The U.S. Borrowing Pandemic

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Ever since the 2008 financial crisis ushered in permanently low interest rates, perhaps the biggest question in finance has been why long term rates remain so low (see Real Returns On Bonds Are Gone). On Monday, the U.S. Treasury announced plans to issue $2.99 trillion in marketable debt this quarter, and $4.5 trillion this fiscal year. The second quarter sum alone is more than double what we borrowed last year.

Given the sharp drop in yields, there’s evidently no shortage of buyers. Corporations have been eager to borrow money too. Apple had $94BN in cash and marketable securities as of the end of March – and yet they borrowed $8.5BN in the bond market on Monday. Liquidity is king. At Saturday’s virtual annual meeting, Warren Buffet mused that the $137BN in cash held by Berkshire, “…isn’t all that huge when you think about worst-case possibilities.”

The most fundamental responsibility of a corporate treasurer is to ensure adequate liquidity for any plausible scenario.

Oneok (OKE) offers an interesting example, because they tapped the bond market for $1.65BN in early March, and just returned for $1.5BN this week. Like most pipeline companies, cuts to spending on new projects exceed their estimated drop in EBITDA. This cash is going to be held, and hopefully not needed. It’ll sit in treasury bills, partially answering the question of who’s going to buy all this new debt the U.S. is issuing.

The negative spread between OKE’s 6.31% blended cost and the 0.10% yield on treasury bills will cost $93MM annually. The $8.5BN Apple raised will also sit in treasury bills alongside the $94BN they already have. These are both small components of the cost of uncertainty.

The Federal government’s fiscal and monetary response has been appropriately massive. They’ve been so effective that Berkshire Hathaway was unable to negotiate any expensive, emergency investments.

The cost is rapidly mounting. Excessive caution was justified in the early days of the pandemic. Hospitals in New York faced the real threat of being overwhelmed, so shutting the economy down to “flatten the curve” was expedient. This has transitioned to a strategy of suppression, with a less clear exit but an increasingly visible and staggeringly big cost.

Fatality rates based on known cases reflect the 2% of the population that’s been tested, and people are often infectious without showing symptoms. Data increasingly shows Coronavirus to be highly contagious but with a fatality rate in the ballpark of the flu for those that are young and otherwise healthy.  For those between 18-49 years of age, the flu has a mortality rate around 0.02%. Coronavirus anti-body tests are revealing substantial portions of the population to have been already infected. New York City estimates a 19.9% citywide rate. Combined with the city’s fatality rate of 161.17 per 100,000 population, this suggests the fatality rate may be close to 0.81%, skewed towards the elderly.

The vulnerable are well known; 96% of New York City patients hospitalized for Coronavirus had additional health issues, often obesity, diabetes or a heart condition. Dr. Scott Gottlieb, a former FDA commissioner regularly on CNBC, said mitigation hasn’t worked, “as well as we expected.” The virus isn’t going away anytime soon.

Suppression can only go so far. We’re going to have to adapt to the virus. The data suggests people under 44 have extremely low risk, but lockdown strategies rarely differentiate based on risk factors. Targeted stay at home orders for older people and those with health vulnerabilities would allow a return to more normal economic activity, arresting the spiraling debt with little increased health risk. We accept 38,000 road fatalities annually, which could be reduced with lower speed limits. Society already makes these tradeoffs.

Few of us are epidemiologists, and deferring to the experts was correct at the outset. But given the huge economic impact and $TNs in Federal spending, we’d all better do our best to become better informed. It’s correctly becoming a political issue.

We are invested in OKE

More Solid Pipeline Results

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Earnings season for big pipeline companies has continued to be encouraging. Enterprise Products (EPD) reported results largely as expected and lowered 2020 growth spending by $1BN. The reductions in capex have been welcomed by investors who have long complained about the level of reinvestment by energy companies. Any reductions in EBITDA have been matched by lower outlays on new projects, which supports free cash flow.

Jim Teague, EPD’s CEO, opened the call by remembering an outbreak of polio as a young boy, “It was a highly contagious virus. It struck without warning…my mom contracted polio…we practiced our own kind of social distancing. What I don’t remember is shutting down the entire economy and 30 million people losing their jobs in one month.”

Teague offered another personal perspective, ”As a young naval officer in an attack helicopter squadron in the Mekong Delta, Vietnam, I took a great deal of pride that I was part of a special fraternity. I have that same kind of pride today.” The wartime analogy strikes a chord with many.

EPD maintained its distribution. When asked about customers claiming force majeure to get out of take-or-pay pipeline contracts, Teague responded, “We’ve looked at all our contracts, and we feel pretty comfortable that we’re not going to have any issue with force majeure as it relates to price.”

Cheniere Energy handily beat expectations with their 1Q20 results. Of more concern to investors is the outlook for Liquified Natural Gas (LNG) shipments, with reports of as many as 20 being delated or cancelled. CEO Jack Fusco addressed this in his opening remarks,”…our long term contracts do not include provisions for renegotiations.” He added, “In instances where that (cancelation) occurs, the fixed liquefaction fee is still paid to us and our marketing affiliate has the option to market the volume into the global marketplace.”

Cheniere continues to expand their export facilities, both at Sabine Pass, LA where they’re adding a sixth train and also at Corpus Christie, TX. They don’t expect coronavirus to harm either the cost or completion schedule of these projects. They reaffirmed previous full year guidance on distributable cash flow and EBITDA.

Magellan Midstream provided some interesting recent volume statistics, in that refined product demand was down 24% in April but “only” 20% in the last week of April. CEO Mike Mears thinks that this category could return to last year’s levels by 3Q20, which most would agree is more positive than consensus.

One analyst asked about interest from private equity firms in acquiring publicly traded MLPs. Mears responded, “We haven’t spent a lot of time talking to private equity firms about acquiring Magellan. That wouldn’t be at the top of our list.”

TC Energy noted that their outlook was largely unchanged with their CEO Russ Girling commenting on their Friday afternoon earnings call that “with approximately 95% of our comparable EBITDA coming from regulated or long-term contracted assets, we are largely insulated from the volatility associated with volume throughput and the commodity prices that are being experienced by many others. Aside from the impact of normal maintenance activities and seasonal factors to date, we have not seen any meaningful change in the utilization of our assets, which further reinforces their critical nature to North America.”

Large midstream companies are generally maintaining dividends and where 2020 results are guided lower, cuts in growth spending more than offset (see Pipeline Payouts Holding Up). In the 2014-16 downturn, MLP distribution cuts were widespread. The payout on the Alerian MLP ETF (AMLP) is the lowest in its history, and 36% below its level of 2016. In a familiar story, 21 MLPs have recently cut distributions. EPD and MMP are an exception to this pattern, which puts them in the company of large pipeline corporations. The components of the broad-based American Energy Independence Index (which is 80% corporations) currently yield 10.5%.

We are invested in all  all the names  mentioned above.

Pipeline Payouts Holding Up

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Most companies get a free pass today on cutting their dividend. So far this month nine S&P500 companies have suspended their dividend, with another half dozen making reductions. Goldman Sachs expects S&P500 dividends to be reduced by 25%.

Energy has been hit as much as any sector. Pipeline stocks have fallen hard, with the broad-based American Energy Independence Index (AEITR) down 36% for the year. It has rebounded strongly in April, up 35% so far this month.

Part of the reason is that the dividend story is turning out to be much less bleak than expected. Most big companies have provided updates, and so far only eight have reduced dividends. Only one of those (Macquarie Infrastructure) has suspended its payout. Using their weighting in the AEITR, 20% of the index has lowered dividends.

A pleasant surprise is that 13 companies still pay dividends that are higher than a year ago, representing 64% of the index. This group includes some big names, such as Enbridge, Kinder Morgan (KMI) and Williams Companies (WMB). Some of these have yet to declare a “post-Coronavirus collapse” dividend, but we think those planning to cut have already communicated. KMI had originally planned to increase their dividend by 25%. The fact that they raised it at all last week was welcome news to many investors. The week before, WMB had said they expected to fund this year’s dividend payments and growth spending from internally generated cash.

Most energy infrastructure companies providing updates have reaffirmed prior guidance or lowered it modestly. All have lowered their planned spending on growth projects, and generally the spending reductions are bigger than any forecast drop in EBITDA. Although the rest of the year is too uncertain to make any confident forecasts, a dollar not spent is a dollar of Free Cash Flow (FCF). Prior to coronavirus, we were looking for FCF to double this year (see Updating the Coming Pipeline Cash Gusher) . Lower spending was a key reason, and 20% cuts are common.

Dividend hikes in this environment are surprising. We’re all enduring a crash course in epidemiology, but it’s fair to say that the companies maintaining and raising their dividends are comfortable that these are sustainable based on consensus forecasts of the economic rebound from the Coronavirus. The yield on the AEITR is 10%.

MLPs are only about a third of the pipeline sector. Only two of the ten biggest companies are MLPs —  Energy Transfer and Enterprise Products. Magellan Midstream is another well-run MLP that’s just outside the top ten. But the rest tend to be smaller and more oil focused, with weaker balance sheets and more gathering and processing exposure. This is why 17 MLPs had cut distributions as of last Friday, according to Hinds Howard at CBRE Clarion Securities. Yesterday on Twitter he noted the figure had reached 21.

The bottom line is that the dividend outlook so far is surprisingly positive for midstream energy infrastructure. However, for investors in MLP-dedicated funds or with portfolios heavily weighted towards MLPs, the news hasn’t been as good.

We are invested in all the names mentioned above.

Can An ETF Go Negative?

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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.

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.

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.

Energy Does More Than Move People

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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.

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.

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

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.

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.

We are invested in all of the companies mentioned above.

Texas Ponders Oil Cuts

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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.

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.

What Do They Know That We Don’t?

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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.

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.

Pipeline Companies Trim New Projects

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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).

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.

Natural Gas Demand Still Stable

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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.

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.

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.

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.

Navigating the Collapsing Oil Market

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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.

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.

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.

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.

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.

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