Description

Long Tallgrass Energy GP, LP (NYSE: TEGP)

This write-up assumes the reader has a basic understanding of MLP corporate structures and terminology such as General Partner, Limited Partner, Incentive Distribution Rights, etc. For those in need of a reference, I refer you to the following website: https://www.energyandincomeadvisor.com/mlp-basics-incentive-distribution-rights-explained/  

Tallgrass Energy GP, LP (NYSE: TEGP)

Price: $26.58

S/O: 157 million

Market Cap: $4,185 million

Net Debt (entity-level): $146 million

Enterprise Value: $4,331 million

Implied EV of GP/IDR Interest: $3,241 million

Current Yield: 5.2% (tax-deferred)

Tallgrass Energy Partners, LP (NYSE: TEP)

Price: $47.20

S/O: 75 million

Market Cap: $3,522 million

Net Debt (entity-level): $2,098 million

Enterprise Value: $5,619 million

EBITDA (2Q17 Run-Rate): $637 million

Distributable Cash Flow (2Q17 Run-Rate): $536 million

EV/EBITDA: 8.8x

P/LP DCF: 8.8x

Current Yield (2Q17): 7.8%

Coverage Ratio (2Q17): 1.3x

Covenant Leverage Ratio: 3.6x

Thesis

I am recommending a long position in Tallgrass Energy GP, LP (NYSE: TEGP), the publicly traded general partner of master limited partnership Tallgrass Energy Partners, LP (NYSE: TEP). This is a long-term, buy and hold situation which I expect to provide a 15-20% IRR over a 3-5 year timeframe with low-risk of permanent capital loss.

Note: I also believe TEP is a good investment at current levels, perhaps even better than TEGP if one goes strictly by the numbers. However, I prefer to invest in TEGP as I feel it better aligns my interest with that of management.

Tallgrass’s management has a stellar track-record of operational execution which has resulted in per-share distribution growth of 31% annualized at TEP (IPO in May 2013) and 51% annualized at TEGP (IPO in May 2015). The company is conservatively levered at 3.6x Adjusted EBITDA, maintains distribution coverage over 1.3x, and generates 97% of its EBITDA from firm-fee and take-or-pay contracts. Furthermore, management owns a 17% interest in TEGP, while CEO David Dehaemers has acquired $5.6 million of TEP units in the open market over the past 3 months.       

Despite these positive attributes, Tallgrass remains overlooked by most analysts and energy investors. This is largely due to the company’s lack of exposure to “hot” production basins such as the Permian, SCOOP/STACK, or Marcellus/Utica, as well as management’s refusal to make headlines with splashy, high-multiple acquisitions. Those that are aware of Tallgrass focus solely on the uncertainty surrounding the re-contracting of capacity on Tallgrass’s two largest assets, a 50% interest in the Rockies Express (“REX”) natural gas pipeline and a 98% interest in the Pony Express (“Pony”) oil pipeline, both of which face a wave of contract maturities in the 2019-2020 timeframe. Together the REX and Pony interests account for 81% of Tallgrass’s run-rate EBITDA. Further, management intends to acquire an additional 25% interest in REX in 2018 which will bring EBITDA exposure to 85%.

Given this concentrated exposure, the market’s focus on this issue is understandable. However, the competitive position of these pipelines and recent re-contracting successes by management suggest that the go-forward re-contracting risk is much less than that implied TEGP’s current price. Moreover, by focusing exclusively on the risk posed by Tallgrass’s large exposure to these assets, the market is ignoring the potential benefits such concentrated exposure can provide. Namely that large assets such as REX and Pony provide numerous opportunities for incremental, high-return brownfield investment. With a combined enterprise value of just $9 billion[1], the Tallgrass complex is small relative to the scale of the assets it owns, giving it an ability to channel meaningful amounts of capital towards these opportunities.

I expect incremental EBITDA from these investments to more than offset any revenues lost from contract expirations at REX and Pony. As the market recognizes this, TEGP and TEP shares should re-rate to a multiple more in-line with their respective growth profiles. In the meantime, TEGP pays a 5.2% tax-deferred[2] dividend which I expect to grow 11% annually through 2021.

Corporate Overview

In August 2012, current Tallgrass management, led by CEO David Dehaemers, partnered with The Energy & Minerals Group (“EMG” was founded by John Raymond, son of former Exxon CEO Lee Raymond) and Kelso & Co. to form privately-held Tallgrass Development. In November of that same year, Tallgrass Development acquired a group of Rocky Mountain based natural gas assets from Kinder Morgan which Kinder divested to satisfy FTC requirements following its 2012 merger with El Paso Corp. Dehaemers was an obvious choice to lead this endeavor on behalf of Tallgrass, having served as Kinder Morgan’s CFO from 1997-2000 and its head of corporate development from 2000-2003.

In May 2013, management IPO’d Tallgrass Energy Partners (NYSE: TEP) to serve as a drop-down vehicle for the assets held at Tallgrass Development. In May 2015, management IPO’d Tallgrass Energy GP, LP (NYSE: TEGP), the General Partner of TEP and owner of its Incentive Distributions Rights.

TEGP is a Limited Partnership which has elected to be taxed as a C-Corp. It is also an “Up-C” tax structure with 100% of basis step-up benefits accruing to TEGP. For the foreseeable future, TEGP is not expected to pay corporate taxes and TEGP distributions will be treated as returns of capital.

TEGP is owned 37% by the public, 17% by management, 23% by EMG, and 23% by Kelso.

TEGP assets consist of the GP interest and 100% of Incentive Distribution Rights, or “IDRs”, of TEP. TEGP also owns 20 million TEP LP units, equivalent to a 27% interest. Combined with its GP interest, which entitles it to 1% of TEP’s LP distributions, it receives 28% of TEP’s LP distributions and 100% of its IDR distributions. TEGP does not directly own any operating assets. The company’s value is solely derived from the aforementioned claims on TEP’s cash flows.

These cash flows come from TEP’s portfolio of assets which I’ll lump into three buckets:

50% Interest in Rockies Express Pipeline (“REX”)

• 4.4 billion cubic feet per day (Bcf/d) bi-directional interstate natural gas pipeline

• 1.8 Bcf/d West-to-East capacity delivering Rocky Mountain production to Midwest and Northeast demand centers

• 2.6 Bcf/d East-to-West capacity delivering Marcellus/Appalachia production to Midwest and connecting pipelines running to the Gulf Coast

• Management expects to acquire an additional 25% interest in the pipeline in 2018.

98% Interest in Pony Express Pipeline (“Pony”),

• 320 thousand barrel per day (Mb/d) interstate oil pipeline

• Runs from Guernsey, Wyoming and Northeast Colorado to Cushing, Oklahoma

• Joint-Tariff with Double H Pipeline to transport Bakken production to Cushing

Everything Else

• TIGT and Trailblazer – 2.0 Bcf/d FERC regulated natural gas pipeline system serving Rocky Mountains producers and regional demand points

• Gathering and Processing – Gathering and processing assets serving both oil and gas customers in the Powder River Basin (PRB)

• Terminals – Own a network of terminals which serve to enhance functionality of Pony Express system

• Water Services – Own a stake in a water solutions business which provides freshwater supply and wastewater takeaway services to Powder River and DJ/Niobrara based customers

More asset-level detail can be found here http://tallgrassenergylp.com/Assets/ and in company slide-decks but this write-up primarily focuses on REX and Pony.

REX Re-Contracting

When Tallgrass acquired its 50% in REX in the Kinder transaction, the pipeline had a capacity of 1.8 Bcf/d and only flowed gas West-to-East. The take-or-pay contracts for this capacity expire in 2019-2020. However, given that Marcellus production has precluded the need to deliver Rockies natural gas to Northeast markets, it is well-established that this capacity will not be re-contracted at the same rates it was when these contracts were originally executed in 2009.

That said, management has done a phenomenal job repositioning REX (details can be found here: https://rbnenergy.com/walking-tall-tallgrass-winning-strategy-for-the-rockies-express-rex-pipeline). Recognizing that it already had “pipe in the ground” in the Marcellus, Tallgrass added facilities to the pipeline which allowed it to transport 2.6 Bcf/d from East-to-West. As a result, the pipeline now flows 2.6 Bcf/d of gas from the Marcellus to Midwest markets and to connecting pipelines that take this supply to the Gulf Coast. This East-to-West capacity is all under 15-20 year take-or-pay contracts. In addition, Tallgrass recently restructured the contracts of its two largest West-to-East legacy customers, offering them reduced rates but for longer terms.

The result is that management has now backfilled more than 90% of the EBITDA that was to lost once REX’s legacy contracts expired with long-term, take-or-pay agreements. As for the remaining uncontracted capacity (roughly 1 Bcf/d), my base case valuation assumes that the pipeline can earn 50% of the basis differential[3] implied by futures contract prices at the time these contracts expire. I feel this is conservative as it’s less than one-fourth of the rate already secured under long-term agreement for identical capacity.

Pony Re-Contracting

Re-contracting concerns around the 320 Mb/d Pony Express oil pipeline are much greater, as 300 Mb/d of take-or-pay contracts are set to expire over the course of 2019-2020 with no new contracts in place to date. Adding to investor concern is the fact that competitors have added a considerable amount of takeaway capacity in the two primary basins where the pipeline sources its supply, the Bakken and the DJ/Niobrara. The problem of course is that oil production volumes are much lower today than they were when competitors originally decided to build these projects. In the DJ/Niobrara in particular, this has led to legitimate concerns about over-capacity.

However, the company’s pipeline is in a much better competitive position than its peers for a couple reasons. First and foremost, in both basins, it is the cheapest option for shippers to get barrels to market. In the Bakken, Pony’s joint-tariff with Double H is 15% cheaper than the recently completed Dakota Access Pipeline. In the DJ/Niobrara, the all-in cost of using Pony is 17% lower than the next cheapest competitor, and 27% cheaper than the one after that. For a shipper moving 30 Mb/d over the course of a year, securing space on Pony could result in savings of $5-15 million annually[4], which in today’s low price environment could be the difference between booking a profit or a loss.

In addition to providing shippers the lowest-cost option for getting barrels to market, Pony also has the ability to “batch[5]” various crude streams. This is a huge benefit for refinery customers who prefer to run unblended crude (aka “neat” barrels) as it generally results in higher yields of clean product (gasoline, diesel, kerosene, etc.). As a result, refiners will often pay more for a “neat” barrel, adding further value to a Pony shipper. Largely a function of this batching capability, management recently announced they will construct two new direct connections, or “interconnects”, to refineries by the end of 2017. Combined with an existing interconnect, Pony will have direct connections to three different refineries with the capability of delivering 300 Mb/d of various “neat” crude streams. Not coincidentally, 300 Mb/d is equal to the amount of contracted capacity set to expire. Put simply, by the end of the year, the pipeline’s connections to refinery customers alone will be capable of back-filling 100% of expiring capacity. And this will be achieved two years before current contracts expire.  

Given these attributes, I see very little re-contracting risk at Pony and assume that current profitability remains intact. However, I ignore annual producer price index (PPI) adjustments allowed by FERC and the very real ability of management to re-contract the pipeline at higher rates. As the pipeline provides customers superior outcomes - i.e. higher netbacks for producers and multiple “neat” crude streams for refiners – at a cheaper price than the competition, it could logically raise prices to capture a slice of this value. But it doesn’t seem like this is management’s intention. Rather, I expect management to continue its efforts to solidify the asset’s position as a “baseload” pipeline, providing customers with the best possible outcome at the lowest possible price.

A Unique Platform for Growth Investments

By focusing on contract expirations, it appears the market is entirely ignoring Tallgrass’s opportunity to deploy substantial capital towards high-return growth projects. This is evidenced by a number of sell-side reports stating that they do not include any growth capex in their estimates outside of the anticipated drop-down of an additional 25% interest in REX from Tallgrass Development.

As previously discussed, the company has oversized exposure to two the REX and Pony pipelines which account for ~85% of EBITDA[6]. Pipelines of this size typically offer a slew of small-size investment projects such as laterals, customer interconnects, and efficiency enhancements. These are usually short-duration, high-return opportunities. However, for the large-capitalization companies that typically own such large-scale infrastructure, the projects don’t always get pursued because they aren’t large enough to move the needle.

With a $9 billion[7] enterprise value, Tallgrass is small relative to the scale of these two assets, meaning that smaller-size, incremental growth projects, combined with bolt-on acquisitions within its footprint, can substantially grow the business over time. To put the size advantage in perspective, relative to enterprise value, for every $500 million of projects that Tallgrass management identifies, a company the size of Kinder Morgan needs to identify $4.4 billion worth of projects with an equivalent return profile to achieve the same level of growth.  

My base case assumes management can invest $500 million per year at a 7.5x EBITDA multiple over the next few years. I feel this is arguably conservative given that management has already announced $600 million of growth investments in 2017 alone, and their track record to date suggests they are not remotely interested in paying anywhere near 7.5x for anything – ever. We will cross our fingers for larger investments and lower multiples.

Valuation

I think the best way to value TEGP is on a total return and IRR basis which takes into account dividends received as well as a terminal value. I chose to use 2021 as my terminal year because that will be the first full-year of operations after the REX and Pony contracts expire.

My base case assumes that the REX and Pony re-contracting happens as I laid out in the write-up. Further, I assume $500 million of growth capex annually at a 7.5x build multiple. In this scenario, TEGP earns and distributes $2.15 per share in 2021, or an 11% annual growth rate from the current run-rate. $1.53 of this comes from the GP/IDR interest which I capitalize at 5%, resulting in $30.50 per share for the GP/IDR interest. TEGP’s 20 million TEP units net an additional $0.62 distribution per TEGP share. I capitalize the LP distributions at 7%, resulting in another $9 per share. So a total terminal value of $39.50 per TEGP share. Over this period, a TEGP investor should also collect $8.50 in distributions. This results in a total return of 81% and an IRR of 16.1%.

For my downside case, I assume that 0% of uncontracted REX capacity gets contracted and that management can’t find any new growth project outside of those already announced. This results in 5% annual growth in GP/IDR distributions and 2% annual growth in LP distributions. I capitalize the GP/IDR distributions at 10% and the LP distributions at 12%. This results in a total loss of 13.7%.

I believe it’s extremely unlikely for all my downside assumptions to come to fruition, especially the no new growth project aspect. If one keeps the terminal value and re-contracting assumptions of the downside case but assumes the company can still find $250 million per year of growth projects, distributions to TEGP can still grow by 8% annually through 2021. If this kind of growth is achieved, then the 10% and 12% cap rates become fairly unlikely.

Potential Risks

Low-Return Growth Projects – Historically, Tallgrass management has shown an aptitude for buying underappreciated assets and repositioning them. If these are hard to come by, there is a risk that they start to reach and returns on capital decrease.

Pony Express Competition – I have not assumed that Pony’s various competitors will lower their rates to try to steal volumes but if this happens it could eat into Pony’s customer base. However, given that all these competitors are new-build pipelines which have take-or-pay contracts in place with anchor shippers, it seems unlikely that they would charge their anchor shippers more than walk-up shippers. At the very least the anchor shippers would demand to also get this lower rate, the net effect of which would probably outweigh the benefit from increased volumes, and serve to piss off their largest customers.

Oil/Gas Price Declines – Due to its high percentage of take-or-pay contracts, Tallgrass’s cash flows are largely buffered against short-term commodity price movements. However, over the long-term, all midstream infrastructure production activity in the areas which its assets service. At the moment, the outlook for both PRB and DJ/Niobrara oil and gas production is for moderate growth but this could change with falling prices. At the same time, recent earnings reports by producers EOG, Devon, and Chesapeake suggest a pick-up in PRB oil drilling activity with promising results to date.  

Interest Rates – TEGP and TEP are yield-based securities and are interest-rate sensitive. However, following the oil price collapse of 2015, MLPs seem to have de-coupled from other yield-based asset classes such as REITs and Utilities. The AMZ MLP index is currently yielding 7.9%, a 570 bps spread to 10-Yr Treasuries. This is 140 bps higher than its 10 year average. If rates do rise unexpectedly there is no doubt TEGP and TEP will get hit just like every other security, but there’s a possibility that the large existing spread may buffer the pain to some degree.   

[1] Calculated by combining the GP and LP stand-alone enterprise values and deducting the market value of the LP units held by the GP.

[2] TEGP has an Up-C tax structure with all basis step-up benefits accruing to TEGP. As such, distributions will be treated as returns of capital for tax purposes for the foreseeable future. This will lower one’s cost basis over time but won’t become taxable until the position is sold or the basis hits zero. I am hoping for the latter.

[3] Basis Differential is the difference between the prices for natural gas at two different locations. For my analysis I use the CIG trading hub and REX Zone 3 trading hub prices.

[4] The range of savings depends on the basin and competitor in question.

[5] This explains the importance of batching: https://rbnenergy.com/you-cant-always-get-what-you-pu-in-crude-oil-pipeline-quality-banks

[6] Pro forma for the 2018 acquisition of an additional 25% interest in the natural gas pipeline

[7] Calculated by combining the GP and LP stand-alone enterprise values and deducting the market value of the LP units held by the GP.

Catalyst

• Incremental re-contracting announcements at either REX or Pony
• Incremental acquisition / growth project announcements
• Continued distribution increases