Too few writers covering energy infrastructure admit to the many distribution cuts inflicted on MLP holders. Instead, they identify numerous other problems whose resolution will draw in buyers. Incentive Distribution Rights (IDRs), the payments made by MLPs to their General Partners (GP), have drawn scorn for the past couple of years. Eliminating them is fashionable and now virtually complete, with only a handful of holdouts. Other solutions include self-funding growth projects. Common practice was for MLPs to pay out most of their cash and raise equity for new projects. It worked until the new projects became big. The Shale Revolution was responsible for that. Selling non-core assets is another piece of advice – it’s rarely controversial. Few companies admit that any assets are non-core, until selling them.

All this free advice is directed both publicly and privately to help draw in new investors and lift stock prices. What’s rarely mentioned are the widespread and substantial cuts in distributions that have alienated the income-seeking MLP investor base. Alerian has a chart showing “AMZ Normalized Distributions Paid”, which shows a cumulative 25% cut 2015-17, if you do the math. Dividends on AMLP are down 34% from their high in 2014, although you won’t find this on their website. Promises have been broken, and the buyers know this.

One reason others don’t dwell too much on this issue is that many distribution cuts have been via mergers and simplifications. When a lower yielding GP acquires its MLP, the MLP investors are subjected to a “backdoor” distribution cut through owning a new security with a lower yield than the one they gave up.

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Energy Transfer has excelled at imposing such “stealth distribution cuts”. Over the past four years they’ve rolled four publicly traded entities into one. In each case, the lower-yielding entity acquired the higher-yielding one, resulting in a lower distribution for investors in the acquiree.

What’s striking is to overlay the normalized distribution history of the four entities: Energy Transfer Equity (ETE), Energy Transfer Partners (ETP), Sunoco Logistics (SXL) and Regency Partners (RGP). ETE is the surviving entity, now renamed Energy Transfer (ET).

ETE investors have seen a five-fold increase in distributions since 2006, a 13% compounded annual growth rate. They’ve increased distributions every year.  That shouldn’t be surprising, because ETE was always the vehicle of choice for CEO Kelcy Warren and the management team. SXL holders had a good run – in 2016 they folded in higher-yielding ETP but retained the ETP name, which gave them a 14% distribution growth rate to that point. But then they were “Kelcy’d”, as ETP adopted ETE’s lower payout in a subsequent combination, leading to a 31% effective cut. Original investors in ETP and RGP did worse.

ET’s price peaked in 2015 (it was ETE back then), when Kelcy embarked on his ultimately unsuccessful attempt to buy Williams Companies (WMB). It’s a measure of how far sentiment has fallen, in that ETE’s yield briefly dipped below 3% in May 2015. Since then, its distribution has risen from $1.02 to $1.22. They dodged the WMB deal, have reduced leverage, completed the Dakota Access Pipeline and expect to cover their distribution by 1.7-1.9X next year. Nonetheless, today ET yields 8.5%, with an estimated 2019 Distributable Cash Flow yield of 15.9%. No wonder Kelcy Warren is back in buying the stock.

It’s true that ET’s management has earned a reputation for self-dealing. During the protracted WMB merger negotiations , ETE issued very attractive convertible preferred securities to the senior executives, but didn’t make them available to other ETE investors (see Will Energy Transfer Act with Integrity?). Although they won the resulting class action lawsuit, it’s clear that if management can get away with something that benefits them but not shareholders, they will. Even so, the current valuation seems excessively pessimistic.

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Kinder Morgan (KMI) and Plains All American (PAGP) drew unwelcome attention for each delivering two distribution cuts to their investors. KMI’s first cut was through combining with their MLP in the technique later used by ETE. They followed this up with a second, unambiguous cut in response to rating agency concerns over leverage.  PAGP’s management administered two direct cuts, stunning investors both times. Oneok (OKE), Targa (TRGP), Semgroup (SEMG), and Enlink (ENLC) all folded in their respective MLPs, delivering backdoor distribution cuts to their MLP holders but maintaining their dividends at the GP level.  But many others avoided cutting their dividends at all.  Antero Midstream (AMGP), Tallgrass (TGE) and Western Gas (WGP) all rolled up their MLPs with no change in payouts.

None of the Canadian midstream companies cut their dividends, reflecting their more conservative approach. This highlights that the distribution cuts were due to the flawed MLP practice of paying out virtually all available cash flow, relying on tapping the capital markets for growth projects. There were a few exceptions, but in general MLP distribution cuts were not due to deteriorating fundamentals in the midstream sector.

MLPs are still cutting payouts. Distributions on AMLP, which is MLP-only and tracks the Alerian MLP Infrastructure Index, are down 6.9% this year. By contrast, distributions on the American Energy Independence Index, which includes the biggest North American pipeline corporations and MLPs and is therefore more representative of the overall sector, are up 6.6%.

We are invested in AMGP, ENLC, ET, KMI, OKE, PAGP, SEMG, TGE, TRGP, WGP and WMB. We are short AMLP.

SL Advisors is the sub-advisor to the Catalyst MLP & Infrastructure Fund.  To learn more about the Fund,  please click here.

SL Advisors is also the advisor to an ETF (USAIETF.com).

If pipeline stocks moved with natural gas rather than crude oil, their long-suffering investors could look back on a good week. On Tuesday crude was down $5 per barrel for the week, before recovering $2 by Friday. It’s tumbled $20 since early October, bringing Brent Jan ’19 to $66. By contrast, the Jan ’19 natural gas contract stormed out of its $2.90 to $3.50 per Thousand Cubic Feet (MCF) range that has constrained it all year, almost reaching $5 on Wednesday. Rarely have oil and gas been so disconnected.

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The energy sector moves to the rhythm of crude. It’s is a global commodity, relatively easy to transport, which allows regional price discrepancies to be arbitraged away. Oil can move by ship, pipeline, rail or truck. Transportation costs vary from a few dollars per barrel for pipeline tariffs or waterborne vessel to $20 or more by truck. Although Canada’s dysfunctional approach to oil pipelines has led to deeply depressed prices, in most cases transport costs are a portion of the cost of a barrel.

By contrast, natural gas (specifically methane, which is used by power plants and for residential heating and cooking) generally only moves through pipelines or on specially designed LNG tankers in near-liquid form. Long-distance truck transportation isn’t common because liquefying methane to 1/600^th of its gaseous volume requires thick-walled steel tanks. Methane moved as Compressed Natural Gas (CNG) is only 1% of its normal volume (i.e. requires 6X more storage volume than LNG) which generally renders long-haul truck transport uneconomic. LNG shipping rates from the U.S. to Asia are $5 or more per MCF, more than the commodity itself. The 10-15,000 mile sea journey is worth it because prices in Asia are $8-15 per MCF, compared with normally around $3 per MCF in the U.S.

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The result is that natural gas prices vary by region far more than crude oil.

There are price discrepancies within the U.S. too. The benchmark for U.S. natural gas futures is at the Henry Hub, located in Erath, LA. This is where buyers of $5 per MCF January natural gas can expect to take delivery. By contrast, 700 miles west in the West Texas Permian basin, natural gas is flared because there isn’t the infrastructure to capture it. Gas is flared because it’s worthless. Mexican demand is coming, but construction south of the border is running more slowly than expected.

The price dislocation in U.S. natural gas highlights the ongoing need for additional pipeline and storage infrastructure. Price differences in excess of the cost of pipeline transport translate into pipeline demand. Although the spike in Jan ’19 natural gas futures reflects a temporary supply shortage that can’t be alleviated by a new pipeline given multi-year construction times, such events are generally good for  midstream energy infrastructure businesses.

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The oil price dislocation was at least partly due to hedging of option exposure by Wall Street banks that had sold put options to producers, such as Mexico. It has very little to do with midstream infrastructure. Having fretted for months over U.S.-imposed sanctions on Iran, the market was surprised by waivers that are softening the blow for Iran’s oil customers. It’s likely to create a reaction (see Crude’s Drop Makes Higher Prices Likely).

Long term forecasts of natural gas demand are less varied than for crude oil, and are driven by Asian consumption at the expense of coal for electricity production.  Crude oil demand forecasts vary more, generally because of differing expectations for electric vehicle sales. Although both are growing, a bet on natural gas looks the safer of the two.

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Nonetheless, crude oil moves the energy sector and U.S. pipeline stocks tag along. On Tuesday when crude oil was -6.6%, the S&P Energy ETF (XLE) and Williams Companies (WMB) both slid 2.3%. Jan ’19 natural gas was +9.1%. WMB derives virtually all its value from transporting and processing natural gas and natural gas liquids. Its inclusion in XLE probably causes it to move with the sector more than its business would suggest.

3Q18 earnings for pipeline companies have been largely equal to or better than expectations. The fundamentals remain strong – investors continue to ask when sector performance will reflect this. Although the recently declared dividend on the Alerian MLP ETF (AMLP) is 34% below its 2014 level, we expect corporations will start increasing dividends, with the American Energy Independence Index likely to experience 10% growth in 2019.

We are long WMB and short AMLP.

MLP valuations show that the trust of the traditional MLP investor has been lost, perhaps irretrievably. In Kinder Morgan; Still Paying for Broken Promises, we showed how that company’s history of investor abuse via two distribution cuts and an adverse tax outcome continues to weigh on its stock price. In Magellan Midstream: Keeping Promises But Still Dragged Down by Peers, we showed how even well-run companies that have honored promised distributions remain hampered by the abuse of others in the sector. The Alerian MLP ETF (AMLP) lowered its quarterly dividend again last week, by 7.5%. It’s now 34% below its 2014 high. The persistent cheapness of pipeline stocks reflects understandable wariness by MLP investors, who bought for the tax deferred income and had it partially removed.

Valuing such stocks on yield alone inadequately captures the past history of distribution cuts. Another common metric, EV/EBITDA (Enterprise Value/Earnings Before Interest, Taxes, Depreciation and Amortization), is a blunt tool making little distinction between appreciating versus depreciating assets, or long term versus short term contracts.

Private equity buyers tend to look at cashflows. Using Enterprise Product Partners (EPD) as an example, Discounted Cash Flow (DCF) analysis reveals underappreciated value. DCF is often used to refer to an MLP’s Distributable Cash Flow, cash available for paying distributions to investors. To avoid confusion, in this article we will only use DCF as initially defined, the present value of future cashflows

EPD is the largest MLP. It is one third owned by the Duncan family and its well respected management team is ably led by Jim Teague. Their pipelines, storage assets and processing facilities handle crude oil, natural gas, natural gas liquids (NGLs) and refined products. They have a huge presence in along the gulf coast and include vertically integrated businesses that, for example, capture, moves, fractionate and export ethane.

EPD’s P/E ratio is unremarkable. Based on a consensus estimate of $1.67 for 2019, they trade at 16X, approximately the same multiple as the S&P500.

EPD’s EV/EBITDA is 11X. By comparison, KMI is 9.4X (penalized for past transgressions) while Oneok Inc (OKE) is at 14.7X, still feeling the love after last year’s successful conversion from an MLP to a corporation. Magellan Midstream (MMP), subject of last week’s blog, is 12.6X. On this measure, EPD could be described as moderately cheap versus its peer group.

While those traditional measures of valuation are unexciting, DCF analysis reveals a truly undervalued asset. Below is simplified look at cash flow analysis based on consensus EBITDA estimates:

2018: $7.0BN

2019: $7.4BN

2020: $7.75BN

2021: $8.3BN

2022: $8.65BN

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2019-22 Total $32.1BN

Financing EPD’s $26BN in debt costs $1.17BN (4.5% borrowing rate) annually. This year they’ll generate around $5.83BN in cash before taxes (which they don’t pay as an MLP). Depreciation and Amortization are non-cash expenses that typically don’t reflect the growing value of their assets, which is why earnings multiples such as P/E aren’t that useful.

For example, EPD owns underground salt caverns in Mont Belvieu, used for storing NGLs. This is wholly different than, say, a coal-burning power plant, which is why EV/EBITDA comparisons with utility stocks make little sense. Pipelines, when properly maintained, generally appreciate in value. As communities grow up around and over them, and other pipelines link into them, it becomes prohibitively expensive to build competing infrastructure.

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With a Debt:EBITDA ratio of <4.0X, EPD is comfortably investment grade with a strong balance sheet. This allows them to rely on debt to finance their backlog of new projects. The Shale Revolution continues to create demand for new infrastructure in support of America’s growing production. Companies like EPD are financing and building it.

EPD’s backlog of new projects over the next four years is estimated at $9.5BN and they’re expected to spend $1.35BN in maintenance capex, which is money spent on their existing assets to maintain their capability.

Because their EBITDA is growing, by 2022 they’ll be able to carry debt of $32.44BN (2022 EBITDA of $8.65BN multiplied by their 3.75X desired Debt/EBITDA multiple – the low end of their guidance range of 3.75 to 4.0x Debt/EBITDA). That’s $6.44BN more than their current debt, which means they could, if they chose, borrow to finance ~60% of their $9.5BN in new projects and $1.35BN in maintenance capex, allowing more cash to be returned to equity holders. Only $4.4BN needs to be sourced from cash generated, so there is no need to issue dilutive equity.

Since new projects can be self-financed, it simplifies the valuation of the business. Suppose you had $59BN in cash with which to acquire the company at its current market capitalization (although as you’ll see, it’s doubtful the Duncan family would sell).

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Over four years, the business will generate $32.1BN in EBITDA, less its interest expense of $4.7BN (4 times $1.17BN) and new investments funded from cash flows of $4.4BN, leaving $23BN. Returning this excess cash reduces the purchase price to $36BN by 2022. Deduct annual interest expense of $1.46BN (since there’s now more debt because of the growth projects) and maintenance capex of $350M, and the business is generating $6.84BN in cash, annually. On the $36BN purchase price, that’s a 19% cash flow yield.

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Even half that cash flow yield would be attractive, which would value EPD 20% above its current market cap after paying out ~40% of its market cap in cash.

Future growth projects add further to the potential value. New energy infrastructure projects generally have required returns from as low as 10-12% to 20%+, depending on the degree of risk. Suppose EPD is able to reinvest 20% of its $6.84BN in annual cash, or $1.37BN, into new projects that have an expected unlevered return of approximately 14.3%. This equates to an EBITDA multiple of 7X (i.e. $100 invested to earn $14.30 is a multiple of 100/14.3, or 7) which is in the middle of the expected range for EPD’s current projects of 6-8X.  Sticking to their 3.75X leverage multiple, they could finance 54% of the project with debt (i.e. 3.75X desired debt multiple divided by 7X project multiple). The rest would come from equity, which would be sourced from current cashflow.

The result would be an investment of $1.37BN in equity ($6.84BN times 20%) along with $1.58BN in debt, for a total of $2.95BN. The 14.3% expected return on the $2.95BN project would generate $421MM annually, contributing to future EBITDA growth. After interest expense of $71MM (same interest rate of 4.5% assumed throughout) and maintenance capex of $21MM (estimated to be 5.0% of EBITDA), there would be $329MM of incremental cash flow for distribution.

By 2022 the business would have $5.47BN in annual distributable cash flows ($6.84BN in cash after interest & maintenance capex less the $1.37BN for new projects). Distributions to the owner would be growing at 4.8% annually. This comes from taking the $329MM generated by new projects, multiplied by an 80% payout ratio, since we’re assuming 20% of cashflow gets reinvested back in the business ($329 times 80% divided by $5.47BN = 4.8% growth rate).

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By comparison, Utilities have a dividend yield 3.5% and REITs 4.25%, both with similar growth rates.  If EPD was simply valued at the same yield as REITs, the $5.47BN in 2022 cash flow would be worth $128.7BN. Add back the $23B in cash received to that point gets to $151.7BN. Discounted back to today at the risk free rate of 3%, gives a market value of $134.8BN. Divide by EPD’s current share count of 2.19BN units gives a price of above $60/unit, more than double today’s unit price.

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Cash flow analysis presents a very different picture of MLP valuation than looking at conventional multiples such as P/E or EV/EBITDA.

The problem for public market investors is that EPD units come with a K-1. This generally rules out tax-exempt and foreign institutions, as well as non-U.S. individuals. The remaining investor base is narrow, consisting of older, wealthy Americans who want stable income. This group is still smarting from the 34% drop in MLP payouts, as reflected in AMLP. The MLP model may not be broken, but the trust of many of the traditional MLP investors is, which in effect means the same thing.

Cash flow analysis is how private equity buyers tend to value companies, although EPD is probably too big for such a take-private transaction. This illustrates why private equity firms often outbid the large midstream public companies for assets, despite the latter’s enormous competitive advantages of linking to existing integrated systems, and the associated synergies of maximizing utilization across their assets.

We are invested in EPD, KMI, MMP and OKE. We are short AMLP

Many MLP management teams have pursued growth at the expense of honoring their promise of stable distributions. We think the sector’s persistently high yields need explaining. Last week’s blog post (Kinder Morgan: Still Paying for Broken Promises) drew thousands of pageviews and over a hundred comments on Seeking Alpha.

Although Kinder Morgan (KMI) got there through a series of steps, ultimately they redirected cashflows from distributions to new projects. From an NPV standpoint, financial theory holds that investors should be indifferent to how a company deploys its cash as they can always manufacture their own dividends by selling some shares.

Markets don’t work that way. Capital investments are not an expense, they’re a use of cash. But the dividend cuts required to fund them were treated as a drop in operating profit by investors. KMI should have understood this, because for many years prior to 2014 they sought investors who valued stable dividends. KMI then decided they no longer wished to appeal to those investors, and their valuation still reflects the betrayal. The bitterness of many investors is on full display via the comments on last Sunday’s blog.

KMI’s problem of an undervalued stock is self-inflicted – but what about other MLPs who have been faithful to their income-seeking investor base? Magellan Midstream (MMP) does all the right things:

• Grows Distributable Cash Flow (DCF) annually
• Raises its dividend (distribution), annually
• Finances its growth projects with internally generated cash, thereby avoiding dilutive secondary offerings of equity
• Maintains a strong balance sheet with Debt:EBITDA consistently below 4X

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Such judicious capital management has probably caused MMP to pass on growth opportunities that others have chosen. Energy infrastructure analysts widely hold that the sector remain undervalued. Dozens of MLP distribution cuts are at least part of the reason – so a company that has remained steadfast should stand out.

But while MMP’s unwavering embrace of its principles has helped, it hasn’t been enough to truly separate them from their less reliable peers.

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MLPs peaked in 2014. Since then, MMP has raised per unit EBITDA by 31%, per unit DCF by 25% and distributions are up 54%. Distribution coverage remains healthy at 1.25X.

MMP’s leverage has risen, from 2.8X to 3.5X, but will drop back next year as new projects come into production. Even at 3.5X it is comfortably below the 4X that most of their peers target.

Magellan’s management team hasn’t issued equity or made dilutive acquisitions.  They’ve done just what they promised by increasing cash flows & distributions while maintaining a strong balance sheet.  And yet, MMP’s stock price is 26% below where it ended 2014.

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MMP’s yield is more than 2% below the AMZ, reflecting a valuation premium relative to the MLP index. But the entire sector is laboring under the history of dozens of distribution cuts, which have lowered the payout on the Alerian MLP ETF by 30%. MMP’s valuation has moved in the opposite direction from its steadily improving operating performance in recent years, reflecting that traditional MLP investors remain far less enthusiastic than in the past.

The most common question asked of investors is, given persistent undervaluation, what is the catalyst that will drive prices higher? We showed last week that an MLP’s DCF yield is analogous to the Funds From Operations measure used in real estate, since it represents cashflow generated after the cost of maintaining the assets but before investment in new projects.  On that basis, MMP’s 9.1% DCF yield (based on $5.54 per unit for 2019) is pretty attractive for a long term holder.

However, many investors prefer immediately rising prices following a purchase to confirm their buy decision. Continued strong earnings should support increases in payouts. 3Q18 results for pipeline companies have been strong. Current forecasts are for 5-6% annual distribution growth for MLPs – slower than their growth in DCF as they build coverage for their distributions. Since many MLP managements continue to believe their stock undervalued, they prefer internally generated cash to issuing expensive equity. We agree.  We expect dividend growth for the broad American Energy Independence Index (80% corporations and 20% MLPs) of 10% next year.

Rising dividends should improve sentiment.

We are long MMP and KMI.

Broken promises aren’t quickly forgotten. That’s the hard lesson being learned by pipeline company managements, as the sector remains cheap yet out of favor.

Kinder Morgan (KMI) reported good earnings on October 17th. Volumes were up, and they sold their Trans Mountain Pipeline (TMX), including its expansion project, to the Canadian Federal government. TMX is Canada’s only domestic pipeline that can supply seaborne tankers. All other pipelines lead to the U.S.

Canada’s landlocked energy resources are becoming a political football. Alberta wants to get its oil and gas to export markets, but neighboring British Columbia opposes the new pipelines necessary for Albertan crude to reach the Pacific coast. Caught between the two provinces, KMI sensibly sought an exit. The transaction was well timed, closing before cost estimates for completing the expansion  were ratcheted up and a court ruled that a new environmental study was required (see Canada’s Failing Energy Strategy). Canada’s taxpayers were on the wrong end of the deal.

Nonetheless, Rich Kinder opened the earnings call lamenting KMI’s valuation. He said, “I’m puzzled and frustrated that our stock price does not reflect our progress and future outlook.” We do think KMI is cheap, but the explanation lies in recent history. Before the Shale Revolution created the need for substantial new pipeline investments, KMI’s investor presentation reminded “Promises Made, Promises Kept.”

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This turned out to be true only until financing new projects conflicted with paying out almost all available operating cash flow in distributions. Investors in Kinder Morgan Partners (KMP), the original vehicle, were heavily abused. They suffered two distribution cuts and a realization of prior tax deferrals timed to suit KMI, not them (see What Kinder Morgan Tells Us About MLPs). Former KMP investors, who are numerous, retain deeply bitter memories of the events and have lost all trust in Rich Kinder.

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KMI was only the first of many. Distributions on Alerian’s MLP index have been falling for three years. Their eponymous ETF has cut its payout by 30%. Alerian CEO Kenny Feng, normally a reliable cheerleader for the MLP model, recently turned more critical, citing,”…significant abuses of [distribution growth] in the past…” The irony is that until late last year Alerian’s own website showed reliable distribution growth, completely at odds with what investors in their products were experiencing. They only corrected it when mounting criticism from this blog (see MLP Distributions Through the Looking Glass), @MLPGuy and others forced a humbling revision.

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Too few commentators acknowledge the poor treatment of MLP investors (see MLP Investors: The Great Betrayal). Pipeline stocks are attractively valued but have been that way for some time. The legacy of broken distribution promises continues to cast a pall. KMI’s objective in abandoning the MLP model was to be accessible to a far broader set of investors as a corporation. So far, it hasn’t helped their stock price.

One explanation might lie in how they present their financial results. Distributable Cash Flow (DCF) is a term widely used by MLPs and retained by KMI even after it became a corporation. MLPs calculate their distribution coverage ratio, which is the amount by which DCF exceeds distributions. It’s somewhat analogous to a dividend payout ratio, albeit based on DCF not earnings. Kenny Feng notes that generalist investors aren’t familiar with DCF or its coverage ratio. It may be why KMI’s stock is languishing.

DCF is Free Cash Flow (FCF) before growth capex. MLPs have long separated capex into (1) maintenance, required to maintain their existing infrastructure, and (2) growth, for new projects. FCF, a GAAP term, is indifferent to the two types of capex and deducts them both. DCF (not a GAAP term) treats them differently by excluding growth capex, and is always higher.

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Unsurprisingly, KMI regularly promotes its 11% DCF yield, which is higher than its energy infrastructure peer group. However, FCF is the more familiar metric, and is lowered by the subtraction of growth capex. Because KMI spent over 70% of its $4.5BN DCF on new projects, the remaining $1.4BN in FCF results in just a 3.3% FCF yield. This is still higher than the energy sector and certainly better than utilities (which are often negative because of their ongoing capex requirements). But it doesn’t stand out versus other sectors, and probably causes analysts to overlook the high DCF yield.

As a corporation, KMI continues to promote a DCF valuation metric used by MLPs, Using the more common FCF yield, it isn’t compelling. However, DCF seems reasonable to us given their business model.

To see why, consider yourself owning an office building. After all cash expenses, including maintenance and setting aside money annually to replace HVAC and other equipment, it generates $1 million in cash, annually. In real estate this is called Funds From Operations (FFO). Because you’re already deducting the expenses required to keep the building operating, and it’s most likely appreciating in value, it’s reasonable to value it based on the $1million recurring cashflow. A cap rate of 5% means you’d require at least $20 million before agreeing to sell it.

Now suppose you decided to redirect $700K of your $1 million annual cashflow towards buying a second building that you also plan to rent out. You still own a $20 million asset, and reinvesting some of that annual cashflow in a new building doesn’t affect the value of what you already own.

In this example the $1million in FFO is analogous to KMI’s DCF. It’s why they believe their stock is undervalued, because 11% is a high DCF yield. Their FCF is so much lower because they’re investing most of their DCF in new assets that will generate a return.

GAAP FCF doesn’t differentiate between capex to maintain an asset and capex to acquire a new one, which is why pipeline companies don’t dwell much on FCF. Moreover, properly maintained pipeline assets generally appreciate. As climate activists slow new pipeline construction in some states, it simply raises the value of nearby infrastructure that can serve the same need.

Critics may believe that DCF doesn’t reflect all the necessary maintenance capex that’s really required, or that the underlying assets are depreciating in value even while properly maintained, although there’s little if any evidence to support either claim. So KMI remains misunderstood.

The dividend might offer a more compelling story. Yielding 4.7%, it’s below the 5.8% of the broad American Energy Independence Index. Because of history, investors are understandably cautious in buying for the yield. But today’s $0.80 annual payout is expected to jump to $1 next year and $1.25 in 2020. This 25% annual growth will push the yield to 7.4% in two years, assuming no upward adjustment in the stock price. A rising dividend might finally vanquish the unpleasant memories of prior cuts, and draw in new buyers.

In spite of its attractive valuation, MLP ETFs and mutual funds don’t own KMI, because it’s not an MLP, providing another good reason to seek broad energy infrastructure exposure that includes corporations.

We are long KMI and short AMLP.

Last week Antero Midstream (AM) became the latest MLP to simplify their structure. This is further evidence of the declining opportunity set for MLP-dedicated funds, and cause for investors to seek exposure to energy infrastructure that goes beyond MLPs to include corporations (see The Uncertain Future of MLP-Dedicated Funds).

Like many MLPs before them, Antero is becoming a corporation. Broader institutional ownership and enhanced trading liquidity were cited as the reasons.

The benefits of being an MLP persist – our friend and regular commenter Elliot Miller would note that the tax benefits remain significant: MLPs don’t pay Federal corporate income tax, leaving more money available for distributions. And those distributions are largely tax deferred, with the possibility of being tax-free to one’s heirs given thoughtful estate planning.

Nonetheless, Antero concluded that the MLP structure no longer suited them. They joined a long list of companies who’ve reached the same conclusion, including Kinder Morgan (KMI), Targa Resources (TRGP), Semgroup (SEMG), Oneok (OKE), Archrock (AROC), Williams (WMB), Dominion (D) and Enbridge (ENB). Tallgrass (TGE) has retained the partnership structure for governance but chosen to be taxed as a corporation, and Plains All American offers a option for both 1099 (PAGP) and K-1 tolerant (PAA) investors.

They’ve all found that MLP investors are too few and fickle to be a reliable source of equity capital. Tax impediments add cost and complexity to tax-exempt and non-U.S. institutions, a substantial portion of the investor base for U.S. public equities. The K-1s are how investors achieve the tax benefits noted above, but their complexity dissuades most retail investors. Once you eliminate these different classes of investor, almost the only buyers left are taxable, high net worth individuals. In other words, older, wealthy Americans.

These investors like their income, and the several dozen distribution cuts imposed in recent years have done irreparable harm. The high payout ratios of MLPs left little cash for funding growth projects (see It’s the Distributions, Stupid!). This wasn’t a problem until the Shale Revolution created the need for investments in new infrastructure, to support the huge increases in U.S. oil and gas output. Cash was duly diverted from payouts to growth projects, leading to a 30% drop in distributions (see Will MLP Distribution Cuts Pay Off?).

EBITDA improved and leverage came down, but MLP investors only care about distributions, which were cut by 30%. Consequently, the sector fell hard and is still 30% below its 2014 peak.

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MLP-dedicated funds are left with fewer, smaller fish to catch. Their promoters still defend them, in spite of their flawed structure rendering them taxable with correspondingly eye-watering expenses (see MLP Funds Made for Uncle Sam). As pipeline companies continue to abandon the MLP structure, it’s showing up in the sinking market cap of the MLP indices. The market cap of both the Alerian MLP Index (AMZ) and the Alerian MLP Infrastructure Index (AMZI) are decreasing even while the sector is up this year.

It’s stark evidence of the declining role MLPs play in U.S.energy infrastructure. Affected ETFs include those from Alerian (AMLP) and InfraCap (AMZA). Mutual funds from Oppenheimer Steelpath, Centercoast, Mainstay Cushing and Goldman Sachs are similarly stuck with a declining opportunity set.

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These MLP-dedicated funds can’t easily change their structure to avoid taxes by becoming RIC-compliant – they’d have to sell 75% of their MLPs, which is prohibitively disruptive. Some smaller funds whose MLP sales weren’t market moving have done so, which shows that others would if they could. Instead, MLP fund proponents are left to argue that their fund structure is optimal, even though no new MLP-dedicated funds are being launched any more.

Some big MLPs are happy enough. Enterprise Products (EPD), Magellan Midstream (MMP) and Energy Transfer (ETE) are all sticking with the structure. It works best if you don’t need external financing. We are invested in all three companies through our funds and separately managed account strategies.

MLPs can still be good. An MLP-only approach is not. MLP-dedicated funds are the worst place to be, given the shrinking MLP market cap and tax burden. But broad energy infrastructure, growing as we pursue American Energy Independence, is cheap.

We are long AMGP, AROC, ENB, EPD, ETE, KMI, OKE, MMP, PAGP, SEMG, TGE, TRGP, WMB. We are short AMLP.

Will rising interest rates hurt pipeline company stocks? Ten year treasury yields are at 3.25%, a seven year high. The bond market is commanding the attention of equity investors once more.

The high yields on MLPs have long attracted income-seeking investors. A common valuation metric is to compare the sector’s yield with the ten year treasury by measuring the yield spread. This is currently around 4.8%, compared with the twenty year average of 3.5%. In comparison, REITs and Utilities both have yield spreads under 1%.

While the MLP yield spread is historically wide, it’s been wider than average for almost five years, which probably means that the relationship has changed. Over the past decade it’s averaged 4.5%. MLP investors require a richer premium to other asset classes than in the past, which is why the bigger MLPs have been converting to corporations, so as to access a wider investor base (see Growth & Income? Try Pipelines).

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While MLP yields have remained stubbornly high, they continue to move independently of the bond market. Visually, energy infrastructure and ten year treasuries have no relationship at all. The correlation of monthly returns is -0.35 over the past decade and 0.16 over the past five years – practically speaking, there is no correlation between the two.

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Over short periods of time, fund outflows from income alternatives can depress MLP prices, but the effect is rarely enduring. Tariffs on regulated pipelines often include an inflation escalator, allowing increases pegged to the Producer Price Index (PPI), which creates some inflation protection for pipeline owners if inflation was to spike higher. This is why we often tell investors that the impact of higher rates depends on whether inflation is rising or not. If rising inflation drives up yields, the higher PPI will feed directly into higher revenues where contracts are correctly structured.

However, if rates move up independently of inflation (i.e. higher real rates), then all assets are affected. Any investment is worth the sum of its future cashflows discounted at an appropriate interest rate. Pipeline stocks would likely be affected like many other sectors.

But economic growth is very strong, which mitigates the effect of rates. Unemployment is the lowest in living memory at 3.7%. Everyone who wants a job has one, and demand is up for many things including pipeline capacity. The U.S. recently became the world’s biggest crude oil producer (see America Seizes Oil Throne).

Permian volumes in west Texas are overwhelming available pipeline capacity, which led to a price discount on Midland crude versus the WTI benchmark of as much as $17 in summer. It’s recently narrowed to $7 – still more than the typical contracted pipeline tariff, but less than the $10-20 cost of truck transportation.

Natural gas currently trades at around $3 per Thousand Cubic Feet (MCF). The natural gas basis between Waha in West Texas and the Henry Hub benchmark location is $2, meaning Waha natgas is worth only $1 per MCF. Permian gas output is 10 Billion Cubic Feet per Day (BCF/D), whereas pipeline capacity is only 8 BCF/D. Some of this excess production is flared, meaning it’s worth zero.

Unlike crude oil, natural gas can’t easily be moved by rail or truck because of the pressure required to compress it. Pipelines are the only option, and the price discount persists because the takeaway infrastructure isn’t available.

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Anticipated Mexican demand is awaiting completed infrastructure south of the border. Futures traders expect the discount to persist for a while longer, which should benefit Kinder Morgan (KMI), Energy Transfer (ETE) and Oneok Inc (OKE). Beginning in 2020, additional capacity will be made available via KMI’s Gulf Coast Express and Permian Highway pipelines, adding around 4 BCF/Day.

Natural gas production is going to keep growing. Shell recently told investors they expect 2% annual growth through 2035, twice the growth in global energy demand overall. Although natural gas is often touted as being a bridge to a world of renewables, another energy executive said, “Gas not a transition fuel, but a destination fuel.”

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The point is that these price differentials, which reflect unmet demand for additional pipeline capacity, are unlikely to be harmed by a modest rise in interest rates. The bond market is under pressure because the economy is booming.

Moreover, today’s battle-hardened MLP investors have endured several dozen MLP distribution cuts. The secular growth in U.S. hydrocarbon production is what attracts them (see Can Anyone Catch America in Plastics?). The companies themselves have also changed, with many of the biggest abandoning the MLP structure to become corporations (see The Uncertain Future of MLP-Dedicated Funds). As a result, broad energy infrastructure is less reliant on MLP investors (often older, wealthy Americans). The adoption of a corporate form, widely followed by the biggest MLPs and most recently by Antero Midstream GP (AMGP) has resulted in a broader, more institutional investor base.

The bottom line is that there’s little reason to fear the current rise in interest rates. Historically, there’s no statistical relationship between bonds and pipeline stocks. Output of oil, gas and natural gas liquids is rising, fueling demand for infrastructure. And the investor base is probably the broadest it’s ever been, as companies move away from the fickle MLP investor towards more conventional holders of U.S. equities. The broad-based American Energy Independence Index, which includes the biggest U.S. and Canadian energy infrastructure stocks, is up almost 2% in October even with treasury yields up 0.20%. So far, the sector has not been impacted by the headlines around rising rates.

We are long AMGP, ETE, KMI and OKE

Ethane prices recently hit a four year high. Although this garnered far less attention than the crude oil rally, increasing supplies of ethane is an unappreciated element of the Shale Revolution.

“Dry” natural gas consists of methane, most commonly supplied to residential gas stoves but also increasingly used by power plants to produce electricity. “Wet” gas includes other natural gas liquids (NGLs), such as ethane (more below), propane (used in your outdoor BBQ), butane (cigarette lighters) and other more obscure NGLs such as isobutene. Typically, the NGLs and other impurities are separated out from the wet gas, leaving methane as the natural gas that flows to customers. Because NGLs have marketable value, wet gas is more desirable.

Ethane, once converted to ethylene through “cracking” is the principal input into production of polyethylene. Simply put, ethane is turned into plastic. Polyethylene is manufactured in greater quantities than any other compound.

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The process is fascinating, and naturally the internet provides ample information. Ethane molecules are broken through heating (“cracked” in industry parlance), and the ethylene produced undergoes further processing into polyethylene pellets. These plastic pellets come with different properties such as strength, flexibility and melting point, which determine their ultimate use. They are heated and molded into many thousands of consumer and specialty products. For an absorbing description that follows ethane molecules from extraction to ultimate use, the Houston Chronicle’s three-part series Texas petrochemical plants turn ethane into building blocks of plastic is highly readable.

Among many fascinating steps, we learn that molten polyethylene pellets are blown into a very thin cylindrical balloon, several hundred feet long. This is then turned into sheets by passing through rollers, and multiple sheets are combined depending on the desired thickness. In the article, these ethane molecules ultimately traveled as plastic pellets to Vietnam where they were processed into packaging for frozen shrimp that was shipped back to the U.S. The petrochemical industry makes this happen.

U.S. ethane production has more than doubled in the past decade, to 1.5 Million Barrels per Day (MMB/D). Ethane is a gas and isn’t shipped in barrels. The MMB/D unit of measure converts the energy content of the ethane to that in a barrel of crude oil. Barrels of Oil Equivalent (BOE), allows volumes of most hydrocarbons to be measured using a common metric. What further sets the U.S. apart is that shale’s light crude comes with relatively high concentrations of NGLs, including ethane. It simply needs to be separated out.  The alternative source of ethane is as a by-product from refining crude oil, a more costly approach.

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The U.S. is producing so much ethane that some of it is being mixed in with the methane natural gas stream as it can’t be profitably used elsewhere (known as “ethane rejection”). Low ethane prices with the promise of ongoing ample supply have led to a flurry of new petrochemical investments.  Cheap natural gas lowers processing costs, since the conversion of ethane to plastic pellets requires heat. For example, Exxon Mobil (XOM) operates one of the world’s largest polyethylene plants in Mont Belvieu, TX, with ethylene provided by a new facility at their nearby Baytown complex.

But the big increase in natural gas output is in Appalachia, where the Marcellus and Utica shale formations are providing most of this new supply. Royal Dutch Shell is building a new ethane cracker in western Pennsylvania, close to its supply. In total, $202BN of investments in 333 projects have been announced since 2010. U.S. ethane exports have been rising, but as these new facilities become operational they will increase domestic demand. Two thirds of the investments involve foreign companies. The recent jump in the ethane price is partly attributable to new domestic buyers.

The result is that ethane trade flows are shifting, and the U.S. is becoming a more important supplier of plastics.

The Shale Revolution draws attention for the growth in fossil fuels — crude oil and natural gas, where the U.S. leads the world.  But we’re even more dominant in NGLs, contributing one-third of global production. The impact of NGLs and consequent growth in America’s petrochemical industry receives far less attention, although it’s another huge success story.

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Enterprise Products Partners (EPD), Energy Transfer Equity (ETE), Oneok Inc. (OKE) and Targa Resources Corp (TRGP) are well positioned to benefit from America’s growing NGL production. Our funds are invested in all of them.

Bethany McLean didn’t intend her latest book, Saudi America: The Truth About Fracking and How It’s Changing the World, to be a booster of the Shale Revolution. The New York Times got it all wrong when they titled her promotional op-ed, The Next Financial Crisis Lurks Underground. Before reading her book, I therefore assumed that in forecasting a collapse in the U.S. energy sector, the very recent one in 2014-16 had simply passed her by (see New York Times Forecasts the 2014-16 Energy Sector Collapse). But McLean accurately chronicles how OPEC nations failed to bankrupt the nascent U.S. shale industry with low oil prices, thereby demonstrating its resilience. She notes the importance of privately-owned mineral rights, an almost-uniquely American concept that facilitated onshore oil and gas exploration long before shale. Those who don’t fear a crash are well represented. The IEA’s chief economist, Fatih Birol, says, “There is a silent revolution taking place in the United States, so silent that nobody’s aware of it.”

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In fact, McLean’s warnings of collapse are based on such weak arguments and are so half-hearted that she’s grudgingly conceding the secular change in world energy markets that’s occurring. A private equity investor (“titan”) suggests “…the Federal Reserve is entirely responsible for the fracking boom.” Really? Did the Fed buy energy sector bonds? Are low interest rates failing to benefit any other sector? In 2016, non-investment grade bond yields for some energy names reached 25%. Although there were bankruptcies, the industry survived as assets moved from weak hands to strong. She also finds some bearish hedge fund managers who have lost money shorting shale drillers. If these are the best arguments for another crash in the U.S. energy sector, investors have little to fear. In fact, the weakness of McLean’s arguments against Shale offered a more convincing defense of its longevity than many authors who set out to do just that.

As is often the case, the characters are most interesting. Although McLean relies heavily on past writings on Chesapeake founder Aubrey McLendon, it’s still absorbing to reread about his enormous risk appetite. McLendon’s fiery death while driving alone two years ago looked like suicide, given his mounting financial and legal problems, but it was ruled an accident. The industry lost a colorful believer whose single-minded approach was financially unsuccessful. By contrast, the methodical, analytical approach of companies like EOG demonstrates that the resurgence of hydrocarbon production in the U.S. is not driven by leveraged operators that are permanently bullish.

Shale firms have long been criticized for outspending their cashflow. The industry’s continued access to capital demonstrates that many expect this to reverse. The world’s biggest oil companies, like Exxon Mobil, are now investing in shale, bringing financial discipline and less reliance on capital markets financing, exactly what McLean believes is needed.

You have to work pretty hard to find a downside to American Energy Independence. It’s a bit like complaining about an outsized capital gains tax bill. Shale is pretty obviously an enormous U.S. benefit; less clearly good for others. Nonetheless, McLean tries to get us worried: if we buy less oil from unstable parts of the world, we’re less likely to care about their security. That’s not obviously bad for our young men and women in the military.

McLean fears that the Trump Administration’s desire to drill for oil in the Arctic National Wildlife Refuge (ANWR), “…will crater prices, thereby making the economics of drilling even less attractive than they already are.” Little thought went into that sentence – there are reasons to leave ANWR alone, but crashing the oil market is not one of them. This is where the real McLean emerges – as an environmentalist opposed to fossil fuels, trying to marshal non-environmental arguments against.

Having made a convincing if unintended case that financial challenges will not derail America’s energy renaissance, McLean then warns that renewables will soon bring its demise. But even here, she makes a strong argument for natural gas as a complement to intermittent solar and wind. She quotes Michael Cembalest, JPMorgan’s thoughtful chief strategist, who wrote that, “An electricity grid with less coal, less nuclear, and more renewable energy would be highly dependent on abundant, low-cost natural gas.” We completely agree.

The short-cycle nature of shale production is its enormous strength, something McLean overlooks. Predicting long term demand for crude oil is never easy, but the development of electric cars makes it exceptionally risky to invest in projects with a 20 year payback, which is what conventional oil projects look like. Shale production relies on drilling hundreds of wells that cost under $10MM each. Output declines sharply from a high rate, but capital invested is repaid quickly, often within two years. Output can be hedged in the futures market. If prices drop, drillers stop completing new wells. This quick payback offers a substantially better risk profile, something the industry recognizes. It’s why capital continues to flow in that direction (see Why Electric Cars Help the Shale Revolution).

Saudi America is a quick read – at only 138 pages, I finished it in around four hours. You won’t gain many insights, but as a chronicle of why the Shale Revolution will continue to transform energy markets, it’s worth a quiet afternoon.