Crude and MLPs March Higher Together

For the first half of the year crude oil prices moved irregularly lower before bottoming in June, since when they’ve moved smartly higher. Master Limited Partnerships (MLPs) have roughly followed this path, and have also moved smartly higher in recent weeks. Non-crude cashflows drive MLP operating performance, but crude drives investor sentiment. No amount of typing by this blogger will shake the relationship between the prices of MLPs and crude.

Interestingly though, U.S. crude oil production has continued to grow all year, seemingly impervious to prices. From 8.85 Million Barrels a Day (MMB/D) in January, output reached 9.2 MMB/D in June. Hurricane season caused a slight late Summer dip in the Gulf of Mexico, but the Energy Information Administration (EIA) is forecasting an average of 9.3 MMB/D for the full year. Production is therefore forecast to continue rising into 2018, for which the EIA is forecasting 9.8 MMB/D. That would eclipse the prior record of 9.6 MMB/D set in 1970. America is Great!

Longer term oil forecasts from both the EIA and the International Energy Agency (IEA) are for rising prices. The EIA’s International Energy Outlook 2017 models crude oil roughly $25 higher by 2020. The IEA goes even further, warning of the risk of a price spike by 2020. They cite growth in annual demand of 1.6MMB/D (around 1.7%) as well as too little new investment in new sources of production. They note that spare capacity (mostly OPEC) of 2 MMB/D doesn’t even cover two years of growth in demand, and expect OPEC to eventually abandon their production limits.

As an aside, a friend recently told me about an investor he knows who is convinced oil prices will collapse as consumers flock to electric vehicles (EVs)  and shun the internal combustion engine. That is almost certainly not going to happen. In fact, depressed crude oil would be just about the worst thing for Tesla fans, because it would hurt their competitiveness. High oil prices combined with strong demand for EVs is a possibility; low oil prices and disinterest in EVs is another. Cheap gasoline will dampen the enthusiasm of those opting for environmentally-inspired transportation choices. Moreover, internal combustion engine technology improvements continue to reduce emissions, narrowing the gap with EVs.

The EIA expects overall energy use to grow worldwide even while energy intensity drops (meaning it’s used more efficiently for a given level of GDP). Other than coal, all sources of energy will see growing production with renewables growing the fastest. Non-OECD Asia is responsible for most of the forecast growth in energy consumption through 2040, including 80% of the growth in petroleum and other liquid fuels.

During the 2015 collapse in crude prices, U.S. production dipped but surprised many (including OPEC) at how robust it stayed. The drop in crude early this year didn’t seem to affect domestic output at all. We now seem to be moving into a period of rising prices combined with rising production. U.S. shale output just isn’t growing fast enough to satisfy the 1.6 MMB/D in new demand noted above as well as offset global depletion (estimated at 3-4 MMB/D annually; see Why Shale Upends Conventional Thinking). The world needs another 5-6 MMB/D in new supply, annually. Rising prices will stimulate shale drillers into more activity, but not enough to depress prices.

In presenting their latest forecast, IEA oil markets head Neil Atkinson conceded, “We underestimated the resilience of U.S. shale producers. We failed to understand the resilience. We failed to appreciate the technical ingenuity.” In other words, the IEA underestimated America. So did OPEC last year (see OPEC Blinks). Both the EIA and the IEA have had to recalibrate their models to reflect the ongoing success of U.S. shale (see Oil Forecasters Have to Work Harder).

Rising crude prices along with rising U.S. output could be just as potent for energy infrastructure stocks as the opposite combination was bad in 2015. Moreover, it’s not only crude output that is rising; the EIA is forecasting natural gas production to average 73.7 Billion Cubic Feet per Day (BCF/D) in 2017. This is up 1.4 BCF/D from 2016, and in 2018 a further jump of 4.4 BCF/D is expected.

Clearly, for the U.S. energy sector, its best days are still ahead.

Below is a new trademarked logo we have designed for our energy infrastructure business. We believe the Shale Revolution is leading to American Energy Independence, and our investment choices increasingly reflect the search for those businesses that will most clearly benefit. Expect to see more of this logo in the months ahead.

Litigating Away From a Cleaner Future

Earlier this month I visited a good friend and client in London where he invited me to address some Summer interns about what we do. In the first moments I was asked if I’d considered the moral aspects of enabling fossil fuel use. Recently armed by Alex Epstein (see The Moral Case for Fossil Fuels), I was able to parry by challenging them to define the metric by which energy use should be justified. Greater use of fossil fuels has led to enormous benefits for humanity (the only proper metric). Draconian cuts in fossil fuel use as advocated by some simply mean rationing energy. Developing nations use less energy than America and suffer shorter life expectancy as a result. Energy improves lives in countless ways.

When U.S. Secretary of State John Kerry advised Indonesians in 2014 to insist on clean energy while 31 million of them can’t access clean water, he was not occupying the high moral ground. Hygiene requires energy. Debating such issues with young college students is wonderfully stimulating; this group was smart and quickly willing to consider views that they initially perceived as unconventional. It’s impossible to leave such exchanges with anything other than a very positive outlook for the future.

Every rational person cares about the environment. However, sometimes those who describe themselves as “Environmentalists” hold an absolutist view that in its extreme formulation works against the very goals they strive for.

When the Federal Energy Regulatory Commission (FERC) approves a pipeline, they are usually required by Federal law to prepare an Environmental Impact Statement (EIS). This examines the impact on the surrounding area of building the pipeline, and assesses whether it’s in the public interest to proceed. Although the Sierra Club pursues many admirable goals, a recent legal challenge to a FERC-issued EIS reflects the practical challenges of being a purist.

Last month, the Sierra Club successfully argued in the U.S. Court of Appeals (DC Circuit) that an EIS should include the impact of burning the natural gas moving through a pipeline. Currently, FERC only considers the direct impact of pipeline construction. The Court found that the emissions from burning the natural gas delivered by the pipeline also needed to be considered in the EIS. The project in question is the Southeast Market Pipelines Project (SMPP) and it is already in operation transporting natural gas to Florida from points west. It’s possible the SMPP network may at some point be forced to suspend operations, although for now the legal battle continues and may even reach the Supreme Court. But the results won’t necessarily meet the Sierra Club’s goals.

Put aside the chilling impact on future infrastructure investment of a project approved by the regulator that might yet be hampered by legal challenges, even following completion. The Sierra Club, by opposing ALL fossil fuels (as well as nuclear power), makes their goal of a fully solar/wind energy sector Utopian, even farther out of reach.

Recent history shows that natural gas has helped the U.S. achieve cleaner electricity production than Germany, a proud champion of renewable energy. As we wrote earlier this year (see It’s Not Easy Being Green), because it’s not always sunny and windy, solar and wind rely on conventional sources of power to provide baseload supply. There’s still no commercial technology to store electricity from sunny days for use at night. In the U.S. that baseload is increasingly from natural gas, which is replacing coal over which it enjoys substantial emission advantages; not just less CO2 but no Sulfur, Mercury or other nasty particulates.  What Germany is finding is that because their baseload reflects a higher mix of coal, the positive effects of sunny, windy days are being offset.

Although it’s known as the Sunshine State, today Florida uses very little solar. Only 2.4% of its electricity comes from renewables (mostly biomass). However, that is changing and Florida Power and Light (FPL) is adding 2,100 MW of new solar capacity by 2023. Duke Energy Florida plans to add 700 MW by 2021. In June, Florida’s power plants produced 21,611 GWH of electricity. The 2,800MW of solar capacity additions noted could, if run at 100% of capacity 24X7, represent 10% of Florida’s electricity.

But they won’t, because even Florida is not permanently sunny. Solar’s intermittency means lower utilization than gas or coal plants and creates a symbiotic relationship with other, reliable sources of power. The Shale Revolution has unlocked enormous reserves of natural gas, and its abundance has led directly to a preference by utilities to switch away from coal. Across America, power stations have been exploiting this huge advantage to achieve significant improvements in emissions. This success is all the more remarkable when you consider that the Federal government is ambivalent at best about adopting formal goals to reduce emissions.

There’s a certain intellectual incoherence in opposing a source of energy that enables wider use of renewables and is already driving emissions down. FPL needs reliable power in order to use solar.  Coal doesn’t travel through pipelines and can be moved by truck or rail without requiring a FERC EIS that is subject to a legal challenge. Coal still provides 15% of Florida’s electricity. An unintended consequence of the Sierra Club’s well-intentioned single-mindedness may be a longer reliance on coal than would be otherwise necessary.

The Oil and Water Business

It’s seldom appreciated outside the energy industry, but drilling for oil, natural gas and natural gas liquids (NGLs) involves handling far more water than hydrocarbons. This isn’t just because production often involves pumping water into a well. Water is usually present naturally, and comes up with the oil and gas that is produced. Ideally in holding tanks the oil separates from the water and floats above it, although often some further treatment is required to isolate them. Following separation, the water needs to be disposed of safely. This is creating some growing challenges.

Much of the available data is fragmented because in the U.S. the states generally oversee Exploration and Production (E&P) activities except where on Federal land. As a result, the aggregated data that does exist relies in part on estimates because of differing standards of collection. In addition, the most recent data is still a few years old, and given the growth in domestic oil and gas production since then, today’s figures would be higher.

“Produced water” refers to any water that comes up along with hydrocarbons. Water occurs naturally  in most plays and comes up with the extracted oil and gas. But it also includes water pumped into a mature well to force oil up (Enhanced Oil Recovery, EOR) and the flowback of water used in fracking. Any water that comes out of a well is deemed produced water and is subject to Federal rules on safe disposal. Sifting through the available studies, while the ratio of produced water to oil varies widely, it’s clear that we produce substantially more of the former. The water/oil ratio differs by region, by play and by age of well. With conventional drilling, early output typically favors oil and becomes less favorable over time. Produced water generally has no value, although not always; for example, iodide recovered from produced water in Oklahoma represents the largest source of iodine in the U.S. But generally, produced water is high in salt content and contains many unpleasant minerals including NORMs (Naturally Occurring Radioactive Material). Its disposal can represent a significant cost, and because increased water disposal reflects deteriorating well economics (since produced water volumes usually increase over time), installing water disposal infrastructure is often delayed.

Some numbers are helpful to illustrate the scope of the issue. A 2012 GAO report cited 56 million barrels of produced water daily, relying on a 2009 study. Back then the Shale Revolution was virtually unknown. U.S. crude oil production was 5.3 Million Barrels per Day (MMB/D), slightly over half of today’s level, while natural gas output is up by a third. Since injection of water into wells via fracking has further contributed to produced water, one would think produced water volumes have increased proportionally. However, a more recent study of 2012 data suggests that produced water hadn’t increased despite rises in oil and gas production.

One possible reason is that the water:oil ratio is higher in older conventional wells (estimates are 10:1) that are being replaced by new horizontal shale wells which have lower produced water ratios (3:1) after the initial flowback. Nonetheless, a lot of produced water must be disposed of and unlike conventional wells that can inject the water back into a reservoir, tight shale rock won’t accept it.

The result is that substantial quantities of water have to be moved by truck or (if infrastructure exists) by pipe to treatment centers for ultimate disposal. Other applications can include recycling water into new completions, irrigation and industrial cooling, depending on the presence of harmful elements in the water. But most of it gets injected back into the ground using deep wells specially designed for produced water disposal. A single oil well producing 1,000 barrels per day, even if it came with only three times as much water would still require 12 water trucks per day (one barrel = 42 gallons; 3,000 barrels of water = 126,000 gallons; assumed truck capacity of 10,000 gallons), to haul the water away. The 56 million barrels a day of produced water, which is cited by several researchers, is twice the daily flow over Niagara Falls. It’s why the industry often regards itself as being in the water hauling business more than the oil business.

That all this water disposal takes place without much media focus is testament to the already tight rules in place and the industry’s general adherence to them. The minor tremors in Oklahoma are often incorrectly blamed on fracking. In fact, the disposal of produced water into unstable rock formations is the primary cause. Although some of that water is likely the result of hydrofracturing, all oil wells generate produced water. Infrastructure for water disposal is a topic that increasingly draws questions from analysts on conference calls. Of course one man’s expense is another’s business opportunity, and MLPs are adding water disposal infrastructure to the services they provide. Crestwood (CEQP) provided water volume statistics on their most recent earnings call and is planning further investments in this area. COO Heath Deneke commented that, “…the water handling business is likely to grow to be an $8 billion to $10 billion per year business over the next five to seven years in the Delaware-Permian.”

Some worry that the growth of crude oil production in the Permian will be constrained by the challenges of safe water disposal, although the industry is working on solutions and the challenges are likely to be manageable.

We are invested in CEQP

A Simpler MLP Can Be Better

“Oceania was at war with Eurasia; therefore Oceania had always been at war with Eurasia.” 1984, George Orwell.

The hurriedly organized investor call with Plains All American (PAA) a week ago (rushed because of approaching Hurricane Harvey) must have been inspired by the revisionist history propagated by “the Party” in Orwell’s polemic against totalitarianism. PAA’s distribution “reset” (Newspeak for a cut) was larger than previously expected and was directed towards rapidly lowering leverage. Like Orwell’s Ministry of Truth, they explained “…we have assessed the appropriate distribution level to accelerate our deleveraging objectives.”

It’s as if balance sheet strength was always their main objective. There’s no mention of paying stable distributions to their unit holders, which in a different era was the reason for investing in MLPs. If you listened between the lines, you could hear, “We care most about our leverage; therefore, we’ve always cared most about our leverage.”

In January, when PAA acquired a Permian gathering system for $1.2BN they reaffirmed prior 2017 EBITDA guidance of $2.3BN and hinted it might be higher. During their 2Q17 earnings call they cut it to $2BN because of the collapse in their Supply and Logistics (S&L) segment (see MLP Investors Learn About Logistics). Nonetheless, they still forecast 15% growth in 2018, reaching their 2017 target a year late and with a better mix of earnings even more oriented towards traditional, fee-based cashflows since their S&L business has shrunk.

Nonetheless, rating agencies determined that this represented too much risk for an investment grade debt issuer. It’s part of a pattern whereby MLP managements are finding that their goals are not aligned with those of their traditional equity investors. An “It’s not you, it’s me” kind of moment. Although you didn’t ask for this, we went for growth with leverage and risked the distribution. Sorry. Get over it. Ironically, Moody’s still downgraded PAA’s debt to junk in spite of steps that favored debt holders over equity.

Simplification, the euphemism for distribution cuts to fund growth and reduce debt, has been used by several other large MLPs beginning with Kinder Morgan (KMI) in 2014-15 and including Targa Resources (TRGP), Semgroup (SEMG), Williams Companies (WMB) and Oneok (OKE). Current MLP investors are by now a battle-hardened bunch, and the veterans among them are unlikely to sell at this stage because of the recapture of their tax deferral. But it’s hard to see why a yield-driven investor would commit new money to the sector, since the clear message being communicated is that the yield that attracts you today may not be there tomorrow.

The trend is for the resulting entities to look more like conventional corporations, relying less on equity markets for growth capital. The General Partners (GPs) have tended to do better out of the changes, or at least fare less poorly. For example, in its November 2016 Simplification Transaction, Plains GP (PAGP) gave up its Incentive Distribution Rights (IDRs) in PAA in exchange for 246MM units of PAA. At the time this was worth around $7.4BN to PAGP plus assumed debt of $642M. Even today, with the stock 30% lower, it still represents over $5BN of value. And yet, under the newly “reset” distribution just announced by PAGP, the IDRs (if they still existed) would be throwing off less than $12.5MM per quarter. In 2016 PAA paid PAGP $565MM.

PAA investors transferred considerable value to PAGP last year in the forlorn hope of preserving their distribution. It’s probably the worst investment PAA has ever made, and the decision was made for them by PAGP.  Having received almost $8BN to forego IDRs, PAGP then cut the distribution that PAA LPs were receiving. (1) Cancel IDRs for large consideration (2) Cut distribution. It wouldn’t make any sense to reverse the steps, because once the distribution was cut retiring the IDRs would have been worth far less. If not for the Simplification Transaction, PAGP’s stock price would have collapsed following the recent distribution cut at PAA.

Investors have conventionally regarded GPs as providing leveraged exposure to their affiliated MLP, with outsized upside and proportionate downside. But simplification protected PAGP investors from experiencing any worse downside than PAA. Moreover, PAGP even now retains the ability to acquire PAA, transferring its assets to PAGP and revaluing them at market which would create a new source of depreciation charges. In that scenario, PAA investors will get stuck with a tax bill in the same way that Kinder Morgan Partners LPs did when KMI acquired their assets. When PAGP’s current tax benefits expire (in 2016 their effective tax rate was under 11% of net income) they will be incented to do just that. PAGP shares are still worth more than PAA units, which is one more reason why it’s good to be invested with the GP.

KMI, TRGP  and OKE all imposed unpleasant tax outcomes as they acquired assets from their MLP affiliates (see The Tax Story Behind Kinder Morgan’s Big Transaction and Another MLP Simplification Benefits From Favorable Depreciation Rules). Simplification concedes that since MLP investors won’t provide needed growth capital on acceptable terms, it’s time for new investors.  Limited Partner (LPs) investors in MLPs get a tax bill.  GPs get a tax shield!

The only MLPs worth holding have already simplified their structure to eliminate IDRs (such as Enterprise Products, EPD and Magellan Midstream, MMP). They at least have a stable construct. Under the GP/MLP configuration the GP always has the option to waive IDRs so as to preserve LP distributions. However, such moves are rare. The power has always been with the GPs, many of which are C-corps today.

The road to American Energy Independence, driven by the Shale Revolution, is being navigated by regular corporations and GPs rather than MLPs. Valuation metrics that have worked in the past, such as Distribution Yield, are less relevant today given the changes to the financing model. A better measure is  Enterprise Value/EBITDA, which allows comparison with other related sectors such as Utilities (see The Changing MLP Investor). At around 11.2X, this highlights the sector’s cheapness quite effectively.

We are invested in EPD, KMI, MMP, OKE, PAGP and WMB

Escheatment

Escheatment used to apply when a property owner died without a will or legal heirs. It was the process by which those assets were transferred to the state. Its meaning has since evolved to include theft of property by the state by legal means. So it was that at the Lack home we recently received a letter from a custodian informing us that under New Jersey state law, a brokerage account with no activity for three years could be seized by the state as un-owned property.

The account in question is a trust for one of our children. There are no fees (a rare benefit of being an SL Advisors family member) and dividends are automatically reinvested, so there is no activity. Moreover, we learned that under certain circumstances the state may liquidate any securities positions on seizure, no doubt creating a capital gains tax bill for the claimant assuming they successfully regain their property. We were able to confirm that we’d rather like to retain the assets in the account and not hand them over to the state’s coffers. But the onus was on us to communicate this wish.

This law is common across most states. The Council on State Taxation rates states based on the fairness of their escheatment statute – New Jersey naturally receives a “D” (the lowest).

Three years is obviously a ludicrously short period of time on which to base such a law. The government’s need for revenues has few good outcomes. As a taxpayer, your best bet is to ensure every investment account has some activity or otherwise looks as if you know of its existence. You may also hope fervently that wealthy neighbors whom you dislike suffer regular memory loss.

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