Plains Offers an Attractive Free Cash Flow Yield 

Strategist

Stephen Ellis

We believe the oversupply of Permian oil takeaway capacity, which we expect to persist for years, had a material negative impact on the returns from Plains All American's pipeline network. Higher Permian volumes will help Plains earn the full tariff on more volumes in 2023, as it only earned partial tariffs in 2022 due to the volumes being on partially owned assets. Combined with higher tariffs due to inflation, we are seeing modest EBITDA growth on the oil side. Plains is pursuing a balanced capital allocation approach, including a "no regrets" growth capital investment framework and a thoughtful distribution of its remaining excess cash flow. For example, we think the recent acquisition of the remaining portion of the Northern Midland Basin gathering system from Diamondback is an immediate winner. It is geographically very close to existing joint-venture assets, and it better aligns Plains with a critical Permian producer in Diamondback. The recent addition of Rattler Midstream and LM Energy assets seems to follow a similar playbook. 

Growth capital spending is expected to decline to $375 million in 2024 from $950 million in 2020 and over $1 billion in 2019. With the improved liquidity helped by asset sales, Plains has finally reached its leverage targets. It now plans to focus on capital returns, boosting its distribution $0.15 in 2023 to $1.07 a unit and $1.27 a unit in 2024. Future increases could 10% annually until the coverage ratio reaches 1.6 times. We think this is supportable over the medium term. 

The most important driver for Plains will be its Permian asset base, where we think the outlook is more of a lower-for-longer scenario, as public producers spend within cash flows and are seeking to hold production close to flat in the near term. Recent M&A with public producers buying some of the growth-oriented private players means sharply lower Permian oil growth, as the public producers are planning to slam the brakes on further growth.

Business Strategy & Outlook

We now do not think Plains has a moat. Midcycle ROICs have continued to decline over the past few years and even allowing for a level of recovery from covid-related demand destruction, ROICs are well below our cost of capital currently and going forward. The biggest problem is that Permian takeaway pipeline capacity is closer to 8.5 million barrels per day compared with about 6 million barrels per day of current production. The overbuild is because several new pipes entered service in 2019 and 2020 just as covid destroyed demand. Now, with public oil and gas firms committed to shareholder returns, not growth at all costs, the oversupply issues become more of a long-term problem. 

We expect Permian production to reach 7 million bpd in the next few years, which still points to oversupply issues before the use of drag-reduction agents that could take the 8.5 million bpd of capacity even higher. Beyond the volatility issues which contribute to asset inefficiency and lower returns, we think Plains simply does not have the pricing power to extract high enough fees to cover its cost of capital given the basin oversupply. Essentially, its assets may be critical to the basin being able to function, with a severe oversupply situation, there’s too much competition to keep fees high enough to earn excess returns. While asset sales complicate the comparison somewhat, we estimate Plains’ transportation per barrel fees have declined more than 20% since 2020. This drop is sizable when more typical numbers might be a 2%-3% increase or decrease in any given year depending on industry cost inflation trends. Peers such as Magellan are reporting similar issues, with contracting levels falling for its oil pipelines compared with 90%-100% a few years ago with materially lower renewal rates. Similarly, other players such as Enterprise Products Partners are looking to convert oil pipelines to CO2 or refined products in recognition of the longer-term issue. 

Another challenge for Plains in the aftermath of covid is that Permian volumes are going to be highly volatile. Plains' lack of diversity is an issue. We think midstream entities function best with steady, stable volumes where pipeline and asset utilization is reasonably high. This is particularly important for oil-based assets, as US pipeline regulations treat oil pipelines as common carriers, and thus they have to take all applicants for pipeline capacity and prorate if they do not have enough capacity. As a result, oil contracts, beyond the initial newbuild contract, are not take-or-pay, so while they are fee-based, Plains is exposed to volume fluctuations. The larger and more frequent the volume changes are, the less efficient the asset is, particularly when a barrel's destination can change from Corpus Christi to Cushing to the Gulf Coast, requiring incremental investment with a less certain long-term return. We believe this dynamic is a cause behind Plains' weaker returns than wide-moat entities' such as Enterprise Products Partners and Magellan, which have significantly more diversified asset bases across multiple basins and products. As a result, they can better manage the portfolio of assets during periods of extreme volatility. 

Plains is investing a lot less than it did during 2012-14, where capital spending topped $3 billion annually. While we think management is making prudent, accretive investments, it also highlights that fewer assets are being placed in service with highly secure newbuild contracts, and more of the asset base is exposed to volume volatility and contract resets at lower fees.

The biggest plus for Plains is the quality of the Permian asset base. The Permian Basin sits at the bottom of the US supply cost curve, thanks to a combination of modest drilling and completion costs and strong well performance trends. Permian wells are typically characterized by strong initial production rates with a fairly high oil content. That puts the play in the "goldilocks" zone between the Bakken (which is typically oilier than the Permian but with less impressive flow rates) and the Eagle Ford (which typically yields higher initial rates but with more natural gas and less oil). The Permian is also much thicker, with numerous productive reservoir layers. As a result, operators think it can accommodate at least 20 wells per square mile on the surface, which is at least double the optimum density in other plays. As a result, there are still enough undrilled well locations in the basin to keep the E&P industry busy for decades.

From an asset quality perspective, Plains’ position in the Permian Basin is dominant and cannot be replicated. It’s not much of a stretch to state that there is a high probability that in some fashion Plains touches every barrel of oil the Permian produces, earning a fee, if not multiple fees. In addition to the Permian, Plains has substantial volumes out of the Bakken, DJ, Niobrara, and midcontinent, including Stack plays.

From a contract perspective, we think Plains operates similar to peers in terms of obtaining long-term take-or-pay contracts for newbuild assets, but it faces more challenges than peers on renewals due to how service is provided. Natural gas pipeline contracts are on a firm capacity basis, which means once capacity is fully contracted, new shippers will be denied service. In contrast, oil pipelines are designated common carriers, which means they must provide service to any shipper upon request, meaning, with a fully contracted oil pipeline, a new shipper request would mean that all existing customers would see reduced capacity allocations to meet the new customer’s needs. This sometimes creates challenges in terms of landing contract commitments, as shippers commit to paying a company tariff without firm rights to that capacity, even if they are “anchor” shippers that contributed to the pipeline’s original development. However, the contracts offer little in the way of volume protection in our view, and more volatile volumes due to covid reduces asset efficiency, utilization, and returns. 

To help mitigate these issues, oil pipelines offer premium rates for capacity that are free from prorating. There is also a “shipping history preference,” where shippers are ranked by how long they’ve been transporting oil on the pipeline, with the shipper with the longest history the last to be prorated, and the shipping history distinction is particularly prized by producers, in our view. Finally, while the Federal Energy Regulatory Commission, or FERC, approves ranges of tariffs for gas pipelines, oil pipelines typically only have a single stated rate, which we don’t think eliminates the market-based nature of rates over time for both oil and gas pipelines.

There are differences in the regulatory structure between oil (NGL pipelines are included) and gas pipelines, meaning that individually, oil pipelines face lower regulatory barriers to entry than a gas pipeline, but more practical barriers to entry also appear for oil pipelines. To review: the Natural Gas Act regulates natural gas pipelines and new construction is explicitly approved by FERC, which decides if the pipeline and tariffs are in the public interest. This approval provides the pipeline owner with certainty regarding its projected returns, but FERC approval also comes with federal eminent domain, which pre-empts state and local laws that might otherwise prevent construction of the pipeline. Thus states, local governments, or landowners cannot block natural gas pipelines.

In contrast, explicit FERC approval is not required to construct an oil pipeline under the Interstate Commerce Act, but it does let FERC regulate rates, which means it acts as a mediator for disputes. This difference means that oil pipelines must obtain approval from each state they plan to use (and not all states are pro-pipeline) and individual landowners can force the pipeline owner to reroute the pipe and incur additional costs if an agreement cannot be reached and a pipeline appeal to the state fails. FERC is also not required to approve rates preconstruction, though it can issue an advance ruling that allows oil pipelines to have substantial certainty over expected capital returns. 

Material ESG exposures create additional risk for midstream investors. In this industry, the most significant exposures are greenhouse gas emissions (from upstream extraction, midstream operations, and downstream consumption) and other emissions, effluents, pipeline spills, and opposition and protests. In addition to the reputational threat, these issues could force climate-conscious consumers away from fossil fuels in greater numbers, resulting in long-term demand erosion. Climate concerns could also trigger regulatory interventions, such as production limits, removal of existing infrastructure, and perhaps even direct taxes on carbon emissions.

Midstream emissions are relatively low in the lifecycle of oil and gas, and midstream firms have relatively lower risk than upstream and downstream firms from carbon taxes. Canadian firms already pay carbon taxes on their carbon emissions, most of which are generally passed to their shippers and other customers. Spills represent a major threat and have created great resistance from environmentalists, Indigenous groups, and other climate-conscious persons. Examples of the opposition are seen in President Biden’s revocation of the Keystone XL presidential permit and the legal challenges surrounding the Dakota Access Pipeline system. 

Plains has yet to lay out any material ESG-related goals or targets.

None

Economic Moat

Plains GP Hlds

Plains GP Holdings LP owns and operates midstream energy infrastructure and provides logistics services primarily for crude oil, natural gas liquids and natural gas through its indirect investment in Plains All American Pipeline, L.P. The firm operates through the following segments: Transportation, Facilities and Supply and Logistics. The Transportation segment consists of fee-based activities associated with transporting crude oil and NGL on pipelines, gathering systems, trucks and barges. The Facilities segment consists of fee-based activities associated with providing storage, terminalling and throughput services primarily for crude oil, NGL and natural gas, as well as NGL fractionation and isomerization services and natural gas and condensate processing services. The Supply and Logistics segment consists of storage of inventory during contango market conditions and the seasonal storage of NGL, purchase of NGL from producers, refiners, processors and other marketers, extraction of NGL from gas processed at the facilities. The company was founded in July 2013 and is headquartered in Houston, TX.

Earnings data Q1 2024

Plains All American Pipeline reports strong Q1 results and growth opportunities

PAGP's Q1 performance reflects strength in adjusted EBITDA and production growth, while facing challenges in market dynamics. The company is focused on capital discipline and sees opportunities in cash flow generation and increasing returns to unitholders.

PAGP reports strong Q2 results and optimistic outlook for NGL projects

PAGP's performance in Q2 reflects strategic acquisitions and optimization efforts, while facing challenges in managing supply agreements. The company is poised to capitalize on NGL project opportunities and maintain financial strength.

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Plains GP Holdings, L.P. (NASDAQ:PAGP ) Q3 2023 Earnings Conference Call November 3, 2023 10:00 AM ET Company Participants Blake Fernandez - Vice President of Investor Relations Willie Chiang - Chairman & Chief Executive Officer Al Swanson - Executive Vice President & Chief Financial Officer Jeremy Goebel - Executive Vice President & Chief Commercial Officer Conference Call Participants Michael Blum - Wells Fargo Brian Reynolds - UBS Gabriel Moreen - Mizuho Keith Stanley - Wolfe Research Neel Mitra - Bank of America Neal Dingmann - Truist Securities Sunil Sibal - Seaport Global John Mackay - Goldman Sachs Operator Good day and thank you for standing by.

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