You’ve probably heard the saying “buy low and sell high” or some version of it. Oil prices have been painfully low, so does that mean it’s time to buy physical oil assets?
The shale boom in North America over the past 10 years has brought many potential buyers through our office looking forConsulting support. The allure of high returns, large drilling inventories and capital flexibility can be tempting. Many buyers who struggled to stomach the valuations of the assets when oil prices were high are now revisiting the space thinking there may now be a number of great deals to be had. That’s where we start exerting a bit of caution with our clients as there is no magic formula or time – given a bit of hindsight, the landscape is littered with “bad deals”.
Most people thought last year was going to be the year of opportunity in the deal market, but operators proved resilient and lenders demonstrated patience and flexibility. Fast forward and more than a year of low prices is putting some operators in sticky situations. The best deals (for the best assets) make sense at almost any oil price, but there’s no doubt it’s better to buy when the sellers have to sell.
We believe a buyer’s market will emerge if low oil prices persist (there are likely great deals happening now and we’ll see them announced over the next few months). But generally speaking, the sellers who are forced to divest assets do not have much exposure to the best acreage, and those who do will part with their best assets only as a last resort. Outside of relatively small “bolt-on” asset deals, we expect corporate M&A to be the preferred entry vehicle for companies entering core areas.
Companies come to us after they’ve started the process and we generally help them get better organized and more focused in their search. Most haven’t considered all the consequences. They want an asset that meets all or most of the following criteria:
In short, they’re looking for a unicorn – that is, an asset someone else has discovered or purchased before really knowing what they had. For the most part, companies don’t sell these assets. They’re the crown jewels.
And although you can’t buy another company’s crown jewels on the cheap, investing in upstream properties can still be a good option.
These days – with the amount of liquidity looking for deals and a wealth of publicly available data to analyse performance – it would be hard to buy something that is materially undervalued by the rest of the market. Well, unless you’re willing to take exploration risk.
Executing the transaction isn’t the first step. We start by asking a few basic questions:
Even if a company can get internal agreement on these issues above, the most important element is its capability. Does it have internal strengths and infrastructure that will help it execute or does it need to acquire the talent through a corporate acquisition?
That’s just the beginning of the process. The answer to our original question isn’t as simple as most people hope but, in our view, it is much more important to identify the right deal as opposed to a good deal. Check the weather before you fly, the timing might be right or you might be flying into a storm.
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Working natural gas inventories in the Lower 48 states totaled 3,519 billion cubic feet (Bcf) for the week ending October 11, 2019, according to the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report (WNGSR). This is the first week that Lower 48 states’ working gas inventories have exceeded the previous five-year average since September 22, 2017. Weekly injections in three of the past four weeks each surpassed 100 Bcf, or about 27% more than typical injections for that time of year.
Working natural gas capacity at underground storage facilities helps market participants balance the supply and consumption of natural gas. Inventories in each of the five regions are based on varying commercial, risk management, and reliability goals.
When determining whether natural gas inventories are relatively high or low, EIA uses the average inventories for that same week in each of the previous five years. Relatively low inventories heading into winter months can put upward pressure on natural gas prices. Conversely, relatively high inventories can put downward pressure on natural gas prices.
This week’s inventory level ends a 106-week streak of lower-than-normal natural gas inventories. Natural gas inventories in the Lower 48 states entered the winter of 2017–18 lower than the previous average. Episodes of relatively cold temperatures in the winter of 2017–18—including a bomb cyclone—resulted in record withdrawals from storage, increasing the deficit to the five-year average.
In the subsequent refill season (typically April through October), sustained warmer-than-normal temperatures increased electricity demand for natural gas. Increased demand slowed natural gas storage injection activity through the summer and fall of 2018. By November 30, 2018, the deficit to the five-year average had grown to 725 Bcf. Inventories in that week were 20% lower than the previous five-year average for that time of year. Throughout the 2019 refill season, record levels of U.S. natural gas production led to relatively high injections of natural gas into storage and reduced the deficit to the previous five-year average.
The deficit was also decreased as last year’s low inventory levels are rolled into the previous five-year average. For this week in 2019, the preceding five-year average is about 124 Bcf lower than it was for the same week last year. Consequently, the gap has closed in part based on a lower five-year average.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report
The level of working natural gas inventories relative to the previous five-year average tends to be inversely correlated with natural gas prices. Front-month futures prices at the Henry Hub, the main price benchmark for natural gas in the United States, were as low as $1.67 per million British thermal units (MMBtu) in early 2016. At about that same time, natural gas inventories were 874 Bcf more than the previous five-year average.
By the winter of 2018–19, natural gas front-month futures prices reached their highest level in several years. Natural gas inventories fell to 725 Bcf less than the previous five-year average on November 30, 2018. In recent weeks, increasing the Lower 48 states’ natural gas storage levels have contributed to lower natural gas futures prices.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report and front-month futures prices from New York Mercantile Exchange (NYMEX)
Headline crude prices for the week beginning 14 October 2019 – Brent: US$59/b; WTI: US$53/b
Headlines of the week
Amid ongoing political unrest, Ecuador has chosen to withdraw from OPEC in January 2020. Citing a need to boost oil revenues by being ‘honest about its ability to endure further cuts’, Ecuador is prioritising crude production and welcoming new oil investment (free from production constraints) as President Lenin Moreno pursues more market-friendly economic policies. But his decisions have caused unrest; the removal of fuel subsidies – which effectively double domestic fuel prices – have triggered an ongoing widespread protests after 40 years of low prices. To balance its fiscal books, Ecuador’s priorities have changed.
The departure is symbolic. Ecuador’s production amounts to some 540,000 b/d of crude oil. It has historically exceeded its allocated quota within the wider OPEC supply deal, but given its smaller volumes, does not have a major impact on OPEC’s total output. The divorce is also not acrimonious, with Ecuador promising to continue supporting OPEC’s efforts to stabilise the oil market where it can.
This isn’t the first time, or the last time, that a country will quit OPEC. Ecuador itself has already done so once, withdrawing in December 1992. Back then, Quito cited fiscal problems, balking at the high membership fee – US$2 million per year – and that it needed to prioritise increasing production over output discipline. Ecuador rejoined in October 2007. Similar circumstances over supply constraints also prompted Gabon to withdraw in January 1995, returning only in July 2016. The likelihood of Ecuador returning is high, given this history, but there are also two OPEC members that have departed seemingly permanently.
The first is Indonesia, which exited OPEC in 2008 after 46 years of membership. Chronic mismanagement of its upstream resources had led Indonesia to become a net importer of crude oil since the early 2000s and therefore unable to meet its production quota. Indonesia did rejoin OPEC briefly in January 2016 after managing to (slightly) improve its crude balance, but was forced to withdraw once again in December 2016 when OPEC began requesting more comprehensive production cuts to stabilise prices. But while Indonesia may return, Qatar is likely gone permanently. Officially, Qatar exited OPEC in January 2019 after 48 years of continuous membership to focus on natural gas production, which dwarfs its crude output. Unofficially, geopolitical tensions between Qatar and Saudi Arabia – which has resulted in an ongoing blockade and boycott – contributed to the split.
The exit of Ecuador will not make much material difference to OPEC’s current goal of controlling supply to stabilise prices. With Saudi production back at full capacity – and showing the willingness to turn its taps on or off to control the market – gains in Ecuador’s crude production can be offset elsewhere. What matters is optics. The exit leaves the impression that OPEC’s power is weakening, limiting its ability to influence the market by controlling supply. There are also ongoing tensions brewing within OPEC, specifically between Iran and Saudi Arabia. The continued implosion of the Venezuelan economy is also an issue. OPEC will survive the exit of Ecuador; but if Iran or Venezuela choose to go, then it will face a full-blown existential crisis.
Current OPEC membership: