Note: This story was updated on 30 April to reflect market developments and to add a boxout featuring the perspectives of Korean LPs.

In this strange time of disruption and distancing, with economies idle due to government efforts to stop the spread of the coronavirus pandemic, something of significance happened in the energy sector. As global demand for oil was falling, Saudi Arabia began to ramp up production.

In March, the world’s largest crude exporter locked into a pricing dispute with the second largest, Russia, which set off a grab for market share. Even after the two sides reached a production curbing agreement last month, an oversupplied product in low demand has sent crude prices down to historic lows, at one point dipping into negative prices per barrel.

At the time of writing, Brent crude, a type of oil recognised as a pricing benchmark, is trading at around $20 a barrel. Another industry standard, West Texas Intermediate, has fallen to circa $13 per barrel, a near 78 percent drop from the high of $60 in January.

For US energy companies, which produced around 12 million barrels per day before the pandemic, low prices are likely to box out their costlier commodity. Producers of natural gas, which have dealt with a 36 percent fall in commodity prices over the past year, will also struggle to make a profit at the current cost of $1.90 per million British thermal units (Btu).

Calling this year’s events unprecedented, Jeffrey Altman, an energy specialist at transaction advisory consultant Finadvice Group, describes the price war as a political factor impacting energy, with lagging industries from government shutdowns an economic factor. The “known unknown,” he says, is the ongoing and aftereffects of an event like the coronavirus pandemic.

“You’ve got a perfect storm here with all of these events, including a new calamity which was never even considered by anybody,” Altman says.

It’s easy for US oil and gas producers, which have always been viewed as risky investments, to see that low prices are unsustainable for their bottom line. But midstream companies, operators of the infrastructure transporting the commodities to market, have also been put in jeopardy.

Oil prices where they are now, hovering around $30 per barrel, “does not work for anyone in the US,” Matt Hartman, co-head of midstream at the investment firm EIG Global Energy Partners, told Infrastructure Investor in early March. “If these pricing levels persist, we expect to see a significant reduction in drilling. We expect to see a lot of bankruptcies, which will impact the midstream side as well.”

For institutional investors, which have committed large amounts of capital to midstream companies as part of their infrastructure strategies, volatility this severe is not exactly what they signed up for when they entered the sector more than a decade ago. Seeking steady, long-term returns, investors were sold on the notion that pipelines and storage containers, which are secured by usage contracts, would be insulated from commodity prices.

Now, the latest round of volatility is posing the question of whether midstream correlates a little too close for comfort with the wider energy sector – and whether that threatens to push some investors away for good.

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As low demand and commodity price volatility roils the energy sector, BlackRock’s Mark Florian talks with Infrastructure Investor’s Jordan Stutts about how an oil production agreement and other market trends are impacting midstream infrastructure assets.

‘Taking it on the chin’

“Investors often approach energy with the view that it’s a homogeneous sector that has commodity price volatility as well as ESG concerns,” Brent Burnett, co-head of real assets at Hamilton Lane, explains. “They’ve backed off upstream commitments earlier, and now we’re seeing midstream get grouped into that as well.”

He says that investors in North American midstream today are still feeling burned by the last commodity price swing, when oil and gas prices sank, capital fled the sector, and a popular financing structure showed its weakness.

That structure was the master limited partnership, which helped usher institutional capital into the sector. Publicly traded, MLPs gave investors access to midstream and a quick exit ramp when volatility hits. Some of the largest North American midstream companies today are structured as MLPs, but their shortcomings were exposed in 2014, when commodity prices fell and investors compounded tight liquidity by making good on that exit ramp.

In response, both public and private midstream companies have sought to tighten their balance sheets, according to Kathleen Connelly, a director at Fitch Ratings who focuses on energy and midstream companies. After the commodity price swing, she says, midstream companies needed to “manage liquidity and ensure they had real financial discipline”.

However, Connelly adds the sector is not insulated from the current round of volatility. One example she describes is the weakening of contract structures so that upstream producers, midstream’s sole customers, can survive.

“Certain midstream players are reducing their own profits so they can help support a customer and keep that customer in a strong enough position to continue doing business,” Connelly explains.

In February, for example, EQM Midstream Partners, an oil and gas MLP that spun out of EQT Corporation, a Pittsburgh-based energy company founded in the 1880s, agreed to a renegotiated midstream contract with EQT Corporation. In a 15-year agreement, EQT Corporation, which provides the majority of EQM’s revenue, received “gathering and compression fee relief” in exchange for upping the minimum volume of natural gas transported by EQM’s assets.

“Midstream players are taking it on the chin so they can help the upstream producers,” Connelly says. “I wouldn’t be surprised if others in the midstream space are forced to renegotiate contracts.”

Read the fine print

But in many cases, midstream companies that agree to weaker contracts may be shaving away an already thin margin. And for firms that don’t renegotiate contracts, another risk could be hidden in the fine print.

A minimum volume guarantee is arguably the most important feature of a midstream contract. The guarantee is that oil and gas producers are on the hook to pay midstream operators a minimum baseline revenue for using a pipeline, refinery or storage container, with additional volume charged as a fee. It is what has insulated the sector from commodity price swings and made midstream assets seem like an investment steady enough to be considered infrastructure.

However, that calculation may have changed in today’s market environment.

Energy demand is falling precipitously in response to governments shutting down large portions of their economies to stop the spread of the coronavirus. Airport traffic in some major cities has fallen by 90 percent, and streets and highways are vacant as lockdowns restrict non-essential travel.

In the short term, some analysts say global oil demand could fall by 10 to 20 million barrels a day, a fifth of total consumption. Natural gas, which saw demand fall over an unseasonably warm winter, could see prices swing upwards if production associated with oil drilling decreases.

If demand falls, producers will reduce drilling and midstream companies will be forced to rely more on minimum volume guarantees, which is how the strength of a midstream contract will make the difference.

Companies that agreed to fixed-rate guarantees based on commodity prices from a decade ago, when oil was as high as $60 per barrel, should fare better than contracts with floating rate guarantees. But if current disruptions drag on, companies signed to floating-rate guarantees will be “trying to survive,” says Brian Hepp, a 30-year energy sector veteran who’s worked at oil industry giants BP and the now-defunct Talisman Energy. That will also create opportunities for investors, he adds.

One of the largest take-private acquisitions last year was Australian fund manager IFM Investors‘ purchase of Buckeye Partners, a Houston-based midstream business, in a deal valued at $10.3 billion

Julio Garcia, IFM Investors’ head of infrastructure in North America, says the Buckeye deal came together in part because of how the commodity price downturn in 2014 impacted MLPs. “We had a good opportunity in terms of being able to see the fundamental value difference between the MLP holding structure and what we think the company itself is worth,” he says.

Garcia says he’s comfortable with the firm’s midstream exposure during this downturn. Depending on which industries cause energy demand to drop – and by how much – Buckeye is in a strong enough position to ride out this period of volatility, Garcia argues.

“The assets we look for aren’t driven directly by commodity price differences but really by volume, in throughput and storage, or contractual arrangements,” he explains. In the transportation sector, he adds that traffic declines are typically followed by a “solid rebound” after a downturn subsides.

‘A lot of ups and downs’

Institutional investors are on a spectrum for how they’re approaching the North American midstream sector, with a lot depending on size of the investor, geographic location and existing exposure. After conversations with more than 15 industry sources, there seems to be a few main approaches investors are taking.

On one end of the spectrum, some investors have completely turned away from midstream, citing lacklustre returns, weak contracts and ESG considerations. German life insurer Munich Re fits that bill.

Martin Kaufmann, a senior vice-president at Munich Re America, says the reasons are “many fold” for why his team never really got close to deploying capital last year when looking into US gathering systems and pipelines. For starters, he says Munich Re is giving more consideration to climate change when investing, so fossil fuel deals in general receive heavy scrutiny.

He also points to weak contract structures. “Munich Re looks for long-term, contracted and stable cashflows, which upstream producers would previously agree to via minimum volume agreements. The move to acreage dedications in the last couple of years added complexity and shifted risk towards midstream companies and their investors.”

For other institutions, the volatility from the last price swing is still fresh in the mind.

Paul Chapman, director of real estate and real return at the New Mexico State Investment Council, a $26 billion state-owned sovereign wealth fund, says he’s unhappy with recent volatility he’s seen from the investor’s energy portfolio, which includes midstream, despite calling its 11.1 percent three-year return “healthy”.

“The problem is the upstream energy component gives it some volatility,” he explains. “You have to be prepared for a lot of ups and downs.”

Now, at the beginning of more volatility, Chapman says his team at NMSIC is “deselecting strategies, where we can, that have a high propensity to invest in US midstream assets”.

A major drawback of private fund exposure to the midstream sector, versus investing in MLPs, is that funds “don’t really have opt-out rights,” he says. But through other commitments, Chapman adds, that’s beginning to change.

“We’re starting to have co-investment sleeves with terms that give us the right to opt out of certain investments,” he explains. “Today, we would opt out of US midstream.”

In addition to correlated volatility from upstream producers, Chapman says NMSIC is also seeking portfolio diversity. Midstream opportunities in Asia, for example, are on the table, but more than anything, NMSIC will focus on renewables moving forward.

“The returns aren’t as exciting as conventional energy, but the volatility is a lot lower,” Chapman explains.

Changing of the guard?

Not all LPs are opting out of North American midstream, though.

Energy Capital Partners, whose investments include midstream, closed its fourth flagship fund in January with $3.3 billion of LP commitments, short of its $6 billion fundraising target. At the same time, the firm received $3.5 billion of additional commitments that it will manage as co-investments.

Doug Kimmelman, ECP’s founder, has spent three decades investing in the energy sector. He says ECP launched the fund thinking most commitments would go to the blind pool, but 60 percent of the money raised came from Asian and Middle Eastern investors that wanted “customised solutions” for the large cheques they were seeking to deploy.

“A lot of countries around the world are new to alternatives, so they’ve got a lot of catching up to do,” Kimmelman told Infrastructure Investor.

Only around a third of investors were from the US, a sharp decline from 80 percent in previous fundraises, he explains, adding US LPs are saying: “Energy has been bad for us. It’s been one of our weaker performers. We don’t need more of it”. He also pointed out that investment committees are increasing pressure to “shy away” from fossil fuels.

Dave Noakes, a senior managing director at Prostar Capital, a Connecticut-based firm focusing on the “logistics supply chain” connecting natural gas and oil exports to key energy hubs in Asia, agrees and says he’s had conversations with investors that suggests some are rethinking their exposure to the North American midstream sector, but interest from others remains.

Asian LPs are becoming more interested in the North American midstream sector, he adds, as a way to diversify their portfolios away from exposure to investments in Asia’s energy sector and to secure access to natural gas exports.

“The overwhelming growth in energy demand over the next 20 or 30 years will come out of Asia,” Noakes explains. “Institutional investors in Asia recognise that in order to achieve ambitious growth, local countries need energy supply. So, they’re investing in that supply chain.”

So, while there are signs that North American midstream is going through a changing of the guard when it comes to the institutional investors that commit to it, nobody yet knows how today’s market disruptions will play out.

That leaves institutional investors to decide on whether to hedge on a rebound and look for good deals now. Or take a view on whether the current round of volatility should underline a more permanent transition away from the sector.

Pause and think

After increasing US midstream deal activity in recent years, South Korean LPs appear to be pulling back until volatility subsides, writes Jihyun Kim.

South Korean institutions are second-guessing future investments in US midstream infrastructure after energy sector volatility in April took a toll on companies with revenues tied too closely to commodity prices. Many of those LPs – such as pensions, insurance companies and asset managers – have paused investment due diligence on US midstream deals, according to a senior source at a Korean insurer. The source explains that economic disruption – caused by the dip in demand for energy as a result of covid-19 – and an oversupplied oil market are showing that US midstream assets no longer have their previous levels of downside protection.

“There are more deals sharing upside risk and return now, as competition for transactions becomes fierce,” the source says. “LPs sharing upside risk and return may see a big impact.” Another source, who works at a Korean pension, adds: “If oil prices keep falling, and upstream companies close their businesses, midstream companies will definitely be impacted.”

In recent years, South Korean LPs, led by the $620 billion National Pension Service, have become increasingly active investors in the US energy sector. These investors have focused on midstream assets such as pipelines and export terminals, which help transport oil and natural gas to global markets. In 2018, the NPS committed $100 million to a co-investment with Morgan Stanley through the investment bank’s North Haven Infrastructure Partners II fund. This formed part of a $1.75 billion acquisition of assets operated by Texas-based company Brazos Midstream.

In December, the NPS partnered with KKR to make a 65 percent equity purchase of Canada’s Coastal Gaslink Pipeline in a deal valued at $6.6 billion. The following month, it joined Blackstone to complete a buyout of Tallgrass Energy for around $2 billion.