|Shares Out. (in M):||491||P/E||0||0|
|Market Cap (in $M):||6,285||P/FCF||0||0|
|Net Debt (in $M):||2,300||EBIT||0||0|
I would like to offer VIC members yet another way to lose money on northeast gas. I own shares of Antero Midstream (AM). The stock is at $12.80 and yielding 9.7% with 1.15x distribution coverage for a forward distributable cash flow multiple of just 9.0x.
Historical MLP yields are ~450 bps over the 10-year Treasury yield, which is currently 2.60%. That would put normalized yields at 710 bps, and simplistically value AM at $17.50 based on the NTM distribution of $1.24/sh for 38% upside.
Historical MLP multiples of DCF are ~13x, and would value AM at $18.50 based on NTM distributable cash flow of $1.43/sh for 45% upside. (Five years ago many MLPs were trading >20x.)
Even the Alerian ETF (AMLP), whose constituents are lower quality, slower growing, and more highly leveraged than AM on average, is yielding less at 8.1% and trading at a higher DCF multiple of ~9.5x.
AM is levered 2.9x pro forma the simplification transaction that closed this week vs. 3.5x for the average AMLP constituent. Management expects them to grow the distribution at a 23% CAGR through 2022 (reaching $2.31/sh that year; 18.0% yield on the current price) and to compound DCF/sh at a 21% CAGR. AMLP doesn’t come close to offering that kind of growth. Whether you believe those projections will be achieved is sort of beside the point – AM is priced for no growth.
I see fundamental downside of ~16%. MLPs generally troughed at approximately 7.5x distributable cash flow in the financial crisis and at the bottom of the energy downturn. Placing a 7.5x multiple on AM’s 2019 DCF of $1.43/sh would result in a share price of $10.75. There might be some downside to the $1.43 figure which is the midpoint of management guidance, but probably not a lot of downside for reasons I will discuss.
With a 9.9% yield I only need this stock to hold flat for the investment to work.
AM is the midstream arm of Antero Resources (AR). It is a C corp and has no IDRs. AR is the 4th largest natural gas producer in the United States and the largest NGL producer. 70% of Q4’18 production was natural gas, 28% was NGLs and 2% was oil. Their footprint is 612,000 net acres in the Appalachian Basin, mostly in West Virginia. 89% of their proved reserves are from the Marcellus and 11% are from the Utica.
AM also has a joint venture with MPLX to build processing and fractionation facilities.
AM has two segments (1) gathering & processing (2) water handling. Gathering gets paid a fixed fee per unit of production. It accounted for 68% of EBITDA in 2018.
The water business also gets paid based on its volumes but it’s inherently more volatile because it is mostly linked to completions activity at AR. Whereas the gathering business keeps getting paid even if AR doesn’t make any new wells because the old wells keep producing, the water business generally doesn’t earn revenue unless AR drills new wells. It accounted for 32% of EBITDA in 2018.
Each segment has some minimum volume commitments. In aggregate, MVCs account for ~30% of AM’s 2019 consensus revenue estimates and 12% of 2020 revenue.
The AM you can buy today is the product of a simplification transaction that closed this week between the old LP units of AM and Antero Midstream GP (AMGP) that eliminated old AM’s IDRs.
Old AM went public in 2014, but before it did the founders of the Antero family of companies (Paul Rady and Glen Warren) carved out the IDRs for themselves and their original PE backers rather than letting AR own them, which is the standard arrangement (e.g. CNX/CNXM, NBL/NBLX, RICE/RMP). The IDR take was zero at the time.
Old AM grew, and they took the IDRs public as AMGP in May 2017 by which time the total IDR take had reached 20%. Make sure you’re sitting down now – the insiders kept IDRs on the IDRs through Series B shares on AMGP. Now it’s probably making more sense to the reader why new AM has languished as such cheap levels. (The Series B shares were also eliminated as part of the simplification transaction.)
Why It’s Cheap
Some investors can’t stand Antero because they think Paul and Glen are out to screw everybody. I was at a dinner in Pittsburgh last fall and some random investor who I had never met came over to my table and started talking to me. He obviously knew the gas producers very well and was on his second or third glass of red. He was seething about the Series B shares and I was thinking, dude, why are you taking this up with me, but it was actually a very helpful window into sentiment on this company.
I mean, yes, the Series B shares were insult on top of injury after keeping the IDRs, but that’s all gone now as a result of the simplification transaction. Paul and Glen own $430 million of new AM and my interests as a shareholder are in line with theirs. To their credit they built a huge company organically and haven’t done the types of things that usually get companies in trouble like “me too” acquisitions at full valuations (see E&P industry, Delaware Basin, 2016), di-worsified away from the northeast (see GPOR, Mid-Con, 2017), bought another company in a transaction that had solid industrial logic but failed to integrate it leading to 500 mmcfe/d of production stuck behind pipe (see EQT/RICE). Nor have they taken on too much debt (see half the industry in late 2014).
They haven’t done anything nearly as egregious as what we’ve seen at companies like Energy Transfer or Chesapeake. I don’t like the IDR and Series B stuff, but it has all been fairly transparent.
I should also point out that they did the simplification transaction in a way that was accretive to old AM unitholders. Contrast that with the situation at EQM/EQGP where the IDR buyout was clearly dilutive to the limited partners.
Law of large numbers for AR and the Marcellus. AR grew production nearly 5x from 673 mmcfe/d at the time of its IPO in 2013 to 3.2 bcfe/d in Q4’18. It went from being a minnow to being the 4th largest gas producer and the largest NGL producer in the United States. Likewise, the Marcellus now accounts for 25% of gross U.S. gas supply, up from <3% in 2010.
Production growth expectations for Marcellus producers have come down over time as the basin has saturated the market. Specific to AR, at their analyst day in January 2018 they were talking about growing production to 5.2 bcfe/d by 2022. Now they are guiding to approximately 4.2-4.8 bcfe/d.
With respect to AM, the company issued multi-year guidance when the transaction was announced last October. They updated that guidance for lower activity levels at AR in January and while they kept pro forma distribution guidance intact, they lowered DCF guidance, implying reduced coverage of 1.1x in 2020-22 vs. 1.25x previously. I think investors saw the coverage reduced to a level just above 1x and thought, oh no, that was the last lever they could to pull before they actually have to cut distribution guidance. That is a valid concern but it seems like it’s priced in at this point.
There is a fear that associated gas out of the Permian will destroy the market. The Marcellus disintermediated early mover/higher cost shale gas plays like the Barnett, the Fayetteville and the old Haynesville. Now their main competition for market share comes from a basin that doesn’t care about its impact on gas prices because decision making there is dictated by oil prices.
Associated gas growth is real, but demand is growing and associated gas can’t fill it all.
Simmons is modeling gas supply/demand growing 5.9 bcf/d in 2019, from 83.0 to 88.9. The Permian accounts for 1.5 bcf/d of that growth (from 10.5 to 12.0), and the Marcellus/Utica accounts for 4.2 bcf/d (from 29.1 to 33.3). The remaining 0.2 bcf/d is a mix of puts and takes with other basins. Basically, if demand growth projections pan out the Marcellus almost by definition has to grow, and AR/AM has a role to play, especially considering the restraint being shown by the other Marcellus bellwethers.
EQT is expected to grow gas production <200 mmcf/d. RRC is growing <100 mmcf/d. GPOR is growing <100 mmcf/d. CNX is growing 60 mmcf/d. That’s just 460 mmcf/d of growth from those key producers net of royalties.
Pretty much all the Marcellus upstream and midstream stocks have struggled as the gas strip has come down. However, at $2.75/mcf Henry Hub and $50/bbl WTI AR should be able to hold production flat within cash flow and even generate some free cash flow in 2020 and beyond, allowing AM to at least hold the line on the dividend at the 2019 guidance level of $1.24.
At slightly higher oil prices like $55/bbl (NGL prices are somewhat tethered to oil so AR would benefit) they can either generate a good amount of free cash flow in maintenance mode or continue growing. Either outcome is great for AM at these valuation levels.
Fear that AR’s huge firm transportation commitments, which used to be seen as an asset back when northeast basis differentials were wide and AR’s realizations were much higher than the peer group’s, are a liability now that the basis gap to Henry Hub has narrowed significantly and peer realizations are catching up. EBITDA per mcfe at AR is pretty similar to peers now. Their realizations are still higher, but their costs are higher too, so when you net it all out they are more or less in line with the group. All else equal if you’re going to generate the same EBITDA per mcfe I’m sure most investors would rather get there without the headache of large take or pay contracts.
2019 is AR’s peak year for unutilized capacity with ~1.1 bcfe/d unused vs. 450 mmcfe/d last year. However, it will fall back to 150-475 mmcfe/d in 2021 as AR grows production. They have 100% of 2019 gas production hedged and 55% of 2020 gas hedged so they probably can motor through any short-term weakness in the gas markets.
Economic weakness in China/Asia. AR gets 19% of its production and 24% of its revenues from C3+ NGLs, which includes propane. U.S. propane production is rising but domestic demand is a melting ice cube. Approximately 2/3 of propane production is exported as a result – to places like China where they lack natural gas distribution infrastructure and propane demand has been rising because of its portability and utility.
China is also a key source of demand for U.S. LNG exports because of their efforts to reduce their use of coal for environmental reasons.
The fear is that if China’s economy craters their demand for U.S. LNG and propane exports will get hurt, and AR will be in a world of pain. A midstream affiliate is only as strong as its sponsor.
That is all plausible but I expect the Communist party to throw the kitchen sink at any economic problems. They have to maintain economic stability in order to maintain their grip on power. They are also building a lot of regas capacity and as Jack Fusco at Cheniere has said they don’t build facilities over there in order to leave them dormant.
I occasionally hear investors raise the concern that AM will have to lower its fee schedule. I agree their fee schedule could be above market, as it was established at a time when Henry Hub was in the $4s.
AR claims AM’s fee schedule is actually below the Appalachian average based on their analysis of 19 public and private fee schedules they have analyzed. Fee schedules are hard to independently compare across G&Ps (e.g. some include compression fees, some don’t) but AM’s trailing ROIC of 17% obviously compares favorably to the average AMLP constituent’s trailing ROIC of <10%. There are fundamental reasons why their ROIC should probably be structurally higher but perhaps there is some room to give back economics to AR. Maybe there will be a fee reduction at some point in exchange for compensation like additional MVCs or minimum well commitments.
Paul and Glen also run AR and they own $165 million of its stock. That is surely a big stake they will want to support, but it pales against the $430 million of AM they own. If they ever do anything it will probably be a win-win.
The simplification process felt like it took forever. Last March they were telling investors the process would be figured out in a matter of months, not quarters, and here we are a year later and the deal has just closed.
Investor churn as a result of the simplification transaction and transitioning of AM from an MLP to a C-corp
Old AM and AMGP were removed from various Alerian indices at the close on Monday, March 11. This appeared to result in forced selling at the end of last week. It also seemed like there was forced selling yesterday by MLP investors who received their shares of new AM and aren’t in the business of owning C-corps.
I could go on, but you get the picture. There have been a lot of reasons to avoid the stock.
The IDRs are gone
The new C-corp structure opens the stock up to a much wider universe of investors
New AM should be eligible for inclusion in a variety of indexes
AR’s well-level economics are strong enough (>2x fully loaded recycle ratios – the threshold for E&P value creation), the drilling inventory is deep enough (>20 years), and the balance sheet is strong enough (2.2x E&P standalone) that some amount of growth at AM is likely, whereas it’s currently priced for no growth
Shareholders’ interests are aligned with management. In fact, it’s pretty rare in the energy space to find an owner/operator management team that owns as much stock as these guys do
Gas prices may have some upside. Or maybe they don’t. I don’t know. Associated gas can’t do it all. LNG export capacity is set to double to nearly 10 bcf/d by the end of the year. That’s approximately 4 bcf/d of capacity additions within a year in a market where production is expected to be 90 bcf/d, and inventories are 32% below the 5-year average. I realize there is a growing consensus that gas is moving from a storage model to a just in time production model, but 32%? This seems like a good setup for gas to at least reach some sort of price that enables an economic return for the marginal producer.
Even if I’m not right about any of this stuff AM is still yielding nearly 10% with excess coverage and very manageable leverage. I don’t need the stock to go up to earn a return that is commensurate with the stock market’s long-term average.
My main concern is about a recession with China and/or India at the center. Those two countries and the broader region are a key source of LNG demand growth, and by extension demand growth for U.S. gas, as well as a key source of demand growth for NGLs.
When I think about the commodity price implosion that would happen in that scenario my thoughts turn to whether AR could keep the pipes full on their FT commitments, or whether their production would go into decline and in turn cause AR to choke on those contracts.
AR can probably stay within cash flow and hold production flat at 3.2 bcfe/d after 2019 in a recession scenario where Henry Hub is $2.65/mcf and WTI is $45/bbl because they have 84.7 net drilled uncompleted wells and 26 net proved developed non-producing wells that don’t require full cycle capital investments to start producing. ~111 wells is equivalent to nearly their entire 2019 program of 120 net completions.
There is no doubt commodity prices can go lower than $2.65/45 temporarily, but those levels are well below threshold prices for the rest of the upstream complex and would force production declines at many other producers before AR had to cry uncle. I could see AR temporarily electing to allow production to decline in order to build up some cash flow to deploy opportunistically. Of course, investors would probably extrapolate the downward trajectory and panic.
I would like to believe there will be a reversal of fund flows as forced selling by MLP investors stops and the new C corp gains entry into various market indices.
|Entry||03/15/2019 11:15 AM|
Just wanted to see how you get to the 30% under MVC's?
The IR has "Underpinned by minimum volume commitments (MVCs): 70-75% on compression, HP gathering and processing" and from the 10K "Antero Resources has dedicated acreage to, and entered into long‑term contracts for gathering and compression services on, Antero Midstream’s gathering and compression systems, as well as long‑term contracts for receiving water services. However, while Antero Midstream has a 20‑year right of first offer to provide processing and fractionation services to Antero Resources, subject to certain exceptions, Antero Resources is under no obligation to consider whether any future drilling plans would create beneficial opportunities for Antero Midstream. Additionally, although Antero Midstream’s water services agreement and the processing and fractionation services provided by the Joint Venture are supported by minimum volume commitments, Antero Midstream’s gathering and compression agreement includes minimum volumes commitments only on high‑pressure pipelines and compressor stations constructed at Antero Resources’ request after the Antero Midstream IPO."
Since the IPO EBITDA has gone from $67 to ~$900 in 2019, assuming 1/3 is water, G&P is $600 implying ~88% coming after the IPO and as such be under a MVC? (Assuming EBITDA and Revenue under MVCs are the same %)
|Subject||Re: MVC coverage?|
|Entry||03/15/2019 12:08 PM|
There is a table on page F-16 of AM's 2018 10-K that shows MVC revenue by segment by year. Search for the term "minimum revenue amounts" in the 10-K and you should find it.
|Subject||thanks for an|
|Entry||03/15/2019 12:21 PM|
interesting and timely writeup. I appreciate all the work you've done in the space. What are your thoughts on AM vs. AR at this stage and (assuming you own AR), how you've sized these positions relative to one another? Thanks!
|Subject||Re: thanks for an|
|Entry||03/15/2019 04:29 PM|
You bet. Yes I own AR.
AM is the safer bet for sure because of the nature of the business model and the ~10% yield. The upside is less though. AM could maybe go up >50% but AR could double or triple just on a reversion to the mean of fair value. The question I am wrestling with is why shouldn't it be an enormous position.
Obviously it's our job to tell the market when it's wrong but at the same time I think it's important to listen to what the market is saying in case it has a valid point. This is going to sound pathetic but I'll say it anyway. Frankly I don't know what the market is telling us with AR at $8.40/sh. It is demonstrably cheaper than peers with more leverage, worse rock, similarly big FT commitments, less inventory, lacking a midstream affiliate, where management owns no stock, etc. Almost no matter what variable you control for it's hard to explain. Even AR's bonds trade on a different planet than its equity.
Maybe it really is just a fund flows issue. The levered pair trade funds dominate trading in these names these days because the generalists have been vanquished. AR is an easy short because it checks all the boxes that investors hate in this environment: outspend, big growth, big FT commitments even though basis diffs have narrowed, debt above 2x (even if just barely), gas exposure. They announced a buyback but appear to be showing minimal urgency about executing on it. There are no big long only investors in the game who are willing to push back and say "f&%# this I am buying 10% of the stock". There is no dividend, so it's dead money as far as the eye can see and there is no real carrying cost on the short.
I thought it was demonstrably cheap 50% higher yet here we are. If it can go down 50% after it reached really cheap levels who is to say it can't go down another 30%? Honestly that is what is on my mind. Yeah value is its own catalyst but when the thing can move 50% just because it's blowing in the wind I would really like to identify an event that will cause the re-rating. Energy is volatile enough as it is. I really don't feel like losing 30% over the next six months for the chance to make 2x or 3x a few years from now. I would like to skip the 30% mark to market loss and just cut straight to the double or triple.
The fact that it's at 0.5-0.6x EV/Stan Meas and 3.5x EBITDA yet I'm looking for reasons not to buy a LOT more is probably the "tell" that it's time to back up the truck.
|Subject||Re: Re: thanks for an|
|Entry||03/15/2019 05:15 PM|
I enjoyed the write up. a few questions.
1) AM seems to have a sweetheart deal with AR. As you pointed out, AM's ROIC is too high. Not a great starting point. AM is also completely reliant on AR. If AR is moderately successful... great. We collect a big fat growing div for the length of the contract. everyone is happy. But, if AR starts burning a lot of cash, the deal could get recut quite a bit lower (along with a significant div cut). AR's hedge book doesn't go out very far and forward curve looks pretty mediocre. Do you have a sense of where gas would need to go for AR to become distressed?
2) can AM reinvest capital at the same above market rate? why would AR allow that?
3) you value this using a yield framework ... but if i were to do a DCF, how should i think about the terminal value here? Are their assets stranded after some period of time (after gas is pumped out of the area)?
|Subject||Re: Re: Re: thanks for an|
|Entry||03/15/2019 06:15 PM|
1) So yes it's high, perhaps too high, but if they had 5 customers each producing 600 mmcfe/d I can almost assure you the ROIC would be lower than if they were just serving one customer producing 3.2 bcfe/d because operations would not be integrated and capital would not be getting invested on a just in time basis. The insurance policy against an unfavorable recut on the fee schedule is Paul and Glen's massive holdings of AM. Again, if they do something I am pretty confident it would be a win win. They found a way to do that with the AM/AMGP collapse through the clever use of tax attributes.
3) I'm not too worried about terminal value. AR is guiding to 120-130 completions in 2019. They claim 3,013 "core" drilling location. Obviously not all of them are as good as the 120-130 wells they will complete in 2019 but that is still 23-25 years of inventory and the wells would keep producing long after the last location is completed. Keep in mind that prior to the shale revolution it would have been almost unheard of for an E&P company to have 23-25 years of inventory. Reserve replacement was a source of constant stress but now you almost never see companies tout that metric because they don't need to.
|Subject||Re: Re: Re: Re: thanks for an|
|Entry||03/15/2019 09:03 PM|
That’s helpful. Thank you.
|Subject||Tudor Pickering has something to say|
|Entry||03/20/2019 06:03 PM|
"Although valuation upside remains attractive and sustainable dividend yield of ~9.0% offers
reasonable income, we see risk-reward as largely balanced as macro headwinds likely continue
to weigh on natural gas sentiment and limit near-term catalysts."
So to recap, a 9% yield with 20% growth is merely "reasonable",
and even then it lacks catalysts and there is a problem with "sentiment".
|Entry||03/20/2019 06:05 PM|
I am sure there are other scenarios, but out of these I think option 4 is the most likely and the only one I am willing to bet on. Eventually the gulf between domestic gas prices and global gas prices must be bridged. Even at $3 HHUB we would be priced below global LNG prices less long term transport costs. This is how I ultimately get comfortable with the gas macro risk; but clearly there can be a lot of pain before exports save us. Am I missing something? How is everybody else looking it?
|Subject||Re: Gas Macro|
|Entry||03/22/2019 02:54 PM|
was waiting for someone to write this. As a canadian who has seen our prducers live with 1.80 AECO (in cad) for the past 2 years I can tell you things can get much worse. Running out 2.70 henry hub is nowhere near what a bear case truly is.
Now the big difference is in Canada takeaway capacity is so contrained (thank you transcanada) that we get these massive discounts. That should have fixed things but becasue so much of the growth is coming from guys drilling for condensate (priced like oil) and the wells come out 60% gas, total supply hasn't come down despite non ecoonmic gas pricing. Sounds familiar?
The US is obviously much better at getting pipe built, but the only true relief comes down to LNG as others have pointed out. So when I look at other writeups talking about the LNG wave coming in 2019/2020 i get more alarmed for the years after when the US is still adding 4-5 bcf a year and demand growth isn't there. I agree things should fix themselves over the long run with enough LNG demand to eat up incremental supply but its going to be 4 to 5 year lag before it balances.
And on the point of backin out canadian gas, Canadian producers are already living with low prices and stil producing as much as our pipes can handle. whats more likely is when transcanada fixed their sytem in 2021 we get an extra 2 bcf of Canadian gas flowing into the US. Canadians would be happy with 2.50 cad AECO.
So in a nutshell it seems like 3.00 HH is more of a hard ceiling than 2.70 is a floor for the next 4 years
|Subject||Re: Re: Gas Macro|
|Entry||03/22/2019 03:10 PM|
Agree that Canadians would be thrilled with C$2.50 AECO but they better hope for West Coast LNG or more West Coast Canadian demand. HH is the only market that seems to matter these days and the AECO differential seems to be structually higher, so would the following be approximate implied AECO prices?
US$3.00 HH - US$1.25 transport = US$ 1.75 x 1.35 = C$2.25 AECO
US$2.70 HH - US$1.50 transport = US$ 1.20 x 1.35 = C$1.62 AECO
How are the Canadians at <C$2.00 AECO long-term?
|Subject||Re: Re: Re: Gas Macro|
|Entry||03/22/2019 04:50 PM|
under 2.00 AECO they struggle but survive. Good operators that are all dry gas like Peyto can basically still flatline production even at 1.75 aeco for the next couple years by spending cashflow. Guys who target condensate like Seven gens, Kelt, Nuvista will all be growing while spending cashflow or just above. Eventually they will run out of inventory so just flatlining production and chewing through reserves isnt a real strategy.
But I do think the extra 2 BCF of takeaway transcanada can bring on will mean canada will grow in the 2021 timeframe and that will be an incremental headwind for HH. My understanding is transportation costs to get out of alberta and into the US system (Dawn) is $1.00. So at 2.75 HH canadian producers are getting 2.30 aeco. not great but they will grow that 2 bcf at that price if oil is above $50
|Subject||Re: Re: Re: Re: Gas Macro|
|Entry||03/22/2019 10:37 PM|
Things can always get worse. My point was just that it will cause a supply response. Peyto, who appears to be among the lowest cost dry gas producers in Canada, is a good example (even though they do produce 10Mbpd of liquids ~12%). Their gas production was down double-digit in 2018 and they are moving into liquids plays now (Cardium). I don't know Peyto that well. We did one call with them years ago, and our take was that they paid out most of their cash flow as a dividend and relied on equity markets to fund growth. Since then they have cut their dividend...twice. I don't think many dry gas producers can hold production flat within cash flow at 1.80 gas. Peyto appears to be close if you believe their reported F&D costs. It is all about oil/liquids though; very few are drilling for dry gas anymore.
|Entry||04/03/2019 12:04 PM|
a couple of questions: what do you think is the right long term % price of NGL to WTI? the company has taken this down over the past year. As you point out the drop is very significant. it appears right now we are at approximately 50% NGL to WTI ratio. i think that's causing the weakness (along with technical factors)
>>>I think the difference between $19 AR and $9 AR has more to do with NGL prices than gas prices (and even more to do with technical factors). 2019-2020 gas prices are slightly higher than they were a year ago. 21-22 are down about 0.20. Antero is still pretty hedged next year on gas at 50+%. Propane prices, on the other hand, are down over 30% from the beginning of 2018 when AR did its analyst day (this is Mt Belvieu, not assuming any ME2 uplift). AR has no hedges on NGLs.
|Entry||04/05/2019 05:26 PM|
I saw them last week. Michael Kennedy said it's highly unlikely AR would try to reset AM's fee schedule. It would require a significant committee process and besides, the fee schedule is pretty fair. That said, the fee schedule was set at a time when they were only drilling 1-2 wells per pad and did not envision 12 well pads. It probably would have been set lower if they had anticipated such big pads because the midstream economies of scale are not really being shared back with AR.
Also, Kennedy thought EQM's recent bolt-on acquisition at 10.3x EBITDA highlighted the value at AM which is trading at the same multiple because AM as a whole is a much better business.