Description

If you’re looking for the highest-torque to rising oil prices, this ain’t it.  This is a play on great assets and good mgmt that should work in any likely outcome for prices.  HME’s core assets are two Alberta oil pools well-suited for polymer flooding.  HME is an outlier in terms of low production costs and microscopic asset retirement obligations.  Mgmt bought these assets for a pittance and they speak-a-my-language when it comes to capital allocation.  Same goes for risk management - debt is low and will likely be zero in 1-2 quarters.  These guys cut their teeth in a tough price environment and it shows.

(In Canadian $ unless noted)

At the current US$98/bbl WTI and production of ~2,700 boe/d, HME is trading at a FCF yield of 27%.  That’s FCF after everything, including capex to maintain production, versus the fully-diluted EV.  They could maintain this production level for almost 16 years before current 2P reserves ran out, and in reality the number is likely much greater than that (more on this below).

Current prices probably won’t last, but production is rising quickly.  HME will likely exit 2022 at or above 3,000 boe/d, and rise further to 4,000-5,000 boe/d in the next couple years.  Assuming US$69/bbl for WTI (avg of first 5 years in the year-end ‘21 reserve report), at 4,000 boe/d, FCF yield would be 23% with a 2P reserve life of almost 11 years (again, likely understated).

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The basics:

Hemisphere owns and produces from 3 oil pools: the F and G pools in the Atlee Buffalo field, as well a pool that is about 20km to the West in the Jenner field - all in Southeast Alberta.  They’re close to pipelines, so transport costs are low.  Jenner is only doing ~100boe/d and will decline over time.  The main attraction is Atlee Buffalo, where they produce from the Upper Mannville formation, composed of sandstone with high porosity and permeability that have made it one of the most prolific formations in all of Canada.  Both F and G pools have been under waterfloods for the past 5 years or so, and mgmt began polymer flooding the G pool this past July with very good results so far.

This is all “Crown” (i.e. government) land, and the company pays a royalty that varies based on the price they receive (spot WCS less a quality adjustment of ~$4/bbl).  With US$ WTI prices up to about 45, the rate is 10%.  Between 45 and 65 it’s in the teens %.  At 100 the rate is ~29%.  New wells pay a 5% royalty until the operator recovers the cost of the well, so Hemisphere has typically paid less than the headline rate. 

Production is 99% Western Canada Select (WCS) crude oil, 1% natural gas, and will go to nearly 100% oil over time.  WCS is a heavy oil and thus more costly to refine than light WTI, thus it trades at a discount to WTI which varies but is usually around 25%.  (And since the Canadian dollar also trades around a 25% discount to USD, the US$ WTI price is usually in the ballpark of the C$ WCS price.)

Polymer flooding:

When conventional wells are drilled, typically about 10-15% of the total oil in the reservoir (Original Oil in Place, or OOIP) comes to the surface due to natural pressure.  This is called primary recovery.  

Operators then often turn to water flooding, or secondary recovery, to get at that trapped oil.  This usually involves converting some oil producing wells to water injectors, and the water sweeps some of that oil to producing wells.  While old boreholes are often re-used, new wells are often drilled to give the trapped oil just the right push.  In the Upper Mannville sandstone of Alberta, this can usually recover an additional 10-15%.

Tertiary recovery (aka Enhanced Oil Recovery or EOR) is used to get even more of that OOIP.  This typically involves a flood with something added to the water.  In the Upper Mannville, this is usually a polymer, sometimes in addition to an alkali surfactant (or ASP).  The polymer increases the mixture’s viscosity (thickness) to a level similar to olive oil.  This mixture is then injected through wells and forms a sort-of “wall” which pushes trapped oil to producing wells.

Wells don’t have extremely high initial production rates, but their decline rates are very low.  The facilities needed have largely been built already, and not much additional drilling is needed to maintain a given production rate.

“Chance favors the prepared mind”

CEO Don Simmons joined Encana when he came out of college in 2000.  Encana had bought drilling rights to a number of oil pools in the Suffield oil & gas field.  The Upper Mannville formation is one of the most prolific formations in Canada, and it’s the same one that Hemisphere is producing from at Atlee Buffalo today.  

Don was involved in the drilling of about 100 wells here in the early 2000s, including the Suffield UU and YYY pools (remember those two … they’ll be important later on).  He was also tasked with looking for additional properties to acquire in the area, and one that caught his eye was the very same Atlee Buffalo property that Hemisphere is working on today.  The Atlee F and G pools are just 30km or so to the northeast.  

At the time, Atlee was buried in Conoco Phillips.  No one was doing much with it - no 3D seismic shoots, horizontal wells, waterflooding, etc.  He asked about buying it but they didn't want to sell.

Years later, Atlee had been sold to Pengrowth, and Don was at a small private company where he did some farm-ins and asset swaps with Pengrowth.  Just as before, nobody was doing much with Atlee yet they didn’t want to sell it.  

In 2013 Pengrowth decided to sell off all their Southern Alberta properties and focus on the oil sands to the north.  They called him to say you’ve got two weeks to put in a bid.  And so, in November 2013, Hemisphere bought the vast majority of Atlee Buffalo from Pengrowth, and later picked up the remaining working interests for a total cost of $3.9M.

There had been about 2 million barrels taken out of Atlee since the mid-1970s, or about 2.5% of the 84M boe OOIP.  (Canada has since forbidden companies from disclosing OOIP, but you can get this from old presentations.)  

Hemisphere drilled about a dozen wells for the waterflood in 2014 before oil prices crashed and didn't recover until only recently.  Hemisphere probably wouldn’t have survived if it hadn’t been for the steady production at Atlee and the support of their former lender.  That lender got warrants which have a cashless exercise feature, and at the current share price we’ll see 8.4M shares added to the shares outstanding this year.  There are also 6.6M in-the-money options, bringing the FD share count to 103.2M. 

Recent events:

• Began polymer flood in G pool in July, saw first production response in November.  Thus far, results are exceeding expectations.
• Converted four G pool wells from producing wells to water injectors during 2021.  
• Drilled their first new wells since 3Q19: 3 new G pool wells that came online in 3Q21
• Drilled 4 new F pool wells in 4Q21 which came online in 1Q22
• Saw a small dip in production this past January due to extremely cold weather.
  
  

2022 plans

Guidance is for an average of 2,600 boe/d, exiting the year at 3,000.  Given that they were at 2,700 boe/d this February, that could be conservative.  I think mgmt has given themselves some room for stuff to go wrong.  The polymer injection doesn't hit every well at once, and even with the best computer modeling there are still surprises.  If they can't get a drill rig on schedule that could affect the average rate by ~100/d.  

The F pool waterflood was in slow decline until the 4 new wells came online.  Mgmt wants to see results for the G pool before polymer flooding the F pool.  The F pool is smaller at roughly 36MMboe vs the G at roughly 48, and the permeability isn’t as good, but still their models show really good economics even at $50 oil, so they might start this mid-year.  Thus total production could reach 4,000-5,000 boe/d and remain at that level for many years.

Whatcha gonna do with all the cash?

Hemisphere hasn’t yet stated its plans for returning capital, though they recently restarted their buyback after repurchasing ~1% of shares in 2019, ~2% in 2020 at extremely low prices. Mgmt and board own 15% of the company, fully diluted - more than 7x their total 2020 comp, so I expect they'll make decisions we'll like. Note that members of the mgmt team have bought shares recently and exercised without subsequent share sales - not huge amounts, but considering the recent runup in the share price I’d say it’s a good sign.  Currently they're using 50% or more of cash flow to pay down debt to zero.  They had $17.9M of debt at year-end, and I'm guessing they paid down at least $5M of that in 1Q22.

Don’s philosophy on returning capital is similar to that of Tourmaline Oil: pay a smallish dividend, do buybacks when shares are really cheap, and special dividends when they’re not.  Having nothing drawn on their credit facility should give them good flexibility when it comes to dividends.  I’m guessing this is the plan we’re likely to see over time.

Valuation revisited - don’t forget about upside to reserves

Hemisphere is trading at 86% and 48% of its PDP and 2P reserve values, using the above-mentioned strip averaging US$69/bbl WTI over the next 5 years (vs spot of ~US$98).  Those values are calculated before tax and excluding G&A, but keep in mind 3 things:

• Oil producers don’t really pay income tax anyway due to intangible drilling credits
• G&A is likely under $3/boe and could go below $2 at 4,000-5,000 boe/d
• Reported reserves are likely understated

On this last point, note that IPCO’s Suffield YYY and UU pools have recovered a cumulative 29% and 50% of Original Oil in Place (OOIP), respectively.  Hemisphere’s current 2P reserves assume only 23% for this same metric.  At the YYY pool’s 29%, 2P reserves would be 30% higher.  At the UU pool’s 50%, reserves would be 2.5x the current level.

But let’s just take the low-ends of what I think are the most likely outcomes for total recovery and long-term production rates: 35% and 4,000 boe/d (out of 35-40% and 4,000-5,000).  Using the same oil price strip, we’d be looking at reserves that are 70% higher than the 2P number, a reserve life of 18 years, and a FCF yield of:

23% at US$69 WTI

18% at US$60 WTI

14% at US$50 WTI

Not a bad inflation hedge.

Following the active development of Suffield in the early 2000s, Encana (later called Cenovus) let Suffield languish for about a dozen years, with no gas well drilling since 2010 and no oil well drilling since 2014.  Finally, in a major strategy shift, they sold it to International Petroleum (ticker: IPCO on the TSX) in early 2018.

IPCO recommenced ASP floods at fields including UU and YYY, and converted its N2N pool waterflood to an ASP flood in 2019.  There’s a lot of similarity with Atlee.  The G (and likely the F) is also now in a polymer flood just ~30km away.  Since the N2N was on waterflood for much longer than Atlee, its cumulative recovery was ~14% vs Atlee at just 4% today.  So N2N has been relatively more exploited, and yet IPCO has had great success so far:

I reviewed every study of similar polymer floods that I could find to make sure these 3 Suffield pools weren’t some sort of outliers.  I don’t think they are.  

Polymer flooding was first used for heavy oil in Canada on a project called Pelican Lake.  When operators saw the success of that project, many similar projects got underway in the late 1980s, and the great majority thus far have been in the Upper Mannville in the East Central Plains and Southern Plains of Alberta.  As far as I can tell, the incremental recovery has been in the ballpark of 25% of OOIP, with the typical project following a waterflood that had brought cumulative recovery to 10-15%.  So, a total of 35-40% recovery overall.   

I didn’t find any projects that totally flopped, though perhaps there’s some survivorship bias here: academics want to study recovery factors over time and could be drawn to the more successful cases.  

From the ones I’ve seen, the main reasons that polymer floods got cut short were oil price crashes and changes in operator strategy.  In some cases, production was initially disappointing but the problem was solved by changing the approach - usually by trying a different mixture of chemicals.  

Note that Atlee Buffalo is FCF breakeven down to $30 WTI, so I doubt a crash in oil prices would end the project.  Even in the darkest days of Covid (2Q20), when the WTI price briefly went negative, they eked out ~$1.3M in cash from operations before working capital, and that’s excluding the gov’t subsidies they received (which were only $83K anyway).

Why cheap?

One reason is obscurity.  This was a nano-cap until recently.  There’s no analyst coverage, and almost the entire shareholder base is retail.

Another reason is that Hemisphere is an odd duck.  Reserve values per boe are unusually high.  The key to understanding this is that costs are low because it’s a polymer flood in quality rock (sandstone with high perm and porosity) which means fracs aren’t needed on new wells, and lifting and transport costs sum to just ~$12/bbl vs peers at, say, $16-19.  Hemisphere has just $8M of reclamation liabilities ($1.9M discounted at 10%).  Peers with similar levels of reserves can often have undiscounted liabilities in the ballpark of $75M.  Reclamation costs get subtracted from reserve values and are treated as first-lien debt under Canadian law.  

Moreover, current production and thus earnings are low compared to the recorded and true value of the reserves, because Hemisphere has only recently begun to ramp up the polymer flood.

The following slides are from March 16th, with Hemisphere shares at $1.40 vs $1.52 today:

Catalyst

Production continues its rapid rise

Reserve auditor gives them more credit for reserves as polymer flood results come in, and as they drill more wells