We regularly get questions from investors about why the dividend yield on MLPs is often higher than for energy infrastructure C-corps that are in the same business. In recent years several MLPs have transferred their assets into their C-corp parent. Examples are Kinder Morgan (KMI), Targa Resources (TRGP) and Oneok (OKE). The merger of an MLP with its C-corp parent has typically been accompanied by a dividend cut for the MLP investors, who wind up with C-corp shares through a swap.

The assets don’t perform any differently just because they’ve been moved to another entity. But it highlights the differences between C-corps and MLPs from both a taxation and a financing perspective.

The two diagrams below show this. In each case, assume the underlying assets and the need for growth capital are the same; the only difference is the type of entity (MLP or C-corp) owning the assets.

Traditionally, MLPs pay out >90% of their Distributable Cash Flow (DCF) in distributions. DCF is defined as cash generated from operations less the cost of maintenance expenditure on existing assets. Note that generally companies (i.e. C-corps) pay out substantially less than this. Across the S&P500 the average payout ratio is currently 42%. This is largely because of the “double taxation” of dividends, in that corporate profits are taxed first at the corporate level (via corporate income tax), and then again at the investor levels (via personal taxes on dividends and capital gains).

Since paying dividends is a very tax-inefficient way for corporations to return value to shareholders, high pay-out ratios would be exceptionally inefficient. The recent trend is for companies to return profits via buying back their stock. S&P500 companies are currently spending 28% more buying back stock than paying dividends. This also reduces their share count, boosting per share growth.

MLPs don’t face the same tax inefficiency, hence the higher payouts. Consequently, they pay out most of their DCF and then issue equity to finance growth. Their number of units outstanding therefore grows, diluting per unit DCF.

When assets formerly held by an MLP are moved into a C-corp, their cashflows are treated differently. Because C-corps have lower payout ratios, less of the Free Cash Flow (roughly analogous to the MLP’s DCF) is paid out in dividends. This has two results:

• Assets held in an MLP will pay a higher yield to investors than those same assets held in a C-corp.
• The C-corp’s lower payout leaves more cash to finance growth, which in our example eliminates the need to issue equity. Not issuing equity means no dilution for shareholders, which in turn means faster per share dividend growth.
• 

Across the energy infrastructure investments we hold, dividends are covered approximately 1.5X by free cashflow. An extreme example is Kinder Morgan (KMI) which has a FCF yield of 10% but a dividend yield of 2.5% (they have announced they’ll be raising it next year). KMI is reinvesting most of its FCF in growth, thereby not issuing any dilutive equity and so driving FCF higher. In addition, since FCF is generally growing, the total return on these investments should exceed the FCF yield itself.

Some will note that the point of MLPs is to hold eligible assets without having to pay corporate tax on the returns, and argue that use of the C-corp subjects those returns to taxes needlessly. In practice, energy infrastructure C-corps that have acquired assets from an MLP have employed tax strategies to minimize or eliminate any corporate tax liability, so this concern is moot (see The Tax Story Behind Kinder Morgan’s Big Transaction).

In summary, C-corps pay less of each dollar earned and reinvest more, compared with an MLP holding the same assets. Lower payouts lead to faster growth, since cash not paid out is reinvested in the business. The dividend yield on a portfolio of equities is an unreasonably low estimate of total return. For example, the S&P500 yields 2%, whereas most observers would assign a higher long term return target to stocks (unless they’re very bearish), because dividends grow over time which contributes to an investors overall return. C-corps that own energy infrastructure exhibit similar characteristics, albeit with higher yields and growth prospects.

We are invested in KMI, OKE and TRGP

Master Limited Partnerships (MLPs) have been reporting earnings over the past couple of weeks. For the most part they have come in as expected, with few surprises in either direction. Crestwood (CEQP) and Tallgrass (TEGP) both reported system volumes slightly higher than expected; generally though, they were unremarkable, which is the sort of boring stability MLP investors like. Although most CEOs are pretty sure their stock is undervalued, TEGP CEO David Dehaemers  is positively convinced this is the case. And since TEGP sports a 5.25% yield forecast to grow by 40% (not a misprint) in 2018, his case appears compelling to us.

The real story of the past week is not MLPs but their customers, who we also follow closely. MLP investors may feel that their patience is being tested, as the sector gyrates with crude oil while persistently refusing to appreciate as its high yields imply it should. At least MLP investors are being rewarded to wait, with attractive quarterly distributions being paid in many cases during August. Even so, the trailing one year return on the Alerian Index of 2% seems paltry compared with the S&P500, whose one year return is 16%. MLP investors might feel unloved. In the classic British sitcom Fawlty Towers, manic hotel owner John Cleese is told not to worry, that there’s always someone else worse off. To which he replies, “Is there really. Well I’d like to meet him, I could do with a laugh.” You can see the clip here at the 18 minute mark.

Therefore, the recent performance of U.S. shale drillers is worth considering, albeit with less shadenfreude than John Cleese. They are the customers of MLPs, and the regularly demonstrated efficiencies with which they extract hydrocarbons are not, of late, rewarding their investors. Over the past year, the six most active independent shale drillers have returned -21%. 2Q17 earnings reports over the past couple of weeks have hastened this slide, as future production growth has been guided down. The announced capex reductions across the exploration and production sector (see Financial Discipline Among MLP Customers) have helped boost crude prices by around $6 a barrel since June 21. However, lower guidance from the six names highlighted is in most cases due to specific technical challenges they’re encountering and resolving. They’re not reporting that margins are too tight. Nonetheless, in such a market investors want every name in the group except the ones they hold to produce less.

Weakness in the stock prices of shale drillers may be weighing on MLPs. Energy infrastructure inevitably trades with the sector it supports. Kinder Morgan (KMI) is in XLE, the energy sector ETF. Swings in sentiment inevitably move its price regardless of its fundamentals.

A piece of good news that didn’t receive much attention was Senate approval of two new commissioners to the Federal Energy Regulatory Commission (FERC). This will restore their quorum, and should allow a substantial backlog (estimated by RW Baird at $14BN) of infrastructure projects to receive approvals and proceed. Their completion will add incrementally to the cashflows of their owners and ultimately augment payouts to investors.

We are invested in CEQP, KMI ad TEGP

Recent earnings reports suggest some moderation in the acceleration of U.S. shale drilling. The CEO of Schlumberger said that equity investors were propagating marginal activity by providing capital based on volumes rather than returns. The retiring Chairman of Halliburton, Dave Lesar, provided some wonderful quotes on his final investor call, including this assessment of the Shale Revolution:

“They are your classic American entrepreneurs, and their success should be recognized. In Silicon Valley, such a success would be greatly celebrated as another industry disruptor. The unconventional disruption is not widely celebrated beyond the energy space, but it should be. The development of US unconventional resources has been as disruptive to the global energy market as Amazon has been to Big Box Retailing or Uber to the taxi business… Made the US more energy independent, caused OPEC to react and changed the fundamental economics of offshore production.”

This is one of the reasons why America is Great.

Anadarko announced a $300MM (7%) reduction in their 2017 capex plan, noting that margins were too volatile to support their previously planned budget (some of this reduction was to non-shale, offshore projects). Halliburton’s Dave Lesar also noted a “tapping the brakes”, which the incoming CEO Jeff Miller clarified as, “going from 80 miles an hour to 70 miles an hour.” Other U.S. drillers including Hess and Sanchez similarly lowered capex. The anecdotal evidence of slower production growth supported crude prices last week, as did OPEC’s meeting in St. Petersburg at which Saudi Arabia pledged to unilaterally limit exports in a further effort to support prices.

The U.S. Energy Information Agency (EIA) publishes a monthly Drilling Productivity Report (DPR). It includes data on output and productivity from the larger shale plays across the country. Many observers including ourselves have commented on the dramatic improvements in productivity that have been taking place. It’s no exaggeration to say that advances in drilling techniques and use of improved technologies have been hugely important drivers behind the rise in U.S. production, in spite of falling prices.

However, part of the productivity improvements have been due to an increased focus on the most productive wells. U.S. producers adopted a defensive posture in 2015-16 as crude prices collapsed, and that included focusing their efforts on their best plays. Although there’s no doubt that actual productivity improved enormously, the figures are likely somewhat flattered by this focus on the best assets.

One measure of productivity is initial output per well (Initial Production Rate, or IPR), and in some plays (notably including the Permian), this statistic has been declining modestly for about a year. It’s still higher than at any time prior to 2016, and enhancements such as multi-well pad drilling, longer laterals and new fracking techniques have been critical to success. Output continues to grow even while initial production rates are flattening out. It’s a consequence of drillers moving beyond their most productive plays, best rigs and most skilled crews. While they played defense successfully, operating efficiencies were achieved and are being applied more broadly. Although crude oil production from shale plays is likely to keep growing in the current economic environment, the flattening of IPRs is a sign of limits on unconstrained growth. A study from MIT concluded that productivity gains were being overstated by insufficiently considering “sweet-spotting”, the tendency to focus on the best acreage.

Recent earnings reports as well as the IPR data noted above suggest that, while U.S. output will continue to grow, there are visible limits on that growth. Furthermore, after seeing annual declines in breakeven prices of 20% in 2015 and 29% in 2016, Rystad Energy forecasts breakevens are poised to rise 7% in 2017. Nonetheless, productivity remains high enough and costs low enough to gain market share, but perhaps not enough to further depress prices.

Those in the oil industry who take a long view increasingly worry about insufficient new supply. It’s hardly today’s problem, with crude oil back to the mid $40s as OPEC’s production cuts are offset by increased shale output. But depletion of existing fields is generally believed to take 3-4 Million Barrels a day (MMB/D) off the market every year and demand continues to increase by 1-1.5 MMB/D annually. As a result, 4-5MMB/D of new supply is required annually to balance the market. Global production is currently around 97 MMB/D.

Last week Amin Nasser, chairman of Saudi Aramco, noted that the 20 MMB/D of new production thus needed over the next five years is unlikely to be forthcoming from U.S. shale, or indeed anywhere else. The International Energy Agency (IEA) offered a similar outlook.

The short-cycle nature of shale is likely impeding new development. In the past, the supply response function of crude was quite slow in reacting to demand changes, which contributed to some extreme price volatility. Since bottoming 18 months ago crude has been more stable. The ability of shale producers to alter production in just a few weeks or months is contributing. It also means that backers of a new, conventional project have to consider the impact on their returns from a repeat of the 2015 oil collapse, since much of the U.S. shale industry was able to protect itself by reducing output.

In the competition between short-cycle and long-cycle, the former’s flexibility represents a significant advantage. It means some projects that might ultimately turn out to be profitable aren’t getting approved.

This is one of the reasons that JBC Energy forecasts an extra 1MMB/D of shale oil output by the end of next year. This would take overall U.S. crude output over 10 MMB/D, to around the same level as Saudi Arabia.

The U.S. Energy Information Administration (EIA), agrees, recently projecting 9.9 MMB/D of average output next year which would correspond with JBC Energy’s 10 MMB/D 2018 exit rate. This will be the highest annual average production in U.S. history, surpassing the previous record of 9.6 MMB/D set in 1970. It’s worth noting that one year ago the EIA was forecasting a decline of 0.4 MMB/D to 8.2 MMB/D for 2017 production, while they’re now projecting a 0.6 MMB/D increase to 9.3 MMB/D. The size of the 1 MMB/D revision over twelve months reflects the dramatic improvements in productivity across the industry (and maybe, ahem, poor forecasting).

A recent example is Devon Energy’s record breaking well drilled in Oklahoma which produced 6,000 barrels a day equivalent of oil and gas during its first 24 hours of operation.

U.S. shale output is set to grow and is becoming the swing producer, quickly responding to price signals and as a result keeping oil prices in a fairly narrow range. Prices may be lower than producers globally would like, but they’re high enough to stimulate increased domestic production, which is what the owners of midstream infrastructure care about. Impressive as these gains are, they’re not going to meet the supply shortfall that Saudi Aramco’s Nasser and others see on the horizon. But it’s hard to see how that problem can be anything but good for the U.S. and MLPs.

“Rusty” Braziel runs RBN Energy, a firm that provides very useful research on production trends in U.S. hydrocarbons. Their website maintains a regular blog and also offers deeper analysis on specific topics. They reach over 20,000 industry executives, and we find many useful insights in their work.

The Domino Effect: How the Shale Revolution is Transforming Energy Markets, Industries and Economics was published early last year, coincidentally just a few weeks prior to the low in the energy sector’s bear market that was largely due to U.S. hydrocarbon output. Like his blog posts, Rusty’s book is well researched and highly engaging. He describes events as dominoes falling against one another in a seemingly inevitable sequence. The first domino was caused by improvements in technology that drove significantly enhanced returns from shale-sourced natural gas production. The consequent abundance drove the price of natural gas lower, inducing Exploration and Production (E&P) companies to switch to more profitable Natural Gas Liquids (NGLs), which were often found with or nearby “dry” natural gas. Lower prices followed for NGLs, and activity then shifted to crude oil. The resulting increase in U.S. production drew the world’s attention to the Shale Revolution as crude slumped in 2014-15.

The dominoes continued, creating a resurgence in U.S. petrochemical investments funded by cheap inputs such as ethane, an NGL. Liquefied Natural Gas (LNG) import facilities were converted to export, since U.S. natural gas prices fell to among the lowest in the world. The book’s explanation of events as inevitably linked provides a compelling framework with which to examine huge shifts in world energy markets.

There is some interesting history; in 1942 the success of German U-boats at sinking oil tankers traveling from the Gulf Coast to New York harbor prompted the rapid construction of pipelines from Texas up to Philadelphia and New York. One of those pipelines, dubbed “Big Inch” because of its 24 inch diameter (double the diameter of the largest to date), was converted from a crude line after the war to carry natural gas. Today it is the TETCO pipeline operated by Enbridge (ENB). Another, smaller pipeline from the same era named Little Big Inch carried refined products. It’s now the Products Pipeline System (formerly known as TEPPCO) and is run by Enterprise Products Partners (EPD). These represent compelling examples of the longevity of pipelines, showing that properly maintained infrastructure that’s still in demand can steadily appreciate in spite of GAAP accounting that allows for depreciation.

Pipeline operators handle the differing quality of crude oil and mixed NGLs from their many customers by operating a “quality bank”. This values the difference between what a specific customer puts into the pipeline versus the “common stream” of mixed products, creating offsetting debits and credits that allow more efficient utilization. Because natural gas pipelines typically require a fairly pure input with limited impurities, these operate differently. The homogeneity of natural gas makes it fungible, allowing a shipper to put produced gas into a network and receive immediate credit for it at the other end without waiting for the actual molecules to travel the distance.

A handy comparison of the different volumes of natural gas and crude oil consumed in America every day calculates how many times they would fill the Empire State Building. Natural gas (in the gaseous state in which it’s typically moved) would fill that space 1,917 times, compared with only 2.4 times for crude. We often write that energy infrastructure is primarily a natural gas business.

We have written about the Rockies Express (REX) gas pipeline now owned by Tallgrass Energy Partners (TEP; see Tallgrass Energy is the Right Kind of MLP). The Domino Effect recounts the original construction of REX by Kinder Morgan (KMI), completed in 2009, as it moved natural gas from the Rocky Mountains to the gas-starved (as it was then) northeastern U.S. One of many consequences of the Shale Revolution has been TEP’s successful reversal of REX to supply Midwestern customers with natural gas from Pennsylvania and Ohio. Pipelines typically resolve regional price differentials caused by relative abundance and scarcity. Prior to REX, Rockies natural gas languished as low as $0.05 per thousand cubic feet (MCF) before leaping to $9 in 2009 when connected to other markets.

Coming after the book’s publication but consistent with the domino theme, OPEC conceded the inevitability of continued U.S. crude production late last year when they agreed on production cuts (see OPEC Blinks). Recent developments appear increasingly inevitable as presented by Rusty, and he provides a solid foundation for those who believe that the cheap, secure resources unlocked by American know-how are unambiguously good.

This interpretation of recent history combines easily with very useful explanations of how hydrocarbons are extracted, moved and refined. Readers get the macro analysis along with an understanding of the basics of drilling. One helpful picture (see above) reveals the main difference between a conventional well and a shale one. Hydrocarbons originate in porous rock, and have historically been extracted where they migrate underground to an open subterranean cavity where a vertical drill can reach them. The Shale Revolution taps directly into the original porous rock, allowing access to reserves that were previously known but inaccessible. Moreover, certain formations such as the Permian consist of multiple layers, allowing pad drilling with multiple wells which has led to dramatic improvements in efficiency.

The final three chapters look ahead to the geopolitical implications of the Shale Revolution. America is the clear winner. The most obvious losers are the members of OPEC, whose oil revenues are destined to be substantially lower even while they also cede market share through reduced exports to North America. It’s quite possible that the U.S. will be less engaged in the Middle East as our energy reliance subsides, a development that most Americans will cheer.

Europe stands to benefit from U.S. LNG exports which will reduce reliance on Russia, where pipeline maintenance is synchronized with political objectives. But the U.S. petrochemical industry is likely to benefit at Europe’s expense from cheap, local NGL feedstocks. The decline in European oil production will probably accelerate. Crude oil and natural gas get the headlines, but NGLs are an under-appreciated success story too. For example, exports of propane (what fuels your barbecue) have jumped well over tenfold since 2010.

Russia will increasingly find the U.S. is a competitor in energy markets, exposing that country’s relatively undiversified economy (60% of Russian exports are oil and gas).

A minor quibble is Rusty’s assertion that America invented representative democracy (“another global revolution”) around 240 years ago. This overlooks the Greek origin of the word as well as that history didn’t start in 1776. But we’ll forgive the Texan hyperbole because there’s so much else in the book that’s worth reading for anybody interested in the Shale Revolution.

We are invested in ENB, EPD and Tallgrass Energy GP (TEGP, the GP of TEP)