Dog days for the wildcatters
The creditworthiness of independents is falling. Barely-positive cash flow and weak enthusiasm for consolidation may not be enough to save them
While US shale production volume continues its unremitting rise, the pioneers of the industry are struggling to keep their heads above water without injections of fresh capital.
The latest firm to fail was Sanchez Energy Corporation on 11 August, with $2.275bn of debt. It was the 26th bankruptcy of the year and leaves the total just shy of the 28 that succumbed during the whole of 2018. Corporate law firm Haynes and Boone found that the 192 failures since 2015 involved more than $47bn of debt. It is not surprising that investors are losing patience.
Free cash flow—which facilitates capital spending without outside financing or the sale of assets—is a key measure of financial health. The Institute for Energy Economics and Financial Analysis' Sightline Institute reported in August that just 11 of the 29 publicly traded fracking-focused companies generated $26mn positive aggregate cash flow in Q2, "far too modest" in the context of its $100bn outstanding long-term debt.
"For an industry that has posted negative cash flows for a decade, these mediocre results represent a financial high-water mark," notes the report. Undermining this slight positivity is the sobering fact that the aggregate number would have been negative without US independent EOG Resources slashing its capital spending by $437mn.
Research from consultancy Rystad Energy found, similarly, that Q2 2019 was the first quarter on record that US shale operators achieved positive cash flow from operations after accounting for capital expenditure (see fig. 1). "That is an industry first," says the firm's energy senior analyst Alisa Lukash. The 40 dedicated shale firms surveyed accumulated a surplus of $110mn, with just 35pc balancing spending with operational cash flow.
No pure shale operator has offered public equity since the 2017 IPO of Houston-headquartered Magnolia Oil & Gas and public capital issuance has decreased for five six-month periods in a row. Capital raised stood at $4.8bn in the first half of 2019, less than a third of the $16.4bn average of the last five years, according to Rystad figures.
With public markets remaining dry for independent oil companies, they are increasingly turning to banks to finance investment and possibly even operations. Credit Benchmark tracks the credit risk views of many global financial institutions involved in such lending, collecting estimates of the likelihood of default across wholesale books. Lead researcher David Carruthers estimates that, as two-thirds of the dataset is not covered by conventional ratings agencies, it captures indicators earlier. Either way, it suggests we may be at a turning point.
Its data shows that the credit quality for US oil and gas firms had been steadily improving since a low point in early 2017, but has shown signs of deterioration since the start of 2019 (see figure 2). By comparison, the credit quality of EU oil and gas firms has improved 20pc since late 2017 and UK oil and gas firms' credit quality rose until about October 2018 but has plateaued since.
The US series—which tracks 255 entities—deteriorated by 80pc between January 2016 and January 2017 (credit worthiness lags falling oil prices). "The US deteriorated the most but then experienced a very sharp recovery," says Carruthers. "Although it has improved, it never got back to where it was and it looks like it is showing signs of turning down again.
"That tells us, everything else being equal, if your balance sheet was struggling back in January 2016, your balance sheet will be struggling a lot more in July 2019—they are still 30pc lower in terms of credit worthiness, and 30pc is a big number," says Carruthers.
The US companies included in the benchmark include "lots of fracking" companies, including so-called wildcatters, which have far lower credit ratings than majors and are more sensitive to oil price changes. However, he notes that the picture is clouded by the dataset including a diverse mix of E&P, integrated, equipment and services, and pipeline firms. The median rating in the EU dataset is BBB while the UK and US have ones of BB, and the US mean rating is lower.
Carruthers says the credit worthiness data corroborates the view that firms are heading for trouble. "I would not be surprised if a number of firms, especially smaller ones, start showing signs of distress. If [credit worthiness] continues to turn down that distress will increase."
He notes that historically there have been clear turning points and once one has been reached—such as the recent apparent change from recovery to downturn—these trends have momentum. "It is not a random scatter, there are clear trends. In the US it turned [positive] in early 2017 and did not look back. The question is whether we are hitting another turning point."
It is not the only credit agency to believe so. In July S&P Global Ratings stated in a research note that an increasing number of oil and natural gas companies are in financial distress due to a combination of investors losing interest, credit access being throttled and companies struggling to operate within cash flows.
With low oil and gas prices, M&A may not save them and "bankruptcy may be the only option". It noted that several companies merged to lower costs but market reaction to the most notable—Haynesville shale gas producer Comstock Resources' deal to buy Covey Park Energy—was "lukewarm".
"The jury is still out on whether contemporary consolidation initiatives will enhance viability for some of the industry's speculative-grade issuers. What we have repeatedly learned is that in most cases, where there is smoke there is fire. Barring a sharp reversal in commodity pricing, the sector could shortly be facing another reckoning."
The shale business, especially the Permian Basin, increasingly appears to be becoming the preserve of majors and the largest independents. ExxonMobil plans to expand Permian production to more than 1mn bl/d oe by 2024, more than quadruple its 2018 production. Chevron is not far behind with a 900,000 bl/d oe target by 2023, nearly triple its 2018 production. BP has made substantial acquisitions in shale plays and there are ongoing rumours that Shell is on the lookout for additional acreage.
By contrast, private equity house Aethon Energy is invested primarily in the Haynesville. "It is not that we do not like the Permian—it is that the valuations are now just too high to enter that basin in a major way on an operator basis," says Gordon Huddleston, partner and co-president of Aethon. "One of the issues is the majors getting involved in the Permian—imagine trying to muscle out the top five.
"We really like the Haynesville, we like the proximity to Henry Hub and all the petrochemical and LNG demand on the Gulf Coast. If we made an acquisition today, we would not be paying very much for undeveloped locations and we would hedge. It is like a baseball game where we are trying to hit singles and make it a very long innings. We are not trying to swing for the fences."
Huddleston says private equity has more opportunity in the mezzanine debt space, a more defensive form of capital investment, as there is a need for capital and a lot of the traditional debt providers and channels have dried up. He also sees a lot more private equity focus on midstream, water disposal recycling as well as traditional pipeline infrastructure.
"I would not be surprised if a number of firms, especially smaller ones, start showing signs of distress" Carruthers, Credit Benchmark
Shale drilling itself is maturing into a very tight margin business where economies of scale and manufacturing processes determine success. "We are very focused on trying to be a low-cost producer," says Huddleston. "Being in good proximity to demand, with low-cost transportation is your best defence. The biggest risk is price, and we are very aggressive on hedging and finding assets that are not burdened by high cost gathering, processing and transport arrangements."
The traditional model of private equity shale investing—with short turnaround times to prove and flip investments—is not viable when potential buyers have difficulty securing capital. "We are seeing people get stuck now," says Huddleston. "They are looking at five to seven years plus for some of their portfolio investments. That requires building out development teams, which is a very capital and human capital-intensive process."
This has created an opportunity for the majors because those smaller groups, at some point, will feel pressured into selling if they are offered a more reasonable metric. Their assets could be worth more to firms with already deep pockets; the developing method of cube drilling, which increases efficiency but requires substantial upfront investment, is better suited to companies with huge balance sheets and a long time horizon.
"There is just such a different focus on the length of the investment—majors see them as 30-year wells. And that is why the majors coming into the Permian and slowly consolidating is not really a bad thing. They are more suited to develop a shale resource, frankly, because it is capital intensive," says Huddleston.
Groups are trading acreage to create more contiguous blocks and to achieve scale. The problem for sellers is that majors such as Chevron have so much acreage that there is no pressure for them to make a big transaction. "They can let it come to them—especially because they know the markets have dried up for high-yield upstream debt for the smaller players," he says.
"In the early to mid-2020s we are potentially going to see peak Permian production. That is not necessarily a function of the resource available, but the appetite of the firms that control the acreage to develop it, and at what pace."