The Federal Energy Regulatory Commission (FERC) became MLP investors’ new BFF last week. Only four months ago, FERC’s revised policy on allowing imputed tax expense in setting tariffs caused a memorable intra-day 10% drop and contributed to dismal 1Q performance (see FERC Ruling Pushes Pipelines Out of MLPs). Ever since, MLP investors have regarded FERC warily, sensitive to additional market shocks. Cost-of-service pipeline contracts, historically common but rare nowadays and the source of much of this volatility, are unlikely to be employed in the future.

The clarification issued last week was unambiguously, if modestly, good. MLPs are still not allowed to include taxes paid by their equity investors as an operating cost in calculating applicable rates on interstate natural gas pipelines. But they can now include taxes paid by a corporate parent (if they have one), a feature omitted from the March announcement. Moreover, Accumulated Deferred Income Tax (ADIT), which most natural gas pipeline MLPs had built up, will no longer have to be refunded to customers. This had been recorded as an income tax liability using accelerated depreciation, offset by cash received from customers on cost-of-service contracts that relied on straight-line depreciation.

Depending on timing, some firms had accrued a significant net cash benefit and faced the prospect of returning this excess to customers. One research firm estimated the sums involved in the $BNs, in effect a retroactive fee adjustment. This possibility has now been eliminated.

By excluding ADIT, pipelines will show more equity invested which will in turn lower their Return on Equity (ROE). Typically, a pipeline tariff is deemed “fair and reasonable” if it generates a 10-16% ROE.  The net result will be that some contracts will fall below the threshold, reducing the likelihood of lower rates and even opening the door to bigger rate increases.

Since 2014 when Kinder Morgan (KMI) led the way, large MLPs have been converting to corporations in order to access a broader set of equity investors (see Corporations Lead the Way to American Energy Independence). More recently, Enbridge (ENB) and Williams Companies (WMB) both announced plans to roll up their MLP affiliates. TransCanada (TRP) told investors that financing assets at their MLP, TC Pipelines (TCP), was no longer viable.

Uncertainty around future FERC policy guidance tipped the scales for these conversions. But many other incentives to abandon the MLP structure and become a corporation remain. These include: onerous profit sharing with the GP (known as high IDR splits) which makes raising equity capital more expensive; potential tax shields at a corporate parent, reducing the tax advantage of being an MLP; the small investor base for MLPs (buyers are mostly old, rich American taxpayers); limited opportunities to drop down assets from parent; unfavorable rating agency treatment of debt due to the complexity of structure; and poor corporate governance rights.

Investors in Boardwalk Partners (BWP) probably received the worst FERC-induced outcome. The March policy statement depressed BWP’s stock price, letting Loews (the General Partner or GP) trigger an obscure clause in their Limited Partnership Agreement. This allowed them to  buy-in all the outstanding BWP units at their recent average price ($12.06), close to its all-time low. Only five years ago BWP was trading over $30. The Loews buy-in relied on a legal opinion that March’s announcement was an adverse regulatory ruling harmful to their business. The buy-in transaction duly closed last week, conveniently just before FERC’s revised policy guidance which would likely have nullified the legal opinion on which the buy-in relied. This is an example of the weak governance to which MLP investors subject themselves when there’s a controlling GP. Former BWP holders will join the growing list of MLP critics.

Investors welcomed the bounce. FERC solidified its reputation for unpredictable rulings that roil the market. But for CFOs trying to optimize their financial structure, their regulator’s market moving pronouncements aren’t helpful. The 202-page policy notice was accompanied by a concurring statement (rather like a dissenting opinion in a Supreme Court ruling) from the two Democrat commissioners. They noted that, “today’s order is simply guidance” and that individual rate cases would be judged on their legal merits.

Although the economics for MLP-owned natural gas pipelines are better than before, it’s unlikely that any MLP that’s converted to a corporation is regretting it. WMB will have to re-examine its previously announced roll-up of WPZ, but will also have to consider a somewhat capricious regulator whose direction may change again following the next general election in 2020.

East Daley released analysis showing that Williams Partners (WPZ) might be better off remaining separate from its corporate parent, WMB. They showed the treatment of TransCo’s pipeline network (WPZ’s principal asset) before and after the policy update, with an almost 5% swing in calculated ROE. The new, lower return supports the case for higher tariffs, which is why MLPs rose.

Interestingly, although Thursday was a good day for the sector, the Alerian MLP ETF (AMLP), which is 100% MLPs, saw net redemptions of $100MM. The FERC news raised prices but didn’t induce new buying. A week of arcane accounting developments (ADIT) and obscure adverse legal clauses (BWP) showed that MLPs are complicated.

In other news, KMI’s 2Q earnings were modestly better than expected. Of note was a 12% increase in volumes of natural gas, reflecting growing U.S. production. It also looks likely that the $2BN proceeds of their sale of the TransMountain pipeline to Canada’s Federal government will be used to pay down debt. Like most midstream energy infrastructure businesses, KMI is far more stable than their stock price would imply. Its Distributable Cash Flow (DCF) is on target to reach $4.6BN this year, up 3%. Since 2014, its worst result has been a 4% decrease.

Nonetheless, KMI’s stock has taken investors on a wild ride. In spite of their steady DCF, in late 2015 they slashed their quarterly dividend by 75% from $0.50 to $0.125, so as to redirect cash towards growth projects and pay down debt. It was a move that many others followed. Today, its payout is at $0.20 and is 2.4X covered by DCF. Decisions on how to finance their business were far more impactful than operating performance, which is why it sports an 11.5% DCF yield, awaiting buyers from more expensive sectors.

In many ways KMI is reflective of the sector.

We are invested in ENB, KMI, TRP and WMB. We are short AMLP.

In recent years as MLP investors balked at providing the growth capital sought by midstream energy infrastructure, the biggest companies have been converting to corporations (see MLPs Searching for a New Look). The collapse in MLPs during 2014-15 slowed investment, subsequently causing many of the biggest companies to simplify as they concluded that the MLP investor base was too narrow. This shift away from MLP buyers (mostly older, wealthy Americans) to the global equity investor is evidently working, at least based on one trade group’s forecast of new investment. The Interstate Natural Gas Association of America (INGAA, not limited to natural gas in spite of their name) lobbies for industry-friendly policies and produces long term forecasts of midstream infrastructure investment in the energy sector. They see a bright future for North America.

Given the renewed focus in recent years on prudent distribution coverage with lower leverage, it’s striking that 2019 is likely to be a record year for investment in new capacity. Following two years of decline as companies grappled with income-seeking investors unwilling to finance growth, in 2017 capex rebounded. The recovery has continued strongly, driven in large part by increasing export capacity for crude oil, Natural Gas Liquids (NGLs) and natural gas. The path to American Energy Independence is paved by such investments.

It’s interesting to compare INGAA’s current forecast with their prior one, which we covered two years ago (see There’s More to Pipelines Than Oil). INGAA has modified their format and their forecast period covers a slightly shorter time period. But after adjusting for differences, we find INGAA’s latest projection to be 39% higher than their 2016 Upside Case, at $44BN of annual investment.

It’s a remarkable statement about the resilience of the Shale Revolution and how America’s Energy Renaissance is evolving. INGAA’s prior report reflected the still raw memories of the 2014-15 energy recession, when questions lingered about the sustainability of the new, unconventional production.

Today, with production of crude, natural gas and NGLs all hitting records, there can be little doubt that the industry has shifted to an era of long term growth.

Natural gas continues to command over 50% of new investment. Although movements in crude oil pricing continue to drive short-term sector returns, natural gas remains the more important commodity. Exports, by pipeline to Mexico, and as Liquified Natural Gas (LNG) globally, are both set to rise sharply in the years ahead. Net U.S. LNG exports in 2035 are forecast to reach 12 Billion Cubic feet per Day (BCF/D), from around 1.3 BCF/D currently. Overall, North American natural gas output should rise 2% annually, from 91 BCF/D to 130 BCF/D. Natural gas use in the power sector is also expected to show healthy growth, both as coal-fired plants are retired and as a backup for renewables. We’ve long asserted that natural gas is critical to increased use of renewables, to provide baseload power for when it’s not sunny and windy.

NGLs receive far less attention than crude oil or natural gas, but ethane and propane are key feedstocks for ethylene and polypropylene (different types of plastics) respectively. U.S. NGL production is expected to double by 2035, to 6.6 MMB/D, with exports also doubling to 2 MMB/D.

Although the U.S. is already energy independent, in that we produce more total energy on a BTU-equivalent basis than we consume, the popular measure relates to crude oil independence. Industry forecasts of the date when the U.S. reaches that milestone generally fall between 2025 and 2030. Because crude oil comes in hundreds of grades, we’ll continue to import the heavy crude favored by U.S. refineries even while net exports triple, from 0.5 MMB/d to 1.5 MMB/D. Another favorable development will be a halving of non-Canadian imports, further lessening our dependency on unstable regions and unfriendly governments. More than 100% of the growth in U.S. crude production is expected to come from the Permian, Niobrara and Bakken formations.

Given this outlook, it’s clear why many large MLPs have converted to corporations. They need a financial structure that will support growth plans. Investment bankers will find much in INGAA’s report to get them excited, since capex implies ongoing debt and equity issuance. For investors though, the new projects will need to generate a return above their cost of capital. That’s what will determine whether INGAA’s report is truly exciting.

Last week the corporate-heavy American Energy Independence Index added another 1% to its outperformance of the MLP-only Alerian MLP Index, reaching a 9% difference since the March FERC decision cast doubt on the MLP structure for certain companies.

A few months ago the NYTimes ran an interesting piece on the difference between intra-day and overnight returns on the stock market. The article compared a strategy of buying on the open and selling every day at the close (“IntraDay”), with a strategy of buying on the close and selling the next morning at the open (“Overnight”). Using the S&P500 ETF (SPY), they found that the returns to the Overnight strategy easily beat the IntraDay one.

We looked at the figures ourselves using SPY back to 1993, and while we came up with different numbers the pattern is clear. The NYTimes piece omitted dividends, which would always accrue to the Overnight Strategy and not to IntraDay, since you have to own a security at the close of business on the record date to earn the dividend. So in this case and the one below, Overnight returns will be even better by the amount of the annual dividend.

The stock market is full of patterns, and identifying a profitable one takes far more than simply discovering one that’s worked in the past. For instance, the relative advantage of Overnight over IntraDay on SPY has declined over the years, probably because the hedge funds who look for these things long ago found it and started exploiting it. The best results came in the years either side of the dot.com bubble (1998-2002). Since the IntraDay strategy is by definition a day trade, the persistent success of Overnight versus IntraDay back then is probably a tangible measure of day traders gradually ceding their capital to more sophisticated participants.

It’s also important to identify a reason for any anomaly. A series of rainy Sundays tells you nothing about next weekend’s weather (correlation versus causality). There needs to exist some economic reason for the anomaly for it to continue. Is there a reason to expect persistence in the Overnight versus IntraDay phenomenon, even though the margin has diminished? The NYTimes article speculates that buying in the morning offers traders some ability to respond to adversity during the day, and that closing out a long position in the afternoon protects against an inability to immediately react to an overnight event causing losses. Since humans continue to be the ultimate investment decision makers, this is a plausible explanation.

Because MLPs are more retail-dominated than the broader stock market, human foibles are more likely to show up there. The data doesn’t go back as far as SPY, but we looked at Overnight versus IntraDay using AMLP, which launched in 2010. The superiority of Overnight is far more significant than with SPY. Although AMLP has lost 29% of its value before distributions since 2010, the Overnight strategy grew by almost 150% while IntraDay lost 70% of its value. It looks as if MLP investors bounce out of bed full of optimism, only to have those positive feelings ground down by a sector that has regularly spent the trading day selling off from the open.

This means that if you’re considering investing in the sector, you may want to wait until the afternoon. Buyers tend to execute their intentions early. For this group, caffeine-fuelled exuberance gradually gives way to low blood-sugar despondency. After lunch, your buy order will face less competition. In energy infrastructure, it seems, your money really does work harder for you at night.

Put another way, a strategy of shorting AMLP intra-day would have generated a positive return of 150% before transactions costs over the past seven years. Unfortunately, transactions costs of even 0.025% per trade (i.e. 0.05% daily) wipe out the profit. AMLP remains a good short (see MLP Funds Made for Uncle Sam) because of its structural deficiencies, but bad as they are they’re not sufficiently catastrophic to support a day-trading, active shorting strategy.

We are short AMLP

A friend of mine recently returned from a trip to Texas and Louisiana, where he met with many contacts and friends in the energy infrastructure sector. In-person discussions and site visits can often leave a more powerful impression than reviewing events from a distance. My friend, an experienced investor, returned with his already optimistic view on the Shale Revolution strongly reaffirmed.

Some of the charts below illustrate why. Permian region oil output barely dipped in 2014-15 during the collapse in crude pricing. The widely described drilling efficiencies lowered break-evens (see America’s Path To Energy Independence: The Shale Revolution), and as the oil price recovered, so did production.

Today, Permian output is visually quite striking, rising at an increasing rate. This higher growth rate is what’s causing the infrastructure bottlenecks. Year-on-year increases of 0.8 Million Barrels per Day (MMB/D) were not obvious based on recent history and clearly few were ready. This is why the WTI basis between Midland, a collection hub for Permian crude, and Houston, recently reached $20 per barrel. There’s insufficient pipeline capacity to move the crude (pipeline tariffs are typically $1-$3 per barrel).

Clearly, even crude by rail (typically $7-$10 per barrel) can’t solve the problem, since the basis trades even wider than this, at the $20 cost of moving the marginal barrel. Trucks and truckers ($10-$20 per barrel or more) are in high demand, and because new pipelines are likely to be available late next year, large investments in truck fleets look unattractive given that the problem is temporary. Fortune Magazine’s Lone Star Rising provides a great feel for the local effects of the current oil boom.

Moving the associated natural gas that is often produced with crude oil in the Permian is also hitting infrastructure limitations. In fact, it’s likely that any moderation in crude output will be caused by waiting for the infrastructure to catch up. Permian natural gas is delivered to the Waha hub, and its basis versus the Henry Hub benchmark looks set to widen from $1 per Million Cubic Feet (MMCF) to $2. With natural gas trading at under $3, it’s not inconceivable that there may be no bid at Waha, a possibility mentioned more than once by energy executives at the Orlando MLP conference recently. Oil producers are hoping that regulators in Texas will allow more flaring of natural gas in the interim.

As a result, the U.S. has some of the cheapest natural gas in the world. Exports of Liquified Natural Gas (LNG) are currently 3.6 Billion Cubic Feet per Day (BCF/D). The U.S. Energy Information Administration expects LNG exports will rise sharply to 9.6 BCF/D by the end of 2019, reaching 13 BCF/D by mid-decade. The growing global trade is causing a shortage of specialized LNG tankers.

Although the Shale Revolution is a U.S. phenomenon, its impact is being felt around the world. Global crude oil demand of around 98 MMB/D is growing at 1.5 MMB/D annually. Less attention is given to depletion of existing oil fields, which is commonly estimated at 3-4%, or 3-4MMB/D. New supply needs to cover this shortfall as well as meet new demand, which means the world needs 4.5-5.5 MMB/D of additional output every year.

Wood Mackenzie recently forecast that decline rates would reach 6.3% for non-OPEC, non-U.S. shale, within three years. They expect U.S. production growth to be triple that of the next biggest country between now and 2025. However, even the most optimistic forecasts of U.S. output leave the world in need of other, conventional sources of supply to balance the market.

Global oil demand is expected to grow for at least the next couple of decades, albeit it at a slower rate, and it’s widely assumed that Electric Vehicles (EVs) will reduce overall demand. Forecasts from the EIA, the International Energy Agency, Exxon Mobil and Wood Mackenzie are all broadly similar in this regard.

An unusual view, but one persuasively made by my partner Henry Hoffman, is that EVs are a huge positive for the U.S. shale business – and not simply because their need for electricity will drive demand for natural gas. Since conventional oil projects take many years to return capital invested (they are “long-cycle”), their investment decisions needs to consider the evolution of EVs and how they might impact long term oil demand and pricing.

EV adoption rates are uncertain, and conventional oil projects are exposed to an EV upside case which will, in some instances, make pursuing them too risky. Shale producers need give little consideration to EVs, because the short-cycle nature of their pay-off is well short of the timeframe over which EVs may have an impact. Because shale wells return cash invested typically within a couple of years, production can be hedged in the futures market. Such wells have very sharp decline rates, so oil demand even five years in the future is barely relevant to today’s investment decision.

Uncertainty about the rate of improvement in EV technology clearly hinders 10-20 year oil investments, which plays to the advantage of the U.S. shale producer. This is not a view that’s widely held, yet it’s probably already having an effect (see Why Shale Upends Conventional Thinking). It strikes me as a really big idea, one that is likely to depress conventional exploration for many years, keeping crude prices higher and underpinning continued growth in U.S. shale. It was almost certainly a factor in Exxon Mobil’s (XOM) announcement earlier this year of a five year, $50BN investment in North American oil and gas production (see The Positives Behind Exxon Mobil’s Earnings). The entry of the biggest integrated oil companies into shale will lead to more predictable output since they won’t be as reliant on external financing. It also validates shale as a long term story.

Betting on higher crude has been a losing trade for hedge funds until recently (see WSJ: As Oil Soars, Few Hedge Funds Are Left to Profit), reflecting conventional wisdom that shale supply will act to rein in higher prices. By contrast, we think crude prices will trend higher over the medium term because of underinvestment in conventional supply. Shale investors should regard growing EV adoption as fundamentally supportive.

For more on America’s Energy Renaissance : The Shale Revolution, watch Simon Lack, Managing Partner of SL Advisors, discuss why he believes the Shale Revolution is the most fantastic American success story.

 

 

This year’s MLPA conference at the Hyatt Regency Orlando reflected the sector’s current transition. It was rebranded from years past to be the MLP & Energy Infrastructure Conference (MEIC), now open to energy infrastructure corporations as well as MLPs. Revealingly, this inevitable recognition of the continuing shift of MLPs to a corporate structure was not embraced by former MLPs. Kinder Morgan (KMI), Oneok Inc (OKE) and Williams Companies (WMB) all declined to participate.

Since almost no corporations showed up, it was an MLP conference after all, albeit with fewer companies and what seemed like a smaller crowd. The conference took place in a more modest set of ballrooms at the Hyatt while another, unrelated event occupied the larger space. The managers of MLP-dedicated, tax-burdened funds (see AMLP’s Tax Bondage) are alone in their unequivocal support of MLPs as the best way to invest in energy infrastructure. The diminished conference must have been a sobering assault on their conviction.

Clearly, energy infrastructure corporations see no value in being associated with MLPs. Moreover, in the smaller group meetings of a half dozen or so investors with management teams, most MLPs were left defending their decision to persist with the MLP structure. “When will you convert to a corporation?”, known as the Simplification Question, came up in every single meeting we attended, even when the company was doing very well (such as Crestwood, CEQP). One management team had an internal over/under bet on how many times they’d be asked all day – trading was at 75.

The industry’s shift to a growth model has already alienated their traditional, income seeking investor base by resulting in widespread distribution cuts to pay for new projects (see Will MLP Distribution Cuts Pay Off?). This is a self-inflicted wound, but the March FERC (Federal Energy Regulatory Commission) Policy Statement may turn out to be nearly as ruinous (see FERC Ruling Pushes Pipelines Out of MLPs). A panel of lawyers discussed the thinking behind the change, which was cited by both WMB and Enbridge (ENB) last week as they rolled up their MLPs into the corporate parent (see Transco Dumps its MLP). Attendees overflowed from the cozy ballroom.

It seems highly likely that FERC  gave only brief consideration to the impact of disallowing income tax expense from cost-of-service natural gas pipeline contracts. The idea that an MLP could expense taxes paid by its equity holders in calculating rates strikes some as odd, but it had been accepted practice for many years. Following a successful court challenge in 2016, FERC waited almost two years to implement the regulatory change required by the judge’s ruling. FERC’s ponderous approach, as well as subsequent questions over precise implementation details, provided further impetus to abandon the uncertainty of the MLP structure. Corporate-owned pipelines are not similarly affected, and so represent a more predictable form of ownership.

One odd twist is that although disallowing an expense ought to benefit the customer, by rolling up into a corporate parent an MLP’s assets are revalued from historic cost to market values. This could ultimately lead to higher tariffs, since cost of service must include an appropriate return on a now more highly valued asset. The lawyers on the panel were unwilling to criticize FERC, since they often represent clients appealing the regulator’s decisions. Among attendees, there was widespread consensus that FERC had screwed up. However, the panel held out little hope of a policy change unless ordered by a Federal court.

Meetings with management teams weren’t only about changing structure. Fundamentals are very strong across the U.S. energy industry, and business is booming for midstream infrastructure. Pursuit of growth projects, while maintaining healthy distribution coverage and reducing leverage, was the theme. The Shale Revolution has long been a volume success, but it’s finally translating into a financial success as well. Investors have had a long wait.

Although the Permian is producing record amounts of crude oil, one CEO said he thought associated natural gas output could reach 30 Billion Cubic Feet per Day (BCF/D), versus 8-9 BCF/D currently. He felt inadequate take-away infrastructure would consequently drive the price at the local Waha hub to $1 per Million Cubic Feet. American natural gas is likely to remain among the world’s cheapest.

Water disposal came up in some discussions, and with volumes of produced water (i.e. water that comes out of the ground with the oil) in the Permian running at 4X the amount of crude output, treatment and disposal is providing additional infrastructure opportunities. Several firms were considering investments in this area.

Plains All American (PAGP/PAA) management was surprisingly defensive when asked about their simplification plans. They feigned surprise at the question (perhaps out of boredom) and suggested to one investor that perhaps he didn’t fully understand their structure. What’s really hard to understand is how the biggest crude oil pipeline operator in the Permian isn’t generating better results when record oil production is exceeding take-away pipeline capacity.

This has caused the Midland-Cushing differential to widen to $15 per barrel recently, far above the $2-3 pipeline tariff between the two hubs (see Dwindling Pipeline Capacity Causes FOMO). It should be a huge win for PAGP, whose investors holds the stock for precisely this scenario. But earlier 2016-17 mis-steps in Supply and Logistics caused PAGP to hedge 2018 basis risk far more conservatively, largely missing out on today’s excess demand for pipeline capacity. At still approximately 60% below their 2013 IPO price, PAGP’s stock reflects the need for better execution by management.

CEQP continues to execute well and met with many happy investors given the stock’s climb over the past couple of years. Meetings with Enterprise Products Partners (EPD) and Magellan Midstream Partners (MMP) were typically reassuring. Neither sees the need to convert from their MLP structure.

Enlink (ENLC/ENLK) Chairman Barry Davis described how they were emulating parent company Devon Energy’s (DVN) investment in IT to manage their operations. DVN has a single Data Control Center that remotely monitors all their activities. ENLC has created a task force to find similar opportunities to automate.

“Refracs” (when today’s new technology is applied to a previously fracked well) are delivering some impressive results for DVN in the Barnett shale for around $600K per well. But as in the past, ENLC will benefit as DVN sheds those assets in a region that they don’t deem strategic, to others willing to invest the time and capital. Nonetheless, a play believed to be in decline continues to maintain flat production.

Cheniere (LNG) explained how, in signing up customers for their next export facility, they can guarantee capacity from Sabine Pass as a stop-gap. Producers are sometimes unwilling to make a binding commitment to use new infrastructure when they’re unsure it’ll get built. LNG’s early-mover advantage allows them to guarantee capacity on Train 3 to producers who sign up for yet-to-be-built Train 6, which makes it easier to get customer commitments.

The industry’s fundamentals are good but complaints were heard that questions of structure continue to dominate. Many feel the MLP-only indices are losing relevance, and unanswered questions linger over the future of MLP-dedicated funds such as the Alerian MLP ETF (AMLP) and many mutual funds, since they face a shrinking number of MLPs to hold (see The Alerian Problem).

Next year REITs will apparently be added to the conference, which is relocating to Las Vegas. The conference organizers grasp the need for a broader approach.

We are long CEQP, ENB, ENLC, KMI, LNG, PAGP and WMB. We are short AMLP.