The capital spending conundrum
Oil companies are cutting back their capex plans, but they need to be ready to respond to any upturn in demand
CAPITAL spending plans across the oil and gas sector are in a state of flux. Smaller upstream companies have slashed their 2009 capital expenditure (capex) budgets. The majors are hinting at flat or slightly reduced spending. It could mark a reversal of the up trend since 2000. But while cutbacks may seem prudent in a recession, a lack of investment in new projects could cause problems for less nimble companies, when demand starts to exceed supply.
The picture is gloomy for smaller, less well-capitalised companies, especially those involved in ventures producing high-cost oil. With outgoings still high, but income falling because of lower oil prices, they are being forced into steep reductions in spending. Some of the most high-profile casualties are in Canada's oil sands, but companies and project pipelines have suffered across the globe.
North America as a whole is likely to be among the world's most affected regions. Exploration and production (E&P) spending there, barring acquisitions, could fall by 10% in 2009, according to research firm IHS Herold - possibly more.
The collapse in US natural-gas prices has prompted firms in that sector to make large cuts in capital spending. Chesapeake Energy, the biggest US gas producer, said in September it would reduce its exploration and development spending in the 30-month period from mid-2008 to end-2010 by $3.2bn - a 17% reduction from previously planned spending. Chesapeake says it will need to cut spending further if it cannot access sufficient funds. It managed to find at least some funding through a cash injection from Norway's StatoilHydro, which bought a 32.5% stake in Chesapeake's shale-gas assets in the north-eastern US for $3.375bn in a deal that closed in late November.
The shape of things to come
Deals like this may indicate the shape of things to come across the global oil and gas industry, as better-capitalised, larger players seek to snap up assets relatively cheaply from struggling rivals. "Market weakness might be a healthy exercise for the oil and gas industry, as it allows larger financially strong companies to pick up assets at a decent price, which is something that has been lacking in the mergers and acquisitions market for a little while," says Aliza Fan, an analyst at IHS Herold.
But the financial markets may need to settle down further before the majors feel confident enough to embark on a spending spree. Says Fan: "The watchwords for all companies are 'capital discipline'. The larger integrated oil firms, as well as the E&P-focused companies, will be spending within cash flow." That means some companies eager to divest assets to finance spending on their core projects may struggle to do so in the short term, unless they are prepared to sell assets more cheaply than they would like.
The majors, with their larger revenue streams, more diversified portfolios and greater presence in both upstream and downstream activities, have greater financial flexibility than their smaller rivals, but they will still want to keep a tight rein on spending in difficult times. The trick will be to do so without paring back expenditure to a point where they risk losing their competitive advantage, should a market upturn materialise. "Turning on production is not like turning on a spigot," says Fan. "If and when oil and gas prices come back, companies will need to be nimble in being able to put their projects on line at a relatively quick pace and with lower budgets."
Mansi Singhal, an oil analyst at Barclays Capital in New York, says larger firms' ability to spread risk is standing them in good stead. "The majors have always tended to be the more conservative firms, even in the up-cycle," she says. ExxonMobil's capex did not exceed cash flow even when the oil price was rising, she points out. As a result, the majors are able to maintain spending despite the downturn and continue to buy back shares and pay dividends.
At ExxonMobil, capital and exploration expenditure totalled $19.3bn in the first nine months of 2008, a rise of more than 30% compared with the same period in 2007, as spending increased because oil prices were high. The firm said in late October it still expected full-year expenditure to reach around $25bn, as it had planned earlier in the year. In March, ExxonMobil said it expected capex for 2009-12 to average around $30bn and had yet to modify that estimate by December.
Chevron, the second-largest US oil firm, has said it does not plan to alter its capital-spending plans greatly. Expenditure totalled $15.8bn in the first nine months of 2008, putting the company on target to match its initial planned capex of almost $23bn for the year as a whole. "We will try to hold our capital spending pretty much in line of where we've been this year. We don't like fluctuating our capital spend up and down. Our long-term view on pricing has not changed," George Kirkland, executive vice-president at Chevron's upstream and gas business, told analysts in November.
Meanwhile, BP said its capex excluding acquisitions, asset exchanges and recent deals with Husky and Chesapeake totalled $14.9bn for the first nine months of 2008 and was expected to rise to $21bn-22bn for the year. ConocoPhillips has said it intends to keep 2009 capital spending close to the $15bn planned for 2008.
These robust forecasts for short- to medium-term spending partly reflect companies' need to complete projects on which final investment decisions (FIDs) have already been taken. Kirkland, for example, estimated that around three-quarters of Chevron's existing project-expenditure plans relate to developments on which it has already taken FIDs, giving little scope for short-term capital spending changes.
A more telling period for capex may be 2010-12, when cautious planning decisions made now may undermine spending, even if the underlying market fundamentals have improved by then. "There is not a lot of wiggle room in the first year," Kirkland said. "Our wiggle room in capital spending is much greater in the second year of our budget cycle and, of course, [there is] a very large amount in the third year."
Russian oil companies are suffering more than most, with punitively high taxes combining with low oil prices to leave producers short of cash. Until the end of October, Russian crude oil exports attracted duty of $50 a barrel, which meant that, with Urals crude trading at around $60/b, the effective value to companies was around $10/b. Export duty has now been cut to $39.35/b.
TNK-BP, the country's third-largest oil producer, which has interests across the energy supply chain, estimated its crude and refined-products exports would fall by 4% in 2008. In late November, it said it had halted investments in the refining sector and planned to suspend commercial downstream projects in 2009. The company, which is 50% owned by BP, has indicated that it could cut capex by up to $1bn in 2009 from an originally planned $4.5bn. A final decision was pending as Petroleum Economist went to press.
Refining plans on hold
Companies are eager to maintain upstream spending where possible, but refinery projects have proved highly susceptible to cancellation or postponement at a time when demand for oil is falling, as has been demonstrated by a series of delays in Saudi Arabian projects.
In November, Saudi Aramco and ConocoPhillips delayed the engineering, procurement and construction (EPC) bidding process for their planned $12bn, 400,000 barrels a day (b/d) Yanbu refinery. The deadline is now likely to be some point in second-quarter 2009, rather than December 2008, as previously planned. Aramco, the world's largest oil producer, has also delayed the deadline for EPC bids on the 400,000 b/d refinery at Jubail, which it is developing with Total, from early November 2008 to February 2009.
"This short delay will allow markets to adjust from the present uncertainties and provide a stronger basis for the long-term success of the [Yanbu] refinery," said Jim Mulva, ConocoPhillips' chief executive.
Medium-sized Western oil companies are having to adopt a similar strategy to that of the majors. Marathon Oil, for example, has delayed a planned $1.9bn expansion of its oil refinery in Detroit, saying it was devising a new timetable and cost estimates for the project. The expansion had been due for completion by 2010.
There have also been several delays to refinery projects in China, although some of these are attributed to bad weather and construction difficulties, rather than the economic downturn. Falling domestic demand does make these delays less costly to the Chinese economy than they might have seemed a year ago, although analysts say that when a number of planned refineries being built by PetroChina, CNOOC and Sinopec eventually do come on line, in 2009-2010, there is now a large risk of over-supply.
Saudi Aramco has also been revising its upstream plans. The company has abandoned $1.2bn plans to upgrade its ageing Dammam onshore oilfield. It has also told three of the main contractors working on its Manifa field - Italy's Snamprogetti, Japan's JGC and Spain's TR - to stop procurement and construction and proceed only with initial engineering work.
Such delays not only allow the market to settle down, they may also enable project owners to renegotiate more favourable terms with contractors with which deals were agreed at a time when their services commanded a greater premium than is the case now. Analysts say this is likely to be the case with the Manifa field delay, given that Aramco reportedly still wants to expand production capacity.
The UK's BG Group illustrated the advantages of pushing projects back in this way when it said it wanted to delay a decision on whether to go ahead with phase three of the Karachaganak gas and condensate project in Kazakhstan alongside Eni and state-owned KazMunaiGaz. "Full advantage should be taken of an expected downturn in oil and gas project costs, as a result of substantial falls in raw material costs and activity levels. BG has initiated discussions with KazMunaiGaz around alternative phasing of project expenditure to ensure the full phase-three capital commitment is not made at the peak of the cost cycle," the company said in November.
The effects of the downturn are also being felt strongly in Indonesia. Medco, the country's largest privately owned energy company, said in November it may delay various energy schemes in its multi-billion dollar project pipeline, which include domestic gasfields developments and liquefied natural gas projects, and an oilfield project in Libya. The company has not specified which projects may be delayed, but has said they will proceed eventually.
Question marks also hang over the timetable for development of Brazil's massive pre-salt oil deposits. As with the oil sands, the relatively high cost of exploiting these reserves threatens their viability when oil prices are low, although the companies involved remain bullish. BG said recently that it expects commercial production from Brazil's offshore Tupi field to start by the fourth quarter of 2010. The field, which is being exploited by state-controlled Petrobras, BG and Galp Energia, is expected to produce 100,000 b/d initially. BG also said exploration success in the Guara and Iara fields had led to planning being fast-tracked on two additional 100,000 b/d projects, with the aim of achieving first production in 2012.
But while the Tupi project is far enough advanced to proceed on schedule, doubts remain over the longer-term timetable. Petrobras' pre-salt plans involve the installation of 10 offshore production systems by 2017, with the aim of producing more than 1.26m b/d from several fields. "We may not see that, because, at least in 2009 and 2010, Petrobras may need to cut its capex," says Barclays Capital's Singhal. "Pre-salt is not dead, but its development may slow down." Petrobras has said it may delay the development of heavy-oil production in mature fields to free up capital to pump into its pre-salt operations in a bid to stick to its timetable.