Description

I am long Range Resources (NYSE: RRC) at $13 ½.  Yes, it’s a gas-levered E&P that has been getting destroyed, so I realize this is going to take some convincing.  But if anyone wants to come with me, this moment will be on the ground floor of something real and fun and inspiring and true in this godforsaken business and we will do it together.  Who’s coming with me?

Cliff Notes Summary   
Range’s Marcellus position in Southwest Pennsylvania has some of the best recycle ratios and deepest drilling inventories in the entire industry.  It is epic.  They generate >3x recycle ratios on unhedged basis and have 33 years of inventory at the 2017 drilling pace.  At $3/mcf Henry Hub, $50/bbl WTI and NGLs at 29% of WTI, I estimate their Marcellus position can grow production at a 13% CAGR for 15 years while still generating free cash flow, with mid to high single digit FCF yields through year 5, double digit FCF yields for years 5-9, and >40% FCF yields in years 10-27.  On an NAV basis I value the equity in this scenario at $38/sh, for 180% upside.  Liquids are 40% of revenues, and if I run $60/bbl WTI through the model I get a value of $55/sh, for >300% upside. 

Alternatively, they could go into maintenance mode and only invest enough to hold production flat indefinitely.  At the strip they would generate FCF of $3/sh, a 22% FCF yield, for decades to come.  Capitalize that at 10x and the stock would be worth $30/sh.  A 15x multiple would put it at $45/sh. 

In order for value to be impaired I believe Henry Hub needs to sustain in the low 2s forever compared with the strip in the high 2s.The risk/reward appears to be highly skewed to the upside. 

So why is it down 85% from its all-time high of $95.41 in 2014, down 30% from its low at the trough of the energy cycle in early 2016, and flat since 1997?  Because their capital allocation has been disastrous.  First, they took on too much debt executing their “growth at low cost” strategy in the Marcellus during the good times, although the debt is manageable and a clear path to deleveraging is available.  Second, they blew $4.4 billion acquiring North Louisiana gas producer Memorial Resource Development (MRD) in late 2016.  They assumed $1.1 billion of debt and gave them 31% of the pro forma equity.  Investors were skeptical of the deal from the beginning, and their concerns climaxed last month when Range lowered their MRD type curves.   The deal grew their debt by 50% but it only grew their production by 27%, and now it looks like the PUDs are not worth very much.  Yikes!

But this is the opportunity.  Management has lost its credibility with shareholders and they are boxed in from doing anything besides selling non-core assets and executing on Marcellus development, which admittedly they have done a great job with.  They have already committed to a financial strategy that prioritizes meaningful free cash flow over production growth.  If a credible activist shows up, they would likely meet little resistance from shareholders, and the process of crystallizing value through the generation of FCF would be accelerated.  The playbook is simple.  Change management.  Sell non-core assets.  Draw a line under the MRD acquisition by writing it down and selling it off, even if they only get PDP value for it.  Sweep some FCF to further reducing debt, and implement buybacks and a meaningful dividend with the excess.  The stock should be an easy double under those circumstances.  Sailing Stone owns 11% of Antero and just filed a 13D.  It’s worth noting they also own 13.6% of Range.

Consensus Narrative
This stock is hated by energy investors right now.  Everyone who bought it in the last 10 years and still holds it has lost money.  The short interest is 13%, or >$400 million.   For anyone who is tempted to believe the stock is down so much because gas prices are weak, the answer is absolutely not. 

Credit Suisse initiated coverage on the group back in December when Bill Featherston moved over from UBS.  Here is a list of the P/NAV for every E&P in his coverage.  This group runs the gamut from oily to gassy, underleveraged to overleveraged, deep inventory to light inventory, good capital allocators to bad capital allocators, and so on.  RRC was materially cheaper than every single one of them by a mile.

When RRC lowered their MRD type curves last month the Street went absolutely berserk and the stock fell 10% in a day.

The analyst at Morgan Stanley lowered his bear case from $5/sh to $3/sh to account for “additional risk from multiple compression”.  At $3/sh the stock would be at 4x EBITDA, the province of subscale E&Ps with Tier 3 economics.  To further highlight how ridiculous $3/sh is, the stock is worth $4/sh just on PDPs alone, and I’m pretty sure the Marcellus PUDs are worth some non-zero figure. 

One brave sell-side analyst put out a relatively positive note highlighting the company’s new emphasis on free cash flow over growth.  A sales guy at his firm told me he had four clients – two long only and two hedge funds – call him and scream at him.

Here’s how hated the stock is right now.  Two other gassy E&Ps – Comstock (CRK) and Eclipse Resources (ECR) - have released their YE2017 reserves and PV-10 values.  Neither company is even on the same planet as Range’s SW Marcellus position in terms of inventory depth or economics, and CRK has a far worse balance sheet, yet they trade at material premiums to Range in terms of EV/PV-10.



Finally, there were 169 million shares out before the MRD deal, and the closing price the day before the deal was announced was $42.01.  With the stock now at $13 ½, the 169 million shares have given up $4.8 billion of market cap, $400 million more than the entire value of the MRD deal, implying some level of value destruction to the Marcellus business if you assume the current trading price has some economic rationale behind it.

Range’s SW PA well economics have seen some improvements since then and their wellhead realizations have improved materially, so it would seem hard to argue that asset has gotten worse. 

Business Description/History
Range is the 7^th largest gas producer in the U.S. and the second largest identified NGL producer.  Their headquarters is in Dallas.  People think of Range as a gas company, but their liquids exposure is significant at 33% of production and 40% of revenues in Q3’17.

The thing that stands out from that table is 73% of their production comes from Southwest Pennsylvania where they generate fantastic well-level recycle ratios of 4.2 – 4.9x (thanks in part to the liquids-rich content) and have 32 years of drilling inventory.  Their consolidated recycle ratios are the best among dozens of E&Ps I have run the numbers on.  You can count on one hand the number of E&Ps that are in the same ballpark.

The company was formed in 1979 as Lomack Petroleum and went public in 1980.  From inception through 1988 they drilled over 500 oil and gas wells, primarily Appalachia.  The company was restructured in 1988 after it succumbed to the commodity price downturn.  Thomas J. Edelman was appointed chairman as part of the restructuring.  He co-founded Snyder Oil (now part of Devon Energy) which had thrown Lomack a lifeline.  One of his colleagues at Snyder, John Pinkerton was appointed CEO. 

I have never met Edelman but from studying parts of his track record he seems like the type of guy who could teach you a thing or two about making money in the oil patch.  After Lomack he went on to co-found Patina, which he sold to Noble Energy.  Patina generated industry leading recycle ratios for a number of years in the early 2000s and now serves as the cornerstone of Noble’s position in the DJ Basin.  He took NBL stock in the deal.  He still serves on the board and owns 3.0 million shares worth $96 million. 

The new strategy for Lomack after Edelman and Pinkerton took over was to grow by acquiring mature properties in Appalachia and in the Permian Basin.  That was back when dry hole risk was much higher and it was much safer to build reserves by acquiring them rather than exploring for them.  Management owned 8% of the stock so even though debt grew from $4 million in 1989 to $727 million by 1997, at least you could say they were eating their own cooking.

The strategy worked.  The stock went from the low single digits to $11, supported by tailwinds of a cooperative price environment and magnified by growing leverage.  

See if you can spot the parallels with present day Range in what happened next…

By the late 1990s Appalachia was a real cornerstone asset for the company.  Operating cash flow was $30 million and maintenance capex was less than half that, so free cash flow was very nice.  Its reserve life was also substantial at 17 years, so they had enough to keep them busy. 

Then two things happened.  First, they went off the reservation and bought a company that didn’t seem like a natural fit - an offshore Gulf of Mexico producer called Domain Energy in this case.  (They changed the name of the surviving company to Range Resources.)  Investors hated the deal because the two companies were a study in contrasts.  Lomak’s consolidated reserve life was long at 15 years while Domain’s was short at 8 years.  Lomak was onshore and Domaine was offshore.  Lomak was an acquirer and Domain was an explorer.   Then, commodity prices turned down. 

Debt/EBITDAX looked manageable at 2.5x in 1997.  By the end of 1998 after the deal closed and commodity prices had fallen, debt/EBITDAX rose to 6.2x.  The stock fell 93% from a high of $14 in 1998 to a low of $1 in 2000. 

The similarities with Range’s current situation are eerie, particularly in light of the fact that many of the company’s senior managers today have been there a long time and several were around during that episode. 

Let’s fast forward…

After surviving a second brush with death they resumed their strategy of active portfolio management, buying and selling a bunch of different assets.  The most noteworthy asset they acquired was a privately held company called Stroud which owned 20,000 net acres in the Barnett, the original shale basin, and came with key technical personnel who were part of the original team at Mitchell Energy, the company widely acknowledged as the original shale innovator.  That deal got Range into the shale game, and over the next 18 months they entered five shale plays and increased their shale holdings nearly fivefold to 880,000 net acres.

They recognized similarities with the Barnett in Appalachia, and in 2004 they were the first company to drill a horizontal/fracked well in the Marcellus.  They tried a “Barnett-style” slickwater frack to test the concept.  From what I read, the initial horizontal well results were somewhat disappointing, but vertical results obtained as part of the initial tests showed enough promise to make them went to lease a lot more acreage. 

They play was on fire across the industry by 2008 and it seemed like the Marcellus gave producers the best of both worlds – high quality rock in a repeatable play and close proximity to premium markets.  At the time, gas in the northeast still sold for material premiums to Henry Hub.  As the land grab settled out it became apparent Range had a huge position in some of the very best rock in Southwest PA.    Range decided to pursue a strategy they called “growth at low cost” and started outspending cash flow in order to grow production as quickly as possible.  It made sense.  If you’ve got the rock and you’ve got the scale then there is some logic to outspending cash flow as long as your EBITDA is growing at least as fast as your debt.

For a while it was, but the industry became a victim of its own success in the new shale gas plays.  U.S. gas production grew so much that Henry Hub went from $6-8/mcf in the early years of the revolution to $1.60/mcf at the low in early 2016, and northeast basis differentials went from healthy premiums to significant discounts.  Range’s debt metrics blew out. 

They survived thanks in part to the extraordinary quality of the rock and the depth of the inventory.  They had successfully made it through the hardest part of the E&P lifecycle – the exploration and delineation phase – with a massive crown jewel position, and were in a position to deal only with high class problems associated with the development phase like achieving incremental productivity gains and seeking new markets for their prolific output.  With the rebound in energy markets starting in Q2’16 Range’s credit metrics started to heal and they had survived.  

So what did they do?  They went out and bought another company in an unproven basin that was still in the delineation phase!   Coincidentally, I just finished reading Deals From Hell and this deal checked a number of boxes that are the hallmarks of bad deals.  One of the hallmarks was dubious industrial logic.  Range didn’t need to acquire more reserves.  Nor did the deal help them high grade their assets. 

The consensus explanation for the motivation seems to be that it was a backdoor way of deleveraging.  They had just sold a big asset package in late 2015, but commodity prices continued to slide and even on a pro forma basis their EBITDAX interest coverage was barely above the minimum level required by one of the covenants on their revolver.  The company still needed to deleverage a bit, and for some reason they did not do a secondary after the capital markets re-opened along with virtually every single E&P in existence.  The MRD deal was technically accretive to their leverage metrics, so I guess from that point of view it temporarily solved the leverage problem, but it came at a cost that would ultimately be significant.

At the time of the deal MRD had three type curves that generated recycle ratios of 3.9x, 2.6x, and 1.5x.  The two best curves were the main curves.  Last month, after a series of disappointing well results, RRC consolidated the curves down to just one that has a recycle ratio of 1.9x.  That is terrible.  Above 2.0x is the level at which E&P value creation begins, so if you’re not even at 2.0x at the well-level, by the time you roll all the land, seismic, and corporate expenses into the mix you are destroying a lot of value. 

How did this happen?  It’s tempting to just chalk it up to management not owning a lot of stock and more, and I think that’s part of it.  The management team used to own 8% of the stock.  Now they only own 0.6%.  But, if they didn’t care about the stock then why try so hard to avoid dilution?  They have told me in the past that everyone in the organization owns stock and that is something they seem to have promoted for a long time. 

The truth may simply be that like a lot of E&P teams they are good at executing and bad at allocating capital.  Mastering the craft of resource exploitation is something almost the entire industry is well schooled in.  It’s an education process that starts in college and continues over the course of their careers as they rise up the ranks.  Capital allocation is a topic that receives much less attention.

The Nature of My Bet
Paying $13 ½ for shares of Range gets you a combination of asset quality and value that has rarely been available outside of broad market dislocations.  At this price you get assets that are capable of delivering a 22% free cash flow yield for decades, assuming flat production.

I am betting that 1) large pools of private capital exist, 2) some percentage of the decision makers who run them will become aware of Range, and 3) a subset of those decision makers will be motivated by the prospect of a 22% FCF yield. 

Alternatively, a corporate buyer like Shell might see the logic in buying a major producer of NGLs at a 22% FCF yield whose main field is in the same neighborhood as Shell’s new cracker, which will consume 88 kbl/d of ethane when it is fully up and running.

With respect to commodity prices, my bet with Range is that I don’t need to be right about what the market clearing prices will be with much precision.  I just need to be reasonably sure that the company’s rock is good enough that the rest of the industry will not be able to achieve well productivity gains faster than Range.  It’s not about the price.  It’s about the margin.  As I will show later on, Range has been very good at driving efficiencies.

Tier 1 shale E&Ps are on the verge of making the transition from being businesses that are perpetually riding the changing trajectories of basin lifecycles, rarely spending much time in any particular phase and therefore only investable by specialists who speak the industry’s unique language of EURs and type curves, to being businesses that can stay in the development phase for years and years, generate free cash flow on a sustainable basis, and are investable by a much wider group of generalists who can appreciate universal concepts like FCF yields.

Don’t get me wrong – there are dozens and dozens of publicly traded E&Ps and the vast majority of them will not make the leap to becoming FCF machines because they don’t have the asset quality or the scale.  There are maybe only 10 that can make the transition and Range is one of them.  If Range’s free cash flow power crystallizes for investors the stock could make the jump to hyperspace.

***

I was largely self-taught when it came to investing.  I started out reading Peter Lynch who emphasized investing in what you know.  I read even more from Buffett who emphasized brands, moats, and pricing power.  That all resonated deeply with me, so naturally over the years I fell in love with energy, which offers a smorgasbord of B2B companies that don’t meet any of those criteria! 

E&Ps don’t have much in common with businesses like See’s Candy.  They don’t have pricing power.  They’re capital intensive commodity producers.  Any moat they have starts with the rock, and it only lasts until the asset is depleted.  Generating free cash flow is almost unheard of.  It’s extraordinarily easy to destroy value because the companies have to reinvent themselves every so often in the search to replace reserves.  The industry also has a long history of promoters taking advantage of investors.  Still, I spend a lot of time studying E&Ps because everything that happens in energy stems from the upstream, but I rarely invest because of those characteristics.

My energy investments have prioritized business models that can grow earnings in line with shale production volumes.  I believe shale is poised to take market share on a global basis for years to come because it is low cost, it has scale, and the shale business model is endowed with characteristics that support continuous efficiency gains at a speed that other resource types can’t compete with.  It also can’t be copied outside the United States except in select locations for a variety of reasons.  It’s hard to predict commodity prices but at least I know the volumes are going to move. 

To that end I have mainly been investing in midstream companies and royalty vehicles aligned with low cost and scalable shale resources because the main driver of their earnings growth is volumes.  These are the closest to Buffett-like businesses in the oil patch.  They tend to generate consistent free cash flow and have meaningful capital return programs, two characteristics that E&Ps have lacked.  Midstream companies even have pricing power if they own the right assets.  However, the time has come to start making exceptions for E&Ps like Range because I don’t know where else you can find the potential to generate >20% FCF yields on a sustained basis. 

Every basin goes through a lifecycle, from exploration and new discoveries in the identification phase, to delineation in the optimization phase, and development in the standardization phase, followed by a reinvention phase when operators employ secondary and tertiary recovery techniques or discover new zones that are commercially viable.

Note:  This graph is five years old so you can ignore what it says about the lifecycle point of the basins.  Just focus on the concept.

The identification and optimization phases are particularly dangerous and I am certainly in no position to invest during those periods because my technical knowledge base is not strong enough.  Rather than majoring in petroleum engineering in college I thought it would be super smart to major in business, a tremendous mistake.  What’s done is done though and a man has got to know his limitations. 

There are good reasons why people seek their fortunes in the E&P business in spite of the long odds.  One reason is scale.  The upstream offers the potential to hit it out of the park in a way that very few businesses can offer.  It’s no coincidence that a number of people who became some of the richest in the world did it in the upstream business, from H.L. Hunt to J. Paul Getty in the olden days to Harold Hamm today. 

The goal of most E&Ps is to build up a large base of producing wells, which is a very desirable asset, as quickly and cheaply as possible.  By the time you get a large base built up, the risks associated with exploration and dry holes have already been absorbed, and so have the capital costs of making the wells.  Sure, production from wells is constantly declining and commodity prices are unpredictable, but the incremental costs of operating the wells are minimal.  As such, producing wells will be profitable under almost all circumstances.  Profitability is a sure thing.  The only question is just how profitable will they be.  80% EBITDA margins are common.

For many years the independent E&P business model was to build the PDP base, and then seek an exit before production from the depleting asset rolled over by selling to a major or a large independent who saw M&A as a low risk way to replenish reserves.    

However, it has been apparent for a while now that shale’s characteristics are very different from those of conventional resources.  Drilling success rates are often 98-100% (meaning dry holes are rare) compared with 50-60% prior.  I’ll use Noble Energy (NBL) as an example since they have a long time series of history and have participated in the shale game.  Notice the spike in success rates in 2005-06 as the shale revolution got under way.

Noble’s CEO recently said one of the things about the business that has changed over the course of his career is the companies’ inventory depths are much greater now.  To his point, before shale arrived, you couldn’t give E&Ps much credit as an investor for resources beyond what was actually booked as proved reserves and reserve life indexes were just 7-9 years.  Companies didn’t generate much FCF (and many burned cash) as they tried to build up their base of producing wells in order to make that exit before production rolled. 

Inventories are lower risk and are measured in terms of decades now.  What this means in terms of financial profiles is that shale E&Ps with deep inventories can settle in and generate free cash flow in the standardization phase for years to come rather than constantly riding the rollercoaster of the basin lifecycle.

Management teams have not committed to it across the board because many are still operating with the playbook they grew up on, which is to grow grow grow.  Now shareholders are forcing them to abandon that business model in favor of sustained free cash flow generation because what is the point of having a deep and low-cost asset base if you blow it all growing production into oversupplied markets?  

The Journal published an interesting article on Dec-06-2017 entitled, “Wall Street’s Fracking Frenzy Runs Dry as Profits Fail to Materialize.”  The article detailed a meeting that took place in New York last September among a number of twelve major shareholders of U.S. E&Ps.  The consensus was they would collectively hold management teams’ feet to the fire on the topic of capital discipline. 

Talk is now turning to action.  The changes that are occurring represent a sea change for the E&P industry and have the potential to unlock significant latent value.  Here are some anecdotes:

• ·        Anadarko (APC) announced a $2.5 billion share repurchase program, equal to 10% of its market cap as of the day of the announcement.  They are also saying they will let incremental cash flow from higher commodity prices accumulate rather than plowing it back into the drillbit in pursuit of growth. 

• ·      Gulfport Energy (GPOR) announced they will spend within cash flow in 2018, and authorized a $100 million repurchase program (5% of the market cap) 

• ·      Antero Resources (AR) held an analyst day earlier this month and announced a long-term plan that would generate FCF of $1.6 billion through 2022 at the strip and $2.8 billion based on flat $60/bbl WTI and $2.85 natural gas 

• ·      Range (RRC) announced a five-year plan that they expect to result in $1 billion of cumulative FCF through 2022.  Range’s plan assumes 13% debt-adjusted production per share growth through 2022, at which point they will still have 3,200 locations and a FCF yield of 33%.  A year ago they were talking about 20% production growth.
  
  It’s not just me modeling free cash flow in a spreadsheet and praying that one day they might see the light.  They have actually put this plan in motion. 

• ·      Cabot (COG):

o   Raised the dividend 150% in May-2017

o   In conjunction with their Q3’17 earnings release they announced a three-year plan for their Marcellus asset that would generate $2.5 billion of cumulative pre-tax free cash flow from 2018 to 2020

o   Raised the dividend 20% in Jan-2018

Let’s explore what Cabot is doing on the capital allocation front because it is instructive.  Over the last 12 months COG has dramatically outperformed its Marcellus peers.

Is it because they are suddenly getting much better pricing?  No.

Perhaps they are growing production faster?  No.

The reason they have outperformed so dramatically is because they committed to production growth restraint, clearly laid out how much free cash flow they are capable of generating in maintenance mode for the next 25 years thereby providing a tremendous level of visibility, and detailed the potential use of free cash flow including an increased dividend and a share repurchase program.  Then they began following through with concrete action steps.

Source:  COG presentation, Mar-27-2017

The $1,446 million of pre-tax FCF at $2.50/mcf realized price equates to roughly $2/sh after tax simplistically applying the prevailing 35% corporate tax rate at the time.  Because of severely negative basis differentials in Northeast PA, COG’s unhedged realizations have only exceeded $2.50/mcf in one quarter since the start of the energy downturn so perhaps I am being generous, although increased takeaway in the region may help basis differentials.  The stock has traded in a range from $21 - $29 ½ in the last year, for an implied multiple on maintenance FCF of 10 – 15x.  Put those multiples on RRC’s $3/sh of maintenance FCF and the stock would be worth $30-45/sh.    

BALANCE SHEET
This is the one area that gives me some discomfort.  A clear path to better positioning exists though.  

Debt/EBITDA is too high at 3.2x consensus 2018 EBITDA, but it is reasonably well structured.  Of the $4 billion they owe, $1.1 billion is a draw on the secured revolver ($3.0 billion borrowing base, $2.0 billion committed amount) with a 2.8% interest rate and a maturity date of Oct-16-2019. 

The rest is virtually all unsecured bonds maturing over the 2021-25 time frame that are trading at or above par with yields of 4.4 – 5.3%. 



The revolver has two covenants worth noting.  The first is a minimum EBITDA to cash interest coverage ratio of 2.5x.  I calculate them at 6.0x on a trailing basis.  Looking forward, I have them at 5.1x in 2018 and 7.4x in 2019 assuming $3/mcf HH, $50/bbl WTI and NGLs at 29% of WTI.  Consensus has them at 6.1x in 2018 and 7.1x in 2019 on a consolidated basis.

The other covenant is a minimum ratio of reserves value to debt of 1.5x.  PV-10 at YE2017 using SEC pricing was $8.1 billion vs. total debt of $4.0 billion, for a ratio of 2.0x.  Range has only booked 1/3 of its proven offsetting locations for each producing horizontal well so their reserves number is likely conservative.

Management’s five-year plan envisions debt/EBITDAX falling to 2.7x in 2020 and <2.0x by 2022.  That is an absurdly slow rate of improvement.  There is no reason for an asset base of this quality and depth to be levered more than 2x.  It should be in the low 1s.  Southwest PA Marcellus peer Antero Resources was recently upgraded to investment grade by Fitch.  Range is already at BB+/Sta from S&P.  The just need one notch to achieve investment grade status.  The asset base can support it.  They would just need to commit to the right capital structure, although I don’t want to see them pursue the rating just yet because it would likely hamper their ability to repurchase shares and establish a meaningful dividend in the short-term.

I believe management will be under pressure to execute asset sales and pay down debt, which they can do easily since paying down the revolver does not expose them to redemption premiums or the hassle of tendering for bonds in the open market. 

Credit Suisse estimates the Northeast PA position could be sold for $800 million, which coincidentally is the same value I come up with.  Howard Weil thinks they would only get PDP value, which I estimate at $540 million (153 mmcf/d at $3,500/flowing).  That’s still pretty good.)  Credit Suisse also estimates the Mid-Con position could be sold for $100 million.  Combined sale proceeds of $640 - 900 million would reduce debt by 15-23% with only a modest reduction in EBITDA.

(If I assume all the FCF gets swept to paying down debt principal, they could completely eliminate the remaining $3.1-3.4 billion within 7-8 years.)

If they sold the Terryville for PDP value of $800 million (360 mmcfe/d at $2,250/flowing) debt would be down to $2.2 billion.  Let private equity try to crack the code there and get value from the PUDs.  At that point leverage on just the earnings power of the Southwest PA Marcellus would be <2x. 

MANAGEMENT & INCENTIVES
Many of the senior leaders have been with the company a long time.  That can sometimes be a good thing – continuity and such.  In this case I would call it being entrenched.  The bonus incentives are somewhat aligned with minority shareholders, but management does not own a lot of stock.

Jeff Ventura has been with the company since 2003.  He joined as COO and became CEO in 2012.  He also became chairman in 2015.  I strongly prefer to see the chairman and CEO roles separated unless the person is a proven owner/operator or owns a ton of stock, and Jeff doesn’t check either box.  He only owns $5 million worth of stock.  Yes, the share price is depressed but that is shocking in light of how long he has been with the company.  His cash comp was $2.5 million last year.  Given that his cash comp in a single year is 50% of his ownership stake I have to conclude his incentives are aligned with keeping his job rather than finding a buyer for the company.

In fact, by my count the entire management team and board of directors only owns $20 million worth of stock outright, not counting stock-based compensation, which I hope we can all agree is not quite the same as outright ownership.  That is pathetic.  Obviously they are not willing to bet on themselves.

• ·      2016 annual bonus criteria:

o   F&D costs:                                           30% weighting

o   EBITDAX:                                             15% weighting

o   Production growth per share:            20% weighting

o   Reserves growth per share:                20% weighting

o   Absolute stock price performance:    15% weighting

• ·      2017 annual bonus criteria:

o   F&D costs:                                           30% weighting

o   EBITDAX:                                             15% weighting

o   Production growth per share:            20% weighting

o   Reserves growth per share:                20% weighting

o   Drilling rate of return:                         15% weighting

Note that the production and reserves growth metrics are calculated on a debt-adjusted basis, as they should be.  It was good to see them drop annual stock price performance in favor of drilling rate of return for 2017.  My understanding is Sailing Stone was behind that.

• ·      2017 long-term incentive program:

o   The usual relative TSR stuff:               75% weighting

o   Production growth per share:            12.5% weighting

o   Reserves growth per share:                12.5% weighting

The production and reserves growth metrics were new for 2017.  Before that relative TSR was the only criteria.  Baby steps…

NATURAL GAS MACRO 

Supply

I’m not bullish on gas prices.  Cheniere’s analyst day presentation includes an estimate that the United States has 800 Tcf of gas supply that is economic at $3/mcf, or nearly 30 years’ worth on the demand run rate of 77 bcf/d.  Those top down figures reconcile with my bottom up assessments of the inventory depths and economics for Tier 1 gas producers.  

It’s highly likely shale gas producers will continue driving further efficiency gains.  A very well-respected E&P CEO said to me a few years ago that one of the main things he learned in all his years in the business was to never underestimate the ingenuity of the American oilman, and so, I decided not to do that. 

Range has been a sterling example of those efficiency gains, as demonstrated by a time series of the F&D costs on their Southwest PA Wet Gas type curve.  Since the stock is already pricing in a gas strip in the low 2s I don’t need to worry about what the market clearing price for gas will be.  I just need to feel comfortable that Range will maintain its position on the cost curve relative to other producers. 

I should also point out that in the nine years since the shale revolution kicked into high gear they have only had negative reserve revisions one time.

Sometimes I like to rack up the consensus production estimates for the top E&Ps just to see how that bottom up view squares with the macro picture.  When it comes to dry gas supply, what jumps out is that just six Appalachian producers are expected to meet nearly half the growth that is coming over the next couple of years, when a supply ramp is required to meet demand from the wave of LNG export capacity coming online. 

It can really only come from those six because they’re the ones with the scale to do it.

Southwestern (SWN) has a big acreage position but they don’t have the balance sheet or enough inventory with top quartile economics to really push the drillbit.  COG has a relatively small acreage position but it is the best in the industry and all of it is outstanding.  

Of the six, Cabot, Range and Gulfport have chosen to dial back the growth.  It will be somewhat harder for Antero, CNX and EQT to dial back because they have midstream affiliates to support but pressure is mounting on them to figure it out.

The bears might argue that a wave of associated gas from oil-focused basins like the Permian will depress gas prices because Permian drilling decisions are not impacted very much by gas prices and the Texas Railroad Commission allows producers to flare gas from oil wells, so in theory many of those producers might be indifferent if gas prices went to zero.  The risk of material pressure on gas prices is a risk especially if there is a spike in oil prices to something like $80/bbl. 

My counter to that argument is Range gets 40% of its revenues from liquids, so if oil goes to $80/bbl they will be fine.  WTI at $80/bbl and Henry Hub at $2/mcf gets me to a $35 share price.

A word on takeaway.  Appalachia is expected to add 8.1 bcf/d of production over the next two years.  Fortunately, there is >10 bcf/d of new takeaway capacity expected in 2018 followed by another 4.8 bcf/d in 2018.  (See the table below from the good people at Howard Weil.)  In any event Range is already set with their takeaway needs

Demand

Total U.S. demand was 75.1 bcf/d in 2016 having grown at a 1.8% CAGR over the prior four years.  Demand is currently running ~77 bcf/d.  Simmons expects demand to grow at a CAGR of >4% over the next three years to ~87 bcf/d by 2020.  The incremental ~10 bcf/d of demand comes from the following buckets:

• ·      6 bcf/d from LNG exports, with 5.8 bcf/d of that coming in 2019
• ·      2.9 bcf/d from positive swings in the import/export balances with Mexico and Canada, split roughly 50/50 between the countries
• ·      0.9 bcf/d from power gen demand, as gas continues displacing coal and nuclear
• ·      0.4 bcf/d from industrial demand, primarily from growing ethylene production

 We should have 10 bcf/d of export capacity in place by some time in 2019.


Source:  RRC presentation, Dec-2017

It’s important to note that counterparties to LNG export facilities are not obligated to take the gas, although they are obligated to pay the fixed capacity charges.  The gas will likely only move if the variable cash costs on a landed basis in the consuming markets are competitive with local prices. 

With Henry Hub at ~$3/mmbtu, the delivered variable cost to U.K. is ~$5/mmbtu as compared with local U.K. spot prices in the ~$8/mmbtu range.  Delivered cost to Asia is ~$6/mmbtu and Asian spot prices are ~$11/mmbtu.

The Chinese LNG demand picture is very robust.  Xi Jinping made a cleaner environment a key priority at last fall’s Communist Party Congress.  To that end, the country is cutting back on coal consumption and replacing it with gas.  They have committed to increasing gas’s share of their energy mix from 7% currently to 10% by 2020, which implies a 50% increase from ~21 bcf/d in 2016 to 31 bcf/d, for growth of 10 bcf/d.

The country has made some efforts at unlocking shale gas, but the reality is they don’t have enough locally produced gas to satisfy demand.  The country is experiencing shortages in some regions right now.  They are increasing their LNG import capacity by 33% from ~8 bcf/d currently to ~11 bcf/d by 2020.  Their LNG imports were 5.5 bcf/d in 2017, so they should have room to increase imports by ~5 bcf/d by 2020. 

5 bcf/d of growth over the next few years would be a big deal for the LNG market.  Global gas consumption is >340 bcf/d but LNG trade is barely 10% of that at 38 bcf/d.  If you add 5 bcf/d to a 38 bcf/d market in a short period it’s a lot.

Australia, Qatar and the U.S. are the “Big 3” LNG exporters but Australia has been sidelined a bit because they are having domestic shortages.  Their LNG export projects came online over the last few years and went from LNG consuming nothing to quickly taking >50% of domestic supply.  Last year the Australian government established a mechanism that allows them to limit LNG exports if more gas is being exported than consumed locally.  The mechanism lasts through 2023.

Source:  https://www.eia.gov/todayinenergy/detail.php?id=33412

Over the very long-term, LNG demand is expected to be significant and can potentially be an enormous market for U.S. shale gas.  Demand of 325 mtpa by the early 2020s would equate to ~48 bcf/d, up 10 bcf/d from current levels.  It’s a huge opportunity for Appalachia which is producing 25 bcf/d.  It would also be a nice outlet for associated gas.


Source:  “American LNG Developers Wade Into Market Awash With Gas”, Financial Times, Sep-30-2017

Not only do we have 30 years of gas supply that is economic at $3/mcf Henry Hub, but our LNG infrastructure is cheaper than the competition.

Source: “American LNG Developers Wade Into Market Awash With Gas”, Financial Times, Sep-30-2017

NGL MACRO
You could make a bullish case for NGL prices if you wanted.  They have historically been linked to oil prices and the macro outlook for oil is relatively constructive since demand is strong, Saudi is holding back production, and Venezuela’s production wherewithal is disintegrating.  Not to mention the major project queue from the boom years is rolling off, plus the impacts of severe global upstream capex reductions over the course of 2015/16 are about to catch up with the industry.  It would be rational for Saudi and Russia to continue cooperating in support of the oil prices because both regimes rely on oil revenues to support their grip on power.  

However, I think it’srealistic to expect NGL prices to eventually decouple from oil prices and become priced on their individual supply/demand dynamics, just like what’s happening with LNG.  As with gas, I’ll simply try to demonstrate that the demand outlook is robust.

First, some nomenclature for various hydrocarbons:

• ·      C1:  Natural gas aka methane is the lightest hydrocarbon molecule with only one atom of carbon.  Used mainly as fuel.
• ·      C2:  Ethane has two atoms of carbon, and can either be left in the natural gas stream and burned for fuel, or it can be recovered in liquid form and used as a feedstock for chemical building blocks like ethylene if the economics are sufficient to cover the costs of recovery.
• ·      C3:  Propane has three atoms of carbon and is primarily used as a portable fuel for heating in homes, crop drying, and as a chemical feedstock.
• ·      C4:  Butane has four atoms of carbon and its primary demand sources are refining, petrochemicals. 
• ·      C5+:  Isobutane and natural gasoline also belong to the “heavies”

 Let’s divide the NGL discussion into ethane and C3+.  
 

Ethane

E&Ps used to recover all the ethane from their production stream, but wet gas production growth in places Southwest PA swamped the market and crushed the price.  Ethane became so cheap it wasn’t worth the cost of paying a midstream company to recover it, so producers began leaving it in the gas stream and just getting fuel value for it.  The U.S. is currently producing ~1.8 mmbbl/d of gross ethane, but is rejecting 400 kbl/d, resulting in net ethane production of ~1.4 mmbbl/d.

Wells Fargo expects gross ethane production to grow by 500 kbl/d over the next five years.  If you assume rejection goes to zero, that adds another 400 klb/d for total supply growth of 900 kbl/d. 

Enterprise Product Partners (EPD) sees 770 kbl/d of incremental ethane demand over the next few years (615 kbl/d by 2019, 155 kbl/d in early 2020s) just from new crackers that have already received FID, and more are on the way.  Wells Fargo also sees 230 kbl/d of incremental ethane export capacity of 140 klb/d by the end of 2019. 

Domestic demand is robust because chemical companies are building lots of ethylene plants to take advantage of the low-cost feedstock.  Ethane competes with Naphtha as a feedstock for ethylene.  Globally, ethane only accounts for ~1/3 of the feedstock.  Ethane is ~25 c/gal.  Naphtha is ~130 c/gal.  It’s so expensive because it’s derived from oil.  As such, it will be hard for naphtha to be cost competitive with ethane, and it’s easy to see why chemical companies would want to build ethylene plants near abundant low-cost supplies.  It gives them a material cost advantage over naphtha-based producers.

Putting it all together, supply/demand are expected to grow at an 11% CAGR over the next five years so the market should at least remain balanced.

C3+

The generic C3+ barrel is comprised of 52% propane, 18% butane, 10% isobutene and 20% natural gasoline.  (Range’s Marcellus barrel has 4% more propane and 4% less natural gasoline, making it slightly less valuable.) 

U.S. demand is stagnant at 1.4 mmbbl/d in large part because home heating demand for propane is a melting ice cube as more homes as gas utility grids expand and hook up more homes in rural areas.  If E&Ps are going to grow C3+ production they will have to export it.

The U.S. already produces 2.0 – 2.2 mmbbl/d and Antero expects supply to increase 475 kbl/d over the next three years.  They expect the Asia/Pacific alone region to soak up 300 kbl/d of that supply.  It’s basically residential demand in China and India.  The IEA expects residential demand in China/India to grow 600 kbl/d from 2016 to 2022.  Propane is great for heating in markets like that where they don’t have mature gas grids but living standards are rising and people want heating fuels that burn cleaner and more consistently than wood. 

The U.S. is dominant when it comes to C3 exports so we may not have much competition to meet that demand.


Source:  Enterprise Products Partners presentation, Jan-2018

Export infrastructure lagged behind supply growth for a while, and NGL realizations as a % of WTI collapsed into the 20% range.  Export infrastructure has caught up and now realizations are in the 50% range for the industry’s generic barrel.

The Northeast region currently produces ~400 kbl/d of C3+ but pipeline takeaway is just ~300 kbl/d.  Rail is being used to plug the gap.  The big midstream project that will facilitate continued supply growth is Energy Transfer’s Mariner East 2, which is supposed to add ~250 kbl/d of takeaway capacity by Q2’18.  The Pennsylvania Department of Environmental Protection forced Energy Transfer to halt construction last month because of permit violations.  My concern is heightened because Energy Transfer also had permit violations when they were building the Rover gas pipeline and it seems like they are sloppy.  I expect the pipeline to get built but I would not be surprised if there are delays.

Source:  Antero’s analyst day presentation, Jan-2018

VALUATION
Let’s look at this a handful of different ways.  

• ·      P/E Ratio (11.8x on 2019):  Range’s consensus EPS estimates are positive.  Very few E&Ps can say they expect to generate positive GAAP net income or that they trade at reasonable P/E ratios unless they have taken massive impairment charges during the downturn that reduce forward looking DD&A expense.  (Range only took $633 million of impairments over the course of Q3’15 – Q1’16 on PP&E at Q2’15 of $8.2 billion.)  Consensus is $0.84 in 2018 and $1.14 in 2019.  Implied P/E ratios are 16.1x and 11.8x.  
  
  Thought exercise:  Slow growth/no growth companies like KO and MCD are trading at 23x on 2019.  If I told you a random S&P 500 constituent was growing organically by double digits, what multiple would you guess it’d be trading at on 2019?  Higher or lower than 11.8x?

• ·      EV/PV-10 ($31/sh):  Range’s enterprise value is $7.7 billion.  Their YE2017 proved reserves have a PV-10 of $9.5 billion at the strip.  Even if you chop 21% straight off the PV-10 for income taxes, you’re still at $7.5 billion and just about covering the stock price.  However, the proved reserves are only based on quantities of 15.3 Tcfe.  Range has only booked 1/3 of its proven offsetting locations for each producing horizontal well.  The 3P resource of the Marcellus alone is 58.5 Tcfe, or nearly 4x the proved reserves.  That looks to me like a healthy margin of safety.
  
  Recall that CRK and ECR are trading at 1.4-1.5x EV/PV-10 while RRC is at 0.9x using SEC pricing.  If you valued RRC at the same multiples as CRK and ECR – and why wouldn’t you given the vastly superior economics and depth of Range’s SW Marcellus position – the stock would be at $31/sh for 130% upside.
  
  
  
• ·      Maintenance FCF (23.5% yield):  As a thought exercise, imagine you were able to buy 100% of Range at the current market cap of $3.4 billion and it was your only asset.  After you recovered from the out of body experience that can only come from spending all of your net worth buying a gassy E&P, you would probably start to think about what to do with it.  Given the low-cost structure and deep drilling inventory of the company, one thing you might do is instruct management to invest just enough money to hold production flat, hedge all the production at the strip, and then harvest the cash.  What would that look like?  It would look pretty good, assuming your definition of “good” includes >20% FCF yields as far as the eye can see. 
  
  Here is my math at the strip, assuming Range’s guidance for basis differentials. 
  
  
  
  But wait, debt/EBITDAX is a shocking 4.0x!  Yes, but you’re hedged in this thought exercise, and if you sweep all the FCF to debt it will be fully paid off in 6 years.  You would be saving $184 million on interest, or $145 million after-tax.  Pro forma FCF would increase to $933 million, or $3.75/sh, for a FCF yield of 28% on your purchase price.  Put a 10x or 15x multiple on $3/sh of FCF and the stock would be worth $30-45/sh.
  

• ·      EQT/RICE Comp (>$22-30/sh):  Citi’s fairness opinion for the EQT/RICE deal included a number of valuation methodologies for RICE.  Three of them included a standalone value for RICE”s upstream business, separate from the Rice Midstream (RMP) units owned by RICE, the retained midstream EBITDA, and the GP/IDRs held by RICE.
  
  Using those upstream values, I was able to back into implied values for RICE’s undeveloped inventory on a $/location basis and a $/acre basis.  I think the location-based the most relevant to RRC because it is more precise than the acreage- based approach.  Let’s just focus on the sum of the parts methodology since it’s more conservative than the precedent transactions or DCF methodologies.
  
  Note that I give RRC’s PDPs a higher multiple than RICE’s because their netbacks are higher and their PDP decline rates are lower due to having a more mature production base.
  
  
  

Keep in mind this should be a floor under RRC’s valuation, not a ceiling.  Note that the 421,000 net effective acres at RICE gives them credit for the Upper Devonian and Utica zones, whereas the implied valuations for RRC only give them credit for the Marcellus and they have 400,000 net acres prospective for the Utica.  Range has been hinting at the Utica’s potential for years but they haven’t done much with it so I am not giving them any credit. 

Range’s economics are also better than Rice’s, due in part to the significant liquids exposure.  Liquids are 33% of RRC’s production and 40% of revenues, but only 1% of RICE’s production and 3.5% of their revenues.  Oil and NGLs are simply worth more than natural gas and it makes a big difference.  This is demonstrated through RRC’s higher recycle ratios.  RRC’s capital efficiency has been better too.

• ·      Full development model ($37/sh):  I ran a full development model on Range’s Marcellus assets and came up with a value of $33 ½ per share at $50/bbl WTI, $3/mcf HH, and NGLs at 29% of WTI.  I only gave N. La. a PDP liquidation value of ~$800 million or $3 ¼ per share ($2,250/flowing on Q3’17 production of 360 mmcfe/d).  That’s 175% upside.  The model is far too detailed to post here, but I will share some of the high-level assumptions and takeaways. 

o   Assumptions:

§  Location counts and economics in line with Range’s current type curves, i.e. no further efficiency gains

§  21% corporate tax rate

§  $180 million cash G&A with 3% escalation CAGR

§  3% well cost inflation CAGR

§  Year 1 capex budget of $941 million allocated fully to the Marcellus rather than just 80% as guided last week

§  D&C capex grossed up by 7.5% for other stuff (land, seismic, capitalized overheads)

§  Development order was SW PA Wet area first because it has the most inventory, followed by SW PA Super Rich, then SW PA Dry and finally NE PA Dry

§  Maximum of 4 rigs on their SW PA Wet acreage, maximum of 2 rigs in the other areas

§  PDP decline rates in line with what IR told me (24% first year, then 17/14% etc. until it hits 5% terminal declines in year 10)

§  $1.25/mcfe for LOE + transportation

§  4% tax rate for taxes other than income

§  All free cash flow swept to debt paydown until debt is fully paid off

§  10% cost of equity capital

§  Debt balances and interest rates as of Q3’17

§  Marcellus differentials based on recent guidance

o   Key takeaways:

§  Production grows at a double-digit rate for the first 10 years while generating free cash flow every year

§  Production peaks in Year 15 before going into decline

§  Mid to high single digit FCF yields for years 1-5

§  Double digit FCF yields for years 5-9

§  >40% FCF yields for years 10-27

§  The debt is fully paid off by Year 8

Keep in mind the $37/sh value assumes a 3% inflation CAGR for G&A and well costs.  Here are the values you get at different commodity price combinations if you assume no cost inflation.  The numbers get pretty crazy.



Those numbers also assume NGLs stay pegged to WTI at 29%.  If the ratio goes higher, look out.

Also, they assume a 10% cost of equity.  I think something in the high single digits would be more reasonable for an asset like RRC’s Marcellus position if it were funded more conservatively. 

Here are the discount rates from the EQT/RICE fairness opinion.  If you plug numbers like these into the RRC development model you get huge figures.



This methodology is certainly an example of the DCF telescope principal in action – small changes to the assumptions have a big impact on the output – but with the stock at $13 ½ it should be pretty clear that there isn’t much downside unless you use some punitive assumptions, and there is a TON of upside.

KEY RISKS
These are the risks I worry about the most.

• ·      The end of QE and the beginning of a rising interest rate cycle tip the economy into recession, hurting demand for gas and NGLs

• ·      China implodes and brings the global economy down with it.  Commodity prices would surely fall, with oil and by extension NGLs being directly exposed

• ·      Long-term delays to Mariner East 2

Catalyst

Crystallization of Range's FCF potential through activistm, M&A, or the simple passage of time.