Related Articles
Forward article link
Share PDF with colleagues

Eni bets on risky plays for growth

Eni is banking on production growth in countries such as Iraq, Venezuela and Kazakhstan where it is suffering both political and technical problems. A 2.5% annual output increase to 2013 looks optimistic, writes NJ Watson

ENI HAS reversed an April prediction that its oil and gas production would rise this year. For investors, the June announcement provided yet more evidence that the Italian energy company is, for now, not the most exciting investment opportunity.

The signs were mixed in the first quarter that Eni's near-term production-growth potential was gaining traction. First-quarter output was up by 2.1% compared with the same period in 2009, driven by operations in Nigeria, Congo and the US. But volumes were down by 3.7% compared with the previous quarter. Adjusted operating profit came in at €4.33bn ($5.4bn), up by 15.4% from first-quarter, because of higher oil prices and production.

At the same time, Eni's free cash flow of €2.26bn during the quarter allowed it to reduce its net debt-to-equity ratio, or gearing, from 46% at the end of 2009 to 38.5% at the end of March. At 46%, Eni was one of Europe's most leveraged integrated oil companies, so any reduction was welcomed by investors. Irene Himona, an analyst at Exane BNP Paribas, worries that with flat production growth this year and increased capital expenditure, Eni "is spending more for less near-term gain".

First-quarter production of 1.82m barrels of oil equivalent a day (boe/d) prompted Eni to forecast output would "slightly increase" compared with 2009's 1.77m boe/d. But at the company's upstream seminar in London in June, Claudio Descalzi, head of exploration and production, rowed back on that forecast to say the full-year target would be "in line with 2009", vindicating analysts such as David Stedman of Daiwa, who had not raised their 2010 production forecasts in line with Eni's.

A challenging year ahead

"We view 2010 as a challenging year for Eni – limited oil and gas production growth, margin and market-share pressure in the domestic gas business (see box), and weak [refining and marketing] earnings," says Stedman.

While most analysts, even those with underperform ratings on the stock, agree that there is value in Eni's shares, the problem is when all this expenditure on "targeting superior production" growth will pay off. "The stock looks undervalued, but the market is tough," says Dario Michi, an analyst with Banca Akros, who has an €18 target price on the stock, which was trading around €15 in early July. "The key point remains the timing [of production coming on stream]. I believe there is value on the stock."

Yet 18 analysts out of the 33 listed as covering the company have a buy or outperform rating on Eni. They are more optimistic that the company's focus on boosting production rather than expanding exploration will pay dividends sooner rather than later. Eni's senior vice-president for development, Antonio Panza, told investors at the same June seminar that this growth would "become evident from 2011".

Eni has 41 projects worldwide that are planned to come on line by 2013, which it believes will yield an average 2.5% a year output increase over those four years. Sixteen of those are significant "projects for growth" that would provide around an additional 0.56m boe/d, the equivalent of 25% of Eni's entire production, by 2013 (see Table 1 and Figure 1). If all goes according to plan, Eni's production should surpass 2m boe/d by then. However, with 2009 production falling by 1.6% compared with 2008 and now forecast to remain flat this year, that puts a lot of pressure on the 2011-13 target.

An immediate threat to that target comes from the six-month moratorium on deep-water drilling in the Gulf of Mexico (see p3). In late June, Eni said it had stopped development on its Appaloosa project off the coast of Louisiana, which was expected to come on stream this year at 7,500 barrels a day (b/d) and where it has already invested $228m.

Iraq will be hard in the long term

This year, the project with the biggest potential of the 16 is the Zubair oilfield in Iraq. Producing at just 183,000 b/d, Eni (32.81%) and its partners – Occidental Petroleum (23.44%), Korea Gas (18.75%) and Iraq's state-owned Missan Oil (25%) – have agreed a deal with the government to lift output by 10% this year to around 200,000 b/d, earning $2 for each extra barrel extracted. An output target of 1.2m b/d, within six to seven years, has been set for the 6bn barrel field.

During the first year of the contract, the partners plan to drill 12 new wells and to overhaul five to hit the production target, which is achievable given the present low level of output. "To raise production by about 10% within a year is possible, because with a little work they can deliver quick results," says Samuel Ciszuk, senior energy analyst for Middle East and North Africa at IHS Global Insight, a consultancy.

Eni's three-year plan is more challenging, calling for the drilling of 46 new wells and overhauling 100 others to increase production to 0.7m b/d. The consortium will then launch an enhanced redevelopment plan between 2013 and 2020 to reach the plateau target of 1.2m b/d, which includes drilling 215 new producing wells and 124 water-injection wells at a total cost of around $20bn. "Everybody expects some delays," says Ciszuk. "[The] construction [industry] is very under developed and there are huge shortcomings in government decision-making."

Eni is hoping for production to begin from the Mavacola and Clochas discoveries in Angola's block 15 in 2011. The fields hold estimated reserves of 254m barrels of oil and are expected to reach a combined plateau of 140,000 b/d. Eni holds a 20% interest in the block. The company has been in Angola since 1980 and its belief in the potential of the country's deep water prompted it to break a world record by paying $0.9bn in a 2006 licensing round for one deep water block – 15/06 (PE 3/10 p13). However, five years of rising output in Angola came to a halt last year as the country bumped up against its Opec production quota. "At some point they'll have to rein in production," says Ciszuk.

The Kashagan project in Kazakhstan, in which Eni holds a 16.81% stake, should finally be producing by 2013 after a delay of eight years, largely as a result of the technically demanding nature of the development. With potential recoverable reserves of up to 11bn barrels and output expected to peak at 1.5m b/d, Kashagan is vital to Eni's upstream portfolio.

The northern shallow-water Caspian Sea, where Kashagan is located, has an extreme climate, with temperatures varying from 40°C in the summer, to –40°C in the winter. In winter the frozen sea puts infrastructure in danger from shifting ice packs, while summer storms can cause rapid fluctuations in the sea level. The projected costs of delivering first oil have ballooned, from the initial forecast of $57bn to $136bn, and Eni said in June that the "break-even price of oil in the project is about $50-55 a barrel" – a comparatively high price to other projects (developments in the mature UK North Sea, for example, break even at a price just over $40/b, according to Oil & Gas UK, an industry association).

Bringing the field on stream is at the heart of the Kazakhstan government's strategy to join the world's top-10 energy producers by 2015. It was so infuriated by the delays and rising costs that, in January 2009, it stripped Eni of the lead role on the project and forced the foreign shareholders of the consortium developing the field to hand over more shares to state-owned KazMunaiGaz (KMG). That doubled KMG's stake to 16.81%, putting it on a par with consortium partners Eni, ExxonMobil, Shell and Total; ConocoPhillips and Inpex hold 8.5% and 7.4% respectively.

The dispute over Kashagan has had a knock-on effect on another project in the country, Karachaganak, in which Eni owns a 32.5% stake alongside the UK's BG Group with 32.5%, Chevron with 20% and Russia's Lukoil with 15%. The KPO consortium has been operating the field under a production-sharing agreement signed in 1997 – the only upstream project in the country without state involvement.

But, in June, prime minister Karim Masimov said the government plans to assert its interests "like we did with the Kashagan project". KMG has said it wants a 10% stake in the project, which produced 382,000 b/d in 2009. Investors are understandably nervous about Eni's production potential from both projects in the country.

The company's Perla and Junin 5 projects in Venezuela, which will have a combined peak production of 370,000 boe/d, are both expected to come on stream in 2013. Eni recently raised the reserves estimate for the Perla gasfield to over 9 trillion cubic feet (cf), up from 7-8 trillion. Perla is a 50:50 joint venture with Spain's Repsol, although state-owned PdV has a back-in right to take a 35% stake in the project. Under a fast-track development scheme Eni hopes to be producing 300m cf/d in early 2013.

Oil in place at the Junin 5 block, in the Orinoco heavy-oil belt, is estimated at 35bn barrels. Eni is developing the Junin 5 block jointly with PdV, which holds a 60% stake. First oil had been expected in 2014, but, in January, Eni advanced the start-up date to 2013, with an early production phase pumping 75,000 b/d. Production will plateau at 240,000 b/d.

But doing business in Venezuela is far from straightforward. In 2007, President Hugo Chavez tightened his grip on the country's energy sector by renationalising stakes held by foreign companies in the country's heavy oil projects. All contracts were renegotiated, with PdV taking majority stakes. Descalzi says "there has been a certain stability" in the last two years in Venezuela since the changes to the law and contracts changed. But foreign firms are still wary of investing in a country run by such a mercurial leader.

Ultimately, chief executive Paolo Scaroni has bet Eni's production growth on risky countries such as Iraq, Russia, Venezuela and Kazakhstan. And the problems with some of those projects, both politically and technically, are ever-present and in some cases mounting.

Eni's gas business under pressure

ITALY'S Eni is not just an oil and gas producer – it is a sprawling, vertically integrated energy company involved in upstream and downstream oil and gas, petrochemicals, oilfield services, engineering and electricity generation. Its €2.7bn ($3.4bn) acquisition of a majority stake in Belgium's Distrigas in 2008 made it the leader in the European gas sector, with a market share close to 25%.

Unfortunately, as a result of the economic downturn, the last couple of years have seen lower gas demand and growing competition in European markets, with gas prices dropping to record lows. By 2012, Eni aims to sell nearly 124bn cubic metres (cm) of gas worldwide, with international sales expected to grow by 7% a year on average. But in 2009, gas sales fell by 0.5%.

In the first quarter of 2010, adjusted earnings before interest, tax, depreciation and amortisation of the company's gas division fell by 16.7% compared with first-quarter 2009 to €1.43bn, with the marketing business suffering a 27.7% year-on-year fall. Gas sales to wholesalers were down by 31.3%, to industrials by 25.5% and to power generators by 71.7%.

Eni forecasts European gas demand will increase by 3-4% in 2010, recovering around half of the decline seen in 2009. But this optimism is not shared. "The gas market will be difficult, both in Italy and Europe, because of the increase in [import] capacity [and regional interconnections] and the risk of political intervention, such as price subsidies," says Dario Michi, an analyst with Banca Akros.

Also in this section
Pemex debt strategy at risk of unravelling
30 July 2020
The Mexican firm had made some progress arresting its hefty debt pile, but the economic downturn and government obsession with upstream targets has started to take its toll
US domestic M&A sent reeling
28 July 2020
Deal-making across the oil and gas patch has slowed to a crawl despite a swathe of potential devalued assets and strained companies eager to divest
Oil firms ready to pick up the infrastructure divestment pace
13 July 2020
Pipelines, storage facilities and processing plants could replace non-advantaged production as prime candidates