumes are expected to reach Europe by the end of the decade, and Azeri gas is expected to be delivered to Italy in 2020.

Pipeline capacity will be exempt from third party access rules for the first 25 years. TAP is also underpinned by long-term gas transport agreements for 25 years, meaning initially ca-pacity will only be used to deliver Azeri gas to southern Europe. Azerbaijan’s SoCAR is the seller of the gas.

In June 2018, most of the Turkish stretch of the SGC - the TANAP pipeline - opened with the first deliveries expected by the end of the month. The pipeline will transport up

to 16bcm/year from the second phase of the Shah Deniz project. The South Caucasus Pipeline carries the Azerbaijani gas from the Caspian Sea to TANAP, via Georgia.

In 2017 the Italian ministry of economic development has presented the Trans-Adriatic Pipeline (TAP) project as a strategic piece of infrastructure that will increase liquidity and security of supply at the Italian gas hub. How-ever, the market impact of the project will mainly depend on whether current long-term contracts for gas supply to Italy are renewed, and on what terms.

In July 2017, the ministry said that in the initial phase, TAP is expected to deliver 8.8bcm/year of gas from the Azeri Shah Deniz

II field on 25-year long-term contracts, start-ing from 2020.

This would allow the Italian system to cope with issues such as volatile imports from Libya and Algeria. It would also make Italy less reliant on Russian gas. Russia is Italy’s main source of supply, and accounted for 43% of the 69bcm imported in 2017, data published by the ministry showed. This means that if Russian gas flows to Italy suddenly dropped - as in the case of an explosion on the Aus-trian grid in December 2017 - TAP could help compensate for the absence of Russian gas.

The pipeline could have a role in turning the PSV into a transit hub, as any extra gas could be exported to northern Europe via Transitgas once reverse flows are fully implemented.

However, the impact of TAP on the Italian system will mainly depend the Azeri gas share of overall imports. This in turn will be deter-mined by the renegotiation of long-term con-tracts expiring before or shortly after 2020.

Long-term deals regulating supply to Italy for a total of 35bcm/year will expire by 2020 and have not yet been renegotiated, according to data published by the ministry of economic development. Most of the volumes nearing expiry are under long-term deals between Italian companies and Algerian producer Sonatrach or with Russian producer Gazprom. This compares to a total of 88bcm/year currently covered by long-term contracts to Italy, although Italian gas demand is much lower than this, reaching 72bcm in 2017, data published by the ministry and Italian TSo Snam Rete Gas showed.

This means that TAP could merely diversify Italy’s portfolio rather than deliver extra gas. In that case Italy’s ability to export would remain largely unchanged.

Moreover, the role of TAP in diversifying sources and reducing Italy’s reliance on Rus-sian gas will also depend on Russian gas giant Gazprom’s involvement in the project.

In January 2017, Gazprom said it was considering sending gas to southern Europe

via TAP or the Poseidon project - a proposed competitor pipeline to supply southern Eu-rope. The comments came in the context of Gazprom’s continuing stand-off with Ukraine over transit flows through the country.

The initial capacity on TAP has already been fully assigned under 25-year long-term contracts and it is exempted from third-party access, which excludes Gazprom from using the pipeline.

TAP capacity can be increased up to 20bcm in the future. Decisions on whether to expand capacity or not will be carried in 2022, the

The PSV Day-ahead was at a discount to German NCG only on seven days in three years

❯❯

coNtiNUeD oN paGe 8



Gas in focus News

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LNG spotLiGHt

coNtiNUeD From paGe 7

spain poised for first reload in five months

Spain is set to carry out its first com-mercial reload since February 2018, as ongoing strong spot prices in Asia have increased their profitability.

Although LNG reloads are now a com-mon occurrence from northwest European terminals such as the Netherlands’ Gate and France’s Montoir, they have been marginal-ised from Spain’s terminals in recent years.

There is now a compelling business case for LNG to be re-exported from Spain, accord-ing to multiple market sources.

Traders’ expectations in recent days that reloads would be carried out in July were backed up by scheduling data from the Span-ish TSo Enagas.

Barcelona and Bilbao will host the reloads, with the former hosting two operations while the latter looks set to execute a partial cargo.

Workable marginsIberia typically has higher gas prices than the rest of Europe due to its higher quota of oil-indexed gas contracts and isolated position in the south of Europe.

That remains the case now, but the mar-gins are still generous enough to justify LNG reloads from Spain to Asia, traders said.

In mid-June, the front month for the ICIS East Asia Index (EAx) exceeded $11.00/MMBtu. At its peak, this put the EAx front-month con-tract more than $2.80/MMBtu above the ICIS Iberian FoB assessment, which represents the cost of LNG reloaded from Spain.

Spot LNG prices were above $10.00/MMBtu as of 27 June. Even with rising char-ter rates, the cost of a return voyage to Asia is around $1.80/MMBtu, ICIS calculations showed, implying there is profit to be made at these levels.

Spain’s PVB front-month prices have also been rising. This is in spite of a comfortable hydroelectric generation outlook and the impending return of two of Spain’s seven

SOURCE: ICIS

$/MMBtu

EAX premium vs Spain FOB

SOARING ASIAN SPOT LNG PRICES INCREASE PROFITABILITY OF SPANISHLNG RELOADS

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SPANISH RELOADS' DIMINISHING ROLE IN WORLD LNG SUPPLY

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SOURCE: CORES

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working nuclear plants after maintenance work ends.

“PVB prices have recently been going up because of the news of these reloads,” the trader said.

summer rarityA reload from Spain in July would be the first to occur in a summer month since August 2015. While it is common for an arbitrage

between Asia and Europe to open up during periods of high demand in the winter months, this is not usually the case in summer.

From a logistical point of view, reloads can be difficult to arrange. Spain is still a developing market with limited hub liquidity, compared with lower costs and deeper liquid-ity found at the ports of northwest Europe, traders said. Rob Songer

Italian ministry of economic development said in November 2017.

safety valveItaly’s current portfolio of sources of supply and historical price spreads between the PSV and north-west European hubs show that exports to northern Europe over extended periods of time will still be unprofitable in the years ahead.

The most likely scenario is that in which Italy will act as a safety valve and occasionally export to north Europe in emergency cases in which tight supply margins will stress the

German, Dutch and French hubs as it hap-pened in March 2018.

If Italy were to receive Azeri gas on top of the contractual volumes from Algeria, Libya and Russia currently supplying the country, the extra gas could make the system oversupplied during certain periods of the year and pressure prices, making it profitable to export to north Europe.

This is more likely to happen in periods such as the first quarter of the year, when supply margins in northern Europe are typically more strained than in Italy. Further Dutch produc-tion cuts could also increase the Netherlands’ dependence on imports, particularly during

winter, in turn increasing the chances that Italian prices drop to a profitable discount to the surrounding hubs. Even with the extra Azeri volumes, Italy is likely to export only in the coldest periods of the year when supply margins in north Europe are under pressure.

In order for north-bound flows to occur, not only should TAP deliver extra volumes compared with the current balance, but it should also be in a position to dispense with gas imports from north Europe. Imports via Switzerland totalled 7bcm in 2017, more than two thirds of the maximum capacity on TAP available from 2020. Alice Casagni

inside story: Uphill, downhill



Gas in focus News

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mozambique FiD closer with centrica, tokyo deal

Final investment decision (FID) on the two-train 12.88mtpa Mozambique LNG project moved a step closer after Japan’s Tokyo Gas and the Uk’s Centrica signed

a long-term offtake agreement for 2.6mtpa of LNG from the project.

The non-binding Heads of Agreement (HoA) was signed on a delivered ex-ship (DES) basis and will run from the start-up of produc-tion from the LNG plant through to the early 2040s, project developer US-based Anadarko said on 15 June.

“At 2.6mtpa, this HoA represents a signifi-cant portion of the marketing off-take target we have set for FID,” Anadarko said.

“our focus now is on converting these non-binding commitments into fully termed sale and purchase agreements (SPAs),” the company said.

The agreement builds on previous con-tracts signed by Mozambique LNG 1 – the company created to be the selling counter-party on all SPAs from the project.

The deal brings cumulative offtake agreements to 6.68mtpa, still short of the 9-11mtpa target set by Mozambique LNG 1 on its website.

Mozambique LNG 1 has previously signed HoAs with Japanese utility Tohuku Electric for 0.28mtpa, with Thailand’s PTT for 2.6mtpa, as well as an SPA with France’s EDF Trading for 1.2mtpa.

“innovative deal”The deal is an innovative one, and possibly the first when an Asian and European buyer contract jointly, according to Flower. It also

raises questions over how exactly the deal will be structured.

“We have been able to acquire a high level of flexibility that will allow us to move LNG be-tween the two companies,” said Chris Wright, senior public affairs manager at Centrica.

“The volume will be split amongst Tokyo Gas and Centrica LNG but it will not be pre-determined and will depend on the supply and demand balance of each buyer for that contract year,” he said.

He added that Centrica is looking to expand its flexible LNG portfolio and that Mo-zambique’s central location between Europe and Asia provides a key strategic position in accessing both the Atlantic and Pacific basins.

Centrica would not comment on the pric-ing of the deal.

But analysts said the company was likely to want a linkage to the NBP gas hub, while Tokyo Gas would want indexation to oil, an Asian spot price index or to the US Henry Hub.

shipping conundrumAs the contract was signed on a DES basis, this means Mozambique LNG 1 will be responsible for chartering vessels for shipping LNG from the plant following start-up.

The venture currently does not have any vessels under charter or any new-build orders, according to LNG Edge. But this is a more long-term consideration.

“ordering new ships is not a critical issue now. It takes about 2.5 to 3 years to build a ship so the acquisition of ships can happen af-ter FID – they probably have 12 to 18 months after to do it,” Flower said.

FiD in Q1 2019?Consultancy Wood Mackenzie said FID could be taken nearer the lower end of the target range, at around 9mtpa.

“Market intelligence indicates that other deals are close with Asian buyers, which could encourage those countries’ national export credit agencies to provide funds for the proj-ect,” said Giles Farrer, Research Director at Wood Mackenzie.

“There are reports that [China’s] CNooC is negotiating a 1.5mtpa deal which takes them close to the volume they say is needed for financing,” said Andy Flower, an indepen-dent LNG consultant.

“The main issue now is probably financing and the upsurge in Islamist violence in the north of the country will not help with that,” he added.

“I think it is possible we could get an FID by March 2019, but I do not expect first gas before 2024,” said Trevor Sikorski, Head of Natural Gas and Carbon at consultancy En-ergy Aspects.

BackgroundFeedgas for the project will be supplied from the giant offshore Area 1 in Mozambique’s deepwater Rovumba basin, where Anadarko and its partners have an estimated 75 tril-lion cubic feet of recoverable natural gas resources.

This is equivalent to 2 trillion cubic metres of natural gas.

Anadarko holds a 26.5% interest in the development, while Japan’s Mitsui holds 20% and India’s state-owned oNGC has 16%.

A mix of other companies is also involved. Anadarko received government approvalfor the plant in March.

The company did not respond to requests for comment by the time of publication. Alex Thackrah

emerGiNG markets

Ukrainian prices to encourage imports from eU hubs in July

European gas exports to Ukraine may remain bullish in July after the incum-bent Naftogaz decided to keep its price offers to customers at the same price

as in June.The company raised the prepaid tariff

to customers with a monthly consumption above 50 million cubic metres (mcm) to Ukrai-nian hryvnia 8,294/thousand cubic metres (€24.496/MWh) for June.

This represented an 8.5% rise on the May tariff to the same category of consumers.

To compare, May tariffs to different catego-ries of customers, exclusive of the transport fee increased by 5.2-5.5% on the previous month.

The price in hryvnia for the same custom-ers remains the same in July, but converts in euros at €25.80/MWh (calculated at the July

forward price on 21 June). To compare, the Austrian VTP July price was assessed by ICIS on 20 June at €22.1875/MWh.

Given the widening spread between the Naftogaz offer price, which is perceived as a reference value for the market, and central European hub prices, traders expect gas ex-ports, particularly from Hungary to remain at least at June’s levels, if not higher.

Flows from Hungary to Ukraine have near-ly tripled in the first half of June compared to May, hovering at a daily average of 13 million cubic metres (mcm).

Companies had been incentivised to export to Ukraine not only because of the Naftogaz price offer, but also because Hungary’s summer tariffs are traditionally low, encouraging the export of gas to Ukraine. A trader active in the

region said a similar situation may occur in July as long as the Naftogaz price premium over central European hub prices remains.

He also noted that some companies may even increase exports to the country.

This is because they may be incentivised to store gas in Ukraine, where it is more at-tractive to inject gas, than in Hungary, for example, even if Ukrainian storage tariffs will double from next month.

Domestic producersMeanwhile, incumbent Naftogaz is also looking to buy gas from local producers in July, the company said on 25 June.




Gas in focus News

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emerGiNG markets

Ukraine demand to support austrian flows to Hungary

High Ukrainian demand is likely to support natural gas prices in Hungary this summer and increase Austrian flows to the country, as the arbitrage

window has opened between the Austrian VTP and Hungarian MGP hubs.

The trend began this June and is likely to continue as low Hungarian transit fees will provide better profit taking opportunities for shippers active in Ukraine.

ICIS-collated data shows that Austrian flows to Hungary along the 14.4 million cubic metres (mcm)/day capacity HAG pipe aver-

aged only 4mcm/day in May. Historically, im-ports via the Mosonmagyarovar border point are the secondary supply source for Hungary.

The Hungarian CEEGEx exchange Day-ahead price was €0.21/MWh lower than the VTP counterpart in May, ICIS and CEEGEx price data showed. This prompted shippers to only offtake their contractual minimum sup-ply to swap back volumes in Austria and find buyers in Italy.

But the price relationship shifted in early June, when Hungarian exports to Ukraine through the 16.8mcm/day Beregdaroc border

SOURCE: CEEGEX, ICIS

€/MWh mcm

HAG �owsMGP-OTC Day-ahead

AUSTRIAN EXPORTS TO HUNGARY SINCE 1 MAY

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Slovakia PolandHungary

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The state company is bidding to purchase volumes at hryvnia 7,629/thousand cubic metre (kcm), which converts to July forward price of €23.78/MWh.

This is higher than the German NCG July price of €21.6725/MWh or the Austrian VTP July of €22.275/MWh, assessed by ICIS on 22 June.

It is not known what volumes the com-pany intends to buy from local producers.

The company said it would start test gas purchases from local producers in June, expecting to buy at hryvnia 6,900/kcm. How-ever, Naftogaz has been unable to conclude local deals this month, despite June being a low-consumption month. Traders said the price may have been lower than local produc-ers’ expectations.

Under an existing arrangement Naftogaz

is buying from local producers such as Ukr-gazvydobuvannya or Chornomornaftogaz at regulated prices. It is also buying on European markets at hub prices and importing the gas into Ukraine.

At the Ukrainian Energy Exchange, gas for delivery to the local virtual point for July ‘18 last dealt on 22 June at hryvnia 9,390/kcm. Aura Sabadus

Ukrainian prices to encourage imports from eU hubs in July


point more than tripled to 14mcm/day on average during 1-28 June.

The June increase coincides with a de-crease of Slovak exports to Ukraine along the Budince border point. Hungary is usually a key supply source for independent Ukrainian ship-pers and industrial consumers in the summer, while Ukrainian incumbent Naftogaz holds the long-term capacity at Budince.

But a source at Naftogaz told ICIS that the company had also looked to buy gas volumes in Hungary and preferred low Hungarian tran-sit fees for spot volumes.

This also impacted the relatioship between the VTP and MGP markets as the CEEGEx Day-ahead swung to a €0.28/MWh premium over the VTP counterpart. This supported imports from Austria as the flow increased to 11mcm/day on average in June to date.

capacity bookings soarHungary will likely remain a key source for spot volumes to Ukraine for the coming quarter due to cheap transit fees in the summer, which has already become visible in capacity bookings at the Beregdaroc border point.

Data by booking platform RBP showed that around 61% of offered monthly capac-ity for June was sold, which equals around 8mcm/day. Meanwhile, a large part of the remaining used capacity has been bought as daily capacity products.

offered quarterly capacity for the third quarter was fully booked, equalling around 10mcm/day. Shippers will use this as a default as it is cheaper per day, while daily capacity products could provide further flex-ibility for shippers.

Another source told ICIS that trading dynamics at Beregdaroc have shifted in the current gas summer as shippers have been favouring monthly and quarterly capac-ity products over short-term capacity. In the previous gas summer, shippers mainly used daily capacity, which saw Beregdaroc over-booked on several occasions.

High demand from Ukraine in the coming quarter may keep Hungarian prices above Austria and sustain the arbitrage opportunity between the two markets, supporting imports along the HAG. David Simon



Gas in focus News

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SOURCE: ICE

€/tCO2e

EUA PRICE SETTLEMENTS

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according to data available from research institute Fraunhofer ISE.

Assuming a 50% conversion factor, de-mand for gas for power generation was 25.3 million cubic metres (mcm)/day. The BP Sta-tistical Review of World Energy indicates that total German gas consumption was 247mcm/day in 2017.

While bullish EUAs make gas more expen-sive, coal is more affected as the higher-car-bon fuel source. Rising carbon prices would eventually lead to significant coal-to-gas fuel switching, but traders contacted by ICIS said that €20.00/tCo2e carbon would be an insuf-ficient trigger in the near term.

Gas’s share of German power generation has fallen to 7.5% so far this year. Surging prices have made the fuel less profitable

since extreme cold weather hit Europe in February and March.

Gas profitabilityICIS modelled quarterly German gas-fired power generation since 2014 against an average of the monthly clean spark spread premiums to clean dark spreads at expiry for the constituent parts of each quarter.

Clean spark spreads are indicators of profit-ability for gas-fired generators that take into account the cost of EUAs, while clean dark spreads are the equivalent for coal-fired genera-tors.

The model confirmed that gas demand rises alongside the fuel’s profitability relative to coal.

This explained 92% of the variation in gas-

Gas-fired power demand set to rise without carbon surge

IN BRIEF

Premium held by German clean spark spreads over clean dark spreads indicates strong future demand for gas from power sector

€20.00/tCO2e carbon price would trigger very little additional fuel switching, equivalent to no more than 2mcm/day in gas demand

Q3 ’18 power sector gas demand set to be fourth-highest for a summer quarter since 2014 under current forward prices


SOURCE: ICIS, Fraunhofer ISE

Twh

QUARTERLY GERMAN GAS-FIRED POWER GENERATION SINCE 2014 AND OUTLOOK

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20€20/tCO2e carbonCurrent outlookQ3 '18Past quarters

Note: for gas plants of 49.13% ef�ciency and coal plants of 35% ef�ciency

Clean spark spread premium to clean dark

fired power generation in summer quarters, falling to 64% in the winter, where outright spark spreads performed better.

on 15 June, ICIS calculated the 49.13% efficiency Q3 ’18 clean spark spread €2.71/MWh below the equivalent 35% efficiency clean dark spread.

Based on this, the model projects that German gas-fired power generation will reach 8.6TWh over this period, the fourth highest for a summer quarter since 2014.

Applying the spark spreads calculated on 15 June to the next five quarters, the model projects that gas demand will increase.

The three winter quarters would all be in the top five for gas output since 2014, while the second and third quarters of next year are set to have the highest summer gas demand in the sample.

€20 carbonICIS recalculated the spark spread premiums based on carbon prices rising to €20.00/tCo2e on the final day of the third quarter, and assumed that this led to realistic gains in the other commodities.

Inputting these figures into the model, winter gas-fired power output would only be expected to rise by around 3% compared to the current outlook. Next summer, gas gener-ation would rise by 9%, although this would only equate to an additional 2mcm/day.

This suggests that €20.00/tCo2e carbon would lead to very little fuel switching that was not already going to occur anyway. William Peck



Gas in focus News

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SONATRACH INVESTIGATION RESULTS

Deletion of territorial restriction from all existing contracts and no insertion in future contracts

Profit sharing mechanisms (so-called “PSMs”) only to be applied in LNG contracts under which the title of the gas remains with the seller until the ship is unloaded (in practice, sales under DES terms)

Consequently, Sonatrach is aiming to

transform the remaining FOB and CIF existing LNG contracts to sales under DES terms

No PSMs in future LNG contracts under which the title of the gas passes to the purchaser at the port of loading (in practice, for sales under FOB and CIF terms)

No PSMs in existing or future pipeline gas supply contracts

have evolved considerably since then, the conclusions drawn from the Commission’s probe may be relevant for the ongoing inves-tigation.

In the NLNG case – which was concluded in 2002 – it was found that only one of the many European contracts entered into by NLNG contained a territorial sales restriction. NLNG agreed to release its customer from this clause.

“NLNG also undertook not to introduce territorial restriction clauses and use restric-tions into its future gas supply contracts,” the Commission said.

“Furthermore, NLNG confirmed that none of its existing gas supply contracts contained so-called profit splitting mechanisms (PSMs) affecting the EU markets and that it would not introduce these in future contracts.”

Wider market ramificationsIf previous cases are any guide, and with the

number of interested parties in the Qatar case likely to be vast, the Commission’s in-vestigation is likely to take years rather than months.

The EU has been at the forefront of the push to liberalise energy markets and pro-mote free trade, but the case could give added impetus to gas and LNG buyers when seeking flexibility in their contract terms.

With a whole host of new liquefaction ca-pacity set to come online around the world in the next decade, and a swathe of long-term contracts due to expire and be re-negotiated, contract stipulations will be at the forefront of industry minds.

Just this week, Qatar Petroleum’s CEo Sherida Al-kaabi reaffirmed his company’s commitment to boost its LNG production capacity from 77mtpa to 100mtpa.

European importers can expected to be involved in negotiations to underpin offtake from the new liquefaction trains, but contract flexibility will be key.

The case could also expedite the transition to more flexible contract terms globally. This process is ongoing in Japan – the world’s larg-est LNG buyer - with the country’s Fair Trade Commission ruling in 2017 that restrictions on reselling contracted LNG cargoes breached competition rules. Alex Thackrah



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CroatiaLNG - LNG Croatia and national grid operator Plinacro launched the second round of the open season procedure on 22 June giving shippers until 3 August to place their bids for regasification capacity on the planned 2.6 bil-lion cubic metres (bcm)/year floating storage regasification unit at the island of krk.

As the first round recorded low interest, the organisers changed the management at LNG Croatia and reshaped the project by amend-ing the technical details of the terminal as well as updating the regasification tariff and tweaking other details.

This resulted in a delay in the original op-erating date of the terminal, which is now expect to be 1 october 2020.

In its latest open season rulebook, LNG Croatia has listed indicative tariffs for regasifi-cation capacity, based on four scenarios.

In the first net calorific value scenario, the regasification tariff for gas year 2021 to gas year 2040 would be €1.39/MWh, if around 1.5bcm/year of capacity were booked. In the second scenario, the same tariff would be applied if around 1.7bcm/year of capacity were allocated. The tariff would decrease to €1.37/MWh for the same duration if around 2bcm/year of capacity were sold, or to €1.05/MWh if all 2.63bcm/year of capacity were be booked, in the third and fourth scenarios.

Plinacro also revised transmission fees along the planned supply route to Hungary. Plinacro will offer around 7 million cubic me-tres (mcm)/day capacity on the send-out pipeline from the terminal and 4mcm/day of capacity at the Dravaszerdahely border point to Hungary.

Europeregulation - Energy companies will need a unique code in order to trade from July under EU regulation, but companies are divided as to how this will impact the market.

Under the second Markets in Financial Instruments Directive (MiFID II), which came into force on 3 January, each company needs to have its own unique legal entity identifier (LEI).

Trading firms were given a last minute six-month reprieve on the need to have an LEI in December 2017, but this exemption will end on 3 July. The European Securities and Mar-kets Authority (ESMA) said on 20 June that the reprieve had not been extended as it had seen “a significant increase in the LEI cover-age for both issuers and clients”. Therefore, from 3 July, companies will need LEIs in order to trade.

“Some people will be caught out by this,” said a regulatory advisor from a European energy trading company. “They expected the deadline to be extended and they will expect the regulators to be lenient. We will see if this is the case.”

ESMA said it was working with regulators on supervisory actions to ensure that LEIs

were being used as it announced that the deadline would not be extended.

However, another regulatory advisor added that many companies had sourced their LEIs before MiFID II came into force in January as these were necessary in order to apply for an ancillary services exemption.

Greeceprivatization - Greece will launch a tender selling a majority stake in gas incumbent DEPA in November, according to a develop-ment plan published by current owner the Hellenic Republic Asset Development Fund (HRADF).

The privatisation plan involves splitting DEPA into two separate units, one handling the commercial activities and a separate one for the infrastructure network services of the company. HRADF will put up for sale just over 50% of its shares in DEPA’s commercial unit in the tender planned for November.

once the commercial sale has been com-pleted, Greece will look to sell 14% of its infrastructure unit in a separate tender.

As things stand HRADF holds 65% of DEPA’s share with the remainder held by Hel-lenic Petroleum. In April this year, a consor-tium made up of Italian, Belgian and Spanish transmission system operators (TSos) won a bid to acquire a 66% stake in Greek gas system operator DESFA.

Latviastorage - Latvian transmission system op-erator (TSo) Conexus Baltic Grid will remove entry and exit tariffs at the Incukalns facility to encourage shippers to store more gas.

Regulator the Public Utilities Commission has approved the new tariffs, which apply from 19 July for daily, quarterly and annual products and 1 August for monthly products.

The TSo has also reduced cross-border tariffs, but has slightly increased the tariff for Latvian end-users.

Injection season began at Incukalns on 5 June, but so far no injections have been made, according to Conexus data.

Last year, a key source of gas for storage injections was LNG delivered to Lithuania’s klaipeda LNG terminal, and a source close to the matter said he hoped this would continue to support injections this year. Lithuanian state-owned supplier Lietuvos Duju Tiekimas (LDT) has purchased two spot LNG cargoes totalling 2TWh for 2018. The first of these arrived on 12 June, according to data from ICIS shipping platform LNG Edge.

However, so far this does not appear to have had any impact on injections.

Netherlandssupply - The Dutch government on 25 June agreed with Anglo-Dutch energy major Shell and US-based ExxonMobil that the state will receive a 73% profit from natural gas produc-tion at the Groningen field, down from 90%.

This shift was designed to ensure output from the field can be ended as soon as pos-sible and allows the government to determine future production volumes.

Minister for economic affairs Eric Wiebes announced the deal, which also made par-tially state-owned operator NAM responsible for any seismic activity associated with the extraction process. It is expected that some 450 billion cubic metres (bcm) of gas will be left in the ground following the end of Groningen production. The agreement stipulates that NAM, Shell or ExxonMobil will not file a claim against these volumes.

Earlier this month Wiebes said output from Groningen could decline to 12bcm/year by october 2020, two years earlier than origi-nally planned.

The current allowance is more than 20bcm/year, with the reduction coming because of pressure from residential groups over earthquakes caused by extraction from the field.Groningen produces low-calorific gas used in the Netherlands, Belgium, France and Germany.

supply - The operator of the Netherlands’ Groningen natural gas field, NAM, expects production in the current gas year to be 19-20 billion cubic meters (bcm), the Dutch mining regulator said on 27 June, up to 2.6bcm be-low the output cap.

In a report the State Supervision of Mines noted that the forecast would leave produc-tion short of the 21.6bcm production ceiling imposed by the government in response to earthquakes caused by gas extraction.

For the next gas year, SSM said it expected production of 19.4bcm, in line with the of-ficial forecast released when the cabinet an-nounced in March that it would close the field as fast as possible. If production in the current gas year does indeed fall between 19-20bcm, that would represent only a modest decrease year on year.

transport - The tariff for the BBL gas pipe-line that connects Britain to the Netherlands will remain unchanged in gas year 2017/18 at €0.78/MWh for all capacity products, the operator said on 26 June.

In a statement, the BBL Company added that the reserve price in annual capacity auctions slated for 2 July would be €6,917/kWh/h/y. The BBL, along with the IUk pipeline between Belgium and Britain, gives shippers in Britain access to continental European stor-age sites.

A recent report, commissioned by the two pipelines’ operators concluded a new tariff re-gime that treated British interconnectors like domestic storage sites would lead to lower wholesale gas prices.

Polandsupply - Poland’s PGNiG announced two pre-liminary supply agreements with US LNG ex-

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https://www.lng.hr/lib/plugins/kcfinder/upload/files/04%2520Annex%25207_Decision%2520on%2520LNG%2520indicative%2520tariff.pdf






Gas in focus News Briefs

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port developers Sempra and Venture Global, according to statements on 26 June.

PGNiG and Sempra announced a pre-liminary agreement for 2mtpa over a 20-year duration that would begin by 2023 from its greenfield Port Arthur project in south Texas. Delivery terms were said to be flexible and could be made available on a free on board (FoB) basis.

PGNiG, Sempra and Australia’s Woodside have a joint agreement to develop Port Ar-thur, although sources said Sempra has led most of the marketing efforts.

Venture Global also announced a similar initial agreement with PGNiG on 26 June for another 2mtpa, also for a 20-year period.

According to Venture Global, the agree-ment is for offtake from the company’s two proposed greenfield projects, Calcasieu Pass and Plaquemines LNG. Venture Global stated that project start-up dates for Calcasieu Pass and Plaquemines LNG are for 2022 and 2023 respectively.

Venture Global has not yet made a final investment decision, and both PGNiG’s agreements with Sempra and Venture Global were not considered binding SPAs. PGNiG already has 2mtpa in long-term sup-ply from Qatargas 3 Train 6 in a contract that lasts through 2034. PGNiG has another five-year contract with Uk-based Centrica on a flexible basis for 0.11mtpa for its Swin-oujscie terminal, which opened in 2015. Both agreements are on a delivered ex-ship (DES) basis.

Spainsupply - Spain’s Gas Natural Fenosa an-nounced that it has renewed long-term gas procurement contracts with Algerian pro-ducer Sonatrach until 2030.

According to a company statement pub-lished on 14 June the renewed gas supply contracts with the Algerian counterpart cover more than 40% of the Spanish utility’s overall gas procurement.

“This agreement is a major step forward to strengthen our historical strategic alliance with Sonatrach. Moreover, it undoubtedly constitutes a significant milestone in the rela-tionship with Algeria as this renewal guaran-tees the stability of gas supply to Spain,” said Francisco Reynes, executive chairman of Gas Natural Fenosa.

While there was no information available as to whether the contract extensions con-cern pipeline or LNG gas imports, the Spanish utility said that the agreement reinforces an “optimal distribution of the supply mix for the country between natural gas supplied via pipelines, which represents 30% of domestic consumption, and LNG”.

Gas Natural Fenosa imports gas from Alge-ria through the Mahgreb-Europe and Medgaz pipelines. It also receives LNG deliveries from Algeria although no long-term procurement contract is known to be in place between the two companies.

UKarbitration - A British commercial court has issued an order to freeze Gazprom’s assets in England and Wales, as part of an ongo-ing dispute between the Russian producer and Ukraine’s incumbent Naftogaz over the enforcement of a landmark arbitration award, according to a statement by Naftogaz on 19 June.

The order, issued on 18 June, requires Gazprom to provide Naftogaz with a list of all assets with a value greater than $50,000 located in England and Wales.

Under the order Gazprom will be required to retain assets in England and Wales with a combined value amounting to $2.6bn, the sum which the Russian producer has been ordered to pay Naftogaz under the terms of arbitration award in February.

Furthermore, Naftogaz has also notified the London offices of 17 banks doing business with Gazprom not to facilitate the reduction of its English and Welsh assets in a way that may affect its ability to pay Naftogaz the $2.6bn. The British court has also set a hear-ing date for 6 July when Gazprom can seek to lift or modify the order.

Gazprom said in a statement: “Gazprom has learnt that Naftogaz of Ukraine has been under-taking the measures to compulsorily enforce the award issued by Stockholm Arbitration within the gas transit contract dispute, in the territory of United kingdom. These actions have been taken despite the order of the Appeal court of Svea district (Sweden) to suspend the enforcement of the above arbitration decision.”

UkraineUnbundling - Ukrainian incumbent Nafto-gaz is committed to unbundle the country’s transmission system by 1 January 2020 but unforeseen events may extend the deadline, said Naftogaz head of trading division Iryna Mykhaylenko on the sidelines of a conference in Budapest.

The cut-off date falls in line with the expiry of the Russian supply contract as a court decision in February obliges Naftogaz to offtake 5bcm/year in 2018 and 2019 from Russia’s Gazprom, with 4bcm/year under take-or-pay obligations.

However, Gazprom has yet to deliver any gas set out by decision.

But in the meantime, Naftogas will prepare the necessary administrative framework and documentation for transferring the com-pany’s assets to Ukraine’s new grid operator called Main Gas Pipelines of Ukraine (MGU), Mykhaylenko added.

Naftogas has previously said that it will not proceed with the unbundling to avoid harm-ing its legal case against Gazprom and violate the court decision on the supply terms.

storage - The Ukrainian regulator NERC has approved an increase in storage injection and withdrawal tariffs from 1 July, according to four sources active in the market.

The injection tariff has been raised to Ukrain-

ian hryvnia 64.40/thousand cubic metres (kcm) (€2.10/kcm), almost double the current injec-tion tariff which stands at hryvnia 32.90/kcm.

Meanwhile, the withdrawal tariff has also nearly doubled to hryvnia 67.10/kcm from hryvnia 32.90/kcm. Prices are exclusive of VAT.

The storage tariff will be set at hryvnia 0.1720/kcm multiplied by the number of days in one year. The regulator did not confirm the tariff increases by publication time.

Ukraine has vast storage capacity and is looking to attract companies to store volumes in its facilities.

There are reports that a few foreign com-panies are using Ukraine’s storage facilities. However, traders active in the region said that even if tariffs remain cheap, they may not compensate for market risks such as ex-change rates, regulatory changes or lack of forward trading.

Demand - Ukraine’s gas transmission system operator (TSo) Ukrtransgaz has announced 12 tenders for the procurement of 2.5 billion cubic metres (bcm) of natural gas for delivery between September 2018 and April 2019, the company said on 26 June.

Starting prices will be linked to the German NCG hub price plus a premium defined at the tender.

The auctions will be held on the ProZorro platforms and interested parties are expected to submit documents by 23 July. Ukrtransgaz said it was expecting offers from both local producers and importers. The gas will be used for balancing the system and as fuel gas for compressor stations to help push the fuel through the system. Last year Ukr-transgaz initiated a similar tender for 2.5bcm for delivery between 1 october 2017 and 30 April 2018.

trade - The Ukrainian regulator NERC has requested the transmission system operator Ukrtransgaz to abide by a 1 August deadline for the launch of the daily balancing gas market.

In a statement posted on the NERC web-site, the watchdog said the grid operator was “slowing down” the launch of the balancing platform and added that the delay was “un-necessary”.

A Ukrainian trader said Ukrtransgaz had started tests on a platform developed by a Hungarian IT contractor, but added that the platform was not user-friendly and required a few updates to modules to help streamline activity.

He also pointed out that Ukrtransgaz had to compile a registry of customers ahead of the launch, but that this registry was still not ready. Currently Ukraine uses an ex-post system imbalance settlement whereby balanc-ing is done on a monthly basis. Under this system daily imbalances are aggregated and settled between transmission system operator and shippers. Ukrtransgaz did not comment by publication time.

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Gas in focus Long-term contracts

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Jun '18 18.95 20.58 21.97 20.89

Jul '18 19.81 21.29 22.72 21.41

aug '18 19.79 21.34 22.70 21.78

sep '18 19.78 21.41 22.72 22.05

oct '18 20.50 21.98 23.04 22.45

Nov '18 20.58 23.06 23.34 22.81

Dec '18 20.53 22.86 23.26 22.92

Jan '19 21.02 23.87 23.35 22.79

Feb '19 20.99 23.83 23.34 22.73

mar '19 20.97 23.80 23.32 22.58

apr '19 20.32 20.60 21.44 22.43

may '19 20.29 20.57 21.42 22.27

Jun '19 20.29 20.57 21.42 22.18

Jul '19 19.85 19.88 21.02 21.91

aug '19 19.85 19.88 21.02 21.81

sep '19 19.85 19.88 21.02 21.72

oct '19 19.82 21.18 21.63 21.44

Nov '19 19.82 21.18 21.63 21.35

Jun '18 6.57 7.14 7.62 7.24

Jul '18 6.89 7.40 7.90 7.44

aug '18 6.90 7.44 7.91 7.59

sep '18 6.91 7.48 7.94 7.70

oct '18 7.18 7.70 8.07 7.86

Nov '18 7.23 8.10 8.20 8.01

Dec '18 7.23 8.05 8.19 8.07

Jan '19 7.42 8.43 8.25 8.05

Feb '19 7.43 8.44 8.26 8.05

mar '19 7.44 8.45 8.28 8.02

apr '19 7.23 7.33 7.63 7.98

may '19 7.24 7.34 7.64 7.95

Jun '19 7.24 7.34 7.64 7.92

Jul '19 7.14 7.15 7.56 7.88

aug '19 7.14 7.15 7.56 7.85

sep '19 7.14 7.15 7.56 7.81

oct '19 7.19 7.68 7.85 7.78

Nov '19 7.19 7.68 7.85 7.75

Russia Norway Netherlands Algeria Russia Norway Netherlands Algeria

German import contracts from

spanish LNG import contract from

German import contracts from

spanish LNG import contract from

icis HereN ForWarDs assesseD LoNG term coNtract VaLUeseFFectiVe 1 JUNe 2018

icis HereN ForWarDs assesseD LoNG term coNtract VaLUeseFFectiVe 1 JUNe 2018€/MWH $/MMBTu

FORWARD CURVE: BORDER PRICES VS NBP

€/MWh

Russia to Germany

Norway to Germany

Netherlands to Germany

Algeria LNG to Spain

ICIS Heren NBP

16

18

20

22

24

26

Nov2019

Sep2019

Jul2019

May2019

Mar2019

Jan2019

Nov2018

Sep2018

Jul2018

HISTORICAL BAFA OUT-TURN AGAINST NBP AND TTF OUT-TURN (MONTHLY INDICES)

€/MWh

BAFA price NBP index TTF index

10

12

14

16

18

20

22

24

Jun2018

Apr2018

Feb2018

Dec2017

Oct2017

Aug2017

Jun2017

Apr2017

Feb2017

Dec2016

Oct2016

Aug2016

SOURCE: BAFA/ICIS



Gas in focus Spot marketS

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MONTH+1 PRICE ASSESSMENTS28 JUNE 2018€/MWh

0

5

10

15

20

25

PSVCzechVTPNCGPEGNord

TTFZTPZee-brugge

NBP

market HiGHLiGHt

Belgian gas exports set to rise in July as iUk works endthe Ztp July ’18 has been dealing at a dis-count to the equivalent TTF product during June which may suggest that shippers will export high-calorific gas (H-gas) to the Neth-erlands from July.

The TTF Q3 ’18 has also been holding a premium to the corresponding ZTP contract indicating that exports to the Netherlands may persist over a longer period of time. A similar situation played out in 2017 when gas exports to the Netherlands ramped up considerably from 29 June and lasted until mid october. The closure of Britain’s Rough storage site in June 2017 meant British shippers were keen to export gas via Belgium to store in the Nether-lands, France and Germany.

During the 13 days leading to the Britain-Belgium Interconnector (IUk) closure, Belgium was a net importer of H-gas from the Nether-lands due to lower year-on-year imports from Britain. Fluxys data indicated that during the same period in 2017 Belgium exported gas to the Netherlands on every session as the TTF Day-ahead held a considerable premium to the ZTP Day-ahead.

Many of the neighbouring European hubs started the summer with extremely low volumes of gas in storage due to a very cold March. The IUk maintenance ended on 28 June and imports from Britain surged, allow-ing Belgium to export more gas to neighbour-ing hubs. Arun Toora

BritaiN

Day-ahead falls as exports unavailable, far curve risesNatural gas prices were moving down at the NBP between 14-28 June, coinciding with annual maintenance on the Interconnector pipeline.

With this pipeline down, Britain could not export volumes to mainland Europe, which reduced overall demand in the country.

There were a couple of sessions of upside on the Day-ahead driven by unplanned out-ages on offshore Norwegian infrastructure, as well as some problems in the British North Sea, but overall the trend was downwards.

Consumption excluding exports was below average for the time of year, with domestic gas use very low and limited storage injec-tions taking place through the fortnight as shippers preferred to wait for lower prices in the third quarter.

Relatively high output from renewable facilities meant gas use for power generation was relatively low.

At the end of the two weeks the NBP Day-ahead moved up sharply, due to the return of the Interconnector.

The upside at the end of that period was not enough to offset earlier losses and on 28 June the benchmark contract had lost around 1.5p/th from 14 June.

Near curve prices tracked the downside at the front, with these contracts moving down on fairly limited traded volumes.

on the far curve contracts reacted to move-ment in the wider fuels complex.

Brent crude was the main driver, with the benchmark oil price pushing higher over the weeks.

Market participants said on several sessions even the NBP prompt was moving in line with oil, which is normally not the case on prod-ucts for near-term delivery.

Coal and carbon were also important driv-ers, with these also moving up during the period.

Coal was cited as the key driver on several sessions, a significant shift from the usual re-lationship between the fuel types.

As these three key drivers were moving up, the NBP seasons also made gains across the two week period. Ben Samuel

Day-aheadNBp 54.538 21.031 B -4.03Zeebrugge 55.088 21.243 T -6.40Ztp 55.598 21.438 B -6.03ttF 56.927 21.950 B -4.10NcG 57.024 21.988 B -3.83GaspooL 57.964 22.350 B -1.38peG Nord 55.598 21.438 B -6.03Vtp 58.743 22.650 B -0.98psV 62.762 24.200 B -1.38czech 58.743 22.650 B -1.25slovak 59.132 22.800 I -0.33aoc 62.762 24.200 I -3.20turkish Gas 48.454 18.683 F 0.42July '18NBp 53.825 20.744 B -4.85Zeebrugge 55.625 21.438 T -2.71Ztp 55.946 21.563 B -2.82ttF 56.854 21.913 B -1.52NcG 57.243 22.063 B -1.45GaspooL 57.503 22.163 B -0.73peG Nord 56.594 21.813 B -1.41Vtp 58.508 22.550 B -1.04psV 62.627 24.138 B -0.72czech 58.313 22.475 B -0.06slovak 60.000 23.125 S -0.80aoc 63.081 24.313 I -2.65Winter 18NBp 63.850 24.473 B -0.57Zeebrugge 60.600 23.227 B -0.28Ztp 60.200 23.075 I -0.54ttF 59.287 22.725 B -0.76NcG 59.418 22.775 B -0.76GaspooL 59.059 22.638 B -0.66peG Nord 60.103 23.038 B -0.65Vtp 59.940 22.975 B -1.34psV 64.505 24.725 B -0.45czech 59.320 22.738 S -0.82Gas year 18NBp 57.050 21.793 I 0.62Zeebrugge 55.950 21.373 I 0.85ttF 55.398 21.163 I 0.65psV 60.731 23.200 I 0.43

period p/th €/mWhData used %chg*

eUropeaN spot Gas price assessmeNt 28 JUNe 2018

*In comparison to prices published in previous issue of EGM. Change on €/MWh figure. All values represent the midpoint of the ICIS Heren bid-offer assessment published in European Spot Gas Markets (ESGM) on the displayed date.

HereN® moNtHLy cUmULatiVeiNDices JULy 18

NBp, p/th

Zeebrugge, p/th

ttF, €/mWh

NcG, €/mWh

GaspooL, €/mWh

peG Nord, €/mWh

Vtp, €/mWh

psV, €/mWh

54.046

55.146

21.789

21.922

21.938

21.794

22.412

23.979Values represent the weighted average of all month-ahead trades gathered and verified by ICIS Heren for its European Spot Gas Markets (ESGM) publication, from the first working day of the month up to the displayed date.




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NetHerLaNDs

curve tracks fuels higher; prompt slips on low demandNatural gas price movements were mixed on the Dutch TTF in the two weeks from 14-28 June, with prompt and near curve prices slipping as contracts further out made mod-est gains.

Strength in the wider fuels complex was the main driver on the far curve, with Brent crude in particular making big gains.

Meanwhile, low demand weighed on the prompt, with storage injections falling to a rate of just 21mcm/day on 15 June, according to data from operator GTS.

over the period, the Netherlands’ year-on-year storage deficit narrowed slightly from 14 to 12 percentage points, but an often significant premium of the Day-ahead to the front month July ‘18 contract left shippers little incentive to ramp up injections further.

While much of Europe has refilled storage sites that were left almost empty after the cold winter, the Netherlands has struggled to keep up.

Expectations of increased storage demand in July lifted the front month contract to move almost completely in line with Q3 ‘18.

Usually, July would trade at a discount to the quarter.

Supply could also be tight in July, with annual maintenance on Russia’s major Nord Stream pipeline to Europe scheduled for the second half of the month.

Towards the end of the period, prompt contracts recovered some of their lost ground when storage injection demand rebounded and an interruption to quality conversion capacity was extended. Patrick Sykes

GermaNy

storage inputs dip despite pending maintenanceGas price movements at the NCG and GA-SPooL were volatile in the weeks surround-ing the oPEC talks on 22 June which were largely expected to provide a new benchmark for oil prices, but fell short of most traders’ expectations.

The GASPooL Day-ahead were among the most volatile contracts, fluctuating between €21.638/MWh and €22.663/MWh.

The NCG Day-ahead lost its premium to the front month from 22 June onwards when the oPEC decision sparked further volatility on European gas markets and the influence of storage demand on June prices weakened.

German storage levels reached a comfortable point at 40% fullness on 15 June, thereby reducing near-term demand.

Injections lost momentum in the second half of June as the average rate put into storage dropped from 92mcm/day between 1-14 June to 78mcm/day between 15-27 June. This was partly due to an injection capacity outage at the katharina storage facility.

July ‘18 maintained a slight premium to Q3 ‘18 throughout the two-week period on the NCG. This premium was largely due to upcoming maintenance on major import routes for Russian gas. The Mallnow border point will be down from 9-14 July and Nord Stream will be offline from 17-31 July. As a planned event, this has now been factored in by market participants and was not causing concern. Jennifer Sanin

itaLy/aUstria

italy’s psV premium to the benchmark Dutch TTF hub and the neighbouring Aus-trian VTP reduced sharply in the two weeks to 28 June, after a planned outage reducing imports at the Tarvisio entry point on the Aus-trian border ended on 21 June.

The cut had reduced import capacity at Italy’s main entry point by up to 40%, or 43mcm/day.

The PSV premium rose during the first week in order to attract more volumes from north Europe at the Gries Pass entry point on the Swiss border. Storage injections also dropped in the period to allow the system to remain balanced, averaging 64mcm/day between 15-21 June compared with an average 75mcm/day between 1-15 June, data from TSo Snam showed.

Market participants turned up injection volumes straight after the end of the outage, to an average of 78mcm/day between 22-28 June. Storage levels were largely aligned with 2017, at 57% full as of 28 June.

The Austrian VTP Day-ahead contract dropped €0.225/MWh during the 14-28 June period on the back of limited capacity at the Austrian-Italian border.

Lower storage injection demand in Austria was another bearish driver for the Austrian spot contract as storage intakes ticked down slightly to 12mcm/day over the fortnight, which was 1mcm less compares to the previ-ous two weeks.

Large exports to Hungary along the TAG pipeline helped to partially offset the bearish drivers for the VTP Day-ahead. The down-ward trajectory of Austrian prompt contract also pressured the near-curve. Meanwhile, contracts on the far-end shed value over the fortnight, despite rising oil and coal prices. Riccardo Patrian and David Simon

psV premium drops as outage ends

BeLGiUm

Belgian imports from Germany surge Belgian natural gas imports from the Neth-erlands and Germany ramped up during the period from 14 June to 28 June.

High calorific imports from Germany averaged around 4.5mcm/day across the two weeks with around 8mcm recorded by Fluxys on 24 June, the highest level of imports

from Germany since mid-April. Belgium was importing from the Netherlands until 21 June but switched to exports a day later as the Dutch TTF Day-ahead premium to the equivalent ZTP product opened up to 0.57p/th. The premium was assessed at 1.68p/th on 27 June.

LNG Edge indicated that the 217,000cbm Al Shamal arrived into the Zeebrugge termi-nal on 27 June, the first since the start of week 24.

The IUk pipeline maintenance ended on 28 June and imports from Britain into Belgium surged to 35mcm. Arun Toora




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cZecH/sLoVak

czech and slovak storage filling levels remain lowczech and slovak storage levels has re-mained below the filling levels in 2017 but shippers have been scrambling to fill storage stocks over the fortnight.

ICIS-collated storage data showed that storage intakes in the Czech Republic ticked up slightly by 1mcm to 13mcm/day on aver-age during the 14-28 June period.

Czech storage tank were only 39% full on 28 June, down by 16 percentage points year on year.

Similarly in Slovakia, storage levels have been lower as in 2017, with storage tanks only 32% of the available capacity utilise, which is 9 percentage points lower compared to 2017.

Meanwhile, Hungarian and Polish storages stocks has been higher year on year as in

2017 due to large injection profiles. Hungar-ian exports to Ukraine along the 16.8mcm/day capacity Beregdaroc border point ramped up over the fortnight to 15mcm/day, which was 3mcm higher compared to the previous two-week period.

Flows to Ukraine should remain high in the coming weeks given high cross-border capac-ity bookings through the RBP platform.

This kept the Hungarian MGP Day-ahead in a €0.25/MWh premium over its Austrian counterpart through the 14-28 June period.

Meanwhile, Slovak exports to Ukraine via the Budince point remained unchanged at 20mcm/day on average over the fortnight.

Exports to Ukraine will remain high in the coming weeks due to large injection demand. David Simon

spaiN

July LNG reloads behind wider pVB premium to ttFconfirmation of three LNG reloads due to take place in July supported the PVB July ‘18 contract’s premium to its TTF counterpart, as traders factored in sourcing additional gas and LNG supply.

The PVB-TTF July ’18 premium averaged €2.65/MWh for the period 14-28 June com-pared to €1.75/MWh for the period 31 May to 13 June, ICIS pricing data showed.

The spread between the two contracts was at its widest since end of February as strong Asian LNG spot prices opened up an arbitrage opportunity to reload cargoes in Iberia and deliver LNG to higher-priced markets in the Far East.

Transmission system operator Enagas re-cently confirmed three reloads taking place during the month of July, two scheduled for 13 and 23 July at the Barcelona terminal, while one, a partial, is scheduled to take place at Bilbao on 11 July.

The return of the Trillo nuclear reactor after a period of maintenance, coupled with healthy hydropower stock levels, could pro-vide a bearish signal to oTC gas prices as it implies less gas for power demand. However, upside is possible if more reloads take place for the remainder of the third quarter or a heat wave hits Iberia. Dalila Ouerghi

FraNce

the trs Day-ahead premium to the PEG Nord equivalent averaged €3.169/MWh over the period 14 to 28 June and reached a high of €3.850/MWh on 27 June.

A tight supply situation in the southern trading region amid rising injection demand was the main factor driving strength on the TRS prompt.

French system operator GRTgaz carried out maintenance on the north-south link, limiting gas flows between the two regions.

Bullish sentiment from this squeeze on sup-plies reaching the south was compounded by an ongoing lack of LNG cargoes arriving at southern terminals.

High prices in Asia continued to attract LNG cargoes away from Europe, depriving the south of a key source of supply.

Traders operating in France said they ex-pected the TRS Day-ahead contract to remain at a premium of at least €2/MWh to the PEG Nord in the run up to the market merger on 1 November 2018.

Undersupply also contributed to strength in PEG Nord. The PEG Day-ahead contract slipped to a discount of €0.550/MWh to Ger-many’s NCG equivalent, making imports from the country too expensive.

In addition, maintenance in Belgium and Norway limited imports from these coun-tries.

Several deals took place on PEG contracts that showed growing premiums to the TTF.

While ‘normal’ relative to the historical average, a premium of around €0.30/MWh on the front winter reflects persistent market doubts that congestion may persist in the merged Trading Region France, and cause price spikes. Kelly Paul

tight supply supports trs, peG Nord

NBp 20.130 21.961 20.043 22.006 23.722 24.689 18.377 19.188

Zeebrugge 21.029 22.535 20.933 21.928 22.637 23.342 n/a n/a

Ztp 21.450 22.300 21.050 21.850 22.525 22.750 n/a n/a

ttF 21.425 22.625 21.300 22.400 21.900 23.000 18.725 22.700

GaspooL 21.575 22.525 21.450 22.400 21.850 22.775 19.100 19.100

NcG 21.450 22.600 21.475 22.325 22.035 22.950 19.095 19.740

peG Nord 21.150 22.575 21.400 22.050 22.290 22.675 19.010 19.030

trs 23.650 25.000 23.750 25.000 n/a n/a n/a n/a

Vtp 21.900 22.825 22.025 22.850 22.215 23.125 19.725 20.425

psV 23.375 24.375 23.550 24.375 24.000 24.925 20.925 21.800

traDeD raNGes For key Gas coNtract For tHe perioD: 15 JUN 2018 to 28 JUN 2018

markets Day-ahead July '18 Winter 18 summer 19

Low High Low High Low High Low High

€/mWh




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storaGe commeNt

injections into european natural gas stor-age sites have stabilised in recent weeks as volumes in store have edged closer to last year’s levels.

But there are still concerns in some areas that storage sites will not enter the next gas winter with sufficient gas to cover sustained high demand.

At the end of the last gas winter, a pro-longed cold snap in February and March caused shippers to withdraw large volumes from store at a time when they would usually be reducing withdrawals or even beginning to inject.

This left sites just 9% full at the start of the gas summer.

High injections in the first two months of the gas summer helped to replenish stocks, but in the last month inputs have slowed as stocks moved closer to last year’s levels.

Shippers added around 5bcm of gas to stocks in the two weeks to 28 June, leaving storage sites just three percentage points less full year on year.

However, this is still the lowest level in the last six years, according to data collated by ICIS.

injections slowing but stocks still low

SOURCE: ICIS

MCM

DE GB NL BE FR

NET STORAGE FLOWS AT TRADED MARKETS - LAST THREE MONTHS

-150

-100

-50

0

50

100

27 Jun2018

30 May2018

30 Apr2018

30 Mar2018

The average injection rate so far this sum-mer has been 337mcm/day. ICIS analysis indicates that if this rate continues for the rest of the summer there will be 69.56bcm of gas in store on 30 September, around 3bcm short of the volume held at the end of last summer.

Although this is not a significant difference, the volume of gas in store at the start of the last gas winter was relatively low in compari-son to other winters.

It is impossible to tell at this point whether

the next winter will be warmer or colder than the last, but the memory of the March cold snap may make entering the next winter with low volumes a red flag.

This is already reducing the Q4 ‘18 con-tract’s discount to Q1 ‘19 at a number of markets, reflecting a potentially tight supply situation throughout winter.

It is also squeezing the spreads between the remaining summer delivery contracts due to injection demand. Julie Fisher


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Competition between Russia and the US for gas sales spills into the political domain as cost of financing can make or break new projects

the battle for the European gas market will intensify in the coming years amid shrinking demand, tougher global competition and financing difficulties.

The International Energy Agency (IEA) 2018 report envisages the US and China com-ing to the fore as gas industry’s major driving forces - the former on the supply, and the latter on the demand side.

“What I can tell you is that demand is from emerging countries, It doesn’t come from Ja-pan, it doesn’t come from Europe,” Fatih Birol, IEA’s executive director told the World Gas Conference (WGC) in Washington on 26 June.

According to IEA, in 2017 global natural gas demand increased by 3% with China ac-counting for almost one third of the global growth. Driven by environmental policy, Chinese gas demand grew by 15%. Between 2017 and 2023, China is expected to account for 37% of the global gas demand growth. The IEA also said that China will become the world’s largest gas importer by 2019, with imports reaching 171bcm by 2023. Most of that import need will be met by LNG.

The IEA painted a bright future for the US as the world’s largest LNG producer and exporter, but noted that project financing will be paramount.

Meanwhile, Russia has historically seen Europe as its main market for gas, with Gazprom supplying more than one third of European demand. It is strongly betting on Europe’s import needs increasing in the future as domestic production declines.

Russia is also counting on expanding LNG exports globally - and is clashing with the US on every front.

The stand-off is already playing out in hurdles put in the way of the Nord Stream 2 pipeline project. The pipe would give Russia’s Gazprom additional 55 billion cubic metres (bcm)/year capacity alternative to the tradi-tional transit route via Ukraine.

Russian incumbent Gazprom and the country’s largest independent producer and LNG exporter Novatek were both absent from the WGC.

And it was not the conference that was on the minds and tongues of Russian industry commentators during the past several days, but Denmark’s threats to deny a permit for the construction of the Nord Stream 2 pipe-line. Such a move could impede - if not block - the project.

The US has been vocal in its opposition to this Gazprom-led venture. Nord Stream 2 backers - European energy companies - are now concerned that potential new US sanc-tions targeting Nord Stream 2 could make the pipeline uneconomic.

Gazprom’s traditional European clients are actively seeking to diversify - sometimes driven by considerations that are more politi-cal than economic. Thus Poland’s PGNiG just announced two preliminary supply agree-ments with US LNG export developers Sempra and Venture Global (see separate story).

The US itself has just started its second year of exporting LNG, from Cheniere’s Sabine Pass and now the Dominion Cove Point plant, but it is facing increasing competition from other global suppliers, including Qatar. FIDs for new projects are being considered in a tough environment with buyers seeking more flexible terms and financing more difficult.

It is obvious that global gas players will use any political tool available to topple a rival. But they must not forget that gas is also competing with other energy sources, and politicisation could turn out to be a double-edged sword. Katya Zapletnyuk

Denmark’s threat to deny Nord Stream 2 construction permit could impede - if not block - the project

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