Description

I recommend Epsilon Energy equity (EPSEF) as a long idea.  My midpoint estimate of intrinsic value is $6.15/share, so at Wednesday's closing price of $3.05/share I think it's trading at less than 50% of fair value.

At this point in the market cycle, where the S&P 500 is trading at record highs, we're in the midst of a nearly 5-year old bull market, the ratio of total US market cap to GDP exceeds peak 2007 levels, and the Russell 2000 is trading at a trailing P/E of something obscene like 70 or 80, I for one am quite excited to find something trading at less than 50% of fair value.  Furthermore, I believe that Epsilon management is aligned with shareholders in a uniquely constructive fashion and that the gap between price and value is likely to close within a range of 1-3 years.

Author's Comment

My goal with this write-up is to present an analysis to others exactly as I would want one presented to me.  That means my goal is to make the analysis unbiased.  So my intention is that all parameters, assumptions, and estimates used are just as likely to be too pessimistic as they are to be too optimistic.  I believe in applying a "margin of safety" only once at the very end, where the investor compares current market price to the midpoint of estimated intrinsic value and decides if the gap is large enough to justify making an investment.  I do realize that I'm talking my own book by presenting this as a VIC write-up, given that it's a very large position for me, but my goal is to be unbiased nevertheless.

One final note: this company is headquartered in Canada and trades on the TSX under the symbol EPS.TO (priced in CAD), in addition to the US trading symbol EPSEF (priced in USD).  Because all assets (other than one remaining Canadian asset currently being marketed for sale), revenue, and financial statements are US-dollar based, this analysis is all US-dollar based.

Background

Epsilon Energy was written up by utah1009 back in July 2010, please see that write-up for some earlier background.  In my opinion, Utah nailed that analysis.  The Marcellus asset was indeed very undervalued, and management was indeed horrible.  Much has changed since then, however.

Today, Epsilon is a hybrid between an upstream Marcellus Shale NG E&P and a midstream NG gathering/processing company.  Epsilon operates neither asset.  It owns an approximate 25% working interest in an upstream JV operated by Chesapeake (CHK) and a 35% working interest in a midstream asset operated by Access Midstrem (ACMP), a midstream MLP.  While this area of the Marcellus produces only dry NG, their acreage is in the sweet spot of the formation - Susquehanna County - and their all-in cost of production is among the lowest of any gas producer in the United States. 

The company is now 30% owned by JVL Advisors and its principal owner John Lovoi (ex-head of Morgan Stanley O&G investment banking), together with the $10B asset manager Advisory Research.  This new management team took over the company in mid-July of this year after the previous management team's strategic review failed.  JVL and Advisory Research bought in at prices in the range of $3-$4 (CAD) per share.  The new CEO, Mike Raleigh, works as an advisor to JVL and is earning no extra compensation (neither cash nor stock-based comp) for his work as CEO of Epsilon, other than via his shareholding in the company through JVL.

Please refer to this article for some more background:

http://seekingalpha.com/article/1861031-epsilon-energy-shareholders-in-charge

Upstream Valuation

As of the 12/31/2012 reserve report, Epsilon-Upstream had 30.2 net Proved locations (14.1 PUD), 146.2 Bcf of net Proved gas reserves (84.1 Bcf PUD), and a Proved PV10 valuation of $178.9M ($69.5M PUD) using the Canadian forecast pricing methodology.  They exited 2012 at 39.7 mmcf/day of (net) production.

Chesapeake did not drill any new wells for the JV during 2013, due to a large inventory of drilled but uncompleted wells left over from 2012 when gas prices were extremely low, but they did complete many of these wells during 2013 and Epsilon expects to exit 2013 with net production in the range of 45-50 mmcf/day.

Using the midpoint of 47.5 mmcf/day as their 2013 exit production, I estimate YE 2013 PDP reserves at 65.2 Bcf, compared to 54.5 Bcf of PDP reserves at YE 2012.  I arrive at that estimate by multiplying the YE 2012 PDP reserves by the exit production ratio 47.5/39.7.  That implies a 2013 PDP RLI of 3.76 years (note: this excludes PUDs and Probables) and a 23.4% average decline rate.  Since the base production consists of wells drilled over several prior years, I model it with a fixed effective decline rate of 23.4% per year with economic viability of 16 years, and 2014 base production that averages 42.2 mmcf/day (i.e., excluding production from new wells drilled in 2014).

Price Deck

I'm using a price deck derived from NYMEX NG (HH) futures market prices, as of last Thursday.  Here they are.

I assumed 2.5% annual inflation for any year after 2022 when required.

Basis Differential

Spot NG prices received by producers in the Marcellus region of PA have been far below NYMEX for the past couple of years due to the explosion of NG supply since 2010.  This severe oversupply situation is expected to resolve itself over the next couple of years since new takeaway capacity is rapidly being constructed to balance the rising supply. 

I believe the basis differentials shown in the table above are quite conservative.  Note that they're significantly more conservative than what's discussed in a recent report put out by Credit Suisse this year ("US Natural Gas Resevoir", August 13, 2013).  The figures shown include a -$0.10/mcf offset (starting in 2016) to account for a potential increase in gathering fees if Epsilon-Upstream is sold to an entity that's not one of the "anchor shippers".  In other words, Upstream currently gets a special deal from Midstream because of the Epsilon association, and that might go away in the future.

I would also note that my assumptions may be a bit too pessimistic as I'm assuming Epsilon gains no benefit from long-term supply contracts of the type negotiated by Cabot Oil and Gas (COG), which is somehow able to sell 65% of their Marcellus gas at NYMEX prices.  I plan on investigating this issue further in the future, to better understand why Epsilon isn't doing something similar.  At least part of the reason relates to a potential exit strategy for the company, which I'll discuss in more detail later.

Operating Costs

Epsilon-Upstream has incurred operating costs of $0.625/mcf in the 9 months YTD as of 9/30/2013.  My model starts off with 2014 operating costs of $0.74/mcf and escalates each year assuming 2.5% annual cost inflation. 

Income Taxes and Exit Strategy

As will become clear below income taxes play an important role in Epsilon's valuation, and executive management is clearly aware of that.  In a July 16, 2013 press release they wrote, "... the Board will explore opportunities to return the free cash from the Marcellus to shareholders in the most tax efficient manner possible...".  An eventual sale of the company is also clearly part of the plan.   In the Q3 earnings press release they wrote, "In our opinion, the optimal time to approach the divestiture market is when both the upstream and midstream have been optimized".

The midstream gathering/processing asset is clearly suitable for acquisition by a midstream MLP,  but it's not so clear that the upstream shale gas asset is appropriate for an MLP due to the relatively high decline rate.  There's also a tax complication in splitting up the midstream and upstream segments since if one segment is sold, but not the other, a corporate-level capital gain tax will need to be paid.

There are several possible solutions to these tax efficiency issues.  One possiblity is a sale of the whole company to a midstream MLP, which would then sell off the upstream piece.  Another option is a conversion of the company into either a hybrid (upstream + midstream) US MLP or a Canadian FAIT (Foreign Asset Income Trust).  A third option is a sale of the whole company to an integrated large scale gas consumer that requires a low cost long-term supply of natural gas, and which might therefore be shielded from the income tax issue since the whole operation would be a cost center for them.

Management indicated that this third option limits the extent to which they're willing to enter into long-term supply contracts, since such an agreement would make them unsuitable as a long-term supplier to a potential gas-consumer acquirer, and that helps explain why they aren't selling more of their gas at NYMEX prices like Cabot does.

Due to all of the above, I think it's appropriate to assume cash income taxes will need to be paid for the next 1-3 years, but after that there will be an effective tax shield.  Management guided to a 40% tax rate during the window that cash taxes are paid.

Estimated YE 2013 PDP PV10 Reserve Value

Using the above assumptions, my model yields a before-tax PDP PV10 reserve value of $133.3M, a 2-year-taxed PV10 value of $128.8M, and a fully-taxed PV10 value of $119.6M.

Estimated YE 2013 PUD PV15 Reserve Value

To model the PUDs I assumed a 5 year drilling plan, as guided by management.  They've booked 14.1 net PUD locations as of 12/31/12, and there was no new drilling in 2013, so that works out to 2.82 new net wells per year assuming no new locations are booked in 2013 or any year thereafter.

I believe projected net cash flows from PUDs should be discounted at 15% per year, rather than the 10% discount rate I use for PDPs, for two reasons: (a) execution risk and (b) expected profit margin is lower due to required capital expenditures.  One might argue that raising the discount rate due to (b) is unnecessary since future capital spending is already incorporated into the PUD NPV calculation, but I disagree since that incremental capital cost makes the net cash flows inherently more sensitive to changes in cost and commodity price assumptions, and therefore more risky.

The average booked PUD reserves per net location in the 2012 reserve report is 6.0 Bcf.  However, It's clear from observing industry trends, and especially peers such as Cabot, that completion technology continues to improve.  Management has also indicated repeatedly that they expect an upgrade on PUD reserves due to improved completion expectations.  As a result, I'm estimating that the PUDs will be booked at an average of 7.0 Bcf per well in the upcoming reserve report.  The following table shows a 10 year type curve derived from Chesapeake's Slide 21 from their May 2013 Investor Presentation "CHK Marcellus - Core of the Core Economics". 

I scaled down the cumulative production curve shown in the slide, which shows 8 Bcf of cumulative production by Year 10, to match my estimate of 2013 reserve bookings.  I'm also assuming zero production after Year 10.  Note: the above table was derived by eyeballing the powerpoint slide; production in years 5 and 6 aren't really exactly the same, nor are years 7-10, but I think the impact of the imprecision is negligible.

Drilling and completion costs are also coming down due to both improved completion and increased use of pad drilling.  The operator, Chesapeake, plans to transition to 80% pad drilling in 2014 as they transition from drilling to hold acreage to full scale development mode.  In the 2012 reserve report there was an average FDC per net PUD location of $7.7M.  I'm assuming this cost declines to $7.0M per location in the future, which is equal to the high end of the $6.4M - $7.0M well cost range given on the same Chesapeake slide.

All of the above assumptions result in a before-tax PUD PV15 valuation of $82.6M, a 2-year-tax PV15 valuation of $72.3M, and a fully-taxed PV15 valuation of $49.6M. 

Estimated YE 2013 Probables PV15 Reserve Value

According to Canadian reserve reporting requirements, "Probable" reserves must have a greater than 50% likelihood of eventual recovery.  So I evaluate them with a 15% discount rate like PUDs, but I also apply a 50% haircut to account for significantly more uncertainty.  I estimate a before-tax Probables PV15 valuation of $7.0M, a 2-year-tax PV15 valuation of $6.1M, and a fully-taxed PV15 valuation of $4.2M.

Total Upstream, Excluding Upper Marcellus

Adding up all the pieces, which gives Epsilon credit only for their 2P reserves, yields a $223.0M pre-tax, $207.3M 2-year tax, and $173.4M fully taxed valuation for Upstream.

Upstream Comparables

It's tough to find good comparables for the upstream assets.  This Susquehana County production and acreage is very desirable due to its extremely low cost of production, but it is dry gas, and that commodity has demonstrated high volatility and unpredictable prices in recent years. 

One interesting comp is the recent Enerplus acquisition (announced November 8th of this year) of 17,000 non-operated Marcellus net acres, 44 net future drilling locations, and 42 mmcf/day of net production, for $153M.  I'm expecting Epsilon to have around 47.5 mmcf/day of net production exiting this year, so that implies a somewhat higher valuation, but on the other hand Enerplus acquired much more undeveloped land and drilling locations (44 net compared to an estimated 14.2 net for Epsilon).  It's tough to know how the actual land compares in terms of potential well productivity, but it appears that Enerplus acquired more land in Bradford county, which is certainly in the Marcellus sweet spot but I don't think it's quite as good as Epsilon's Susquehanna County land.  Also, it looks like only 60% of Enerplus' new land is held by production compared to 80% of Epsilon's.  Overall I'd hold the value roughly flat and say that according to this comp, and not taking any other factors into account, Epsilon-Upstream is worth around $153M.

I do think it's worth pointing out that Enerplus is currently paying cash taxes in the US, so it's possible they considered the fully-taxed valuation most relevant when deciding how much they were willing to pay.  I'd also point out that the seller was not disclosed, so we don't know what their circumstances were.  But having said all that, in the interest of coming up with an unbiased estimate of intrinsic value I think it's appropriate to blend my more optimistic 2-year-tax valuation of $207.3M with the recent comp value of $153M, which yields a blended valuation of $180.1M.  Since that represents a 13.1% reduction from my model's 2-year-tax valuation, I discounted the before-tax and fully-taxed valuations by the same percentage.

Another comp to look at is Cabot Oil and Gas (COG), whose Marcellus acreage is very close to Epsilon's.  An August report from Cannacord Genuity gives an estimated 2014 EBITDA of $2.1B for Cabot, so COG is currently trading at a forward EV/EBITDA multiple of around 7.8x.  I estimate a 2014 EBITDA of $47.4M for Epsilon-Upstream, which means my original (unblended) midpoint valuation of $207.3M corresponds to a forward EV/EBITDA multiple of only 4.4x.  So my original valuation could hardly be called too optimistic when judged relative to COG, especially since the Cannacord analyst assumed $5.00/mcf NYMEX prices for 2014 and I'm using $4.25/mcf NYMEX and a realized price of only $3.00/mcf for Epsilon.  Nevertheless, I place more credence in the Enerplus comp than the Cabot comp due to Epsilon's non-operated minority interest, limited drilling inventory, much smaller size, and the fact that COG may be overvalued by the stock market.  So I'll stick with the blended valuation of $180.1M for Epsilon-Upstream.

Estimated Upper Marcellus Value

All of the above (except for one currently proved well that is Upper Marcellus) refers to what's known as the "Lower Marcellus".  However, there are recent signs that the "Upper Marcellus" is also economically viable.  The new management team at Epsilon had some independent reserve engineers come in and do an assessment, and now they're talking about the Upper Marcellus potentially being a 240 Bcf "contingent resource". 

Cabot is also getting more serious about the Upper Marcellus.  On December 9th they reported that two Upper Marcellus wells had a 30-day initial production rate of 24 mmcf/day.  They also said, "... based on the results to date, we continue to believe that the Upper Marcellus across our acreage position will provide rates of return that rival or exceed most unconventional resource plays".  Cabot has said they expect to complete their development plan for the Upper Marcellus by the end of 2014, and if that happens on schedule it will certainly solidify the value of Epsilon's Upper Marcellus resource.  Other companies have also expressed an interest in delineating the Upper Marcellus, such as Carrizo and Enerplus.

While some may exclude a "contingent resource" like this from an intrinsic value analysis and consider it only as "option value" or as a "sweetener", I think that's conceptually incorrect.  The thing is, options such as the Upper Marcellus locations have some fair value, and I believe that estimating this option value at $0 is clearly biased to the negative.

Management claims a contingent resource of 240 (net) Bcf on 127 gross locations (most recent corporate presentation on the website).  If we assume an average of 25% working interest, that works out to 31.75 net locations and 7.6 Bcf per location, and I've assumed $6.8M of capital spending per location.  I also assumed that no Upper Marcellus drilling would start until 2019, and discounted that time delay by 10% per year, so that immediately haircuts the Upper Marcellus valuation by a factor of (1/1.1)^6 = 0.56x just due to time. 

I then multiplied the 31.75 net locations by a factor of 0.25x to account for a very low level of certainty that these locations will become real producing wells, so that brings it down to 7.93 net locations.  (Note: I'm haircutting the Probables by 0.5x due to uncertainty, so another factor of 0.5x seems reasonable for this contingent resource.)  Finally, I performed a PV15 discounted cash flow analysis assuming a 5 year drilling plan.  All of the above results in a fair value estimate of $37.3M for the Upper Marcellus contingent resource, assuming no income tax liability.

Commodity Price Sensitivity Analysis

My midpoint valuation for Epsilon-Upstream is the total of all values listed above, which comes out to $217.5M assuming a 2-year period where cash income taxes are paid.  A low-case valuation can be derived by assuming realized prices 20% lower than the baseline values given above,which comes out to $173.8M.  A high-case valuation uses realized prices 20% higher than those given above, which works out to $262.9M.

Upstream Summary

All of the above analysis is summarized in the tables given below.

Midstream Valuation

Epsilon owns a 35% working interest in the Auburn Gas Gathering System (GGS), along with partners Statoil (21.125%) and Access Midstream Partners (43.875%).  This GGS connects the local gas wells to Kinder Morgan's TPG 300 pipeline.  The "anchor shippers" are Epsilon, Chesapeake, and Statoil, who have collectively dedicated 18,000 acres to the Auburn GGS.  The system can currently handle up to 300 mmcf/day with current dehydration and compression systems, but it's scalable to 500 mmcf/day if Epsilon spends another $15M-$20M for its share of the upgrade cost. 

This GGS business appears to be very desirable.  Epsilon-Midstream earns a very high 79% EBITDA margin on the gathering fee revenue according to the Q3 2013 financial statements.  Furthermore, almost no maintenance capital is required to keep the operation functioning since there are very few moving parts other than the compressors, which are rented.  The gathering fee revenue is a per-mcf tolling charge that is theoretically independent of fluctuations in commodity prices, so this is indeed a very high quality cash flow generator.  One does need to keep in mind, however, that a GGS has a limited geographical scope and that eventually the NG volume produced from a specific region will decline due to depletion.

The Auburn GGS is currently running at around 200 (gross) mmcf/day with intermittent spikes up to 300 mmcf/day depending on pipeline pressure variations.  Using slide 12 from Epsilon's August investor presentation (Projected Annual EBITDA Sensitivity), 200 mmcf/day corresponds to around $8.9M of annualized EBITDA net to Epsilon-Midstream. 

Potential Sources of Near Term Growth

Currently only the Epsilon/Chesapeake/Statoil JV is utilizing the Auburn GGS to reach the TPG 300 pipeline, but there is good reason to think that will change in the not-too-distant future.

Chesapeake is currently producing 825 mmcf/day of NG net to its interest (around 1 Bcf gross) in the Northern Marcellus area (Slide 15 December presentation).  On November 1 of this year Kinder Morgan added an additional ~600 mmcf/day of capacity on the TPG 300 line serving the Northern Marcellus area. All of this new capacity has been allocated to Chesapeake and its partner Statoil. As a result of that expanded takeaway capacity, Chesapeake is expected to ramp up drilling in its "core of the core" acreage in Northwest Wyoming county, Southwest Susquehanna county and Southeast Bradford country. There are 3 key gathering systems serving this geography: Rome, Overfield and Auburn.

Based on my research both Rome and Overfield are maxed out in their connection to the TPG 300 line, thus Chesapeake is considering connecting its Overfield system to Auburn in order to move more gas through the TPG line.  If Chesapeake opts not to connect to the Auburn system and to build a new gathering system instead, it would take around 18 months and would certainly be less cost effective than connecting to the existing Auburn system.

Additional sources of NG volume for the Auburn gathering system is increased drilling by the Epsilon/Chesapeake/Statoil JV jointly or separately in the gathering area acreage, or additional volume from smaller independent E&P operators in the area who have already expressed an interest in connecting to the Auburn GGS. Epsilon management seems confident that additional volume will flow through the system in 2014 and beyond, and they've said it's reasonable to expect they'll spend the $15M-$20M in 2014 for the capacity upgrade.  Considering the prolific nature of production in the area and the steady increase in takeaway capacity, it seems highly unlikely that any gathering system with significant gathering capacity will remain unused for an extended period of time.

My midpoint estimate for Midstream volume and EBITDA ramp is as follows: 300 mmcf/day and $13.5M EBITDA in 2014, 400 mmcf/day and $18.0M EBITDA in 2015, 500 mmcf/day and $23.0M EBITDA in 2016.  The low case would be a 4 year ramp rather than a 3 year ramp: 225 mmcf/day and $10M EBITDA in 2014, and the next 3 years as above.  The high case would be a 2 year ramp: 300 mmcf/day and $13.5M of EBITDA in 2014, 500 mmcf/day and $23.0M EBITDA in 2015.

Midstream Comparables

The best recent comp for the Auburn GGS is the February 27, 2013 announcement by Western Gas Partners (WES) that they were acquiring: (a) the Liberty and Rome gathering systems from parent Anadarko Petroleum (APC) for $490M, and (b) a 33.75% interest in the Larry's Creek, Seely, and Warrensville gathering systems from an affiliate of Chesapeake for $133.5M.  The acquisition from the parent was priced at 7.6x forward EBITDA and the third-party acquisition was priced at 9.7x forward EBITDA.  A blend of the two yields an 8.7x multiple, which I think is a reasonable midpoint for valuing Epsilon-Midstream, with 8x on the low end of the range and 10x on the high end.

There are also many publicly traded MLPs with assets similar to the Auburn GGS.  According to a very informative research piece from Morgan Stanley dated April 17th, 2013 (page 60), the "Processing and Gathering" peer group trades at an EV / 2016E Adj. EBITDA of 13.1x (after accounting for the 34% average rise in EV since the report was written).  So I think it's clear my range of 8x-10x is not at all unreasonable.

If we assume a sale at YE 2015 at an 8.7x forward EBITDA multiple, with estimated 2016 EBITDA of $23.0M, the implied valuation is $200.1M.  I discount that by 1/1.1^2 to account for the 2 year delay, add in the PV10 of 2 years of expected after-tax cash flows generated during the ramp, and deduct the $17.5M of capital spending required to expand capacity.  The net result is a Midstream present value of $166.3M.  Using the low-case assumptions of a 4 year ramp and a 8.0x multiple gives a present value of $143.8M.  The high-case assumptions of a 2 year ramp and a 10.0x multiple gives a present value of $193.5M.

Remaining Assets and Liabilities

The remaining assets and liabilities are given in the table below.

There's only one more Canadian asset left for sale and management has indicated it's the most valuable one (Belly River in Alberta).  I'm estimating a value of around $3M for it.  As of Q3 2013 there was an $11.2M WC deficit, while my model estimates +$8.3M in Q4 free cash flow.  The PV10 of 2 years worth of (after-tax) G&A is -$2.5M, and I estimate that the Decommissioning Liability will grow to $4.4M.  There's a deferred income tax liability of $21.7M on the balance sheet.  Management couldn't give me any guidance on how to model its present value, but I thought a 0.5x haircut was reasonable so I modeled the PV as -$10.9M.  Finally, there's $40M CAD worth of convertible debt on the balance sheet, with a conversion price of $4.45 CAD.  At $1.064 CAD per $1 USD, that's equivalent to $37.6M USD of debt at a conversion price of $4.18 USD.

Adding Up the Pieces, Risks, and Conclusion

There are currently 50.54M fully diluted shares outstanding.  If the $37.6M of debentures convert at $4.18 that increases the share count by 9 million, so that brings the fully diluted share count up to 59.53M.  Adding up all the pieces given above gives a midpoint NAV valuation of $328.6M, which becomes $366.2M after the assumed debenture conversion.  So that's how I get to my $6.15/share midpoint estimate of NAV/share. A low case NAV/share estimate can be formed using a combination of the low-realized-price (2-year-tax) Upstream valuation and the low case Midstream valuations given above, which works out to $5.04/share.  The high case NAV/share estimate comes out to $7.37/share.

What are the biggest risks? I'd say natural gas prices.  Although I've tried to be very conservative in my NG price assumptions and the basis differential for Epsilon, the amount of NG production coming out of the Marcellus Shale - particularly in this best-of-the-best Susquehana County acreage - is huge.  But the industry is responding, and takeaway capacity should increase significantly in 2014 and 2015.  Another significant risk is that although the Upstream and Midstream assets are high quality, Epsilon does own only a fairly small non-operated minority interest in both.  So Epsilon don't have much control over how quickly or slowly its partners may decide to develop the two assets, and some potential buyers may not be interested in purchasing a small minority interest like this.

Hopefully some of you made it to the end, I do realize this was a rather extensive analysis.  I hope it's clear why I'm so excited about this investment, despite the risks listed above, particularly given the current elevated valuations in the broad US stock market.  If anybody has any questions/comments I'd be very interested in hearing them.

Catalyst