The Depletion Business

As goes Exxon, so goes international oil and gas

“People say ‘Well, you’re not growing’,” he said. “That just tells you how hard it is to hold your own in a depleting business.” Rex Tillerson, CEO ExxonMobil, March 2016 Analyst Presentation.

As noted in an FT article last year, and reinforced at this month’s analyst presentation by the Exxon Mobil CEO, it is now impossible for the large international oil companies to expand production without acquisition.

This is not news –  but it does have increasing implications for the supply of oil ahead, and the structure of the industry, as this inability to grow is set to feature prominently over the next 5-10 years: the low oil price environment exacerbating a long-term trend.

Let’s look at the Exxon numbers in a bit more detail before widening the lens out to the industry and then the possible futures ahead.

Exxon has labeled the energy world in the early 21st Century a depleting business. Technically, this refers to reservoir volumes, which deplete at various rates over time. The decay in production associated with this is referred to as decline – but labeling one’s own activity as a declining business is probably not savvy. Nevertheless, the CEO of Exxon has called the industry to account to be honest about the reality of being able to inflate production without acquisition.

Modern oil production generally declines (see here for example)  at a rate of somewhere between 4-8% pa depending on the age, size, configuration (oil / gas ratios) of the oil field portfolios. For a company the size of Exxon, which in 2015 produced about 4.1mmboed (4.1 million barrels of oil and gas equivalent per day), a decline rate in the centre of the range (6%) equates to around 250,000boed reduction per annum. This is an estimate only, but it seems to chime with much of the Exxon presentational material.

Over a five year period, to sustain flat levels of production, Exxon will have to create 1.25million boed of new production. Recognising the extreme difficulty of this task in the past, which Exxon was just about able to achieve, Tillerson has declared that his firm will not be committing to anything other than flat production at best. As IHS noted this week, 2015 has the lowest volumes additions since the 1950s – the international industry is finding it harder to discover meaningful levels of oil and gas, and the projects required to develop them are becoming more extreme to design and manage. Historically, Exxon have also engaged in portfolio tail divestments of around 30kboed, or about 150kboed over a five-year period.

In sum, Exxon has set itself the task (acquisition-free) of developing a new net production target increase of ca 1.40million boed between now and 2020 – to cover field decline, divestment and to maintain a flat production base.

In its presentation to analysts, Exxon also adds a couple of caveats – one is around OPEC quotas (standard boilerplate), the other is around the assumption that oil prices are in the range $40-80/bbl – presumably flagging that if oil prices are lower than this, or at the lower end, many bets are off regarding the investment needed to even achieve flat production.

Exxon is naturally cautious, and this has paid off in the past – the company notes almost zero impairment charges due to cancelled projects in the last two years, compared to $5-10bn by each of their main competitors,

It also claims project over-runs of about 5% in schedule and cost in its operated projects, versus 35% schedule and 20% cost increases in projects operated by others (where they have invested, and so know in intimate detail).

The projects ahead for Exxon still remain complex though –Arctic breakthroughs and major field expansions such as the much-delayed Kashagan field. They estimate around 750 kboed of new production in 2016-17, and then a wide range of outcomes from 2018-2030. Hence the flat production target remains a real test, (especially with the caveat of a $40-80/bbl hurdle rate).

What does this mean for the IOC program over the next five years? If we add up the production levels of the largest five – Exxon, Shell, BP, Chevron, Total – it equals about 15 million boed in 2015. Add in BG with Shell and the total is around 16 million.

We can assume zero net growth is the aim for all the major IOCs (without further acquisition) – although guidance may be for a small amount of growth. Then, given the down-turn and recent history of project delays and cost-overruns even in an investment-friendly $100/bbl context, we can further reasonably suppose the overall target of production stability is unlikely to be achieved. Exxon’s candour about limited production growth appears to accept this.

Assume the decline and divestment rates calculated for Exxon apply across this aggregate, this requires new net production across the five majors of about 5.3 million boed per day by 2020. Lets then put a guesstimate of 75% achievement rate – downside due to the variety of project factors that will hamper investment and delivery, offset by production improvements from existing fields. By this (albeit simplified) method, there is a shortfall of about 1.3 million barrels per day by 2020 to flat production – or an even greater defecit if limited growth is projected.

At the same time, IEA projects about a 5-6 million boed global demand increase required over the same time period –  but by this reckoning, the actual supply growth to meet this will be closer to 6-7.5 million boed.

The key point is, as Exxon point out, at least for the next 5-10 years, free of acquisition, the oil majors are in the depletion management business. And the next half-decade is already underway, with so far new oil investment close to a standstill. Even with an oil price resurgence, the majors may not be able to convince themselves or their investors that another round of megaproject investment in the remaining larger resource fields is the way of the future.

For example, if today they could convince themselves or others that future major projects are viable at say $60-70/bbl break-even, then recent history notes that the actual break-even might be 25% higher at about $75-85/bbl. As prices rise, these projects will become more tenable, but the path to sanction will be more cautious, gradual and drawn-out, making aggregate production decline sharper than forecasted.

What does this equate to for IOC growth opportunities? As ever they have various paths open to them, with maybe the new addition from Exxon – managed decline and depletion. Four routes can be broadly outlined:

  • Organic Growth – driving current portfolios, enhanced existing production improvements, leveraging existing infrastructure via technology (eg shale)
  • Asset Acquisition – specific project or acreage acquisition eg projects in various stages that fit the existing portfolio and skills,
  • Corporate Acquisition – all-in purchase including all assets of production and support staff
  • Managed decline and depletion – clear targets, financial engineering (eg buy-backs), reliable returns focus

The organic growth option looks the most ambitious at the present time, and the most uncertain of outcome due to the investment environment and the complexity of handling an array of project types and partner requirements. It is difficult to judge where each firm will go – each has a natural bias – but the following directions are suggested from current portfolio trajectories and announcements:

  • Organic Growth – Total and Chevron
  • Corporate acquisition – Shell  (with BG)
  • Asset acquisition – BP
  • Decline plus asset acquisition – Exxon (history shows given their reluctance to fully integrate acquisitions eg XTO, assets may be more acceptable to them)

In summary, Total and Chevron seem to be following the typical IOC route of the last decade, Shelland BP a more hedged version with recognition of acquisition to support growth, and Exxon a path of managed decline with options to acquire assets that pass various tests.

If Exxon are leading the way of the IOC future, then it is one of stoic decline with disciplined investments. The others will follow their own alternative paths for now.

This still doesn’t answer the question of how the industry goes about solving the production defects overall, and fill production supply gaps.

Firstly, demand reductions due to efficiency and policy shifts eg COP21 and Chinese renewable investments, especially wind and solar, may fill the shortages more effectively than predicted so far. Policy shifts can work both ways however, and fuel subsidies, for example, by China may increase oil demand in the short-term. This is why predicting the oil price is fascinating but really a mug’s game – there is always an extra factor you overlook.

Pricing signals may also work – but higher oil prices spurring investment may not plug the supply hole that is due to emerge – and this is the wider issue. A trigger of oil up to say $80-100/bbl will not ease the demand shortfall from the international oil company supply side – their input to the supply picture over the next 5-10 years is fixed or in decline, unless altered by the acquisition of a growth area such as unconventional oil (although net increase to the industry will likely remain zero).

As the IEA summarise it in their Energy Outlook report, supply risks therefore remain:

On the supply side,the decline in current upstream spending, estimated at more than 20% in 2015, results in the combined production of non-OPEC producers peaking before 2020 at just above 55 mb/d. Output growth among OPEC countries is led by Iraq and Iran, but both countries face major challenges: the risk of instability in Iraq, alongside weaknesses in infrastructure and institutions; and the need in Iran (assuming the path to sanctions relief is followed successfully) to secure the technology and large-scale investment required. An annual $630 billion in worldwide upstream oil and gas investment – the total amount the industry spent on average each year for the past five years – is required just to compensate for declining production at existing fields and to keep future output flat at today’s levels.

That leads to a straightforward conclusion: as long as world energy demand requires more incremental supplies of conventional oil and gas, the more it will have to rely on NOCs (OPEC+) to provide it.

Because it won’t be provided by the privatized and global IOCs – they are in the depletion business.