Top questions from investors during the volatile market environment

Energy 4/03/2020
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What does historical data show about the strength of rebounds after large MLP selloffs?

  • The chart highlights the 10 worst days for the Alerian MLP Index (AMZ)
  • Historically, that day has been followed by a strong rebound over the following 30 days
  • We continue to believe that midstream energy companies maintain solid fundamentals and are currently undervalued

Source:  Bloomberg
MLPs=Alerian MLP Index. It is not possible to invest directly into an index. The Alerian MLP Index is the leading gauge of energy infrastructure MLPs. The capped, float-adjusted, capitalization-weighted index, whose constituents earn the majority of their cash flow from midstream activities involving energy commodities, is disseminated real-time on a price-return basis (AMZ) and on a total-return basis (AMZX). Past performance is no guarantee of future results.

Does lower production cause lower volume, which in turn, result in lower revenue for midstream companies?

Overall, lower production results in lower amounts of commodity transport. The simplest version of the pipeline business model comes down to the idea that volumes equal revenue. So, what is the impact to earnings if volumes go away?

For better or worse, bankruptcies of producers in the energy sector have been around nearly as long as the sector itself, so this isn’t a new situation for pipeline companies. In the short term, there are two mitigants which tend to dampen the impact of a headline decrease in production:

  1. Many pipeline contracts, especially those for pipelines built in the last 10 years or so, have one version or another of a “minimum volume commitment” (MVC). This requires the shipper to pay for the volume reserved, whether it is utilized or not. If a producer has a MVC and is producing less, due to low commodity prices, they are still contractually obligated to pay for the pipeline space.
  2. For crude oil and natural gas liquids, there are some alternative modes of transport, including rail, road, and even barge in some parts of the country. However, these alternatives are much more expensive, and in many cases, are so by more than an order of magnitude, which means they tend to be the first forms of transportation to be eliminated when volumes dissipate. In addition, they tend not to have long-term contracts in place that back up the pipelines and provide support with features like the MVC.

We have seen many bankruptcies playout, even recently during the commodity price decrease of 2015 and 2016. Because most of a producer’s assets are oil and gas reserves, deep underground, their creditors are typically paid when those resources are extracted and sent to market. Because the cheapest method to get them to market is through the use of a pipeline, those contracts are considered a cost of doing business in a bankruptcy. Ultimately, either the producer continues operating during a reorganization or their assets are sold and the wells still produce. In that case, the only difference is that the pipeline is paid by the acquiring company, rather that the bankrupt producer.

During the 2015-2016 period, we continued to see earnings growth for pipeline companies. Pipelines that were dependent on crude oil grew more slowly because volumes did not experience the same level of growth, but they were supported by the MVCs and alternative methods of transport took the brunt of the hit.

During this extreme market volatility, will performance decline for utilities on days where the market rallies?

Utilities typically exhibit less volatility and beta than the energy market and the broad market. If that holds true, they would underperform on a day when the market is up when beta is rallying. Likewise, we would expect relative outperformance on risk-off down days.

What will the impact be of crude oil approaching $20 per barrel?

Obviously, the very low crude oil prices recently have been very difficult for the energy sector. A price of $20 compared to $30 will not change the investment thesis in the near term; U.S. production volumes will decline in both cases. If prices stay at these levels, there will be a greater impact. While the companies own and operate essential assets, they will be overwhelmed in the short term by the simultaneous supply/demand shock and technical selling pressures in the market. We believe that large-cap companies with resilient business models, cash flows, and more conservative balance sheets are capable of withstanding a downturn and that is where we are positioning our portfolios.

In general, how long are the fee-based contracts midstream companies tend to have with producers?

Generally, 5-20 years, complemented with shorter-term contracts for remaining capacity. Specifics for each pipeline type:

Natural gas pipelines: generally 5-30 years in length. These are mostly with utilities and they value surety of supply over everything else. Additionally, these contracts are not volumetric based, but rather based on a demand or reservation charge. That makes them much more consistent and safer as they have almost no volume or fee exposure.

Refined product pipelines: for new projects, typically 5-10 years, but most of these are evergreen contracts, meaning they are simply month-to-month nominations by shippers. It’s driven by demand that is very consistent and usually doesn’t move more than a few percentage points.

Crude oil pipelines: for new projects, typically 5-15 years, trending towards 5-10. After the contracts roll, they move to evergreen contracts, similar to refined products. There have been several built over the last several years, so many more contracts compared to the refined product space.

Within all these contracts, you also have: 1) negotiated rates and 2) FERC based rates.

Negotiated rates are simply rates between the pipeline company and the shipper. They are negotiated and as such, the return may be higher or lower than normal returns.

FERC based rates are typically set by the FERC and are much more consistent with a 10-14% type ROE. The tariff is actually mandated and as a result, very difficult to change. For example, in the event of a bankruptcy, if you are shipping on a FERC based tariff pipeline, you either pay the rate or you don’t ship. It’s that simple. A negotiated rate pipeline would be different in the event of a bankruptcy and provides more nuance.

I thought the pipeline space is supposed to be somewhat immune from commodity volatility, but that hasn’t been the case. Given the state of the markets, do you expect distributions to flow through?

In terms of the pipeline space correlating with commodity volatility, what we are seeing currently in the market is the definition of systemic risk. And so in the short term, you do see a lot of things tied together. What’s important to note in particular, is that the earnings of these companies are very insulated from commodity prices.

The commodity price downturn of 2015 that bottomed out in February of 2016, when oil was down into the mid-20s, is a good example of this. Over that period, even though we saw equity markets trade off a lot, earnings stayed static and in some isolated cases even grew. This reflects the contracts in place, and the volume transported, which is the core of that business model. This is another example of the long-term stability of the space.

The U.S. owns and operates, through publicly traded companies, the largest energy infrastructure network in the world. Clearly there are current concerns about declines in demand for diesel, jet fuel, gasoline, and of course, oil temporarily. Natural gas has a little bit lesser of a concern with regards to declines in demand, because electricity demand actually has held up a lot better than transportation demand, and natural gas typically is one of the key sources for generating electricity from the fuel perspective.

As we look forward and the world returns to a more normalized state, we still see energy infrastructure assets being very critical. We’ve tried to shape our portfolios to focus on the companies that we feel have a couple of key attributes:

  1. Companies that had strong distribution, or dividend coverage coming into this downturn.
    We took this approach because, in a downturn, volume typically declines temporarily. The companies that have some dividend or distribution coverage, should be able to sustain their distributions over that shorter period of time.
  2. Companies that have lower debt-to-EBITDA, or a better balance sheet coming into this particular environment
    Looking at their balance sheets, and their ability to keep their debt metrics and balance sheets in reasonable shape, in an environment where we’re having lower EBITDA for a temporary period of time, is important.

What are the implications of production cuts for long-haul pipelines as they invested a lot of capital believing that production was going to remain high?

One of the first things to consider is that if production declines and doesn’t return, there’s going be a pretty rapid increase in the price of the commodity. A consultant we work with has crude oil priced at $31 in 2020, $46 in 2021, and then $84 in 2022, based on the fact that there will potentially be some lost productive capacity on a global basis in the short run. But, if it doesn’t return quickly enough, in a couple of years, you’re going to set the stage for a pretty material price spike. So, we think that companies are trying to manage that as best they can, so they don’t set the world up for a whiplash with everything that’s happening right now.

Of course, if crude production capacity was to remain two million barrels lower in the United States into perpetuity, we would have excess pipeline capacity coming out of certain basins. We think what you’re seeing right now, in real time, is that in the current environment companies are doing what they can to minimize CapEx spend, so they’re not adding additional capacity in basins that potentially don’t need it, or at least time it better for when they do need it, and let those projects sit on the back burner until they’re called upon again.

With that said, we do have solid contract life in the portfolio. One example, Plains All American, has noted to us several times, that they don’t have any contract expires until 2024. If production remains low or decreases further into 2024, this could result in a revenue impact at that time. If crude oil prices reach $84 in 2022 and our consultant is correct, there will be a lot of new drilling, and that capacity will get filled. We will continue to watch to see how these scenarios play out.

In conclusion, we do believe we have a short-term challenge, but it’s important to remember, from the longer term, global perspective, we’re in an energy transition, and at Tortoise we believe that through this energy transition, natural gas will continue to displace coal. Renewables will play a role, but oil will also still have a role going forward, and for a long period of time. Other countries around the world simply aren’t going to have much available capacity over the next several years to fill demand that likely continues to grow.

The U.S. will continue to be a really significant and important buyer of crude oil, and will retain a position as one of the top three suppliers of crude oil in the world. So the U.S., Russia, and Saudi Arabia will retain those categories as the top three suppliers of crude oil in the world for a long period of time. That’s our view over the short and long term.

With people currently working from home and using more natural gas to cook and heat their homes, could this be a contributing factor to increased natural gas demand through electricity?

Energy comes from three primary sources: residential use, commercial use, and industrial use. Typically, in residential use, it is for the utilities themselves, the highest margin business that these companies earn. But this question is about the actual consumption of electricity. With everybody staying at home, residential use of electricity will be up a couple percent.

That will likely be offset by some declines in commercial and industrial use that could be down 5 to 10%. But on average, the general consensus is that electricity demand throughout the year will probably be down somewhere around 5%. That is significantly lower than estimated declines in transportation demand from jet fuel, and specifically, gasoline demand.

In summary, we continue to see steady demand for electricity, even in this environment, and actually increased demand for electricity from a residential perspective.

Do you see the credit markets providing a catalyst for midstream energy companies?

When looking at large, integrated, midstream companies with critical assets, we think it’s fair to assume that they’re not going to spend any more money on CapEx to build out existing pipeline infrastructure. Yet when the product starts flowing in their pipelines and continues to grow, along with steady cash flows, these companies are going to have excess cash flow to do a couple of things: reduce debt, and potentially buy back shares.

In many cases, the larger names will continue to pay dividends. After they pay their dividends, they’ll still have excess cash to improve their balance sheets if they need to, and/or buy back their stock if the stock continues to stay at what we think are extremely low levels. And that’s because they won’t be spending that capital on new growth projects.

From a credit perspective, the rating agencies have downgraded some E&P companies, and they’re reviewing all ratings of every single sector. The midstream entities, and even the upstream entities in the energy sector, came into this particular downturn in much better shape from a balance sheet perspective than they have in previous downturns. The rating agencies will take action as they see fit, but, we see strong cash flow generation being a significant driver from a valuation perspective, and hopefully avoid downgrades.

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Past performance is no guarantee of future results.