One of the most stirring moments in The Lord of the Rings is the point where Sauron’s army has broken into the city of Minas Tirith, and the forces of good seem certain to be defeated, but then they hear the horns of the riders of Rohan coming to their aid.
There were many who hoped that the US oil industry would play something like that role this year: riding to the rescue of consumers suffering under the burden of high fuel costs. It has not quite worked out like that. US oil output is rising, but it has lagged behind many of the more optimistic forecasts from the first half of the year.
Crude prices have dropped back significantly over the past three months, to a little over $90 a barrel for Brent, compared to a peak over $120 a barrel in early June. Fears that the world economy is sliding towards recession, and the realisation that Russia has been able to maintain its oil exports at around pre-war levels, despite international sanctions, have been key factors in that. The sustained release of crude from the US Strategic Petroleum Reserve (SPR), which is now down to its lowest levels since 1984, has also had some impact. The slow and steady production growth from the US Lower 48 states has been less significant.
The Biden administration apparently does not yet believe that it can afford to give up on the effort to hold crude prices down. The Department of Energy last week firmly denied a Bloomberg report suggesting that the government could start buying crude to refill the SPR if prices dip below $80 a barrel.
A spokeswoman said: “We anticipate that replenishment would not occur until well into the future, likely after fiscal year 2023.” In other words, that is not until after September 30 of next year at the earliest.
US crude production is on course to average about 11.73 million barrels a day for 2022, an increase of about 550,000 b/d from 2021, on Wood Mackenzie’s forecasts. That still means the US will be the second-largest contributor to increased global crude supplies this year, behind only Saudi Arabia. But it is some way short of growth that many had been expecting.
Wood Mackenzie’s forecasters have consistently been predicting only moderate growth in US production this year. Pablo Prudencio, principal analyst for the US Lower 48 upstream, says that back in March our model, which considers individual drilling forecasts for hundreds of areas, showed that projecting output growth of 1 million b/d was just not possible without some unrealistic assumptions for E&P companies’ spending and oilfield services capacity.
And that is how it has played out. US Lower 48 oil production is growing at a measured pace, rather than the turbo-charged rates of 2012-14 and 2018-19.
The conditions that have kept the brakes on growth are worth looking at in some detail, because they provide useful pointers to how the industry will perform in the future. Over the past few weeks, the active rig count in the US has stagnated. Two years ago, in September 2020, the number of horizontal rigs drilling oil wells in the US hit bottom at about 150, according to Baker Hughes.
That number rose steadily to reach 551 in late July, but has since then gone sideways as crude prices have slipped back, and was 545 last week. The constraints that have curbed Lower 48 production growth this year seem to be still in effect.
The first and foremost of those has been the pressure from investors for companies to use their cash flows to strengthen balance sheets or return capital to shareholders, rather than for growth.
The US unconventional oil and gas industry has been a money pit for most of its history, and investors’ patience ran out two years ago. They are now insisting that management teams prioritise shareholder returns through buybacks and dividends. “In 2018-19, companies were competing over which could grow the fastest. Now that has all changed,” says Prudencio. “And it is not a short-term change. This is a structural shift.”
Not all operators face the same pressures. The US Majors, ExxonMobil and Chevron, are committed to ambitious production growth goals in the Permian Basin, and are continuing to invest to meet those objectives. Some privately-owned E&P companies have been pursuing more rapid growth and spending accordingly. But the listed E&Ps, which account for the majority of US Lower 48 production, are generally aiming to meet investors’ demands.
Many have increased their spending somewhat from the plans they had in place at the start of the year, mainly to accommodate rising costs, but they remain committed to a fundamental strategy of capital discipline.
The second key factor is that there are still significant constraints in the supply chain. As I wrote back in May, shortages of equipment and labour in the upstream industry worldwide mean that “cost inflation is back”, and the US is no exception. In some cases, essential equipment and services are simply unavailable at any price, or available only after long delays.
The quarterly energy survey published by the Federal Reserve Bank of Dallas in June found that the percentages of respondents citing either “shortages” or “significant shortages” in the supply chain were 65% for personnel, 83% for equipment, and 89% for steel pipe and casing.
In spite of these shortages, service providers are cautious about adding capacity. Like the operators, they are focusing on investor returns rather than going for growth. As Jeff Miller, Halliburton’s chief executive, put it on the company’s second quarter earnings call: “This is a margin cycle, not a build cycle.” The capacity constraints seem unlikely to ease in the short term, at least.
The third constraint, which is probably some way behind the other two, is the set of pressures created by governments’ climate policies and investors’ environmental, social and governance (ESG) requirements. In some cases, these issues interact with the industry’s other challenges. Operators seeking to reduce their greenhouse gas emissions want to use more modern rigs and pressure pumping fleets, which can exacerbate equipment shortages. Investors that have a negative long-term view of oil demand may be more determined to prioritise short-term cash distributions over reinvestment.
The scale of the impact is difficult to assess, but is likely to be there at the margin, at least. And while there has been a backlash against ESG investing building, led by some politicians and investors, assessments of climate risk are not going to disappear from capital markets.
We are heading into the season when companies will be deciding on their capital spending budgets for 2023, and it is certainly possible that some will attempt to accelerate production growth from the pace we have seen this year. But given the constraints around investment and activity, a return to the jet-propelled expansion of the 2018-19 still seems unlikely. As consumers weigh up the outlook for oil supply next year, they should be ready for the possibility that US producers will again be jogging, rather than charging, to help them.
The European Commission has proposed a package of energy policy moves, intended to help the EU manage the crisis caused by restrictions on its imports of natural gas from Russia.
The proposals include an obligation to reduce electricity consumption by at least 5% during peak hours, and a goal of reducing overall electricity demand by at least 10% until 31 March 2023. There would also be a temporary cap on the revenues that could be earned by lower-cost electricity generators, including renewables, nuclear and lignite, set at €180 per megawatt hour. The most controversial proposal, however, is likely to be a windfall tax on the profits of oil, gas, coal and refining companies not covered by the revenue cap.
The tax would be collected by member states on any profits for 2022 that are more than 20% higher than a company’s average over the past three years. The revenues would be used to help energy consumers, in particular vulnerable households, hard-hit companies, and energy-intensive industries. The tax is being described the commission as “a temporary solidarity contribution on excess profits.”
European benchmark TTF gas futures for the coming winter have continued to drop back, as it has appeared increasingly likely that demand curtailments can be avoided over the coming months, providing the weather is mild. The Winter 2022 contract fell to €189.5 per megawatt hour at the beginning of the week, its lowest level since early August. It is now down about 45% from its peak in late August, although it is still more than five times its level of a year ago.
One of Germany’s three remaining reactors for power generation, Isar 2 in Bavaria, will be shut down for about a week for repairs after a leak was discovered. The reactor is one of two that had been scheduled for permanent shutdown at the end of the year, but will now be kept on standby until April 2023 in case they are needed over the winter.
The new government of the UK, led by Prime Minister Liz Truss, has been saying more about its energy strategy after setting a goal of making the country a net exporter of by 2040. Jacob Rees-Mogg, the secretary of state for business, energy and industrial strategy, said he wanted to “extract every ounce of oil and gas from the North Sea”. Details of the government’s plan to ease the burden of energy costs for businesses are expected soon.
Source: Wood Mackenzie