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America Seizes Oil Throne

Last week the U.S. became the world’s biggest crude oil producer. Not everyone agrees – Russian production figures still show them ahead. But the Energy Information Administration (EIA) is confident that we are, and that we’re going to stay there at least through next year.

This represents a milestone in the path towards American Energy Independence. Only 10 years ago, U.S. output was 5 Million Barrels per Day (MMB/D) and was in decline. Today it’s reached 11MMB/D and is growing rapidly.  Horizontal drilling and hydraulic fracturing unlocked the huge reserves in shale formations, and the decline was arrested. Over the next several years U.S. output grew sufficiently to more than meet global demand growth.

In 2014 Plains All American (PAGP) produced a powerful chart showing how North American crude was gaining market share. OPEC finally tired of their commensurate lost share which they believed was hurting their revenues. The subsequent 2014-16 energy sector collapse was OPEC’s attempt to bankrupt America’s nascent shale industry. Although the financial pain was widespread, the industry didn’t break. American capitalism responded – costs were slashed, productivity enhanced and a leaner, stronger shale industry emerged.

OPEC relented (see OPEC Blinks), concluding low prices were damaging their members more than the shale upstarts. U.S. production began rising again. It passed its 2014 high last year, and last week took the world’s top producer spot, well ahead of many forecasts.

It’s an epic story, with significant consequences across geopolitics, trade and the environment. America’s improved energy security is underwriting a more robust approach to Iran. In the 1970s, support for Israel in its wars against Arab states led to gas lines as OPEC’s flexed its muscle and imposed an oil embargo.

American exports of Liquified Natural Gas (LNG) are creating new trade opportunities with Asia, where South Korea, China and Japan are among our biggest buyers. In spite of the escalating tariffs with China, they recently exempted U.S. crude oil imports from a list of items subject to new tariffs. Germany’s plan to buy more natural gas from Russia via Nord Stream 2 is more easily criticized when U.S. LNG is available. Trump’s tweet, “What good is NATO if Germany is paying Russia billions of dollars for gas and energy?” is hard to fault.

American Shale gas has contributed to the world’s biggest reduction in CO2 emissions (see Guess Who’s Most Effective at Combating Global Warming). It’s made possible the shift from coal to natural gas in electricity generation. The Shale Revolution has been positive in so many ways.

Although few stop to think about it, the Shale Revolution reflects the success of American capitalism. Oil and gas originate in porous rock all over the world, but it’s taken a unique combination of advantages for the U.S. to emerge as virtually the only shale player on the planet. In America Is Great! we list the many attributes whose presence was necessary, such as a skilled energy sector labor force, existing infrastructure, access to capital, advanced technology and so on. Apart from the geology, they’re all the results of America’s capitalist system. The least appreciated is privately-owned mineral rights. All over the world, an individual’s property ownership is limited to the surface, with the government owning what’s beneath. By contrast, American landowners have been able to profit from their mineral rights. This has created private sector wealth in a way that a government claiming eminent domain of a lucrative property never could.

All this means that the Shale Revolution was not luck; if it was going to happen anywhere, it was going to be in America.

The energy infrastructure sector has been lethargic over the past few weeks. 2Q18 earnings were strong, but investor positivity was fleeting. Since early August, flows have been light and buyers cautious. The Alerian MLP ETF (AMLP) has seen outflows on most days, although that may be because people are becoming aware of its flawed tax structure (see Uncle Sam Helps You Short AMLP).

Record U.S. oil production should serve as a reminder that pipeline companies are the vital enablers of our energy success. Cash flow yields on the American Energy Independence Index are 8.75% and we expect 15-20% annual cash flow growth this year and next.  The dividend yield is 5.6% and growing 10%/year.  Hydrocarbons have to be processed, stored and moved; record volumes should support 3Q18 profits when they start being reported next month.

We are long PAGP.

We are short AMLP.

Canada’s Failing Energy Strategy

On July 6, 2013, 47 residents of Lac-Megantic, Quebec died horribly when a 74-car freight train carrying crude oil exploded in a fireball. It was the deadliest freight-train accident in Canadian history. Five bodies were never recovered and were assumed to have simply vaporized. DNA samples were required to identify others. Heat from the inferno was felt over a mile away.

In spite of this tragedy, moving crude by rail (CBR) is comparatively safe. Since 2013, safety standards have been tightened throughout North America. The International Association for Energy Economics (IAEE) found the incidence of spills with CBR to be less than for pipelines. However, this is a deceptive statistic. Once you adjust for the greater volumes of crude moved by pipeline versus CBR, as well as the greater distances covered, pipelines remain substantially safer. The report concludes that, “the risk associated with shipping crude oil is noticeably larger for rail deliveries than for pipeline deliveries.”

2,500 miles west, off the coast of Vancouver, live around 75 endangered killer whales. Their connection with Lac-Megantic is not obvious. Fortunately for the Orcas, vocal advocates have successfully made their continued survival more important than avoiding another freight train tragedy. By blocking the Trans Mountain Pipeline Expansion, they have ensured that more Albertan crude oil will reach its buyers by rail, given continued inadequate pipeline capacity.

The Trans Mountain Pipeline (TMX) was put into service in 1953, and has been in continuous operation ever since. It’s another example of the long life of installed energy infrastructure, which generally appreciates in value when properly maintained even while accounting rules allow for its depreciation. Kinder Morgan (KMI), which acquired the pipeline in 2005, had been frustrated in its efforts to more than double the capacity of TMX by adding a second pipeline alongside the first. The TMX Expansion’s approval became a provincial political football. Land-locked Alberta has few choices in exporting its crude oil.

British Columbia sought to prevent a new pipeline from Alberta reaching the Port of Vancouver. Oil that passes through on its way to export markets has little value to local residents, since British Columbia doesn’t need any more oil. Environmentalists worried about a spill, and regard Albertan oil-sands crude as exceptionally hostile to the environment (it’s true that an oil sands facility is not pretty). First Nations tribes claimed their water supplies were threatened, although of 133 indigenous groups consulted, 43 were in support. And the anticipated increase in tanker traffic at the port of Vancouver, from two to ten per week, risked displacing the dwindling community of killer whales.

It was this last point that prompted the Federal Court of Appeal to overturn the government’s approval of the expansion in late August. Although the absence of a meaningful dialogue with First Nations representatives was cited, failure to consider the increased tanker traffic, “was so critical that the Governor in Council could not functionally make the kind of assessment of the project’s environmental effects and the public interest that the (environmental assessment) legislation requires,” said the ruling, written by Justice Eleanor Dawson. Canadian law provides wildlife with considerable protections.

In a deft move, KMI had by now extricated themselves from the vagaries of Canadian energy policy. For months, they had complained about the impossibility of building a pipeline linking two provinces holding opposite views on its completion. Finally, in May they unburdened themselves of the whole sorry mess and sold TMX to the Canadian Federal government for C$4.5BN, viewed by many as a pretty full price. KMI shareholders dodged a bullet.

A few weeks after agreeing the sale of TMX, KMI estimated in a filing that completion of the expansion would cost C$1-1.9BN more than originally expected and take a year longer. On August 30th, KMI shareholders formally approved the sale, hours after the Court of Appeal ruling. TMX was by now worth considerably less than the C$4.5BN paid — the bailout by Canadian taxpayers was complete.

Prospects for the TMX Expansion are uncertain, with a delay of two years or more seemingly inevitable. The Canadian government is considering an appeal, redoing its environmental review, and crafting legislation to force it through. Canada wants to complete the pipeline. Meanwhile, Alberta grumbles about contemplating separatism, and has in the past suggested that it might halt crude oil shipments to British Columbia altogether.

Canadian crude oil will continue to reach its buyers, although more of it will move by rail. The International Energy Agency expects CBR shipments to double over the next two years due to lack of pipeline capacity. Suncor, Canada’s largest oil and gas producer, won’t expand crude oil production until it sees progress on pipeline approvals. The persistent $25-35 per barrel discount of Western Canadian Sedimentary crude to the WTI benchmark is directly linked to limited transportation choices, and must be regarded as a huge success by Alberta’s neighbors in British Columbia. Since the U.S. is both its biggest energy customer and nowadays its biggest competitor, Canada’s position is unenviable.

American readers will be relieved that such extreme dysfunction doesn’t exist in the U.S. Recall though, Boston’s annual winter imports of liquefied natural gas from Trinidad and Tobago to keep the lights on.  Pipeline opposition isn’t limited to our northern neighbor (see An Expensive, Greenish Strategy).

The investment takeaway is that opposition to new pipelines increases the value of those already installed. When shippers resort to rail to move crude oil, their bargaining position on pipeline tariffs is weak. Oil and gas companies suffer lower revenues, consumers higher prices, and railway lines benefit if demand is sustained long enough to justify their capex. But for pipeline companies, installed pipelines with decades of useful life can represent a scarce resource. If the possibility of excess pipeline capacity concerned markets during the 2014-16 energy sector collapse, we are now headed solidly in the other direction.

We are long KMI.

Could Oil “Super-Spike” Above $150?

In July, Pierre Andurand’s hedge fund, Andurand Capital, lost 15% on bullish crude oil bets. Oil was weak in July, but is up 21% in 2018. Notwithstanding this correct outlook, his fund is -5% for the year. Few things are more frustrating for a manager or his clients than losing money on a profitable call.

Putting aside the challenges of hedge funds, which we have amply covered in years past (see The Hedge Fund Mirage; The Illusion of Big Money and Why It’s Too Good To Be True), a bullish outlook on crude enjoys solid fundamental support. Andurand once ran a hedge fund that profited mightily during the 2008 financial crisis, only to fold following large losses in 2011. More recently though, his calls on oil have been better than most (see Fund Chief Survives Oil’s Swings), including correctly forecasting the 2014-15 collapse. Few of his peers successfully navigated this period. Reportedly, Andurand sees a multi-year bull market that could eventually reach $300 a barrel. Bernstein Research, whose deep investment analysis is widely respected, has warned of a “super-spike” above $150 a barrel.

Both supply and demand for crude oil are relatively inelastic over periods of a few quarters or so. Global transportation relies heavily on refined petroleum products. Higher prices discourage some trips, but for the most part miles driven and flown don’t dip much with higher prices. Bringing on new supply typically takes several years. So over the short run, small shifts in demand or supply disproportionately move prices.

Global crude oil demand rose by 1.7MMB/D (Million Barrels per Day) last year and in 2016, up from the ten year average of 1.1MMB/D. Demand growth is driven by developing countries, especially China and India. But far more important to a balanced market is depletion of existing oilfields, something that receives little attention. Output from most plays peaks early in their operational life, when underground pressure is most effective at pushing oil to the surface. Thereafter, production steadily declines. Estimates vary, but most analysts agree that 3-5MMB/D is the global drop in annual production from existing plays, absent any new recovery-enhancing investments.

This year the Energy Information Administration (EIA) estimates that the world will consume 100 MMB/D, a record. In order to offset depletion plus demand growth, new supply of around 5-7MMB/D is required.

Following the oil price crash 2014-15, energy companies adopted greater financial discipline and planned for lower oil prices in the future. The combination of higher required returns and lower assumed prices has had a chilling effect on investment. The U.S. Shale Revolution is at least partly responsible. U.S. output barely dipped during the 2014-15 collapse.  Although low prices weren’t sustained for long, the episode caused subsequent projects to be evaluated against the possibility of a repeat. For example, in April BP’s chairman said they were, “still working with the assumption that this is going to be a world with an abundance of oil.”

Major oil projects have always had risk to input costs and demand over the ensuing decade or longer. But today, those risks are even harder to quantify. It’s generally believed that oil demand will peak within a generation, yet growth in recent years has been as high as ever. Although Electric Vehicles (EVs) have many enthusiasts, sales growth of gasoline-chugging cars easily outpaces EVs in China, which is why crude demand keeps growing.

Improved financial discipline, wariness of a second Shale-induced price collapse and uncertainty around EV growth are three significant factors impeding investments in new supply. Taken together, these three factors have created greater risk aversion than the industry has shown in the past.

Consequently, capital invested in conventional projects remains low and projects are more modest. Companies are favoring “short-cycle”, whose smaller up-front investment consequently gets repaid more quickly with greater IRR certainty.

However, there just aren’t enough short-cycle projects available, which is causing concern within the industry. Schlumberger CEO Paal Kibsgaard warned that, “It is, therefore, becoming increasingly likely that the industry will face growing supply challenges over the coming year and a significant increase in global exploration and production investment will be required to minimize the impending deficit.” Bernstein Research concurred, “Investors currently calling on exploration and production companies to return more cash to shareholders at the expense of funding future production may also come to regret their strategy.”

There are many examples of countries underinvesting in maintaining existing levels of production.

Because less risky, short-cycle projects are mostly shale plays in the U.S., a stark difference in financing has opened up between America and Europe. EU bank financing for Exploration and Production, always far smaller than in the U.S., has collapsed in recent years.

Although Saudi Arabia is believed capable of producing as much as 12.5 MMB/D for a few months, many observers feel this is unsustainable. U.S. shale is one of the few areas of growth. Permian output in west Texas is expected to average 3.3 MMB/D this year and 3.9MMB/D in 2019. Yet, infrastructure constraints recently caused the EIA to trim its outlook for U.S. 2019 production from 11.8MMB/D to 11.7 MMB/D, up 1 MMB/D versus this year. Concern that U.S. production could lead to another price drop is limiting new global investment – yet, the most optimistic forecasts of U.S. output show that significant additional new supply beyond US shale is going to be needed.

A determination to avoid past mistakes of unprofitable oversupply is likely to lead to the opposite; an undersupplied oil market. The question is, how high must crude go to satisfy the new profitability goals and other concerns of the integrated oil companies. Many fear that $100 a barrel will be insufficient – and the market is poorly positioned for any supply disruptions, perhaps caused by Iran or some other geopolitical shock. Another Shale-induced price collapse, falling demand due to EVs and new-found financial discipline represent long-term concerns inhibiting the search for new discoveries.

Oil needs to be high enough to compensate for all three risks. Since today’s prices aren’t high enough to stimulate enough new investment, oil should move higher. This will encourage conventional investment, but will also test the limits of the U.S Shale Revolution in growing output.  To bet on increasing oil and gas volumes in the U.S., invest in the network of infrastructure that moves these supplies to market.

The components of the American Energy Independence Index are growing dividends at 10% per annum.

Reliable Yields Are the Best

Before jumping at an attractive yield, investors should pause to consider its consistency.

In recent years, traditional MLP investors were victims of one of the greatest betrayals in U.S. financial history. Older, wealthy Americans were drawn to companies that paid out most of their cashflow in distributions. For years, America’s energy came from roughly the same places in the same amounts, which meant little need for pipeline operators to re-invest in the business. The Shale Revolution changed all this – new sources of oil and gas required new infrastructure (see Will MLP Distribution Cuts Pay Off?).

MLPs decided to grow, redirecting cashflows from payouts to new projects. K-1 tolerant, income seeking investors were the quintessential long term buyer sought by every CEO. All they wanted was stable income. Although for years MLPs provided this, in 2014-15 many of them seized the opportunity to be growth businesses, which redirected cash away from investors. Alignment of interests was lost. MLPs in aggregate demonstrated that Distributable Cash Flow would be paid to investors only as long as they didn’t have any better uses for it. Payouts were cut, trust was shattered. Today’s sector remains 28% below its August 2014 high, and its recovery offers something for everyone (see Growth & Income? Try Pipelines).

Stable and growing dividends remain highly valued. Although the Alerian MLP ETF (AMLP) has cut its distribution by 30% (see It’s the Distributions, Stupid!), Alerian used to post a chart with 6% average ten year distribution growth.  Index components change, and Alerian was using the historic growth of existing index members regardless of how long they’d been in the index. This introduced a survivor bias, in that MLPs cutting distributions used to be dropped while the newly IPO’d ones they added were typically growing quickly. This confused many, because it failed to match actual investor experience. It seemed that everyone but Alerian knew MLP distributions were being cut. Facing growing criticism (see MLP Distributions Through the Looking Glass), Alerian revised their chart to better match reality.

However, energy infrastructure overall has provided far more distribution stability than shown by MLPs. The American Energy Independence Index consists of the biggest pipeline companies in America, which are mostly corporations although it includes a few MLPs as well. It yields 5.5% based on 2018 dividends, a payout that is up 10% on 2017. We expect dividend growth of almost 11% next year. While income seeking investors are naturally drawn to attractive yields, the reliability of the payout is critical.

The chart shows that Alerian MLP Index dividends fell far more than for energy infrastructure as a whole. Moreover, they still have a long way to recover back to the levels of 2014. Although we think MLP distribution cuts are mostly behind us, the group’s history is one that income seeking investors shouldn’t soon forget. By contrast, American Energy Independence Index dividends dipped but quickly recouped their losses. The members of this index have demonstrated far more reliability with their payouts.

The Alerian MLP Index yields 7.3%, although it’s only accessible via structurally flawed MLP-dedicated funds that pay corporate tax (see The Tax Drag on MLP Funds). Because tax expense for such funds flows out of their NAV, in reality, the yield is lower. The energy infrastructure sector’s 5.5% yield is accessible through conventional, RIC-compliant funds with no tax drag. Corporations have managed their cashflows, including payouts, far more reliably than have MLPs. Moreover, those lower payouts have meant more retained earnings to be reinvested back into their businesses.  This is what will drive the 10% annual dividend growth we expect 2017-19, a level MLPs failed to achieve even in the boom years leading up to the 2014-15 collapse.

As the second chart shows, when payouts are cut less in the short run, they grow faster over the long run. Energy infrastructure is a growth business that offers attractive yields. Investors who favor companies with a reliable history of dividends are likely to fare better.

We are short AMLP.

Growth & Income? Try Pipelines

The chart below is a sobering one for pipeline investors. Over the past five years, the S&P has returned 13.1% p.a., versus -2.7% for the Alerian MLP Infrastructure Index (AMZIX). An allocation to AMZIX contributed almost a 16% p.a. performance drag, such that $100 invested in the S&P500 in July 2013 would now be worth $185 rather than $71. The Alerian MLP Fund (AMLP) did 1% p.a. worse than this.

Starting in 2014, oil prices collapsed and MLP unit prices followed. As a consequence, energy infrastructure has a correlation with the S&P500 of only 0.63, which makes it an interesting diversifier. Cuts in payouts to fund growth were poorly received by an income-seeking investor base (see It’s the Distributions, Stupid!). Sentiment remains cautious. However, there are growing signs that pipeline companies have turned the corner.

Dividends have started growing again. 2Q18 earnings were full of upside surprises, as higher volumes drove profits. Energy Transfer Partners (ETP) telegraphed a good quarter when discussing its combination with Energy Transfer Equity (ETE), (see Running Pipelines is Easy). Their Distributable Cash Flow (DCF) duly came in 17% ahead of expectations, in part through higher capacity utilization. Analysts expect to see 15% annual growth in DCF over the next two years.

Enterprise Products (EPD) reported a 2Q18 EBITDA beat of 13%. Enlink Midstream, LLC (ENLC) provided higher 2019 guidance. Kinder Morgan (KMI) is reducing leverage faster than expected due to its sale of TransMountain Pipeline to the Canadian government. DCF at Cheniere (LNG) is expected to grow 3 fold over the next two years as Liquefied Natural Gas exports take off. It was hard to find any bad news.

Many of the biggest MLPs have converted to corporations, which makes the Alerian MLP Indices less representative of the sector than in the past. Last year we launched The American Energy Independence Index, which holds a diversified basket of the largest North American pipeline corporations, along with a handful of big MLPs. It yields over 5%, and we expect DCF growth of 15-20% annually through 2020. This will support healthy dividend growth as well as improved coverage ratios.

This resumption of dividend growth is attracting investors again, which has helped the sector to a higher YTD return than the S&P500.

Energy infrastructure offers a low correlation with the market, as well as being attractively valued with improving fundamentals. Adding pipeline exposure can improve a portfolio’s prospects while adding some diversification.

We are long EPD, ENCL, ETE, KMI.

We are short AMLP.

It’s the Distributions, Stupid!

Jim Carville’s admonition during Bill Clinton’s 1992 run for President was, “It’s the economy, stupid!”

In its August 2018 edition, The Utility Forecaster warns readers to approach MLPs “with caution.” Too risky for income investors is their conclusion. MLP buyers have been badly abused, and Chief Investment Strategist Robert Rapier reminds readers of the many “simplifications” that triggered unwelcome tax bills, as well as the multiple distribution cuts. Without doubt, MLP prices have followed distributions.

In one important respect though, Rapier adopts a simplistic yet incorrect explanation. “…during a long downturn in oil and gas prices, contracts expire and MLPs had to renew agreements under less favorable terms. Many MLPs found themselves doing what was once unthinkable – they had to cut distributions.”

It’s conventional wisdom that the 2014-15 oil collapse hurt pipeline company operating earnings, which caused payout cuts. But the numbers don’t support this narrative. The Kinder Morgan (KMI) chart below shows their Distributable Cash Flow (DCF) per share alongside a significantly more volatile stock. KMI’s DCF per share is little changed from 2015 to 2016, but the share price fell by half. They cut their payout twice: once when combining Kinder Morgan Partners (KMP) with KMI (“simplification”, in which KMP investors received KMI stock with a lower payout as well as a tax bill); and again later when KMI cut its dividend. KMI was learning that MLP investors want income over the promise of growth.

To fund their growth projects, KMP was paying out most of its DCF and then seeking to recoup some of it through secondary offerings.  In effect, investors were being asked to reinvest a portion of their distributions back into the company. Many holders found this unattractive, since they spend the income. So KMP’s yield rose, which made issuing equity too expensive. KMI concluded MLP investors no longer suited their purpose, and left to become a corporation. Today, KMI yields 5.1%, with a payout more than 2X covered by its $4.7BN DCF.

MLP buyers can be focused on distributions to the exclusion of anything else. Two recent examples highlight:

In late July, American Midstream Partners (AMID) slashed its distribution by 75% so as to, “…significantly reduce leverage, provide capital for strategic growth opportunities, and create long-term value.” Although these all sound like desirable objectives for a total return investor, AMID’s stock fell 43%.

Meanwhile, Hi-Crush Partners (HCLP) tripled its distribution and now yields 23%. The higher payout is unlikely to persist, but if it’s sustained for a year the company will convert to a corporation. Whether or not this is good for investors, its stock rose 28% on the day of the announcement.

MLP investors want their income.

The chart from Bank of America is even more striking. On the MLPs they cover, they show steadily growing EBITDA with improving leverage, alongside a declining Alerian MLP Index. Falling MLP distributions clearly drove index performance more than improving financials.

It’s as if MLP investors look at payouts and little else.

Probably the simplest measure of MLP payouts is to look at dividends on the Alerian MLP ETF (AMLP), which are 30% lower than in 2015.

There were nonetheless some companies whose operating performance sagged. Plains All American (PAGP/PAA) relied in part on its Supply and Logistics division to support its distribution. When arbitrage opportunities dried up in 2016-17, almost $800MM in EBITDA evaporated, leading to a second distribution cut. Today, increased Permian volumes are boosting cashflows once more. On last week’s earnings call they forecast 2019 EBITDA growth of 14-15%.

But episodes such as PAGP were the exception – operating results for the most part held up.

As memories of the 2014-15 bear market recede, we believe the conventional explanation for it will shift. MLP prices didn’t collapse because of weak operating performance. They fell because DCF was redirected to pay down debt and finance new projects, all to achieve growth (see Will MLP Distributions Pay Off?). Income seeking MLP investors don’t want their income redirected in this way. Hence, persistently weak MLP prices which have led the shift to a corporate structure for those companies wishing to access a far larger pool of buyers.

BofA Merrill is forecasting 2016-20 distribution growth for 27 of the 32 midstream infrastructure names they cover. JPMorgan forecasts 6-10% growth 2017-19. We expect our American Energy Independence Index to grow its dividends by 9% this year and 11% in 2019.

These forecasts are supported by growing pipeline demand. There are bottlenecks in moving crude oil and natural gas out of the Permian Basin in west Texas, and in getting natural gas out of the Marcellus in Pennsylvania. New pipelines to transport Canadian heavy oil from Alberta continue to face political challenges. The Shale Revolution is driving volumes higher.

With pipeline demand and dividends both growing, the sector is poised to continue its rally.

We are invested in KMI and PAGP. We are short AMLP.

Includes corrected text and a revised chart compared to an earlier version, with respect to Kinder Morgan

Running Pipelines is Easy

“A monkey could make money in this business right now.” Kelcy Warren, Energy Transfer Partners CEO, August 2nd, 2018.

Presumably when Energy Transfer Partners (ETP) announces earnings next week they’ll be good. That was the clear message in the attention grabbing combination of ETP with its General Partner (GP), Energy Transfer Equity (ETE). The 1.28 exchange ratio represented an 11% premium but also a 30% distribution cut for ETP investors, given ETE’s lower payout. The new company anticipates coverage of 1.6X-1.9X by 4Q18, a Distributable CashFlow (DCF) yield of 11.5% based on its current price.

Kelcy Warren’s comment on favorable conditions contributed to positive sentiment across the sector, something that has been sorely missing until recently. Wall Street’s most recent solution to the weak MLP market has been eliminating the GP/MLP structure, and with it the Incentive Distribution Rights that boost the GP’s share of DCF. ETE endorsed that recommendation, but still retained some special rights through the issuance of “A” class shares to insiders. Overall though, we think this move shows ETE’s attractive valuation.

In 2Q results, pipeline companies reported earnings buoyed by higher volumes. Output of natural gas, Natural Gas Liquids (NGLs) and crude oil are all hitting new records. The U.S. is on track to be the world’s biggest oil producer by late 2019 – if infrastructure bottlenecks don’t delay that for a year.

As pipeline capacity out of the Permian Basin has dwindled, it’s caused a spectacular widening in regional differentials. Crude oil in Midland, west Texas is worth $17 less per barrel than in Cushing, OK. This reflects the cost of moving the marginal barrel, which has to go by truck since there’s no spare capacity on pipelines or railroads. This $17 differential is a thing of beauty to a pipeline owner with some uncontracted availability. For oil producers faced with unexpectedly steep shipping costs, it’s a hit to profitability. The larger companies tend to have committed transport which guarantees them access to market. For example, Devon Energy (DVN) reported realizations on crude oil production within 2% of the Cushing benchmark. It’s the smaller, more speculative companies that stand last in line.

Enterprise Products (EPD) reported Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) of $1.767BN, $202MM ahead of consensus. One analyst announced, “EPD Embarrasses Street Estimates”, while his own equally inaccurate earnings forecast sat alongside an “Overweight” recommendation. Wrong, but right too.  EPD reported strong volumes across NGLs, crude, natural gas and propylene (feedstock can be ethane or propane).

EPD is the biggest MLP, and they’re succeeding by behaving like the corporation many of their peers have become. Although MLPs pay out 90% or so of their DCF, EPD sports a coverage ratio of 1.5X (i.e. pays out only two thirds). Consequently, they announced almost $500MM in retained DCF which they plan to reinvest in the business. While MLPs historically have funded growth with new issuance of debt and equity, EPD is self-financing. While they’re not planning to buy back stock, their 5.9% distribution yield compares favorably with the S&P500 yield from buybacks and dividends of 4.5%.

EPD hasn’t over-borrowed and then cut its distribution to fund growth, like many MLPs. By behaving unlike MLPs, it’s remained one, while many others have offended their investors and decamped in search of new ones as a corporation. American Midstream Partners (AMID) is a small MLP that shrunk further following a 75% distribution cut. They plan to redirect the savings, “…towards accretive growth projects and reduce debt.” Their income-seeking investors, now substantially deprived and less excited than management about this redirection of cash, let the stock fall 50%.

EnLink Midstream, LLC (ENLC), the GP of Enlink Midstream Partners (ENLK), beat EBITDA expectations by 5%, while raising guidance. This propelled both ENLC and ENLK sharply higher. Regrettably for the EPD analyst noted above, his miss on earnings was compounded with an Underweight on ENLC.

Oneok (OKE) reported increased pipeline utilization and modestly increased full-year guidance. Since absorbing their MLP last year OKE has become the poster child for such conversions, outperforming the Alerian MLP Index since then by over 35%. In the ensuing year OKE has announced $4.3BN of growth projects and in January issued $1.2BN in equity. Their Debt/EBITDA is down to 3.4X. Former Oneok Partners (OKS) investors endured an adverse tax outcome as they swapped their LP units for OKE shares, so at least the subsequent rally offers some vindication.

Williams (WMB) met expectations but guided to higher capex on new projects. Investors liked the prospect of accretive growth and drove the stock up 3%.

Crestwood (CEQP) raised guidance again, continuing a strong run of operating performance under CEO Bob Phillips.

It was hard to find any bad news in energy infrastructure. The sector also diverged pleasingly from the S&P500 Energy ETF (XLE), as mixed earnings from large producers such as Exxon Mobil (XOM), Conoco Phillips (COP) and Devon Energy (DVN) weighed.

If MLPs had all behaved like EPD, and unlike AMID, there would be more MLPs today. Elliot Miller is a frequent commenter on our blog. We had the opportunity to meet Elliot in person in May, at the Orlando MLP and Energy Infrastructure Conference. Elliot is a very thoughtful investor who gently chides us from time to time for not being more constructive on MLPs. We attended a couple of investor events with Elliot, and his pointed questions were well-aimed and entertaining. He’s right that MLPs’ enhanced tax status gives them an advantage, and Elliot might agree that EPD represents investor-oriented management at its best. ETE clearly intends to retain the tax benefits of an MLP as well.

Just as too few MLPs have behaved like EPD, there are too few Elliot Miller-like investors willing and able to do careful research. Many traditional MLP investors are disillusioned with distribution cuts to fund growth (see Will MLP Distribution Cuts Pay Off?). More Elliots would have led fewer MLPs to convert to corporations.

Many potential buyers are attracted by valuations but fearful of a repeat of the 2014-16 collapse. We’ve long maintained that this was chiefly caused by issues of financing growth, with midstream operating performance back then remaining generally satisfactory. Valuations are good, and corporate dividends growing. The corporate-heavy American Energy Independence Index has seen 9% dividend growth year-on-year, with >10% likely next year.

As the memories of the ‘14-‘16 sell-off recede and increased hydrocarbon throughput continues to drive profits, additional investors will be drawn to the sector.

We are long CEQP, ENLC, EPD, ETE,  OKE, WMB.

Uncle Sam Helps You Short AMLP

The Alerian MLP ETF (AMLP), with its tax-burdened structure (see AMLP’s Tax Bondage), is by design unable to come close to the return on its benchmark, the Alerian MLP Infrastructure Index (AMZI). Because AMLP doesn’t qualify for treatment as a Regulated Investment Company (RIC), it’s subject to corporate income taxes just like any other corporation. The fund’s tax liability has acted as a substantial drag on returns; since inception in 2010, it has returned just 1.99% (through June 30th), less than half its benchmark of 4.39%.

When AMLP’s portfolio rises, its NAV lags by the amount of the additional tax liability. When its holdings fall, AMLP reduces its taxes owed which cushions the blow somewhat. In fact, the tax drag acts to dampen its volatility. Tax-impaired returns ought not to be that attractive, although occasionally an investor notes that he likes the resulting lower volatility. While MLPs have been choppy in recent years, embracing this type of tax-encumbered, reduced price movement seems wrongheaded; after all, AMLP holders presumably expect a positive return, and the tax structure lowers it.

AMLP is simply the biggest of around $50BN in flawed funds. The chart below is from an Oppenheimer prospectus which helpfully explains how taxes hurt returns on their funds.

In an additional wrinkle to the pay-off profile, taxes only accrue when AMLP has unrealized gains. In such cases it holds a Deferred Tax Liability (DTL). When it has unrealized losses, as currently, it doesn’t accrue a tax loss carryforward, or Deferred Tax Asset (DTA). At such times the tax-induced low volatility disappears, and AMLP moves up and down with the market.

We are approaching an inflection point. AMLP’s unrealized losses are shrinking as the sector grinds higher. Its current DTA (which is offset with a valuation allowance, thus negating it) will flip to a DTL with the next 4-5% rise in its portfolio. At that point, further gains will trigger taxes owed. Its modestly lower volatility will return. With an approximate tax rate of 23%, AMLP will provide its holders with only 77% of the upside or all of the downside.

Like the approach of a surfer’s perfect wave, this situation offers the AMLP short-seller a rare, asymmetric opportunity. Just as an AMLP holder is accepting diminished upside for full downside risk, the AMLP short will enjoy the complete benefit on the downside with constrained losses on the upside. Combining a short AMLP with a diversified long position in energy infrastructure names or a properly structured, RIC-compliant, non-tax-burdened fund creates an interesting trading opportunity.

Such a long/short portfolio should be profitable in a rising market and roughly breakeven in a down market. There are financing costs, but AMLP has $10BN outstanding and so is not that hard to borrow.

Because AMLP is 100% invested in MLPs, a diversified long portfolio that includes energy infrastructure corporations further allows the investor to bet on a continued shrinking of MLPs as a subsector of energy infrastructure. As the biggest MLPs convert to corporations where they can access a far bigger set of buyers, this leaves fewer names with a lower median market cap (see Are MLPs Going Away?). MLP fund investors face the additional risk that one of the larger funds elects to drop the tax burden by selling 75% of its MLPs, becoming RIC-compliant. This could depress MLPs and hurt valuations of all MLP-dedicated funds.

This kind of asymmetry has value. Option premiums reflect the substantial upside/downside difference for the holder. Long-dated bonds (most dramatically, zero-coupon bonds) also offer a modest amount of asymmetry due to convexity, which causes investors to drive their yields somewhat lower than they’d otherwise be. In theory, AMLP should trade at a discount to NAV because of its tax-driven asymmetry, reducing the benefits of shorting and providing some additional return to holders to compensate for its flawed structure. Because the AMLP short is receiving the benefit of the tax drag, it’s one of the few ways you can really get Uncle Sam to work for you.

The benefits of shorting AMLP highlight the diminished return prospects of the holders. There are several other similarly tax-impaired funds, including mutual fund products from Oppenheimer SteelPath, Cushing Mainstay and Goldman Sachs, and a couple of small ETFs. While none of these are short candidates, they all suffer from the same structural flaws as AMLP. Their holders are unlikely to enjoy returns close to the indices, even while they incur unimpeded downside risk.

MLP-dedicated funds are unique in owing taxes at the fund level. Fund investors seeking energy infrastructure exposure should select a RIC-compliant, non-tax paying fund with less than 25% in MLPs.

We are short AMLP.

FERC Boosts MLPs

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.

Is Shale Driving Oil Higher?

Could the Shale Revolution be driving oil prices higher? It seems counter-intuitive – the U.S. is on course to be the world’s biggest oil producer by next year. And it was the additional shale supply that led to the 2014-15 oil collapse.

Yet, a growing chorus of industry voices is warning of an impending supply squeeze. This includes the Saudi Energy Minister, Khalid A. Al-Falih, who recently expressed concern about shortages of spare crude oil capacity. Last week David Demshur, CEO of oilfield services company Core Laboratories (CLB) forecast oil at $100 a barrel. He cited declining output in many key conventional plays globally, even while U.S. output is growing strongly. The International Energy Agency added their warning that, “…the world’s spare capacity cushion…might be stretched to the limit.”

Part of the problem relates to supply disruptions. Venezuela’s output continues to plummet because of chronic underinvestment. Renewed sanctions on Iran are impeding their exports sooner than expected. Saudi Arabia has promised to increase output to offset the loss of Iranian crude, but many question their ability to sustain output much above 11 Million Barrels a Day (MMB/D).

Meanwhile, global oil demand is expected to grow at around 1.5-1.7 MMB/D over the next year. Depletion of existing fields, estimated at 3-4 MMB/D annually, is worsening according to some observers. So the world needs at least 4-6 MMB/D of new supply to balance current consumption of around 98 MMB/D. Concern is growing of a shortfall.

Although blaming the Shale Revolution for a looming supply shortage sounds implausible, Shale’s lower risk profile is drawing capital investment away from conventional projects. You can see this in Exxon Mobil’s (XOM) five year plan to commit $50BN to North American oil and gas production. You can also see it in the dramatic decline in the size of large projects. As we’ve noted before (see The Short Cycle Advantage of Shale) conventional oil and gas projects take far longer to return their capital invested than shale projects.

The energy business has always been cyclical for this reason, because of the supply side’s slow response function. Shale’s ability to recalibrate output much more responsively to price can smooth out the cycle, if there’s enough short-cycle supply available. But there isn’t. North America is the major source of such projects and virtually the only source of shale activity. Rising U.S. output is nonetheless insufficient to provide adequate supply.

Conventional projects have always had to consider macro factors, such as global GDP growth, commodity prices and production cost inflation before committing capital. Add to those the likely path of government policies aimed at curbing fossil-fuel related global warming, and the unknown pace of technological improvement with electric vehicles. Today it’s probably as hard as it’s ever been to confidently allocate capital to a conventional oil or gas project with a 10+ year payback horizon.

Moreover, short-cycle projects like Shale lurk in the background, capable of wrecking the market with oversupply, yet able to protect themselves by quickly curtailing production.

This uncertainty is limiting the commitment of capital to conventional projects. If the warnings are prescient, oil prices will rise to a level that induces more investment back in to conventional projects. The market will self-correct. But it’s looking increasingly likely that higher prices will be required in the meantime.

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