Governments: don’t agree to renegotiate over falling prices
“If we see a demand to renegotiate a contract because prices have dropped we know one of two things has happened: either the contract was mis-specified in the first place. Or the company is just trying it on!”
Paul Collier this week, at the opening of the Connex initiative in Berlin to support developing countries in their negotiations of oil, gas and mining deals with Big Business.
“We are going to see a lot of this in the next year,” Collier continued. “But the contract should have built into itself the means to adapt to changing prices. The single most basic thing we know about commodity prices is that they rise and fall.”
Couldn’t agree more. Modern contracts are built with a variety of what are known as fiscal tools, which can each each be implemented in a number of different ways and serve different purposes. For instance, in production sharing contracts in the oil business it’s not uncommon to see a royalty, a profit share, participation by the national oil company, and corporate income tax.
The royalty’s main role might be to assure a certain level of income to the government no matter what stage of profitability the profit has reached. That is why it is levied “off the top” before even recovery of billions of dollars of investment is considered. During the last commodities boom, many contracts were perceived as unfair to governments because they had flat royalties which are not “progressive” in fiscal terms. A 10% royalty with oil at $50 a barrel captures $5, and $10 when oil is at $100 a barrel. It is incapable of picking up a higher proportion of the greater profits, or superprofits which a project is generating when prices run higher. But then again, that is not its function.
For that the same contract might employ a sliding scale profit share. After the royalty and this year’s repayments of investor costs have been calculated, the profit share splits “profit oil” between the company and the government. Sliding scale in the sense that the government’s share increases over the life of the project according to a formula pre-set in the contract, often related to an “R-factor” which measures how much money the company has received compared to how much it has spent on the project.
Having all these different tools makes life complicated. On the other hand, the point is precisely to be able to create a contract which, in its totality, has the flexibility, as Collier is suggesting, to adapt to different price and profitability conditions. To be sure there are always trade offs involved, which means a contract is unlikely to offer both a high guaranteed income and a high share of increasing profits, to either party. If it does then the other party has likely given away too much.
Governments, particularly, are often squeezed by the natural to desire to maximise revenues out of a project over its lifetime, and their need for cash. Publics want to see services and benefits out of projects which by the time they reach “first oil” and start producing have already been centre stage as part of their country’s economic planning, and media attention, for years.
With the new reality of oil at $50-60 a barrel, it will be companies, as Paul Collier said, who will be looking for a revision of terms. But there is a really important point here: the economics of an oil project once it has started production look radically different to the point before the decision to invest was made. The billions of dollars that went into exploration and then development of the field – the wells, the infrastructure, pipelines and so on – are sunk costs. The company cannot pull that money back and reinvest it somewhere else. This is true to some extent in many industries of course. A manufacturer cannot relocate a factory to a lower cost environment either. But it is more true in extractives because the balance of fixed costs at the start of a project and ongoing, or operating, costs as a field produces oil, are different. The start-up costs are relatively greater and the ongoing costs relatively lighter compared to the overall turnover generated by the project.
This means there is a big difference between the rate of return an oil company can expect to see over the lifetime of a project, “full cycle economics”, and what it can expect from now on – “point forward economics” – in any project already producing oil. Falling prices have moved hundreds, possibly thousands of projects into a scenario where profitability over the lifetime of a project looks lower – and in some cases have turned negative. But, whatever they say or imply to governments, that is not what will determine whether they walk away from a project or not.
Because it is perfectly possible to make low or no profits over the lifetime of a project but still expect to make a fat operating profit – from now until the end of the project. A company in that situation will still produce oil to generate those operating profits precisely because that is the best outcome available to them now. It would only think about walking away if the price of oil went so low it started to approach what the ongoing operating costs were.
Globally, US tight oil – “shale oil” – is relatively high cost. But even here companies are quoting figures of $40 to $45 a barrel for their projects to keep running. Most “conventional” production has operating costs well below that. Saudi Arabia has famously low operating costs of only a few dollars a barrel, one reason they are untroubled by the current market. But even in deep water offshore, or frontier provinces such as are emerging in Africa, operating costs might only be $20-25 a barrel. This is the “economic limit” which would be the real determinant of whether it made sense for a company to walk away from a producing field. And we are some way away from that.
And just to give a sense of the numbers. Take a field in Africa with 100 million barrels of reserves. It cost a billion dollars to develop, is in early stage production, and has operating costs of about $20 per barrel. If the company digs out the forecasts it made before it decided to go ahead, it could now be looking at a Net Present Value (future profits distilled into a lump sum figure today) of $800 million assuming the current low prices continue. This would be above and beyond the costs incurred, but since it would take decades to earn those future revenues, there might indeed not be enough of a profit to make the project worthwhile compared to other oil fields the company could invest in, or indeed projects the investors behind them could put their money into in other sectors. In other words, if they were facing the investment decision today, they would say no. And – this is Paul Collier’s point – they may say this loudly to the government now.
But that would have been five years ago. Today the figures look very different. Take out the billion dollars of development costs they can never get back and under the same assumptions the project offers them a Net Present Value of $2 billion. Maybe less than they would have hoped – on the prices of a year ago that would have been more like $3 billion. But they won’t walk away and it is not the government’s business to subsidise the company’s shareholders for falling prices on a deal already made.
Because the deal was made in full knowledge that this could happen. That is the reality of the risk-reward paradigm. This risk was already factored in – or should have been.