Eni’s big bet on a recovery
The Italian major faces a number of headwinds, but its upstream focus should leave it primed to capitalise on any oil-price revival
A year ago Eni’s chief executive, Claudio Descalzi, talked of oil prices jumping to $200 a barrel within the next decade if Opec failed to cut production. At today’s prices of around $30/b that may seem far off. But it chimes with Eni’s corporate strategy, which leans heavily on exploration and production. Given considerable recent successes in the field, the company is increasingly well-placed to take advantage of any price rebound.
That’s not to say everything is going Eni’s way. Its flagship Coral floating liquefied natural gas project in Mozambique, based on 0.811bn barrels of oil equivalent (boe), has reportedly been delayed, although Eni would not confirm this. The first 2.5m tonnes-a-year FLNG train had been due on-stream in 2019, with BP lined up as its major buyer. A second 10m t/y facility was to have been built onshore, beginning production around 2021.
Problems with financing such a large upstream development programme in a period of weak prices could delay other projects. Eni cut its capital expenditure by 17% to around €12bn ($13.1bn) in early 2015, but efficiency gains were expected to preclude any delays and the company says a revised three-year strategic plan will be disclosed in March. Eni hasn’t been too accurate with its market predictions either. Last May, Descalzi expected oil would trade at $55-60 a barrel in 2015 and $70/b this year.
The company has suffered from exposure to Libya. The country’s production has slumped and political chaos makes a recovery in the short term unlikely. With Libya’s National Oil Company (NOC), Eni runs the 150,000 barrel-a-day (b/d) El Feel field, in the southwest of the country. But local disputes have left it shut in for more than a year. The offshore Bourri field, in which Eni has a 50% stake, is still producing about 35,000 b/d. Greenstream, the pipeline that ships Libyan gas to Italy and in which Eni is a partner with NOC, now operates at just 60% of its capacity of 11bn cubic metres a year (cm/y), or about 1bn cubic feet a day (cf/d), says Descalzi. But he has expressed caution about sustaining these flows. He has also supported the UN-led peace deal signed in December, although the country’s factions have not agreed yet to accept it.
Eni has had some struggles in the Arctic too. It still plans to start production from the $6bn, 100,000 boe/d Goliat project in Norway’s section of the Barents Sea, despite other companies pulling out of the area. But the project is already two years behind schedule and well over budget – it may need $100/b to break even. Far from stepping back from the region’s offshore, though, Eni last year snapped up 40% and operatorship of PL 806 in the Barents, as well as stakes in Norwegian and UK North Sea licences.
But its upstream business continues to bring success elsewhere. Eni has had by far the best record of any Western major over the past few years. In 2015, it found the giant Zohr gasfield discovery off the north coast of Egypt, which at 30 trillion cubic feet (Tcf) changes the energy dynamic for the whole of the eastern Mediterranean. The field is expected to supply both Egypt and southern Europe, and makes development of other fields in the east Med more likely. Eni had been targeting discoveries of 0.5bn boe for 2015, but the Zohr find alone provides over 5.5bn boe.
Eni wants the field on line by 2018, and reckons Zohr will yield an internal rate of return of 25% -- justifying fast-track development costing of $7.69bn. Initial plans were for eight wells to be brought on stream annually from 2018 until 2026, when production should reach a peak more than 3bn cf/d. (Eni could not confirm this schedule). The Zohr find increases Egypt’s 77 trillion cf of proved natural gas reserves by almost half.
The company also made an important Egyptian gas and condensate discovery in the Nooros exploration prospect, in the Nile Delta. The field was producing after just two months through a tie-in to the existing Abu Madi gas-treatment plant, 25km away. Eni finalised a $5bn agreement with Egypt in 2015 to develop the reserves, along with deals for several more exploration concessions.
Even before Zohr, Eni’s exploration successes in the past seven years increased its reserves by more than 10bn boe, amounting to growth of 35% in the company’s resource base, outpacing that of most of its peers.
Production growth keeps beating expectations too. The company had been targeting an average annual increase of 3.5% up to 2024, bringing 2bn barrels on stream at a low cost of $2.60/boe. But over the first nine months of 2015 output rose by 8.7% to 1.703m boe/d. For the whole year, Eni expects 9% output growth. At the same time, operating costs are down and were expected to fall by 12% to $7.30/b in 2015.
The expansion is based on 16 major start-ups and some ramp-ups, which Eni hopes will add more than 0.65m boe/d to output by 2024. Three quarters will come from onshore or shallow-water fields. The new projects are said to break even at $45/b, including exploration costs below $2/b, operating costs of around $8/b and average development costs lower than $20/b.
Efficiency gains, says Eni, mean that the 17% capex cut it announced early last year will not affect its production growth plans. Unlike some of its rivals, the company is going through a high investment cycle, meaning it also needs a high oil price to cover capex, operating expenditure and dividends. The last of these was cut early last year – Eni was the first of its peers to take that step – along with its share buy-back scheme. It is also selling non-core assets, and slashed exploration spending by 35% in 2015, and by a quarter between 2015 and 2018. In the short term, at least 70% of Eni’s activity will focus on appraisals.
Eni hopes a price recovery will reward all this upstream focus. This is also behind its positioning in Africa, where it is the continent’s largest producer and hopes to capitalise on projections for sharply rising economic and population growth. As well as its biggest projects in Mozambique and Egypt, the company and its partners last year decided to press ahead with the integrated Offshore Cape Three Points (OCTP) oil and gas project in Ghana, where Eni is operator with a 47.22% stake. First oil is expected in 2017.
In the Congolese Marine XII block Eni discovered 250-350m boe of gas and condensates last July. This is close to its Nene Marine field, which reached production of around 15,000 boe/d in mid-2015. Further delineation wells are planned, along with options to develop discoveries in the block, which add up to around 5.8bn boe. In Angola, Eni sanctioned a three-year extension on exploration block 15/06, near the West Hub oil project, although the latest round of awards at the end of 2015 all went to domestic companies, squeezing Eni out.
In the Americas, Eni invested in Mexico for the first time in 2015, signing a production-sharing contract – with operatorship and 100% interest – to develop the shallow-water oilfields of Amoca, Miztón e Tecoalli. The fields could hold 0.8bn barrels of oil and 480bn cf of gas. Eni also last year started production at Venezuela’s giant Perla gasfield, Latin America’s largest. Developed in just five years, it produced 450m cf/d in 2015 and should reach 1.2bn cf/d in 2020. Eni’s net gas production should amount to 110,000 boe/d by then. Gas is sold to state firm PdV at $3.69 per million British thermal units.
But Eni hasn’t abandoned engineering altogether. Descalzi says the industry needs such in-house capabilities again, and that lower oil prices bring an opportunity to renegotiate contracts. “In the 1980s, we didn't use engineering-procurement-construction contracts. We did a lot of things in-house. In the 2000s, we outsourced a lot of things and became weaker in engineering.” Eni has since hired 2,000 people to beef up its pool of engineers. Amid all the upstream activity, Eni is also restructuring, shedding assets it no longer needs and raising cash for exploration and production. In Q4 2015, it sold its 4% stake in Portugal’s Galp. It is pulling back from refining, halving its capacity compared with 2012, while also selling retail assets in Eastern Europe. Last year, it sold a 12.5% stake in engineering group Saipem to remove the firm’s debt from its balance sheet. Post-embargo Iran is also a target for Eni, which was active in the country for 15 years before sanctions, developing two large fields. Descalzi says any decision to invest will depend on the new contracts that will replace the older and much-maligned buy-back terms.
In the European gas-to-power sector, where Eni sells 50bn ccm/y to industry and runs over 4,000 MW of gas-fired capacity, the company has successfully reduced its exposure to long-term oil-linked take-or-pay contracts. With insufficient demand and falling hub prices the contracts had proved a major burden. Now 70% of its contracts have been aligned to hub indexes. Descalzi is busy pushing gas in Europe, advocating the replacement of coal to meet the EU’s emissions goals. Eni and others believe a carbon-pricing system is the most efficient solution, and have lobbied the UN and EU to support one. This would favour gas-fired power generation as a flexible partner to intermittent renewables.
A potential rise in European gas demand is partly behind Eni’s strategy to push ahead with an aggressive exploration and development programme. But the wider success of that plan depends on a recovery in the oil price. If it stays low for too long, Eni may find cash flow is insufficient to develop all its huge finds on schedule.