“Fundamental balances imply that non-OPEC countries have to sanction more projects because, every year, non-OPEC production has declined.”

Paul HORSNELL Head of Commodities Research STANDARD CHARTERED BANK

Not too big to shale

USA
April 5, 2017

TOGY talks to Paul Horsnell, head of commodities research at Standard Chartered Bank, about OPEC, oil prices and the USA's energy policy. The bank provides advisory, mergers and acquisitions, and structured financing services for the oil and gas industry.

Standard Chartered Bank operates six offices in the USA where it provides corporate and institutional banking services. The US entity is a licensed subsidiary of Standard Chartered, a London-based international banking and financial services firm whose main business activities exist in Asia, Africa and the Middle East.

• On new E&P projects: “Fundamental balances imply that non-OPEC countries have to sanction more projects because, every year, non-OPEC production has declined. There are more than 50 million bopd in global production that are non-shale, and the average decline rate is 6-7%. That means that every year 3.5 million bopd of new output is required just to sustain global production.”

• On OPEC and oil prices:
“If you check back through the cycles, the market has always ended up in an equilibrium where OPEC is reasonably happy with the outcome. This one is not going to be any different.”

Besides touching on these topics, TOGY talked at length to Paul Horsnell about the implications of US energy policy on global oil markets. Most TOGY interviews are published exclusively on our business intelligence platform TOGYiN, but you can find the full interview with Paul Horsnell below.

What challenges and opportunities face the oil and gas industry in the coming years?
The biggest challenge, as it has been for years, is the oil industry learning to live long-term with shale development and shale finding its place in the long-term market. The transition will take a few years, but 2017 is when it will start.
Demand has been the upside over the past three years, with people wondering if this is a structural feature of strong demand or if it is just cyclically tied to prices. The industry had gotten so used to a pessimistic demand outlook. It expected that demand would never reach 100 million bopd, but now it is almost at that level. The industry’s profile will look very different in a world where liquid hydrocarbons demand stays strong for a few more years compared to one where it’s fading away. That’s a long-term issue, but one people are thinking of in 2017 when it comes to demand.
On the supply side, there’s a whole series of smaller issues that have come into the mix. Over the course of 2018-2019, we will see the resolution of issues such as Saudi Arabia’s policy towards the oil market and the future of countries facing multi-year disruptions such as Iraq, Libya and Nigeria. The year 2017 will be very interesting with a lot of geopolitical dynamics. This is all about closing the oil price cycle that started in 2014, moving away from the high-volatility disruptions that happened between 2014 and 2016, and beginning a more sustainable industry model in terms of both market fundamentals and company dynamics.

 

What are the implications of OPEC’s 2016 output cut and their diminishing relevance to the global oil market?
Prices fell particularly fast in 2014 due to the decision of some key OPEC players. If prices start to come back up, it will be due to policy initiatives. Prices would not be as high as USD 55 per barrel if the Algiers and Vienna agreement hadn’t come through. For an organisation that many see as irrelevant, we spend a lot of time as analysts and journalists discussing it. In that sense, its relevance is in the mind of the beholder. OPEC’s aim is not for people to think it’s relevant, but to stabilise or destabilise the oil market as a policy decision. There’s nothing that most OPEC members would like more than for people to think they don’t matter. They know they matter.
OPEC has always had this on-and-off phasing. We know when OPEC works best is when it’s combating a demand-side crisis, for example in 2008. There are always some lags, but generally OPEC has found it easy to do. They have been their weakest when there is a major change in relative output; when some country has entered a multi-year capacity increase, whether that was Venezuela in the 1990s or Iraq over the past few years. Some of those cycles take a long time to play out. If you check back through the cycles, the market has always ended up in an equilibrium where OPEC is reasonably happy with the outcome. This one is not going to be any different.
When I say that 2017 is the year the market has to come to terms with shale, I include OPEC in that assessment. Their relevance in a sense will be defined by how they cope with shale development overall. OPEC must not see shale as something marginal, but inter-marginal.
OPEC itself is a loose formation of countries that all have different market power and abilities to change production. It does come down to those few core members, and when their oil policies are aligned they are quite effective. When they’re not, OPEC can be a destabilising force in the oil market.
The current price cycle has been made longer by deliberate OPEC policy. Production rates continue to increase. The Saudis are reacting to others, but clearly what’s going on in OPEC does matter. The OPEC switch is on, in the sense that there will be some interaction between market pricing and OPEC output. This relationship had been off during 2015 and 2016 and the market could be fairly certain that the downside wasn’t protected. Nothing much was going to happen in terms of helping the market rationalise. In the end, who has OPEC affected? Shale producers, in the sense that they’ve been deflected off the curve that they were on. It’s a long-term factor in the cuts and capital expenditure for regular production, somewhere between USD 1 billion and USD 1 trillion in reduced or delayed capital expenditure. That’s the real effect, and some of it will never come back.

What is the future of offshore deepwater production?

Some offshore deepwater projects are just delayed and will progress in the future. Projects that have been cancelled were those seen as being very frontier developments. It’s going to take a while for the Arctic to see projects. Once you take something off the books, it’s hard to put it back on later and start work on it.
There were some projects that clearly required USD 100-per-barrel oil prices to be economically viable. There hasn’t been enough cost reduction to make those projects feasible at USD 50 per barrel. Those sorts of frontier projects that once required USD 100-per-barrel prices might now require USD 90 per barrel due to rig rates and loans. That’s where the real adjustment has come in. We’re not going to see the impact until 2019 at least, but when it comes it will be very hard for the market to adjust to developments not progressing that otherwise would have.
When the market’s comparison is to the counterfactual universe where prices stayed high, markets aren’t good at that so it’s not going to really manifest itself other than through the market finding that it’s at USD 60 but still tight. Newer shale developments are growing fast but still financially tight; it’s a slow price-determining burden. Shale moves slower than OPEC, but still pretty quickly. We’re trying to price the market using two very fast-moving comparisons, OPEC and shale, when the process is actually going to price it at an incredibly slow pace.

What fundamental balances need to be in place in order to attract offshore investment?
Fundamental balances imply that non-OPEC countries have to sanction more projects because, every year, non-OPEC production has declined. There are more than 50 million bopd in global production that are non-shale, and the average decline rate is 6-7%. That means that every year 3.5 million bopd of new output is required just to sustain global production. So if a project is economically sound, it will be necessary to pursue development just to moderate some of the declines in the conventional plays.
Some of these projects are not technically demanding and are in areas where there is already infrastructure or infrastructure can be brought in. Those kinds of projects are clearly going to be high up in the merit order. What is being squashed out are higher-cost plays either because they are in deeper water, have complex geology, or are in areas that are difficult to operate in or where there is no existing infrastructure.
The view prior to shale development was that all offshore deepwater plays needed to be developed, but now we don’t need so much of it. But there will still be an awful lot of deepwater projects. The 3.5 million bopd required means in a five-year period you need 17.5 million bopd just to hold it constant, and a lot of that is going to be offshore.

How have crude trade routes been changing and how does this affect the market?
The US oil export ban was a major factor in the change of global trade flows. The big change that happened over the past 10 years was a regionalisation of the crude oil trade. The Americas have become much more intra-American. There is less trade between it and the rest of the world.
European and African trade, which used to be marginal, has become much more active. Angola and West African trade is moving into Asia. There’s a splitting off of the Americas from the rest of the market. What the removal of the US export ban has done is create a potential vent for US surplus oil.
The US is still one of the biggest importers of crude in the world. Exports are driven much more by logistics or quality. The bulk of what leaves the US stays in the Americas. It does tend to be light crude and in many cases very light. The fundamental imbalance in crude for the US is a refining system that is geared very much toward heavy crudes and an incremental domestic production increase on the crude condensate boundary with a lot of condensate on top. There is this mismatch.
Trade is helping this imbalance. The price of light crude and very light condensates relative to heavy and medium crude is depressing. I could argue that the export ban wasn’t complete because Alaskan crudes have been able to move for quite a while. They’ve been moving into Asia. This freedom means that not all of that extra light is now jamming up the US Gulf Coast.
I would still raise questions about how big a world market there is for light crude, especially crude of 50 degrees API or more. There is a limited sort of capacity in the rest of the world to process that sort of crude. The sharp increase in total US exports is a measure of the quality balances in the market. Since the ban was lifted, there has also been a ramping up of imports. This is a rebalancing of the US internal market. This regionalisation is not going to be broken. There are niches, but it will always be marginal.

How feasible is the new US administration’s goal of becoming a net oil exporter by 2035?

It is possible that within 18 years the US could be a net oil exporter. The current dynamics probably argue against it, but if you run through President Trump’s energy policy, it has clear strands of being supply oriented and trying to reduce industry regulation. The important factors will not be oil production due to regulation, but the timing and phasing of how things progress.
There is an implicit question that the downturn in the coal industry will at least be moderated or even turned around. This is the biggest structural change in the entire US energy mix over the course of 2006-2016. Gas took over from coal. That was a big change and one that will be very hard to reverse. The Trump policy is seeking to promote coal but it’s also the regulatory reduction that will help the natural gas supply even more so than the oil supply. There are various circles here that don’t easily become squares.
On the bigger question of can the US become a genuine net exporter of oil, demand-side management is probably not on the agenda at the moment. The supply-side policies are assuming that the current change in policy will maintain itself until 2035. In the real world, we have to consider that critics of US energy policy point to this as the problem. Whenever there is a plan it is reversed by the next administration. Could US domestic supply add an extra 8 million-10 million bopd by 2035? It’s not out of the range of projections, but it’s not grounded in feasibility, either. I don’t think it would be a base case for all those reasons.
Policy moves around, and shale is not a blank check to increase it all. There is a cost to time. One of the distinctive features of shale is that its own internal decline rates are an order of magnitude larger than conventional oil. Depending on the area, rates of decline are between 60% and 80%. As output increases, the amount that you need to produce to hold it constant also gets bigger.
One reason production will increase very rapidly in 2017 is because the US hasn’t drilled so much over the course of the past couple of years. With production down, the replacement is also down. It gets harder and harder as it goes up. To get to 2035 and bring net imports down to zero implies taking shale up to 15 million bopd. That’s a big industry to sustain.
Even if through technical development we manage to get the average decline rate down to 50%, that still requires 7.5 million bopd of new projects every year just to stand still. That means every year will require bringing on 50% more shale production than there is now. At some point that becomes about adding enough to stand still and then adding an extra million. That’s why production has fallen over the past couple of years. We haven’t brought on enough wells to balance the equation. The amount being brought on is more than the decline each month.
The last thing to consider is, who cares? What does it matter whether the US is importing X or Y? In the broader scheme of things it doesn’t matter. It’s not about the economics. It would be a very odd policy objective in itself. It goes back to President Nixon and the goal of energy independence.

How will recent trends in the West towards economic nationalism affect the oil industry?
In terms of the oil and gas industry, let’s call it economic populism. The objectives are to limit economic benefits to a particular strata of society. Typically, it’s toward a group that felt dispossessed or economically disadvantaged for some reason, and it takes different forms in different countries. In the US, it’s the middle-aged blue-collar worker from somewhere around the Great Lakes who is the target beneficiary of those policies.
If you look at it through that lens, the policy that gets pushed aside is anything that is going to make energy more expensive for that person. That majorly constrains policy options; taxation on energy can’t increase. It means potential policies such as the suggested border adjustment taxes that will increase domestic energy prices.
If you think in terms of the key demographic here, the logic has an obvious link to higher prices paid. It’s not clear that that is necessarily negative in terms of energy. It is not going to mean a raft in demand management or taxation, whether it’s directly onto energy products or coming through. Quite a lot of this economic populism in the energy industry has been left on the side.
The energy industry is strongly represented within the US administration. Of the five policies released on the White House website on inauguration day, the first was energy related. The policies are aimed at delivering lower energy prices to the consumer by shifting the supply curve down. To do that, taxation is a wedge that shifts the curve in the wrong direction. Energy may end up a bit on the sidelines of this; I don’t see it as the direct object. What the US wants to do on energy is clear and defined: it wants cheaper energy for its target demographic.

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