Europe is set to retain numerous gas supply options throughout 2017 as traditional pipeline suppliers continue their market share offensive and LNG imports to the continent rally from their unexpected lows in 2016.
With demand -- especially in the key power sector -- seen continuing its recovery from the past two years, much focus will again be placed on declining domestic European production and the subsequent need for increased imports.
EU gas demand is expected to have increased by some 6% in 2016 to around 447 Bcm, according to industry group Eurogas, following a rise of around 4% in 2015, and according to Platts Analytics' Eclipse Energy could rise further in 2017 driven by the arrival of more LNG.
The demand recovery from the lows of 2011-14 has been a result of increased gas consumption for power generation and signs of revival in industrial activity in Europe.
Gas demand for power generation in the UK rose 50% to 19.8 Bcm in the year to December 15, while Italian gas-for-power demand jumped 12% to 20.9 Bcm, according to data from Platts Analytics.
Demand in France also rose sharply towards the end of 2016 as parts of the French nuclear fleet were taken offline for safety checks.
From January 1 to December 15, 2016, French gas demand for power generation more than doubled to 3.8 Bcm.
The situation around the availability of French nuclear capacity in 2017 is still uncertain and coal prices are expected to remain volatile after their late-2016 rally, so the level of gas demand for power generation will be dependent on numerous interlinked factors.
There was some coal-to-gas switching in Northwest Europe in 2016 given the divergence in coal prices to the upside and gas prices to the downside, while in the UK coal use in power generation slumped due mostly to the continued impact of the carbon price support mechanism and the retirement of a big chunk of coal-fired power generation capacity.
But no new UK coal plant retirements are expected in 2017, according to Platts Analytics.
Industrial demand will likely have been boosted by the weaker euro in 2016, benefiting Europe's export-oriented industries.
But with demand expected to be relatively robust in 2017, there is a risk of a price spike at the start of the year in the event of a cold snap given gas storage constraints at the Rough facility in the UK and historically low stocks in NWE.
On the other hand, a milder winter would lead to less storage injection demand in the summer 2017 and subsequent pressure on prices.
According to the latest forecasts from Platts Analytics, NWE storage stocks are expected to return to the top of their three-year range by the end of September 2017 as higher LNG sendouts are absorbed into storage facilities.
Supply Dynamics
The biggest shift on European gas markets is expected to be in the volume of LNG supply.
According to Platts Analytics, in the latter part of the first quarter there will be a "substantial" year-on-year increase in LNG deliveries to NWE, reducing the need for overall storage withdrawals by 42 million cu m/d on the year.
In the UK, Netherlands, Belgium and France, Platts Analytics assumes 80 million-90 million cu m/d of LNG sendouts in Q1, 2017 compared with 58 million cu m/d on average in February-March 2016.
The increase in imported LNG volumes could put pressure on prices and increase demand for coal-gas switching.
LNG imports into Europe surprised to the downside in 2016 due to higher demand in the Middle East and several trips at liquefaction plants including Gorgon in Australia and Angola LNG.
But the picture is set to shift in 2017 as high counter-seasonal demand in the Middle East dissipates and Qatari production returns to around 300 million cu m/d.
Global LNG supply will be boosted further as U.S. and Australian volumes ramp up, although there is the possibility that many cargoes will be swallowed up by the key north Asian markets given the rally in spot LNG prices in December to close to $10/MMBtu.
While LNG is expected to stage a European recovery in 2017, the traditional pipeline suppliers to Europe -- Russia, Norway and Algeria -- will continue to fight to retain, or even grow, market share.
In 2016, Russia smashed its record for deliveries to Europe and Turkey with exports hitting an all-time high of an estimated 180 Bcm.
Norway, meanwhile, was expected to have exported close to its record high from 2015 of 115 Bcm, and Algeria saw its exports to Italy rise threefold to some 18 Bcm.
Renegotiation
The reason for the rise in Italian imports from Algeria was an increase in Algerian production, a shift in the volume terms for Eni's import contract with state-owned Sonatrach and a competitive oil-indexed price given low crude prices in 2016.
At the end of 2016, Eni CEO Claudio Descalzi said it had made a "very important achievement" by again reworking its Algerian import contract for Gas Year 16 (October 2016-September 2017).
The contract, which expires in 2019, is now aligned to the Italian PSV hub, Descalzi said.
"That will allow us to get the break-even for gas and power in 2017 as promised," he said at an investor day in New York in December.
Eni was not the only company to renegotiate long-term gas contracts in 2016 -- Engie and RWE were among those to rework their Gazprom supply contracts to "de-risk" their Russian gas purchases.
Russian gas supplies to Europe are expected to be strong again in the first months of 2017 as buyers look to max out their take-or-pay volumes ahead of a likely rise in oil-indexed contracts, especially in southern Europe, following the recent oil price rally stemming from OPEC's decision to cut production from the start of January.
Oil indexation does seem to be losing its influence in long-term contracts -- even in southern Europe -- but the oil price still matters.
The head of Gazprom Export, Elena Burmistrova, said in May that hub pricing was not a "panacea" for the gas industry and the ideal way to price gas in Europe was still a regime based on oil indexation with only elements of hub pricing.
But given that global oil prices are currently in contango, oil-linked gas prices become more expensive further down the curve in 2017.
Gazprom has also said it is not "dumping" gas in Europe and the entire boom in supplies is due to buyer-led nominating behavior to meet demand.
Supply Outlook
Russia has said it expects to export in 2017 similar volumes to Europe as in 2016, while the European Commission decision in October to allow Gazprom more access to the OPAL gas link in Germany could mean increased flows of Russian gas.
It is not yet clear whether Gazprom will choose to divert flows to Nord Stream and OPAL away from the Ukrainian route, or use the extra OPAL capacity to flow more gas.
Whichever way it falls, the key is that OPAL is a cheaper option for Gazprom than Ukraine.
Tensions between Moscow and Kiev remain heightened, with the anticipated result of the multiple arbitration cases between Gazprom and Naftogaz in March an added pressure.
The state of relations between Russia and Ukraine is always a matter of concern for European gas buyers.
Disruption to flows via Ukraine -- as always -- cannot be entirely ruled out especially in an extreme cold winter scenario.
Norway, meanwhile, is forecasting gas output at 107.3 Bcm in 2017 while the UK has been buoyed by the startup of three new fields in 2016 -- Laggan-Tormore, Alder and Cygnus.
Algeria too expects to bring on a number of new gas fields in 2017, including the major Engie-operated Touat field.
Closer to home, the Groningen field quota has been reduced to 24 Bcm from 27 Bcm for Gas Year 16, although a number of appeals are being heard currently that could see the quota fall further.
The drop in Dutch gas production is a worry for European gas supply security, with increased dependence on imports the result.
Also in the Netherlands, the expiry of long-term capacity contracts for the BBL pipeline to the UK has shifted European gas market dynamics significantly.
The TTF/NBP spread and whether it goes above full-cycle BBL costs (including entry-exit) could become a new key pricing point.
Current geographical spreads are so poor there is no incentive to move gas given the high cost of pipeline capacity.