Wednesday, March 3, 2021

Magellan Midstream Partners, L.P. (MMP)

We had a good exchange in the comments of the Hydrocarbons and Pipelines post in which we established that pipelines are probably the best part of the oil value chain. (And remember Arman Alchian wrote about how pipelines have so much bargaining power - in the absence of regulation - that producers and refiners are "hostage" to them.) I also posted a good link to Convexity Maven in the February 26th Links about midstream investments (e.g. AMLP):

The AMLP listed ETF is a collection of the larger fossil fuel MLPs that have not converted to a C-Corp profile. Notwithstanding its disadvantageous tax structure, its current yield of nearly 10%, or about 825bps wide to the T10yr, can only be explained as either a stupendous tax-loss motivated liquidation, or the realization that MLPs are a feat of financial engineering that is inherently flawed. Fossil fuels will not be eliminated in the near future, and their transportation from the ground to the gas tank is a necessary function that at some point must be a profitable venture. It is my fervent hope that MLPs are not the subject matter for Betheny McLean’s next best seller. A 10% dividend for a listed 20-stock Index is the wrong number; either AMLP will rise in price, or the 19.5 cent dividend will be reduced to 14 cents. I suppose it is possible that the underlying MLPs are functionally a $200bn Ponzi scheme that relied upon rising oil prices to maintain the illusion of profitability; but I suspect the answer is a bit more banal. What we likely have here is a mismatch in capital where Retail investors have tossed in the towel and Institutional investors can't or won't buy a (K-1) partnership structure. 

One midstream company that caught my eye is Magellan Midstream Partners, L.P. (MMP). Their business is slightly different than the stereotypical pipeline (which drains a producing, depleting basin). See this asset map of their refined products pipeline and terminals, and their crude oil pipelines, and how they describe their business:  

We are principally engaged in the transportation, storage and distribution of refined petroleum products and crude oil. As of December 31, 2020, our asset portfolio consisted of: our refined products segment, comprised of our approximately 9,800-mile refined petroleum products pipeline system with 54 connected terminals, as well as 25 independent terminals not connected to our pipeline system and two marine storage terminals (one of which is owned through a joint venture); and our crude oil segment, comprised of approximately 2,200 miles of crude oil pipelines, a condensate splitter and 37 million barrels of aggregate storage capacity, of which approximately 27 million barrels are used for contract storage. Approximately 1,000 miles of these pipelines, the condensate splitter and 30 million barrels of this storage capacity (including 24 million barrels used for contract storage) are wholly-owned, with the remainder owned through joint ventures.

The stock is yielding almost 10%. They distributed $927 million last year (current market cap $9.7 billion) versus cash from operations of $1.1 billion. What's the deal - is this a wasting asset? Here is a risk factor that they disclose in their annual report:

The demand for refined products in the market areas served by our pipeline system has historically been stable. We generally rely on recent historical trends on our system and third-party forecasts in assessing future refined products demand, and those forecasts vary both by forecaster and by product. While increases in vehicle efficiency and more widespread penetration of electric vehicles are generally expected to reduce demand for gasoline over time, distillate demand is expected to be less affected, while demand for aviation fuel is expected to grow. Projections published by the Energy Information Administration in February 2021 suggest that overall demand for refined products in the market areas served by our pipeline system, primarily the West North Central and West South Central census districts, will decline by approximately 0.6% annually over the next ten years, when compared to the more historical demand levels of 2019.

If demand for refined products actually does fall single digit percentage a year, pipelines and hydrocarbon land owners will do a lot better than refiners. But look at where Magellan's pipeline runs - from the Houston Gulf Coast refining complex north to the Great Plains states. Are people in Minnesota, Iowa, Illinois, etc. really going to be using less fuel in the years to come? This subject came up at Magellan's investor presentation yesterday:

It’s hard for us to see the work from home trend really distinct in a material way, especially in the markets we serve in the Mid-Continent. So we don't anticipate that that to have a long term effect on gasoline demand. And I think, for that matter, especially in our part of the world, even when people are staying home, they're not really staying at home, they're still out and being mobile in their cars, rather than taking mass transit, or those sorts of things. So we're not expecting long term gasoline demand destruction from COVID on gasoline. And diesel demand, we expect to recover nicely, both with just a recovering economy and the diesel demand needs for transport of goods. We also serve a very large agricultural sector, which we expect to continue to do well overtime. So we don't really expect any long term impacts from diesel demand destruction.

In other words, people with real jobs still have to show up to work in person, and they aren't buying flaky electric vehicles that you don't work on farms or in the winter. But in response to the electric vehicle and work from home and covid related uncertainty, they commented that they

"significantly reduced any [capital expenditures] where we are taking speculative positions on the outlook for the market over 10 or 20 years."


Uncertainty about the demand outlook means capital expenditure discipline. That in turn means rents stay high and more of it can be returned to shareholders. It’s like tobacco!

What is amazing about the 10% dividend yield is that MMP's 30 year debt yields 3.8% with 9.6% dividend yield. It is strikingly similar to the equity risk premium at Altria, whose 30 year debt yields 4% with 7.7% dividend yield on the stock.

See how low Magellan's dividend yield got at the peak of the midstream boom in 2014-2015. It was yielding under 3% - yet their debt was yielding closer to 5%. 

Wow: if you had followed the equity risk premium as a signal to chose between owning the stock or the bonds, you would have been in their debt instead of their stock given the -200 bps spread. Now with a +580 bps spread it seems to make more sense to own the stock.

6 comments:

Anonymous said...

Keep the posts coming, back in the day you posted few and far between, seems like a lot more activity here these days and I love it.

Thank you!

CP said...

Highlights from annual report:

* Magellan owns the longest refined products pipeline system in the country. We can tap into nearly 50% of the nation’s refining capacity and store more than 100 million barrels of petroleum products, such as gasoline, diesel fuel and crude oil.

* refined products segment, comprised of our approximately 9,800-mile refined petroleum products pipeline system with 54 connected terminals, as well as 25 independent terminals not connected to our pipeline system and two marine storage terminals

* our crude oil segment, comprised of approximately 2,200 miles of crude oil pipelines, a condensate splitter and 37 million barrels of aggregate storage capacity, of which approximately 27 million barrels are used for contract storage. Approximately 1,000 miles of these pipelines, the condensate splitter and 30 million barrels of this storage capacity (including 24 million barrels used for contract storage) are wholly-owned, with the remainder owned through joint ventures

A very light form of crude oil known as condensate makes up an increasing amount of U.S. shale crude output, but North American demand for it is limited because too much can overwhelm refinery distillation systems. Starting in 2012, several companies announced plans to build facilities that “split” condensate into various products, such as unfinished distillates and naphtha, which is used to make gasoline or dilute heavy crude, to export or sell domestically.
https://www.reuters.com/article/us-usa-oil-condensate-splitters-factbox/factbox-u-s-condensate-splitter-projects-idUSKBN0UB09720151228

* The refined products segment was responsible for 75% of revenue and 66% of operating margin in 2020.

CP said...

*During 2020, approximately 65% of the refined products segment’s revenue (excluding product sales revenue) was generated from transportation tariffs on volumes shipped on our refined products pipeline system. These transportation tariffs vary depending upon where the product originates, where ultimate delivery occurs and any applicable discounts. All transportation rates and discounts are in published tariffs filed with the Federal Energy Regulatory Commission (“FERC”) or appropriate state agency.

*In 2020, the products transported on our refined products pipeline system were comprised of 58% gasoline, 37% distillates and 5% aviation fuel and LPGs. Our refined products pipeline system generates additional revenue from providing pipeline capacity and tank storage services, as well as providing services such as terminalling, ethanol and biodiesel unloading and loading, additive injection, custom blending, laboratory testing and data services to shippers, which are performed under a mix of “as needed,” monthly and long-term agreements.

*Our gas liquids blending activity primarily involves purchasing butane and blending it into gasoline, which creates additional gasoline available for us to sell. This activity is limited by seasonal changes in gasoline vapor pressure specification requirements and by the varying quality of the gasoline products delivered to us. When the differential between the cost of gas liquids and the price of gasoline fluctuates, the product margin we earn from these activities is impacted. We hedge the economic margin from this blending activity by entering into forward physical or exchange-traded gasoline futures contracts at the time we purchase the related gas liquids. These blending activities accounted for approximately 92% of the total product margin for the refined products segment during 2020.

*Product margin, which is calculated as product sales revenue less cost of product sales, is used by management to evaluate the profitability of our commodity-related activities.

*While increases in vehicle efficiency and more widespread penetration of electric vehicles are generally expected to reduce demand for gasoline over time, distillate demand is expected to be less affected, while demand for aviation fuel is expected to grow. Projections published by the Energy Information Administration in February 2021 suggest that overall demand for refined products in the market areas served by our pipeline system, primarily the West North Central and West South Central census districts, will decline by approximately 0.6% annually over the next ten years, when compared to the more historical demand levels of 2019.

CP said...

*Our 450-mile Longhorn pipeline has the capacity to transport approximately 275,000 barrels per day (“bpd”) of crude oil from the Permian Basin in West Texas to Houston, Texas. Shipments originate on the Longhorn pipeline via trucks or interconnections with crude oil gathering systems owned by third parties and are delivered to our terminal at East Houston or to various points on the Houston Ship Channel, including multiple refineries connected to our Houston distribution system.

*Our Houston distribution system consists of more than 100 miles of pipeline that connect our East Houston terminal through several interchanges to various points, including multiple refineries throughout the Houston area and crude oil import and export facilities, including through the facility owned by Seabrook discussed below. In addition, it is directly connected to other third-party crude oil pipelines providing us access to crude oil from the Permian and Eagle Ford basins, the strategic crude oil trading hub in Cushing, Oklahoma and crude oil imports.

*We typically reserve at least 10% of the shipping capacity of our pipelines for spot shippers. Spot barrel movements on our pipelines generally ship at higher rates than those charged to committed shippers. Generally, we seek to secure long-term commitments to support our long-haul crude oil pipeline assets. The majority of the capacity on our Longhorn pipeline is supported by take-or-pay commitments. At December 31, 2020, approximately 70% of the capacity of our Longhorn pipeline was subject to long-term commitments with an average remaining life of approximately six years. Our Houston distribution system is generally not subject to long-term agreements. As of December 31, 2020, approximately 90% of our crude oil storage available for contract was under agreements with terms in excess of one year or that renew on an annual basis at our customers’ option. The average remaining life of our storage contracts was approximately three years as of December 31, 2020. These agreements obligate the customer to pay for storage capacity reserved even if not used by the customer. Our BridgeTex and Saddlehorn joint ventures also have long-term take-or-pay customer commitments. At December 31, 2020, approximately 80% of the capacity of the BridgeTex pipeline was subject to long-term commitments with an average remaining life of four years. At December 31, 2020, approximately 75% of the capacity of the Saddlehorn pipeline was subject to long-term commitments with an
average remaining life of six years

CP said...


*The rates on approximately 40% of the shipments on our refined products pipeline system are regulated by the FERC primarily through an index methodology. For the five-year period beginning July 1, 2021, the indexing method provides for annual changes in rates by a percentage equal to the change in the producer price index for finished goods (“PPI-FG”) plus 0.78%. As an alternative to cost-of-service or index-based rates, interstate liquids pipeline companies may establish rates by obtaining authority to charge market-based rates in competitive markets or by negotiation with unaffiliated shippers. Approximately 60% of our refined products pipeline system’s markets are either subject to regulations by the states in which we operate or are approved for market-based rates by the FERC, and in both cases these rates can generally be adjusted at our discretion based on market factors.

*Our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after taking into account reserves established by the board of directors of our general partner for commitments and contingencies, including capital investments, operating costs and debt service requirements. In addition, our general partner’s board of directors authorized the repurchase of up to $750 million of our common units through 2022. We do not accumulate equity in the form of retained earnings in a manner typical of many other forms of organization, including most traditional public corporations

*the development of new pipeline capacity from the Permian Basin has resulted in takeaway capacity that significantly exceeds current production. This excess capacity has created a highly competitive environment that has decreased the crude oil price differential between the Permian Basin and end markets, including Houston, resulting in lowering the rates we are able to charge for our transportation services

*Because we are a partnership for federal income tax purposes, we are a pass-through entity and are not generally subject to entity-level taxation, and distributions to our unitholders are not taxed as dividends. Instead, our unitholders are treated as partners and allocated their proportionate share of our income, which is reported to them on schedule K-1 and which could subject them to other taxes, including state and local taxes imposed by the jurisdictions in which we conduct business. This taxation and reporting arrangement is different from and less common than the arrangement that prevails among most publicly traded companies, and may create complexities that could discourage some investors or investment funds from investing in us. In addition, the methodologies of most indices of publicly traded equities exclude publicly traded partnerships, and as a result many passive investment funds are prevented from investing in our equity. The inability or unwillingness of individual investors or investment funds to invest in us reduces demand for our units.

CP said...

*If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture.

*Investment in common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts (known as IRAs) and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income.