Monday was the day crude oil futures traded as low as negative $41 per barrel. As with the 1987 stock market crash, Monday’s participants will recall that date for the rest of their lives, the way I do October 19, 1987. Shortage of oil storage is the problem – nobody is going anywhere, so we’re not using much gasoline or jet fuel. Some have commented, only half-jokingly, that being paid $40 to take a barrel of oil would draw in a lot of buyers with the ability to temporarily repurpose other forms of storage.

But oil is a nasty product to handle. It is highly toxic, and leaks noxious gases such as hydrogen sulfide. If the air that you’re breathing contains as little as 0.1%, it kills you within seconds. This is why Texans aren’t filling up their swimming pools with the stuff.

The May futures contract traded 231 thousand times on Monday. One contract is equivalent to 1,000 barrels of oil. It traded from $17.85 to minus $40.32, a range of $58.17 which must be a record. A trader careless enough to be long 1,000 contracts who suffered a $10 adverse price move before dumping his position would lose $10 million. Given the volume and daily range, yesterday’s losses will be big enough to draw their own press coverage.

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The United States Oil Fund, LP (USO) is an ETF that gives investors exposure to crude prices. Watching it has been the financial equivalent of a train wreck lately. Retail investors piled in last week, adding $1.6 billion of inflows. “Crude can’t stay this low” is sufficient analysis for many. Crude pricing is unlikely to correct before such adherents are wiped out.

Many have concluded crude prices are wrong, but few have questioned USO’s raison d’etre. This is an ETF that buys futures contracts. Crude is in contango, meaning prices in the future are higher than today. Some interpret this as a forecast that the market must rebound, but forward prices are a poor predictor of what actual prices will be. What is clear is that the buyer of, say, July futures confronts the inevitable “rolldown” as today approaches July and actual supply/demand for crude increasingly determines the price. The rolldown is the price difference incurred as the holder of the July contract “rolls” into August by selling July and buying August at a higher price.

The bullish crude view has to constantly paddle upstream against the rolldown current. USO apparently rolled May futures into June last Friday, on terms that looked more like paddling up through spring rapids. Wiser and poorer for the experience, on Sunday they announced an improvement in their strategy. Henceforth, 20% of their futures positions will be invested in later-dated contracts, thus avoiding having to roll them all at once.

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What is the point of an ETF that buys and holds futures contracts? Why don’t retail investors wishing to speculate on crude oil simply buy the futures themselves? Or an oil royalty trust? USO is a dumb way to bet on crude prices. A year ago, the July 2020 WTI futures contract was trading at $60 and yesterday was at $23, down 62%. Over that time USO has dropped from $13 to $3, down 77%. Its structure makes it hard to figure out how much it should move for a given change in crude prices. If crude can go negative, as the May futures did on Monday, can USO? Could USO go bankrupt?

Why do people bother with it? As well as being of dubious value to investors, few probably realize that they get stuck with a K-1 instead of a 1099, as USO is a partnership.

People buy USO because it’s easy to buy an ETF in a brokerage account, but more complicated to trade futures. Often it requires a separate agreement.

The reason is that the SEC regulates equities, including ETFs, while the CFTC regulates futures. USO and crude oil futures are both financial instruments – they ought to have a single regulator. The Senate Banking Committee oversees the SEC. The Senate Agriculture Committee oversees the CFTC, reflecting the original importance of agricultural futures. Brokers make valuable campaign contributions to the senators who oversee their regulator. The Finance/Real Estate/Insurance sector is the biggest source of such funding to the Senate Agriculture committee. No senator wants to give that up.

Merging the two regulatory agencies has often been suggested in the past, but is widely acknowledged to be a political non-starter. Even the passion for reform that followed the 2009 financial crisis was insufficient to overcome the economics.

USO is a result of our fractured regulatory structure, which is caused by the need for senators to raise money. USO buyers made a bad market call, but multiple overseers of financial instruments led to a poorer vehicle, which ultimately cost them even more. Yesterday USO was trading at a 27% premium to its NAV, indicating continued strong demand for this flawed ETF. It’s an instance of regulatory failure, caused by campaign contributions outweighing a more intelligent regulatory framework.

As the world’s economy has stopped moving, demand for transportation fuel has collapsed. The latest weekly report from the U.S. Energy Information Administration (EIA) presents the statistical reality in our country. Gasoline supplies are down 46% from a year ago. Kerosene (jet fuel) is down 72%. Nobody has anywhere to go.

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Interestingly, propane supplies are up. Natural gas liquids are part of the hydrocarbon value chain. At one end is methane, the simplest molecule. This is the natural gas that produces electricity, heats homes and runs through your gas stove. It’s known in the industry as “dry gas”. Natural gas liquids (NGLs) are successively more complex molecules of carbon and hydrogen; these include ethane (can be burned but is mostly used as a feedstock for plastics); propane (heating and cooking where methane supply isn’t available), butane and others. The hundreds of blends of crude oil sit at the more complex end.

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In today’s energy market, the farther you are from transportation fuel, the better.

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Natural gas demand has held up. Power demand has risen compared to a year ago. Residential/Commercial is up because people are spending more time at home. And we’re exporting more. There is almost no evidence of coronavirus in this part of the energy market.

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NGLs don’t receive much attention, but there are two reasons investors in midstream energy infrastructure sector care: (1) NGLs require processing when extracted to separate them into their useful products, creating multiple opportunities to “touch” each molecule and charge a fee, and (2) the U.S. produces around 26% of world consumption, far bigger than our share for natural gas or crude oil.  NGL exports continue to make new records.

Many Indians  cook and heat their homes with Liquid Petroleum Gas (LPG), a combination of propane and butane. Methane requires too much pressure to go in the ubiquitous gas bottles seen all over the world, so LPG meets the needs of consumers without a natural gas hook up. The U.S. exported over 100 thousand barrels per day of NGLs to India in 2019.

Last week Bloomberg ran a story highlighting rising LPG prices (see One Fuel Is Thriving During the World’s Biggest Lockdown). In Asia, LPG is often produced as a byproduct of refining crude oil, and lower gasoline demand means refineries are cutting output. LPG demand in India is up, whereas demand for transportation fuels is down 20% or more. James Mann of the Texas Pipeline Association warned that cutting oil production would have the unintended consequence of also reducing NGLs and gas, potentially leaving  some customers short of needed  product.

Some big U.S. midstream energy infrastructure companies generate a significant portion of their profits from NGLs. Last Tuesday the Texas Railroad Commission held hearings on a request to curb Texan oil production (called “pro-rationing”). Enterprise Products Partners CEO Jim Teague was invited to give his view. He was against pro-rationing, and went on to note that their LPG export facilities were in high demand.

The following slides show the importance of NGLs to some of North America’s biggest pipeline companies.

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We are invested in all of the companies mentioned above.

Yesterday the Texas Rail Road Commission (RRC) began their public hearings via Zoom on a request from some oil companies that they limit oil production (“proration”) to avoid unnecessary waste (see Navigating the Collapsing Oil Market). On the surface, it seems a pretty straightforward question. The pandemic has crushed oil demand, which is estimated to be down 30% globally. At the same time, OPEC+ has collapsed into acrimony because of a dispute between Saudi Arabia and Russia.

The Saudis responded by increasing production into an already oversupplied  market. Oil storage is at a premium, and is expected to run out within months. To a U.S. oilman, this looks like a thinly veiled effort to bankrupt the U.S. energy business, permanently lowering our supply and allowing others to profit later from resulting higher prices.

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So Scott Sheffield, CEO of Pioneer Resources (PXD) testified before the RRC about the substantial energy job losses that will occur without action by the RRC. Matt Gallagher from Parsley Energy (PE) echoed Sheffield’s comments.  They argued that without the regulator imposing production limits on Texas oil production, the industry will suffer widespread bankruptcies and a permanent drop in employment.

They were followed by Lee Tillman, CEO of Marathon Oil, and it suddenly became more complicated. Tillman noted that naturally a company that only produces crude oil in the Permian in west Texas will favor pro-rationing. But Marathon produces in Texas, Oklahoma, New Mexico and North Dakota. Production will be cut, but some of Marathon’s most profitable wells are in the Eagle Ford, in south Texas. They might not choose to cut any Texas production. The message was clear – if the RRC imposes pro-rationing, in Marathon’s case it could result in more Texans losing their jobs than needed.

Diamondback’s CFO Kaes Van’t Hof went a step further, saying that they’d respond to prorationing by laying down all rigs, punishing oil service companies.  He pointed out that they had signed long-term contracts for the oil they produce, and had hedged their future production.  Diamondback was once a small company too, which didn’t stop them from running their business responsibly (subtle dig at Pioneer and Parsley).

So the view from the moral high ground is different, depending on which part of it you’re standing on. RRC member Ryan Sitton, a proponent of prorationing, tried to build the case on avoidance of waste which allows the RRC to limit production. It’s a dubious theory – if crude oil is being produced and sold to a consumer, how does one objectively define that as wasted even if the price is ruinously low? And the RRC has long permitted flaring of unwanted “associated” natural gas that is produced with oil (Texas Reconsiders Flaring), even though this is waste by any definition.

It’s also not clear whether other oil-producing states will follow the lead of Texas if the RRC does choose prorationing. Under U.S. law, companies are not allowed to co-operate in limiting production, and the Federal government cannot impose limits other than on Federal land or offshore. So the question falls to the states.

Tillman argued in favor of the free market being allowed to work, noting that production will drop anyway, as it should given collapsing demand. But when asked if he supported U.S. efforts to control market forces via organized production cuts with Saudi Arabia and Russia, he defended this as a geopolitical issue correctly solved with diplomacy.

It’s hard to escape the conclusion that U.S. oil producers want the free market to work until it no longer works for them, at which point they demand government intervention.

Saudi Arabia shouldn’t be able to pump oil at their desired level if low prices bankrupt U.S. producers, while sheltering under U.S. military protection. Trump probably pointed that out, and a group of nine U.S. senators definitely did. Playing the military card is just another form of the free market, no less important than securing pipeline capacity for future oil production.

It’s easy to see why cartels are so unstable.

It’s hard to see why a pipeline company would want the government to step in and compel them to make space for the less responsible companies that hadn’t already secured take-away capacity for their oil.  The American energy industry may emerge stronger, by letting the markets and the bankruptcy process move the acreage from the weakest hands to the strongest.

The other day a client asked if we’d looked at insider buying among management teams of pipeline companies.

So far this year, Energy Transfer (ET) dominates with $108MM, representing 63% of all the insider buys so far. Kelcy Warren receives plenty of criticism, not least from this blog (see Energy Transfer’s Weak Governance Costs Them), but he’s certainly invested in his business. He’ll be frustrated at having made those purchases in February, because ET lost more than half its value during the March collapse. But investors appreciate his conviction.

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Kinder Morgan (KMI) saw $25MM of insider buying, along with $7MM of sales. Rich Kinder is a long-time buyer of his eponymous stock. He alienated an entire class of investors in 2014, when KMI cut the dividend to finance a backlog of growth projects, and simplified their structure in a tax-adverse manner for many. He created a verb — to be “Kindered” is when faithful investors are hit with both the abrupt cancellation of promised distributions and an untimely tax bill (see Kinder Morgan: Still Paying for Broken Promises). But Kinder has bought KMI at regular intervals, including at prices much higher than today’s.

Enterprise Products Partners (EPD) saw $12MM in buying from the Duncan family. And Nustar Energy LP saw almost $5MM in buys. That three of these four are MLPs (as was Kinder Morgan years ago) shows that management teams can accumulate real wealth more easily at the helm of an MLP, with its weak corporate governance, than at a corporation.

Magellan Midstream (MMP) was an outlier among respected companies, in that it had insider sales of just under $1MM.

There was no activity at Macquarie Infrastructure (MIC), perhaps unsurprisingly since they withdrew 2020 guidance and suspended their dividend.

Plains All American (PAGP) saw $4MM of buying even as they cut their distribution by 50%, while still planning to spend half of their previously planned growth capex budget. Many investors would have preferred still less spending and a maintained distribution, but this company has lost 90% of its value since the August 2014 peak. Poor capital allocation has a long history at PAGP.

Most other names saw some insider buying, including several well-run companies. Enbridge (ENB), Cheniere (LNG), Oneok (OKE), Pembina (PPL) and Williams Companies (WMB) fall into this category. This is a very positive step by all these buyers, because the science around viruses is a key factor driving energy demand in the months ahead. Nobody has the information they’d like.

The biggest insider selling was at Targa Resources (TRGP), where Rene Joyce, a member of the Risk Committee, was forced to sell to meet a margin call. TRGP saw no insider buying either. Back in 2014 TRGP briefly touched $140 a share, when ET was rumored to be interested in an acquisition. Joyce’s forced sale at $7 reflects the same judgment that caused TRGP to spurn ET’s approach.

Given the recent leverage-induced catastrophe in MLP closed end funds (see The Virus Infecting MLPs), if Rene Joyce was to move to either Kayne Anderson or Tortoise, it seems likely both his old firm and his new one would improve their risk management.

We are invested in all the names mentioned above.

Coming into 2020 the pipeline sector was in good shape. Spending on growth projects peaked in 2018, and lower growth capex combined with rising cashflow from existing assets were set to drive Free Cash Flow (FCF) higher. Across the companies that are in the American Energy Independence Index it was on course to more than double, from $9BN last year to $21BN this year (see Updating the Coming Pipeline Cash Gusher).

Some companies have been providing updated guidance in recent weeks. The top ten companies represent 60% of the sector by market cap. Four of them have already revised their spending lower for the remainder of the year, with only Enbridge reiterating prior growth project guidance.  We expect the remaining five to revise their numbers in the weeks ahead.

Global crude oil demand is estimated to have fallen by 25% or more in April, and the collapse in crude prices is the dominant energy story. But pipelines carrying natural gas, natural gas liquids and facilities supporting Liquefied Natural Gas (LNG) exports represent 62% of the sector’s market cap, versus just 28% for petroleum products. Natural gas demand has so far shown little coronavirus impact (see Natural Gas Demand Still Stable). Midstream MLPs are more weighted towards crude oil than pipeline corporations, which has hurt recent relative MLP performance (see The Disappearing MLP Buyer).

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Our recently updated FCF blog assumed 2020 growth capex of $37BN. Reductions here will provide a cushion to offset any shortfall in cashflow, since a dollar not spent is a dollar of additional FCF. Four companies on the list (Oneok, Pembina, Williams and Inter Pipeline) have lowered growth spending by $1.4BN, around 23%. Enbridge said on their recent update that they’d raised the return hurdle for new projects. Enterprise Products is likely to lower their spending, last estimated at $3-4BN. Others have yet to provide any new guidance.

It’s also worth noting that first quarter spending was already completed by the time these updates were provided, so the 23% reduction is in practice more like a 31% cut for the remaining nine months of the year. If we assume a 23% cut in the industry’s originally planned $37BN 2020 spending, that’ll free up an additional $8.5BN to support FCF.

We are invested in the names listed above.

Crude oil drew the headlines this week. Trump’s Wednesday tweet forecasting a 10 Million Barrel per Day (MMB/D) agreed supply reduction (“Could be as high as 15 Million Barrels”) caught markets off guard. The demand collapse is astonishing. The world was consuming around 100 MMB/D of crude oil and liquids before the coronavirus. Estimates are for a 20-25% drop in April. Every producer is feeling the financial pain, which ought to concentrate minds as OPEC holds an emergency video meeting on Monday.

Natural gas demand is both more regional and more stable. Some midstream energy infrastructure companies, such as Williams (WMB) and Cheniere (LNG) are entirely natural gas focused, even though their stock prices move with energy sentiment. Crude moves the S&P Energy ETF (XLE), of which they are components, so their stock prices follow.

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U.S. natural gas production is heavily influenced by domestic prices. Although in recent years we’ve become a net exporter, over 90% of output is consumed domestically. Given the collapse in global crude demand, we’re interested in domestic natural gas demand.

The seasons dominate. Winter is the peak period as households and commercial buildings need heat. The power sector uses more in the summer as electricity demand rises for air conditioning. The chart shows the monthly pattern.

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The Energy Information Administration (EIA) releases weekly data, which can provide a clue about how demand is being affected by the shut down’s effect on the economy.

We’ve taken the last two weeks, which cover late March to April 1. Since consumption is typically falling this time of year, a sequential weekly drop is normal. Multiplying by 31/7 to get the monthly rate, those two weeks are running at 2,393 Billion Cubic Feet (BCF) and 2,229 BCF respectively. These two figures sit comfortably between last year’s March total of 2,658 BCF and April’s 1,984 BCF.

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Looking a little more closely, power demand is stronger than a year ago, continuing a trend of natural gas substituting for coal. And lower crude production will also mean less associated natural gas output from areas like the Permian, which will benefit those drillers focused on pure-play natural gas.

There’s no historical precedent for what we’re experiencing, and it wouldn’t be surprising to see natural gas consumption falling even after adjusting for the seasonals. So far, that doesn’t seem to be happening which supports the encouraging updates provided by natural gas oriented pipeline corporations.

We are invested in WMB and LNG.

To the list of previously inconceivable events, add Texas oil drillers asking for their regulator to impose production curbs. Pioneer Natural Resources (PXD) and Parsley Energy (PE) filed a request with the Texas Railroad Commission (RRC) to hold a hearing on the state’s oil and gas production. It’s over 40 years since they last considered such a move.

The U.S. energy industry has been hit with a 1-2-3 punch – coronavirus demand destruction; collapse of OPEC+ limits on output; Saudi Arabia’s launching a price war while increasing exports.

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Senator Ted Cruz (R-TX) described a call between nine U.S. senators and the Saudi ambassador complaining about “economic warfare”. The Saudis blame Russia. “The Saudis are hoping to drive out of business American producers, and in particular shale producers, largely in the Permian Basin in Texas and in North Dakota,” Cruz told CNBC. “That behavior is wrong, and I think it is taking advantage of a country that is a friend.”

The petition to the RRC from PXD and PE included recent presentations from two energy consulting firms that paint a dire picture.

IHS Markit is forecasting a drop in global demand for crude oil of 14.2 Million Barrels per Day (MMB/D), and a 7.2 MMB/D drop for the year. This is far more than the drop during the 2008 financial crisis. The combination of collapsing demand and rising supply is filling up available global storage capacity, which is estimated at 1.3-1.6 billion barrels, assuming the excess oil can be moved there. The 1H20 forecast crude surplus of 1.8 billion barrels will use this all up.

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Producers around the globe are already shutting in production, which can cause permanent damage to a reservoir depending on its structure. Shale oil production is easily curtailed through sharp decline rates by simply reducing the number of new wells drilled and completed. Once producing, a shale well’s operating costs are very low. Lifting costs (meaning the cost to produce after the well has been drilled) are just $3-5 per barrel. So this type of production is unlikely to be shut-in. New wells drilled will drop sharply, causing U.S. shale output to fall mostly through curtailed drilling of new wells and the normal fast decline rates for existing wells. The breakdown of OPEC+ has made many other producing regions in the world unprofitable.  Even Russia may need to start shutting-in production as spot prices drop below $15 a barrel.

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The decision to drill new US shale wells to offset production declines will face a different analysis.  Producers will look towards the forward curve which is currently $11 higher one year out than spot prices, to lock in hedges for wells they expect to exceed their breakeven return threshold.  This slide from BTU Analytics shows that a drop in drilling activity of around 50% (which they estimate would occur with WTI prices in the mid $30s) would stabilize US production around 11 MMB/D.

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Rapidan Energy Group’s forecast is for U.S. oil production to fall by 1.25 MMB/D. The two other forecasts on the chart, from the U.S. Energy Information Administration (EIA) and the International Energy Agency (IEA), were produced only a couple of weeks earlier, showing how rapidly situations are changing. Rapidan is forecasting an even bigger drop in 2Q20 global demand, of 16.4 MMB/D, but with a faster recovery so their 7.1 MMB/D full year demand drop is close to BTU Analytics.

Current prices are ruinous for all producers. President Trump recently said he’d be discussing oil prices with Russia. He told NPR, “”We don’t want to have a dead industry that’s wiped out. It’s bad for them, bad for everybody. This is a fight between Saudi Arabia and Russia having to do with how many barrels to let out. And they both went crazy; they both went crazy.”

The U.S. has limited leverage over Russia. We could curb imports of foreign oil, although that would cause problems for domestic refineries which generally aren’t equipped to handle the light grades produced by shale drillers. The U.S. military’s ongoing defense of Saudi oil infrastructure is gaining attention, and seems absurd when that country’s policies are so damaging to our domestic energy sector. A single presidential tweet on the topic wouldn’t hurt.

Approximately 80% of our investments in midstream energy infrastructure are corporations – we invest in MLPs selectively. There’s a big difference between investing in pipeline corporations with their wide investor base, and MLPs whose pool of natural buyers is withering.

That’s why eight of the ten biggest names in the American Energy Independence Index (AEITR) are corporations. Last week, Bloomberg published Pipeline Funds Imperiled With Even MLPGuy Seeing Their End. MLP-dedicated funds, and more importantly their investors, face some tough decisions in the months ahead.

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MLPs long ago lost the support of their traditional investor: the older, wealthy American willing to accept the tax complexity of a K-1 in exchange for attractive, tax-deferred yields. The Alerian MLP ETF (AMLP) has cut distributions by a third since 2014, reflecting what MLPs have done (see When Will MLPs Recover?). These investors feel betrayed, and they’re not coming back.

The Alerian MLP Infrastructure Index (AMZI), which is what AMLP tries to track, has a float-adjusted market cap of just $61BN. This is too small to justify a sector-based approach, a point made in the past by CBRE’s Hinds Howard (known as @MLPGuy on Twitter). Regulatory limits cap holdings of big MLPs, causing smaller MLPs to be overweighted. The AEITR is 73% companies rated BBB or better, compared with  just  42% in the AMZI.

Publicly traded funds represent an important part of the MLP investor base. At the end of February, Wells Fargo estimated there was $30BN in such funds, of which Closed End Funds (CEFs) represented over 40%. Showing arrogant recklessness, these CEFs entered March with leverage of up to 40%, and in the subsequent forced deleveraging they blew up.

We’ve often warned about this, most recently in November (see Should Closed End Funds Use Leverage?). Their rapid demise contributed significantly to the overall selling of MLPs in mid-March. These portfolio managers owe everyone else an apology (see The Virus Infecting MLPs). It’s been the worst month in memory for pipelines — the AEITR is -40%. But the Kayne Anderson MLP/Midstream Fund (KYN) is down 65% for the month. The Clearbridge Energy MLP Fund (CEM) is -80%. The Tortoise Energy Infrastructure Fund (TYG) is -82%. This group has destroyed most of their client capital. They have no risk management. MLP CEFs no longer exist as a practical matter. They can’t do much more damage.

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Open-ended MLP-dedicated mutual funds such as those run by Steelpath (now owned by Invesco), Center Coast Brookfield and Mainstay Cushing face a choice. The extreme volatility and diminished pool of names make it unlikely they’ll attract many new clients. Like AMLP, their complex, tax-inefficient structure has always been a burden, because they pay corporate taxes on profits (see MLP Funds Made for Uncle Sam). Invesco recently had to spend $400 million correcting mis-stated NAVs dating back to 2015 – evidently the tax treatment even confused the fund’s accountants. Today, all these funds are a long way from having to pay corporate taxes.

It must make sense for them to broaden their mandate to include pipeline corporations, whose market cap is roughly twice as big as MLPs. Doing so will place further downward pressure on MLPs as these funds diversify their holdings.

Tax-exempt U.S. institutions and non-U.S. investors rarely invest in MLPs, because they face onerous tax liabilities if they do. Valuations are so depressed that some may decide it’s worth the trouble. But they’re likely to stick to the big three of Enterprise Products (EPD), Energy Transfer (ET) and Magellan Midstream (MMP).

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The result is that it’s hard to identify much natural demand for MLPs. By contrast, pipeline corporations can be bought by anyone. This absence of investors has led to even the three biggest MLPs performing worse than the three biggest pipeline corporations in the last month. The broader trend for pipeline corporations to outperform MLPs began early last year. The American Energy Independence Index is 80% corporations, and has beaten the Alerian MLP Index by 14% since then.

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Moreover, compared with pipeline corporations, MLPs are (1) more exposed to crude oil with less natural gas, where demand is more stable, (2) more exposed to gathering and processing, which depends heavily on production from the specific areas served, (3) riskier credits, with more BBB- (one notch above junk) and below than corporations, and 4) less protective of investor rights, with poorer corporate governance and in some cases blatant conflicts of interest. In other words, the MLP-dedicated portfolio has more of what’s most vulnerable (see Today’s Pipelines Leave MLPs Behind).

The smaller MLPs are especially short of natural buyers. Years ago when the MLP industry had its own conference, StonMor (STON) was an incongruous participant as an MLP in the “deathcare” business (funeral homes and cemeteries). They had a complex structure even for an MLP, and they were out of place among energy investors. They’re now a corporation, and following various self-inflicted problems in 2016 are trading at roughly 5% of their value from years back. They didn’t fit in anybody’s portfolio.

MLPs unable to interest institutions will similarly struggle to attract natural buyers.

Investors in MLP-dedicated strategies should ask themselves: who are the likely buyers of what they own? For now, everything is so cheap that they could easily bounce. But over the longer run, we think MLP-dedicated funds will wish to diversify, which could mean selling most of their MLPs and buying pipeline corporations. A conversion of one of the big three would probably force the issue.

This will hurt performance, and nobody wants to be invested in the last fund to make that shift. Diversified exposure to midstream energy infrastructure through corporations, with just a handful of big MLPs, offers plenty of upside once we get past the coronavirus. But CEF investors saw their MLP allocations reduced in a fire sale, thanks to incompetent portfolio management. Having incinerated most of their investors’ capital, MLP CEFs won’t be a source of demand going forward. High net worth investors have been abandoning MLPs for years. ESG funds buy the biggest pipeline corporations (see our video ESG Investors Like Pipelines) but not MLPs because of their weak governance.

Open-ended ETFs and mutual funds that are loaded up with MLPs are likely to diversify. So if a portfolio of MLPs no longer makes sense, their only place is as part of a bigger portfolio. And if an investor owns just a few MLPs, she’s likely to focus on the big ones. A portfolio of MLPs has an uncertain future.

Disclosure: SL Advisors manages investment products designed to incorporate the advantages described above.

Yesterday Williams Companies (WMB) provided an investor update on their business. WMB isn’t directly involved in crude oil, and they’re best known for owning Transco, a natural gas pipeline network running down the eastern U.S.

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So far, natural gas demand is un-impacted, and slightly above historical norms.

WMB provided some information on their overall sensitivity to the drop in economic output. Natural Gas Liquids (NGL) prices have collapsed along with crude oil, and this affects 2% of their business on the Gathering and Processing (G&P) side. Somewhat counter-intuitively, natural gas prices have firmed with the drop in crude. This is because Permian oil production results in associated gas, which has weighed on prices in recent months. The looming drop in Permian output will reduce natural gas supply, benefiting natural gas dedicated plays where WMB earns 38% of its EBITDA and 85% of that is associated with gas directed drilling. 7% of their EBITDA comes from oil-driven G&P.

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On the gas transmission side, which includes Transco, they expect no near term impact. Two thirds of their gas transmission customers are utilities and power companies, and 90% are investment grade credit.

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Overall, WMB expects 2020 EBITDA to come in at the low end of their prior guidance, due to weak NGL prices and lower output from oil drilling. They expect cash flow to support their dividend, which currently yields over 12%, as well as any spending on growth projects which they expect to revise down.

We are invested in WMB.

As our response to Coronavirus shifts from purely medical to political, markets have seen a glimmer of light. So far, decisions have been made, whether right or wrong, based on advice from epidemiologists. But as the economic cost has exploded, it’s provoked the obvious question: if the most vulnerable cohorts are identifiable, and the vast majority unlikely to require hospitalization, does everyone need to be at home?

Comparing fatalities with lost jobs seems crass; but something this big is a political issue that considers the overall impact to the country. A study from Oxford University suggested that up to half the UK population may already be infected. This would imply a very low fatality rate and very limited hospitalization, a huge positive if it turns out to be accurate.

When Thomas Friedman of the New York Times and Donald Trump agree that we need some certainty about when restrictions on life will be lifted, you know where the debate is headed. Coronavirus remains most importantly an issue of science, and we won’t offer any amateur views. But decisions are likely to reflect not only medical input from here. Barring a sudden deterioration, we expect governors such as New York’s Andrew Cuomo to soon define a timeframe that will see many people return to work.

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Pipeline investors care about volumes. Weekly data from the Energy Information Administration shows little impact so far on natural gas demand. Residential/Commercial is down – mild winter weather has probably depressed Residential, and Commercial may also be lower. But overall the figures look stable.

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EIA supply figures look similarly stable, although the chart from Criterion Research is a few days more current and shows a sharp drop. Ultimately though, if demand stays flat supply will recover.

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Gasoline demand hadn’t yet dropped, based on this chart through Monday. Drivers filling their tanks in case of distribution problems probably helped, but demand is obviously going to fall with most of us at home.

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Unemployment claims on Thursday will be important. JPMorgan is forecasting a 6X jump from last week, to 1.5 million. The highest forecast is for 4 million. For reference, on October 2, 1982 the figure was 695,000. In the depths of the financial crisis on March 28, 2009, we hit 665,000. So we’re likely to see the biggest figure in history.