[NGW Magazine] Floating LNG could help Angola

This article is featured in NGW Magazine Volume 2, Issue 21

Angola’s upstream capex nosedived with the oil price, so output could follow suit from 2019, but gas offers a budgetary solution for the export-dependent country, if it can offer acceptable terms.

An estimated $67bn was cut or deferred from Angola’s upstream capital expenditure in the 2015-20 period, relative to what was expected in late 2014, according to a report by global consultancy Wood Mackenzie last month. These were primarily in deep and ultra-deepwater oil projects.

Of the countries in sub-Saharan Africa, Angola was the most affected by the oil price shock. Moreover, that loss of investment will impact its future oil production post-2019 that will impact oil export revenues in a country reliant on these for public spending.The government in Luanda and its state-owned oil producer Sonangol are taking steps to address these concerns.

Angola though also has sizeable offshore gas reserves which, as the global LNG supply glut diminishes in the 2020s and if the government reorients its fiscal terms, could be developed through floating liquefaction (FLNG) projects, such as the one that Cameroon has developed and Equatorial Guinea soon will.

WoodMac senior research analyst Adam Pollard thinks that FLNG might work one day for Angola’s Lontra gas field, if the country enables developers to be paid for any gas they produce.

Impending Crisis

“Sonangol is part way through a five-year restructuring programme to modernise and improve its efficiency. What we see now is that the new president Joao Lourenco has a priority to address the oil and gas industry,” Pollard told NGW October 25.

Two days earlier Angola’s government put a committee in place, led by its new petroleum secretary Carlos Saturnino, to conduct an urgent audit of the sector – ostensibly lasting one month – to identify key challenges; it also includes Sonangol, the finance ministry and presidency, and the six leading oil producers in Angola: BP, Chevron, Eni, ExxonMobil, Statoil and Total.

“The key issue is how to stimulate upstream investment and avoid this impending drop in production,” explains Pollard: “There’s a lot of oil that’s been discovered. What WoodMac modelled in 2014 was an increase from 1.65-1.7mn b/d currently to over 2mn b/d in 2019. But some new projects have been deferred or cancelled under the lower oil price environment. Instead a decline looks likely, with 2019 looking like the inflection point where output begins to drop off without additional volumes from new projects. We see quite a steep decline after that.”

There have been no new final investment decisions (FIDs) in Angola for three years now, since operator Total and partners gave the green light to the Kaombo oil field. 

“Total is developing the Kaombo oil project on block 32 – the last FID to be taken in Angola back in 2014. There are other discoveries on that block. BP’s block 31 has discoveries too. These are all ultra-deepwater discoveries, that would need improved economics to go ahead,” Pollard explains.

“Some Angolan projects [up to 2014] had development costs of $35-$45/b, before you’ve paid tax,” he added. That simply won’t provide returns to investors in the world of $50-$60/b oil price.

Kaombo was originally due to start producing this year. The 230,000 b/d Total-led venture, based on six oilfields feeding into two offshore production ships, includes Sonangol, the Sonangol-Sinopec joint venture, ExxonMobil, plus Portugal's Galp. As of late October the field was expected to start production in 2018.

Trust and economics

Under the former president Jose Eduardo dos Santos, the government reacted slowly to the oil price collapse. In mid-2016 he appointed billionaire daughter Isabel dos Santos to chair state Sonangol who cut costs, shelved projects and cancelled a $1.75bn deal to buy key upstream assets from US firm Cobalt International, chiefly its 40% interests and operatorship of offshore blocks 20 and 21. The US firm responded with an arbitration claim against Sonangol for over $2bn damages.

“As it stands, the licences on the two Cobalt blocks have expired,” notes Pollard: “Sonangol has told Cobalt that if it can find a buyer, then it would extend the licences, so there could be a development. But with arbitration, and questions over the licences, I think Cobalt is finding it difficult to find a buyer” (see article alongside for Cobalt's comments).

BP exits Katambi Gas

BP in mid-2017 pulled out of the Katambi gas find made in 2014. It is on block 24 which BP operated with Sonangol. Katambi has in-place resources of 8 trillion ft³ gas plus 280mn barrels of condensate. 

Additionally BP wrote off $753mn of Angolan exploration costs – chiefly but not exclusively on Katambi – in its 2Q 2017 results. It did this, despite the early 2016 adoption of a new law to improve terms for ‘marginal’ fields (gas as well as oil) that appears too little or too late to have impressed investors.

Gas was also found by Cobalt in 2013 at its Lontra-1 offshore well, while the Zalophus find (also Cobalt/BP) was assessed at 2.8 trillion ft³ gas plus 313mn bbls condensate by Sonangol in 2016. Lontra and Zalophus are separate fields, although no official reserves figure has been given for Lontra.

“A number of companies have left the Kwanza basin where BP relinquished its acreage,” Pollard tells NGW: “Companies were finding gas, and the current production sharing agreements in Angola don’t have commercial terms for gas. Having suitable gas fiscal terms and a strategy for gas is one part of the change needed. In addition, establishing a cost efficient development plan to suit $50-$60/b is required."

Uneasy power structure

Not only lower oil prices since 2014 and the Cobalt dispute have rattled investors, but also political paralysis. But the latter may now change.

Newly-appointed Saturnino was sacked in 2016 from his former position as Sonangol upstream chief by incoming Sonangol chair Isabel dos Santos for alleged “serious management failures.”

Lourenco, who appointed Saturnino as petroleum secretary October 13, clearly felt he was qualified for his new job. He had been Sonangol's upstream chief until 2016, and before that, its negotiations director back in 2009 when he helped strike a strategic partnership with Cobalt. Rebuilding such relationships with international oil companies is one of the challenges he will face in his new role. Another will be supervising, maybe even reining in, the Sonangol chairwoman who is among a handful of officials guaranteed their jobs by a law introduced by Jose Eduardo dos Santos when he left office.

Lourenco merged the petroleum and mining ministries into a single ministry, headed by Diamantino Pedro Azevedo, a former CEO of state iron ore mining company Ferrangol. Two secretaries of state – Saturnino for petroleum, and Janio Victor for mining/geology – now report to Azevedo. Time will tell whether that adds a level of scrutiny, or merely bureaucracy.

However Pollard thinks the October decision to convene the six leading oil producers in Angola on a committee with the key state players is a sign that the government recognises the need for reforms.

“The good thing is there is acknowledgement that things need to change, and the first thing the government did was talk to the operators, which is pretty positive. The government is working with the industry to address the most important issues and finding the best way to go about implementing change.,” he said. One area that certainly merits consideration is Angola’s lack of rewards for developing gas.

No framework for developing gas

“In Angola, there is no upstream contractual framework for developing gas,” explains Pollard.

Until now, all associated gas has been supplied free to the 5.2mn metric ton/yr Angola LNG plant. “The cost of building pipelines to the grid and to Angola LNG are reimbursed, but all the gas is owned by Sonangol, leaving no real incentive to develop gas. If you make a purely gas discovery, then there’s no liquids production to justify development.”

Angola LNG was developed at a cost of $10bn by partners Chevron 36.4%, Sonangol 22.8%, and BP, Eni and Total (each 13.6%) and started exports in 2013. Developed at a time before cheaper on-ship floating liquefaction was a proven technology, it has the distinction of being the world's first liquefaction venture fed solely on associated gas.

Without Angola LNG, that gas would be flared. But the venture was beset by major problems: a rupture on its flare line forced a complete shutdown from April 2014 to June 2016 during which key contractor Bechtel undertook major repairs of unspecified cost. A further two-month outage followed in 2H 2016.

Since the start of 2017 owners point to much more reliable export volumes. But the high cost, and project management difficulties, are likely to persuade future gas developers to consider FLNG solutions first – a more modular technology where standardised liquefaction units can be fitted at specialist shipyards in Asia, prior to deployment.

Multi-trillion ft³ resource

As of today, there’s no floating LNG project officially on the table for offshore Angola, as a list of such projects in the planning or pre-engineering phase listed in an appendix to last year’s Oxford Institute for Energy Studies report on FLNG illustrates.

And there would be no need to take FID on floating LNG this year or next. Most analysts expect the global LNG market likely to remain oversupplied until 2022-24. In the previous issue of NGW Magazine, WoodMac’s LNG research analyst Lucas Schmitt told NGW: “Currently we expect the market to rebalance around 2023, possibly earlier on a seasonal basis.” 

And yet, as WoodMac’s Pollard notes: “If you don’t take FID on projects shortly, there’s a feeling you might be left short by mid-decade.”

In Angola he sees “plenty of potential resource there, particularly in those blocks in which have several trillion ft³ were discovered by Cobalt.” If the government can come up with a “workable gas strategy and terms” then a way can be found to commercialise the gas.

“Sonangol has said it is going to come up with gas terms, which might be the thing which turns around the undeveloped gas discoveries” including Lontra.

“Floating LNG sounds like an obvious thing for Lontra – but we wait and see what the terms look like,” explains Pollard, adding that Katambi, Lontra and Zalophus are predominantly gas, but there’s also “quite a bit of associated gas on block 21 at the Cameia field.” 

Pre-2014, Eni had talked of possible gas monetisation at its block 15/06, including FLNG, but has not responded to NGW’s request for an update on this.  As operator, it started up initial East Hub oil production ahead of schedule in February 2017 on this block, and says 15/06 output will later plateau at 150,000 b/d. Eni’s partners are Sonangol, and a Sonangol-Sinopec joint venture. In the past year though Eni has changed its approach, integrating its exploration and marketing teams, so that it is demand for oil and gas that will determine its upstream activities.

Any deepwater gas prospects would be require monetisation as LNG exports. Asked about a possible internal gas market in Angola, Pollard is sceptical: The domestic market is small at the moment. However, there are plans to grow it through industrialisation, which could offtake gas. There’s talk of a small gas-fired power plant [near Soyo]. However, Angola has a lot of hydro-electric plants which it relies on for electricity. Future gas supplies to the Angolan market is a possibility.

Mark Smedley