BP’s long game in Iraq is paying off
Basra, Iraq // BP’s business model in Iraq has proved to be highly profitable, even as progress has sometimes appeared to be slow and plans have had to be curtailed.
The London-based company had attracted scepticism when it became the first of the big-oil majors to commit to the country after the 2003 war.
BP last week marked five years since signing its technical services contract to increase production from the “supergiant” Rumaila South oilfield, one of Iraq’s oldest and a large source of revenue. In that period, said BP, the field has produced 2 billion barrels, delivering US$180bn to the government.
“Now, we can’t claim all the credit for that because we inherited an existing oilfield,” said Michael Townshend, the head of BP Iraq and Middle East chief. “But what we can claim credit for is the amount of incremental production that we have delivered. So, over the last five years we can say we’ve delivered about $75bn of incremental revenue to the government and we’ve spent about $5bn to do it.”
BP estimates it can produce at least another 20 billion barrels from the field over its life. But that is something of a double-edged sword for Iraq, as the recent oil price slump has shown the country’s over-reliance on oil in general, and on the Rumaila field in particular.
With production running at an average of 1.3 million barrels per day at the field, total annual revenue at oil prices of $100 a barrel was just under $50bn a year, accounting for a large percentage of the federal budget.
If oil prices stay at $60 a barrel through next year, annual revenue from the field drops by about $20bn. That makes BP’s goal, under a new contract agreed in September, to increase production to an average of 1.4 million bpd next year crucial, even if it would only fill a relatively small $2bn of the budget hole.
The importance of Iraq to BP has also grown, as evinced by the frequency of visits by Bob Dudley, the chief executive.
Under the terms of the new extended contract, BP and its partner PetroChina agreed to lower the field’s plateau production target from 2.85 million bpd, which was due to be hit in 2016. The new target is to raise production to 2.1 million bpd by 2024, and to lengthen the life of the field.
BP and PetroChina extended their deal by five years to run to 2034. They also negotiated higher shares of the operating company — they will raise their stakes by 9.5 per cent to 47.5 per cent and 46.5 per cent respectively, cutting the government’s share from 25 per cent to 6 per cent.
What is particularly interesting for BP is that the terms of the contract mean it doesn’t lose out if oil prices fall. The operating company gets paid $2 for every incremental barrel produced, after costs, and it takes this and its cost reimbursement as physical oil in tankers lifted from Basra’s terminal. Furthermore, the incremental barrels are counted after taking into account a natural decline in the field of 17 per cent annually, so BP and PetroChina’s share of production has been on a rising trajectory since the contract began.
What happens when oil prices fall? “It means you need more ships,” said Mr Townshend. “If the oil price halves you need twice as many ships as before. It’s very simple.” BP won’t discuss the terms of its deal, but a simple calculation based on what BP has said about the field’s success suggests it has recovered its share of investment in the field of a little over $2.5bn and made a further $1.5bn on top of that over four years. That would tally with some analysts’ estimates of a return on capital of between 15 and 20 per cent a year.
How the company fares over the next few years depends on what terms it has agreed with the government about how to calculate the field’s natural rate of decline, as that determines what is considered “incremental” barrels for which the consortium gets paid.
It is likely those terms remain favourable on the new higher equity percentage, as BP is raising its investment next year — by $1bn, to $3.5bn, Mr Townshend said.
In his presentation to BP investors this month, the company’s head of upstream, Lamar McKay, made only brief mention of the Middle East (passing references to Iraq and Oman). He instead concentrated on BP’s big projects in places such as offshore Angola, Azerbaijan, and the contiguous United States.
But the Middle East prospects are showing growing potential and attractiveness, especially in a low oil price environment.
“Across the Middle East you tend to have contracts that are not oil-price sensitive, whether that’s Iraq, where it’s dollar-on-the-barrel; Oman, where it’s gas prices; [or] a recently signed deal in Kuwait that is oil-price independent,” said Mr Townshend. “On the other hand, each of the countries is very oil-price dependent, so budgets get squeezed. It’s good for the company but a very unique mix, an interesting dynamic.”
The challenges for BP at Rumaila are mainly logistical. The additional $1bn investment next year is constrained by what the company estimates is physically possible, given the particular impediments in Iraq that can slow projects down, such as moving equipment into the country, hiring and training staff, getting visas for specialised staff, etc.
The difficulties that have limited progress so far are clear from a visit to the field’s largest gathering point, Markesia, which is headed by Arkon Abdul Satter, an Iraqi petroleum engineer.
“Much of the equipment here [is] dated from 1956, when the field started to produce,” said Mr Satter. “Everything was badly in need of upgrading in 2009.”
Although there was a big jump from 900,000 bpd in 2009 to 1.2 million bpd the year after that, the next 100,000 bpd increase took more than three years.
That is because BP has had to make many incremental changes across a huge industrial site — 80 by 20 kilometres — while battling against natural reservoir decline. Many of the refittings, refurbishments, and expansions take considerable time when trying to do them without disrupting existing flow. The work in the first four to five years focused mainly on drilling dozens of new wells and adding updated well pumps, removing bottlenecks, increasing the amount of gas that is used productively and not flared, and implementing better management operating plans.
The work of the next phase — which aims to get production to 1.8 million bpd by 2018 and plateau at 2.1 million bpd by 2024 — will be mostly about water.
Rumaila has hitherto produced “dry” oil — that is to say it came up with a low water cut that is still only 10 per cent. That percentage will grow substantially as water is used in coming years to increase pressure in the wells to pump up more crude. But that will require large-scale engineering projects to pump water into the well, to dehydrate and desalinate the oil at the gathering stations, and then pump the water back in an efficient way that does not harm the environment.
Getting the water engineering right would mean increasing the recovery rate of the well, and that goes straight to BP’s bottom line — every percentage point increase in the well’s recovery rate equates to about $200m for BP.
“A 40 per cent recovery rate for Rumaila would give you another 20 billion barrels. That’s realistic,” said Mr Townshend. “Will that view change in five years? Yes. It is dependent on being able to handle the water, getting pressure water in, recycling the water and pushing it back down again — 8 million barrels of water a day. These are massive challenges, and similar challenges exist in Abu Dhabi and Kuwait.”
But at least people are more focused on the engineering now, at least for the country’s south.
“When we first talked about Iraq five years ago virtually the only questions we got were, ‘well tell us about security’,” Mr Townshend recalled. “I think that’s changed now. I think perceptions have changed.”
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Updated: December 21, 2014 04:00 AM