Double success for Energean – IPO and FID

Energean put the East Med on the map this week propelling the region into the headlines.

Energean debuted on the London Stock Exchange at the beginning of this week with its Initial Public Offering and USD460 million of new money putting the company’s market capitalisation at just under USD1 billion. The company’s flagship asset is its 70% stake in the Karish & Tanin gas fields offshore Israel which contain 2.4tcf of gas and 33mmboe of light hydrocarbon liquids. First gas is targeted for 2021. The company also has producing assets in Greece and an exploration portfolio throughout the Aegean region.

In the same week Energean reached Final Investment Decision on the Karish & Tanin development giving the green light to commence the USD1.6 biliion project. USD405 million from the IPO proceeds will be used to fund Energean’s 70% share of the project and partner Kerogen will fund its 30% stake. A USD1.275 billion bank facility will also be used to fund this ambitious project.

Energean has secured long-term gas agreements with some of the largest private power producers and industrial companies in Israel. To date it has contracted for the purchase of a total of 61bcm over a period of 16 years, at an annual rate of c.4.2bcm p.a..

The East Med has become a hot play for gas and Karish & Tanin follow in the footsteps of giant gas fields in the region including Leviathan, Zohr and Aphrodite. Energean is set to become an exciting story to follow as industry interest in the East Med grows and the demand for its gas becomes increasingly important being in the centre of short gas MENA countries and the doorstep of Europe.

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Leviathan and Aphrodite gas to fuel ELNG at Idku

As widely reported, Shell has been in talks to buy gas from Israel’s Leviathan field and Cyrpus’ Aphrodite field. It is understood that Shell are looking to contract up to 10bcm p.a. for 10 years in a deal worth up to USD25 billion.

Shell would use the gas to properly restart LNG exports from Egyptian LNG at the Idku liquefaction plant. BG Group was the operator of the plant prior to its acquisition by Shell and previously had a non-binding 15 year deal to source gas from Leviathan – this deal stalled amid the takeover by Shell and regulatory hurdles in Israel.

Leviathan is owned by Delek Drilling (45.34%), Noble Energy (39.66% operator) and Ratio Oil Exploration (15%). The field is on track to target first gas by end 2019.

Aphrodite is owned by Noble (35% operator), Delek Drilling (30%) and Shell (35%). Aphrodite lies in Block 12, offshore Cyprus and was discovered in 2011. BG Group farmed into 35% of the field from Noble Energy in November 2015 for USD165 million. Its commercialisation was previously called into question given the resource was too small to justify export infrastructure to mainland Europe or Egypt. However with the recent Calypso discovery in Block 6, which operator Eni has dubbed as a “Zohr like” play, Cypriot gas could finally take off.

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Venture Global doubles LNG supply contract with Shell on Calcasieu Pass

On 6^th March, Venture Global announced that it had agreed to double its gas sales with Shell North America LNG from 1mtpa to 2mtpa under an amendment to the earlier gas sales agreement for LNG from Calcasieu Pass.

This brings the total committed capacity to 3mtpa with Edison having agreed 1mtpa in September 2017. The sale contracts are for 20 years and under FOB terms. The counterparties to date provide validation of the attractiveness of the project being one of the lower cost, mid-scale liquefaction projects and shows confidence in it going ahead and being able to deliver LNG in a reasonable timescale.

The Calcasieu Pass project is for 10mtpa with easy access to the sea and more than a mile of deep water frontage. It is waiting for non-FTA export approval later in 2018 following which it will look to take FID dependent on securing of further gas sales contracts. Venture Global sees first commercial operations at the end of 2021.

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Tortue unitisation across Mauritania and Senegal

The governments of Mauritania and Senegal have signed an Inter-Governmental Cooperation Agreement in another step forward for the Tortue gas development which straddles the border of the two countries. The field will now be unitised with an initial split of resources 50:50 and a mechanism for future equity redeterminations based on actual production and other technical data.

FID of the field remains on track, targeting year end 2018 with first gas in 2021. The BP-led joint venture is looking at a near-shore FLNG concept which will reduce costs significantly.

The unitised ownership will be BP 61% operator, Kosmos 29%, and government partners retaining the remaining 10%.

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Mitsui victory for AWE battle?

AWE’s board has recommended Mitsui’s all cash bid of A$0.95/share which was received on 28^th January. This superior offer follows a heated battle since the end  of last year.

• November 2017: CERCG cash bid of A$0.71/share conditional on due diligence, rejected following AWE’s assessment that it undervalued the company
• December 2017: CERCG revised cash offer of A$0.73/share
• December 2017: Mineral Resources scrip offer at A$0.80/share
• December 2017: Revised Mineral Resources cash and scrip offer at A$0.83/share – recommended by the AWE board on 21st December
• January 2018: Mitsui all cash offer at A$0.95/share

The Mitsui bid is comparatively clean – all cash, no further due diligence and FIRB approval already obtained. As Mineral Resources did not come back with a superior offer by the deadline of 2^nd February, AWE has entered into an implementation deed with Mitsui with a recommendation to shareholders by the AWE board. Mitsui has a right to match any superior offer and there is a break fee if AWE changes its recommendation.

Mitsui is a natural buyer of AWE and its assets with an established history in Australian E&P. It is in the Northwest Shelf LNG project with Mitsubishi on the west coast, in offshore Victoria gas and Queensland Coal Bed Methane gas project.

Absent any superior offers, Mitsui offer documents are planned to be dispatched to shareholders on Monday 12th February with the offer period for shareholders to accept the offer open until 20th March. The offer required 50.1% acceptances from shareholders to proceed.

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Canadian LNG: Wrong place wrong time for Petronas

Petronas entered Canada in 2011 to build a full upstream gas and LNG business. It did this in the face of declining domestic production and need to source international gas for both domestic consumption and its LNG trading portfolio. It made a move in June 2011 to partner with Progress Energy for CAD1.1 billion by agreeing to fund the majority of future drilling and capital expenditure on the company’s vast acreage position in the Montney play. In 2012, Petronas decided to acquire the whole of Progress Energy for CAD5.3 billion.

Petronas had a fully-fledged plan – consolidate acreage in the Montney (which it did by acquiring Talisman’s portfolio in 2013 for CAD1.5 billion), work up a plan to develop the gas in the ground and send it to an LNG plant, and bring in partners to help fund the hefty project once the plan was in place. In 2013, it appeared that Petronas was making good progress going out to award FEED contracts for the project. Between 2013 and 2015, Petronas brought in a string of Asian partners who were all hungry for more gas to satisfy their domestic appetites and keen to develop a gas and LNG project with Petronas. By the end of 2014, the ownership of the so called Pacific Northwest LNG project was Petronas 62%, Indian Oil 10%, Sinopec 10%, Japex 10%, China Huadian 5% and Petroleum Brunei 3%. However, the project then began hitting a series of roadblocks.

LNG was a completely new industry to Canada and the country did not have the regulatory framework in place – environmental policies and new taxes were being made up as Petronas progressed its project. There was much bickering and negotiations with the provincial and federal governments – with so many moving parts outside of its control, Petronas and its partners could not finalise its investment decision.

There was also strong opposition from environmental groups and the First Nations. Although their agendas overlapped on environmental protection and land preservation, the two groups did have opposing objectives. Some environmental groups wanted the project shelved altogether, whereas the First Nations wanted to share in the economic benefits with suitable protections for their lands.

The straw that broke the camel’s back came in September 2016 when the federal government granted environmental approval, but attached 190 conditions that would require the advanced project to be re-engineered and relocated to meet new onerous environmental requirements. The Pacific Northwest partners went back to the drawing board and even considered moving the liquefaction facility to another island and sourcing power from an hydroelectric plant rather than self-generate from gas. By July 2017, the partnership announced that it was pulling the plug on Pacific Northwest LNG and began looking for buyers for its Montney acreage.

Pacific Northwest LNG had become too expensive and uncompetitive compared to US Gulf Coast LNG projects. While Pacific Northwest was struggling to progress things along, the US had clearly overtaken Canada on LNG exports and were able to do things more cheaply. The US had extensive pipeline infrastructure to carry gas to the coast for export, existing LNG import terminals which could be flipped for exports by adding liquefaction facilities and moved quickly on the regulatory front to give companies and investors certainty on their LNG projects.

Cost stack for pre-FID LNG projects delivered to Asia
Source: Wood Mackenzie

Petronas took a brave step in opening up a new LNG industry in Canada, a developed country it thought would be business friendly with the protection of the law. Clearly the advent of LNG overwhelmed Canada and it was not yet ready to handle such complex projects. Petronas was the unlucky company that found itself in the wrong place at the wrong time.

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US LNG: a snapshot of where things stand in 2018

US shale has been a game changer for the gas markets. Often overshadowed by oil story, US gas production is the unloved sibling of oil – oversupplied, low prices, unprofitable and sometimes an unwanted by-product of oil production in the form of associated gas.

However 2017 came to demonstrate the vast potential for US gas and a complete change in direction with the country becoming a net exporter of gas for the first time. This started with first export from Sabine Pass LNG in 2016 which has now grown to four liquefaction trains with trains 5 in the works.  LNG export capacity could reach 8-9bcf/d in 2020 up from the current 2bcf/d, with additional facilities already under construction:

• Cove Point commenced feed gas at the end of 2017
• Elba Island Phase I will come onstream in H1 2018 and Phase II in H1 2019
• Freeport train 1 is planned for operation in 2018 with subsequent trains coming online throughout the rest of 2018 and 2019
• Corpus Christi and Cameron will also come online towards the end of this decade

Source: EIA

US LNG has been somewhat of a disruptor – it has brought destination flexibility and shorter-term procurement to the market that was once characterised by entirely long-term, oil-price linked offtake. This will shake up the market place and how LNG sourcing will evolve is yet to be understood.

Asia is slated to be the big winner with this extra source of gas with South Korea, Japan and China being the largest importers. This is all helped by the recent expansion of the Panama Canal, enabling LNG from the US east coast to Asia with a cheaper and 11 day shorter journey time. This puts into question whether any US west coast and Canadian LNG projects will take off – very likely no in the near-term. The east coast’s proximity to upstream gas, existing pipeline infrastructure to get gas to liquefaction plants and adapted docks means it remains an advantageous location to host LNG terminals.

Related post: Canadian LNG: Wrong place wrong time for Petronas

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Mozambique LNG moves one step closer to FID

On 31^st July, Anadarko finalised two agreements with the Mozambique government (the marine concessions) which pave the way for FID of the LNG project. The agreements would allow Anadarko as operator to progress with the design, building and operation of the marine facilities for the project and could see FID in 2018. The next step is to begin with resettlement plans, the completion of which would allow construction to commence.

Separately, the partners continue with efforts to secure long-term offtake contracts and the high proportion of offtake by equity holders of the licence reduces the risk surrounding the project. Asian players Mitsui (20%) and PTTEP (8.5%) have a need to source long term gas supply, as do the Indian participants ONGC (16%), Oil India (4%) and Bharat (10%). The remaining Area 1 licence holders are Anadarko (26.5%) and ENH (15%).

Area 1 is estimated to hold c.75tcf of recoverable gas and will initially have two LNG trains at the proposed onshore processing plant with 12mtpa capacity for the Golfinho/Atum field. The scale of the resources does pose a threat to upcoming global LNG developments, particularly Australian projects which also target the Asian gas markets, and could see a glut in the 2020s particularly with Qatar also looking to up its LNG exports.

Earlier this month saw Petronas cancel its large Pacific NorthWest LNG project on the west coast of Canada.

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Gunvor to expand into spot LNG trading as supply increases

Bloomberg

Gunvor Group, the world’s fourth-biggest oil trader, plans to expand into short-term buying and selling of liquefied natural gas (LNG) as global supply rises, two people with direct knowledge of the matter said.

The Cyprus-based trading house will charter vessels for spot agreements and sell cargoes in Asia and the Atlantic basin, tapping into supply from Nigeria, Australia and Southeast Asia, the people said, asking not to be identified because the plan is confidential.

Seth Pietras, a spokesman for Gunvor in Geneva, declined to comment by e-mail.

Gunvor follows Vitol, Trafigura Beheer, Glencore, global energy companies and utilities in competing for spot cargoes as new projects boost LNG supply, first from Australia and later from the US.

The company, which has so far focused on long-term contracts, has an agreement to liquefy natural gas at the planned Magnolia LNG project in the US as well as an accord to supply Panama with the fuel.

Gunvor is also considering a tie-up with OAO Novatek for the sale of fuel from the proposed Yamal LNG project in the Russian Arctic, Leonid Mikhelson, CEO of Tarko-Sale, Siberia-based Novatek, said in January.

Gunvor hired Ksenia Babenkova as an LNG trader for its Geneva office from Gazprom Marketing & Trading, while Kalpesh Patel from BG Group will start in Singapore, according to the people. They will focus on short-term trading.

Rising Trade

LNG trade will rise by 40% to 450 billion cubic meters (16 trillion cubic feet) by 2019, the International Energy Agency said in its medium-term gas market report in June. Spot and short-term LNG contracts accounted for 27% of total trade last year, compared with 25% in 2012, according to the International Group of Liquefied Natural Gas Importers, a Paris-based lobby group.

Spot prices for cargoes delivered to Northeast Asia, the world’s biggest buyer of LNG, rebounded to $11.70/MMBtu on Aug. 18, according to New York-based Energy Intelligence Group’s World Gas Intelligence publication. Prices fell for 21 weeks through July 14, the longest stretch since Bloomberg began reporting WGI data in June 2010, from an historic high of $19.70 earlier this year.

Almost 70 million metric tons of LNG capacity, or 20% of global capacity, is poised to come online in the next few years in Australia, Neil Beveridge and Oswald Clint, analysts at Sanford C. Bernstein & Co., said in an Aug. 22 report.

Source: Bloomberg

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Apache divesting international assets? A hard one!

On 31 July 2014, Apache announced its Q2 2014 results

• Apache said it was looking to exit its Canadian LNG positions and was considering options around its international assets
• This comes amidst Jana Partners, a hedge fund which recently picked up c.USD1bn of shares in Apache, wrote to investors arguing that Apache should focus its efforts on the North American onshore
• Reasoning behind this is that over the last few years, a number of North American onshore pure plays have outperformed Apache
• Apache's international assets, it is argued, are diluting its North American onshore story
• However, analysts do not necessarily agree
• Apache's international assets, especially those in Egypt and the North Sea, generate significant free cash flow for the group
• These are areas of existing production and are low risk operations
• The cash flows are important for the funding of the North American portfolio
• It is further noted that given the number of North Sea assets on the market, the geopolitic issues plaguing North Africa and the relative maturity (though strong cash flow generation) of these assets, it is unlikely that Apache will fund a buyer willing to pay full value
• Its other main operations are in Australia, including the Wheatstone LNG project

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