PEY.TO - Peyto Exploration & Development

[Nelg]

The company really shot itself in the foot with the HH-AECO basis swaps (this is something material I missed in my earlier analysis, so I was caught off guard by how quickly their leverage increased).

 

I think they roll off after 2021, but they unfortunately don't seem like they can capture the full upside from stronger AECO prices, and will likely result in increased leverage under the forward curve. I'm estimating they'll be around 4.5x until later next year (at AECO of ~$2.80/Mcf and WTI of ~US$41/bbl), which doesn't give a ton of headroom even after their covenant relief. Maybe we'll get $5 gas prices this winter though.

 

I'm not bullish or bearish on the company, but their balance sheet does not give them complete control of their future if gas prices decline again (for whatever reason).

[petec]

I just plugged spot AECO and propane prices into a model with basic cost and decline assumptions and came out with a 50% free cash flow yield at current prices.

 

As identified upthread, the issue is the hedges - they won't generate this much cash. But interesting to see what they could do if spot holds as the hedges roll.

 

[kevin4u2]

I have incorporated the hedges into a model and still get over $1/sh FCF for 2021.  Everyone keeps citing the hedges and as problem (along with the debt), but basis deals are only 209mmcfd while total gas production is estimated to be 454.5mmcfd.  That makes the basis deals 46% of hedged gas.  I'm getting a $2.40/mcf blended gas price for 2021, with 72% hedged.  Cash flows are going to materially improve next year. 

 

Another thing to keep in mind that fighting a 35% or 40% decline rate is much different than the estimated 25% for next year.  That allows them to maintain production with about $100 million in less capex than in previous years, greatly increasing FCF at the same production rate years ago. 

 

I see an 11% increase in production for next year and 33% improvement in realized prices based on capex at $300 million and production efficiency of $10k/boe/d.  This also means debt to CF will likely fall to 2.5 times by the end of next year with ~$80 million in debt repayment.  The last two quarters have destroyed their CF but the next 4 are going to be much higher. 

 

I would agree with the other posters, this has a lot of upside (at least 3-5x) over the next couple years.  If you are a gas bull, then this is a potential rocket ship. 

 

I just plugged spot AECO and propane prices into a model with basic cost and decline assumptions and came out with a 50% free cash flow yield at current prices.

 

As identified upthread, the issue is the hedges - they won't generate this much cash. But interesting to see what they could do if spot holds as the hedges roll.

[petec]

Would you mind sharing the model?

 

[kevin4u2]

Would you mind sharing the model?

 

No problem. All figures in $CAD.

 

Assumption $300 million 2021 capex at $10k/boe/d efficiency

2021 Average Production = 88,920 BOE/d

 

2021 Hedges (all from pg.51 Presentation or Marketing section of website)

AECO 7A - 68,158 mcf/d - $2.62/mcf

AECO 5A - 8,701 mcf/d - $2.22/mcf

AECO Phys Basis - 51,422 mcf/d - $2.03/mcf

AECO Phys Fixed - 161,875 mcf/d - $1.86/mcf

Emerson Fixed - 8,943 mcf/d - $2.98/mcf

Malin Fixed - 33,333 mcf/d - $3.23/mcf

 

Total Hedged NG - 328,483 mcf/d - $2.22/mcf

Total Unhedged NG - 126,067 mcf/d - $2.80/mcf

 

2021 NG Blended Price -  454,550 mcf/d - $2.38/mcf  (NG = 75,758 BOE/d, 72% hedged)

2021 Oil - 13,160 BOE/d @ $36/boe (14.8% NGLs)

 

Est. Average Realized Price - $2.92/mcf ($17.51/boe)

Est 2021 Revenue - $568 million

(Est 2020 Revenue - $386 million)

 

2021 CF = $383 million

2021 FCF = $175 million (Maintenance CAPEX = $208 million for flat production)

Shares outstanding = 164.88 million

 

2021 Debt repayment = $76 million

Ending Debt = $1.09 billion

Net Debt/EBITDA ~ 2.5

 

This is close to pg 48 of the presentation showing a 30% profit at $2/GJ gas and $30/bbl NGL price.  You can tweak the numbers the outcome doesn't change much as so much of the NG is hedged for next year at decent prices.  Of course they are leaving some on the table but who cares.  The debt covenants will be done after Q3 next year.  My preference would be to maintain production in 2022 and significantly pay down debt. Somewhere around $150 million is achievable.  Debt repayment accrues to the equity holders so consider it a dividend. For 2022 they are already 45% hedged (assuming flat production) at $2.42/mcf (same calculation as above), and I estimate average NG price is estimated at $2.68/mcf.  They just have to execute and that is what they are good at.

 

I would note that these are not too far off TD estimates for 2021, however I have no idea how he calculates $643 million in revenue, on 84,235 boe/d at $17.17/boe (all right out of the report).  They have CF at $336 million & 325 million in capex next year.  CF rising from $1.29/sh this year to $2.04/sh next year, up 58%. YE debt to EBITDA of around 3x.  I have CF rising from $1.30/sh to $2.32/sh next year.

 

Cheers!

 

 

[Nelg]

Thanks for sharing. I think I might be double-counting the hedges in my model, so can you help me understand how those hedges flow into their reporting?

 

In their Q3 report:

AECO 7A averaged $2.04/GJ = $2.15/Mcf in the quarter.

Unhedged realized gas price:$2.62/Mcf

less diversification activities: -$1.01/Mcf

plus hedging gains:  $0.03/Mcf

Realized Gas Price = $1.64/Mcf

 

In your model, is your unhedged realized gas price just assuming AECO + a premium? And then for all of the hedges you just listed from their last presentation, this would effectively show up in their reported "diversification activities" and "hedging gains/losses"?

[kevin4u2]

Thanks for sharing. I think I might be double-counting the hedges in my model, so can you help me understand how those hedges flow into their reporting?

 

In their Q3 report:

AECO 7A averaged $2.04/GJ = $2.15/Mcf in the quarter.

Unhedged realized gas price:$2.62/Mcf

less diversification activities: -$1.01/Mcf

plus hedging gains:  $0.03/Mcf

Realized Gas Price = $1.64/Mcf

 

In your model, is your unhedged realized gas price just assuming AECO + a premium? And then for all of the hedges you just listed from their last presentation, this would effectively show up in their reported "diversification activities" and "hedging gains/losses"?

 

Here is my thoughts

 

AECO 7A averaged $2.04/GJ = $2.15/Mcf in the quarter.  - This is actual AECO average prices in the quarter.

Unhedged realized gas price:$2.62/Mcf - This is unhedged realized gas price.  This is the total revenue per mcf that they got for sales in the quarter.

less diversification activities: -$1.01/Mcf - This is the expensive ($1.40USD/mmbtu) basis they purchased, blended away with some other hedges.   

plus hedging gains:  $0.03/Mcf - These are gains on some other hedges.  There is really no reason to isolate them out.  They should just be added with the above line.

Realized Gas Price = $1.64/Mcf - This is 2.62-1.01+0.03= 1.64/mcf

 

In my model, I am simply taking the fixed gas prices right out of their presentation and calculating a weighted average.  These are the "realized gas prices" for each market.  When I said they are leaving money on the table, that is because they are.  If they sold all their gas at AECO they would realize much higher prices.  But they purchased the US basis hedges at a time when they couldn't get pipe access.  It was costly but necessary at the time.  They were getting next to zero at AECO.  Now it looks like a stupid decision but that is only because the new UCP government in Alberta fixed the NG market. 

 

Check out the 2019 disconnect of AECO from Henry Hub, and then see how they now track again in 2020. 

https://www.oilsandsmagazine.com/energy-statistics/oil-and-gas-prices#dailyNatGasCAD

 

Finally for your last question, In your model, is your unhedged realized gas price just assuming AECO + a premium? And then for all of the hedges you just listed from their last presentation, this would effectively show up in their reported "diversification activities" and "hedging gains/losses"?, No, I am just reporting the bottom line "Realized Gas Price". 

 

If one wanted to back calculate those costs you could.  For the current quarter, for example, AECO Oct/Nov/Dec averages say $2.58/GJ, so with peyto add a 15% premium for heat content and you get a $2.97/mcf "Unhedged realized gas price".  Then you look at slide 51 of their presentation (Marketing Summary), you will see they have 204,167 mmbtu/d (199,185 mcf/d) of AECO phys fixed price gas sold at $1.79CAD/mcf.   

 

So for this production of 199,185 mcf/d Peyto would report in Q4 2020:

Unhedged realized gas price = 2.97/mcf

less diversification activities = -1.18/mcf

Realized Gas Price = $1.79/mcf

 

I hope this makes sense.  So what I did above is just calculated a weighted average of all the "Realized gas prices" as listed on p51.  Yes the AECO phys basis hedges sucks but when you add up all of the other revenue streams, the average is still looking around the $2.40/mcf for Peyto in 2021.  Currently 2021 AECO average futures are selling at close to $2.90/mcf (Peyto unhedged realized gas price).  That is close to $80 million in less CF in 2021, but that gap will close over the next couple years. 

 

My point is even at $2.40 gas and $35 oil Peyto can generate significant CF and FCF over the next couple years because of their low decline asset base.  As I mentioned above, fighting off a 25% decline rate is much different than Peyto circa 2015 with a 40% decline rate.  It requires $120 million less capex just to maintain 80,000 boe/d rate of production, so in essence, they can earn the same FCF with $0.80/mcf lower gas prices compared to 2015.  I actually see their FCF being slightly less next year than 2015 ($1.00 vs $1.06), however the major difference is the share price averaged $30.98/shr in 2015 while today they sell for $3.07/shr.  A 33% FCF yield, I'll take that all day long. 

 

If Peyto were to sell for the same EV/DACF as it did in 2015, the share price would have to rise to $18.50 in 2021.  I don't expect that to happen given the current political climate in Canada and the worldview that the O&G sector is going to be phased out over the next couple years.  Oil demand may decline, however NG has a very bright future in an more electric world.  The Peyto AGM presentation of 2019 does a very good job explaining how NG isn't going anywhere.  Less Energy = Better Climate, however for the vast majority of people in this world More Energy = Better Life, so who wins?  My bet is NG. 

 

Cheers. 

 

[Nelg]

Now that I've fixed my model I am getting similar numbers to you...but have you looked at it on a NAV basis instead of FCF yield?

 

I've (somewhat arbitrarily) assumed $300m capex/year at $11k/boe/d capital efficiency with a 23% decline rate for 10 years and then put the company into runoff after that point; peak production hits around 115mboe/d.

 

Then assuming a 10% discount rate, I get a residual equity value of ~$5-600m; commodity prices are the forward curve through to 2024 then flat prices after that (ie, leveling out at WTI US$44/bbl and AECO $2.30/Mcf).

 

Stressing WTI and AECO prices (also arbitrarily) by 10% and 20%, equity value gets cut in half in that scenario. I get the whole NGTL prioritization change and upcoming capacity expansion...but notwithstanding Darren's recent blog post basically saying the largest producers are effectively a domestic OPEC now, commodity prices are still out of their control. Do you have a strong view on whether gas prices will be above the current forward curve?

[kevin4u2]

No I haven't looked at it that way.  I did take a look at Insite's forward price forecast and while near year have risen recently, further out years declined, so the net difference was negligible.  The current NAV still supports a $10 share price, fairly easily.

 

As for commodity prices, I think we are at the beginning of an upturn in several commodities.  I also think inflation will run hot over the next few years.  For NG, it really comes down to oil prices and whether OPEC forces prices down to punish US shale.  The residual NG from shale has really depressed prices, however, that said if oil rises Peyto does benefit on the NGL side. I think even low NG prices, like $2/GJ gas Peyto can generate good returns. 

 

One thing I also find interesting in modeling different scenarios is that whether Peyto pursues growth or pays down debt, there is no real difference in year end debt to CF.  The only benefit to paying down debt is it restricts supply, however you lose access to regular drilling services and staff gets bored. 

 

I also found the latest monthly letter from Darren Gee to be quite interesting.  Even in a world of higher electrical demand, I have a hard time imagining a scenario where NG doesn't play a large role for years to come, as oil demand falls. 

 

 

Now that I've fixed my model I am getting similar numbers to you...but have you looked at it on a NAV basis instead of FCF yield?

 

I've (somewhat arbitrarily) assumed $300m capex/year at $11k/boe/d capital efficiency with a 23% decline rate for 10 years and then put the company into runoff after that point; peak production hits around 115mboe/d.

 

Then assuming a 10% discount rate, I get a residual equity value of ~$5-600m; commodity prices are the forward curve through to 2024 then flat prices after that (ie, leveling out at WTI US$44/bbl and AECO $2.30/Mcf).

 

Stressing WTI and AECO prices (also arbitrarily) by 10% and 20%, equity value gets cut in half in that scenario. I get the whole NGTL prioritization change and upcoming capacity expansion...but notwithstanding Darren's recent blog post basically saying the largest producers are effectively a domestic OPEC now, commodity prices are still out of their control. Do you have a strong view on whether gas prices will be above the current forward curve?

[kevin4u2]

Petec are you still holding?  The numbers have materially improve and it looks like PEY has miles to run. 

 

The polar vortex is showing some production challenges for NG (down 15bcf/d) and how unreliable wind power is in Texas.  Should be some record draws from storage tomorrow and next week.  We will end storage below the 5 year average. 

 

Plus the under-investment for the past two years along with LNG exports now running 10+bcf per day, the rest of this year looks interesting from a supply/demand perspective (along with 2022).  Berkshire just bought a bunch of NG pipelines assets, so they know gas will be in the mix for a long time. 

[drzola]

Tourmaline Energy and Arc Resourcs maybe good plays In Natgas as well folks.

Robotti went big in Birchcliff Energy in 2020 I believe.

 

[kevin4u2]

Must read of where storage will end up.  We will struggle to refill for next year.  NG will be strong for 2021 and 2022.

 

https://seekingalpha.com/article/4406742-natural-gas-market-squeezes-higher-on-latest-cold-blast

[petec]

Petec are you still holding?  The numbers have materially improve and it looks like PEY has miles to run. 

 

The polar vortex is showing some production challenges for NG (down 15bcf/d) and how unreliable wind power is in Texas.  Should be some record draws from storage tomorrow and next week.  We will end storage below the 5 year average. 

 

Plus the under-investment for the past two years along with LNG exports now running 10+bcf per day, the rest of this year looks interesting from a supply/demand perspective (along with 2022).  Berkshire just bought a bunch of NG pipelines assets, so they know gas will be in the mix for a long time.

 

I am, although funnily enough I was wondering whether I should lighten up here. What’s your thesis behind “miles to run”?

[petec]

Must read of where storage will end up.  We will struggle to refill for next year.  NG will be strong for 2021 and 2022.

 

https://seekingalpha.com/article/4406742-natural-gas-market-squeezes-higher-on-latest-cold-blast

 

Why are they so certain that supply cannot grow in 2021? I was under the impression that there were quite a few drilled but not completed wells, and anyway the fracking industry has historically responded fairly quickly to high prices. Happy to be proven wrong.

 

Longer term my guess is gas sits well below $3 on the back of:

- More associated gas, because I expect oil to be in tight supply when the economy rebounds.

- Flaring restrictions leading to additional supply.

 

LNG is my big position in energy, partly because it is about to generate vast amounts of cash and partly because the above dynamic (low gas, high oil) is very good for its marketing spreads.

 

[SharperDingaan]

It implies that much of the incremental gas from new drilling, will go into tar sands incremental production (takeaway is no longer a problem).  Net new gas is primarily from rising gas cuts on old wells; at current/future prices, producing longer than they otherwise would have. Not a bad assumption.

 

SD

 

[petec]

It implies that much of the incremental gas from new drilling, will go into tar sands incremental production (takeaway is no longer a problem).  Net new gas is primarily from rising gas cuts on old wells; at current/future prices, producing longer than they otherwise would have. Not a bad assumption.

 

SD

 

Sorry, this makes my head hurt. Can you elaborate?

[bizaro86]

It implies that much of the incremental gas from new drilling, will go into tar sands incremental production (takeaway is no longer a problem).  Net new gas is primarily from rising gas cuts on old wells; at current/future prices, producing longer than they otherwise would have. Not a bad assumption.

 

SD

 

Do you think there will be significant expansions of in-situ in the near term? There isn't really anything under construction, and these thing take ~3 years to build. I could see some expansions getting sanctioned at the top tier reservoirs (CVE Christina Lake type stuff) but unless liquids pricing takes another leg up and stays high I think that'd be it, and it wouldn't be enough to move the needle on gas demand. Maybe 5-6 years out, but that's a long time in the life of a low-perm gas well...

[SharperDingaan]

Alberta's big user of gas (mostly for heat) is the tar sands, and as more tar sand is produced - there is more demand for gas. As at December 2020, Alberta's monthly production limits ceased, and tar sands plants are now producing at pre restriction levels - and higher. Lot of additional gas required.

 

Both shale, and wet gas formations (Peyto), produce more gas as the well ages. The additional gas (cut) initially at the expense of less liquids, before eventually being replaced with ground water. All else equal, if gas supply/demand is currently matched, tomorrows price will be lower - simply because of more volume (higher gas cut) coming from older wells. And the higher the current gas price, the longer an old well can keep producing before it becomes uneconomic.

 

Peyto just recognizes that for about the next 1-2 years, the combination of tar sand expansion, and recovering economy; is likely to suck up new supply about as quickly as it can be produced. Most would be inclined to agree.

 

SD

 

 

[bizaro86]

Alberta's big user of gas (mostly for heat) is the tar sands, and as more tar sand is produced - there is more demand for gas. As at December 2020, Alberta's monthly production limits ceased, and tar sands plants are now producing at pre restriction levels - and higher. Lot of additional gas required.

 

Both shale, and wet gas formations (Peyto), produce more gas as the well ages. The additional gas (cut) initially at the expense of less liquids, before eventually being replaced with ground water. All else equal, if gas supply/demand is currently matched, tomorrows price will be lower - simply because of more volume (higher gas cut) coming from older wells. And the higher the current gas price, the longer an old well can keep producing before it becomes uneconomic.

 

Peyto just recognizes that for about the next 1-2 years, the combination of tar sand expansion, and recovering economy; is likely to suck up new supply about as quickly as it can be produced. Most would be inclined to agree.

 

SD

 

 

 

I'm a reservoir engineer by profession, I understand the use of gas for steam, and the changing cuts as reservoir pressure drops. Dew point, saturation curves, all that good stuff.

 

My point was that new oil sands production takes 3+ years from sanction before it gets to the point where it would be burning gas for steam. And there haven't been any sanctions yet this cycle.

 

The production limits issue was mostly a non-issue by December - natural declines on the conventional side and the ability to purchase quota meant that production was limited by reservoirs and economics, not government fiat.

 

If it takes 3 years for oil sands gas usage to have any appreciable growth, that is a long portion of the life of a tight gas well, especially if you weight it by production.

[kevin4u2]

Petec are you still holding?  The numbers have materially improve and it looks like PEY has miles to run. 

 

The polar vortex is showing some production challenges for NG (down 15bcf/d) and how unreliable wind power is in Texas.  Should be some record draws from storage tomorrow and next week.  We will end storage below the 5 year average. 

 

Plus the under-investment for the past two years along with LNG exports now running 10+bcf per day, the rest of this year looks interesting from a supply/demand perspective (along with 2022).  Berkshire just bought a bunch of NG pipelines assets, so they know gas will be in the mix for a long time.

 

I am, although funnily enough I was wondering whether I should lighten up here. What’s your thesis behind “miles to run”?

 

Darren Gee was just on BNN the other day and stated that they will double CF in 2021.  That will put them at north of $440m this year.  From my post above, because of the low decline rate, FCF will be very strong (>$200m).  Back in 2014, they generated $662m in CF and FCF was $232m.  Needed $429m in CAPEX then compared to $200m now.  Big difference.  They will invest most of their FCF this year to grow production by 16k boe/d (+20%).  Should exit the year over 100k boe/d.

 

I'm sure you saw the recent reserve release.  Their all in gas cost is now $2 CAD/mcf.  They can make a 40% profit margin at $2.50 AECO and $55US WTI (slide 48). 

 

Their H2 2020 results were also very strong.  Made an acquisition near Sundance for $35m in Q1 adding 2,900 boe/d.  Mostly I liked this:

 

The outlook for commodity prices in 2021 has significantly improved over the last six months which drives higher

forecast cashflows, beyond the required funding for Peyto’s capital program. In addition, there have been extreme

natural gas prices being realized at certain trading hubs over the last week due to record cold temperatures across

much of the United States. As an example, Peyto was fortunate to have 20,000 MMBTU/d of unhedged gas sales

exposed to the Ventura hub that averaged over $160/MMBTU for the last 5 days. As these superior commodity

prices are realized, Peyto will look to use the free cashflow to reduce indebtedness and strengthen its balance

sheet, while evaluating the ability to increase dividends to shareholders. Based on strip pricing, Peyto currently

projects it will exit debt covenant relief during the second quarter of this year. While the 2021 drilling program is

budgeted to be greater than 2020, Peyto currently has the team and resources to do much more and eagerly looks

forward to 2022 and beyond.  

 

They made $16m in 5 days at Ventura.  I have debt to EBITDA at 2.3x by year end, paying down $200m in debt over next 2 years, and will exit 2022 with debt to EBITDA at 1.8x or better at strip pricing & their hedges. 

 

Their strategy appears to be fill their gas plants (~100k boe/d), and milk the FCF/profits.  TD analyst just came out with 95,300boe/d for 2021 and 104,500boe/d in 2022.  My calculations have them with slightly lower production rates.  They will also have 3rd party processing revenue this year. 

 

Regarding the gas demand, the polar vortex will bring end of winter storage to well below the 5 year normal.  Look for a record draw tomorrow.  LNG exports are running 10-11 bcf/d (have already recovered to 10bcf/d).  Propane prices are currently very good.  In Alberta, coal to NG power plant conversions will drive demand, and LNG Canada exports in 2024.  Peyto will begin directly supplying Cascade power plant in 2023 (60k-120k GJ/d).  The US big gas players have forecasted flat production this year.  All this points to a struggle to fill storage to an adequate level by next winter.  NYMEX should wake up in Q2 and realize prices are not adequate for next winter.  Buy now and enjoy the ride for the next 2 years.   

 

At the average EV/DACF for the past 4 years we are are conservatively talking $11/shr this year and $15/shr next year.  Upside includes higher gas prices, higher oil prices, or an increase in EV/DACF valuation to historical norms.  It is definitely not out of the range of probabilities to see a >$20/share price in 2022. 

 

I made a fortune back in 2001 when Peyto was just starting out.  They were the best performing stock on the TSX after their first 15 years in business (1999-2014).  They have paid out close to $20/share in dividends.  I think this run might be just as good, time will tell.     

 

 

 

 

[kevin4u2]

And I think the Tech to Energy rotation is just getting underway.  The last 4 years will unwind. 

[petec]

Petec are you still holding?  The numbers have materially improve and it looks like PEY has miles to run. 

 

The polar vortex is showing some production challenges for NG (down 15bcf/d) and how unreliable wind power is in Texas.  Should be some record draws from storage tomorrow and next week.  We will end storage below the 5 year average. 

 

Plus the under-investment for the past two years along with LNG exports now running 10+bcf per day, the rest of this year looks interesting from a supply/demand perspective (along with 2022).  Berkshire just bought a bunch of NG pipelines assets, so they know gas will be in the mix for a long time.

 

I am, although funnily enough I was wondering whether I should lighten up here. What’s your thesis behind “miles to run”?

 

Darren Gee was just on BNN the other day and stated that they will double CF in 2021.  That will put them at north of $440m this year.  From my post above, because of the low decline rate, FCF will be very strong (>$200m).  Back in 2014, they generated $662m in CF and FCF was $232m.  Needed $429m in CAPEX then compared to $200m now.  Big difference.  They will invest most of their FCF this year to grow production by 16k boe/d (+20%). 

 

 

How are you defining free cash flow? After all investments or after maintenance investments?

[kevin4u2]

Petec are you still holding?  The numbers have materially improve and it looks like PEY has miles to run. 

 

The polar vortex is showing some production challenges for NG (down 15bcf/d) and how unreliable wind power is in Texas.  Should be some record draws from storage tomorrow and next week.  We will end storage below the 5 year average. 

 

Plus the under-investment for the past two years along with LNG exports now running 10+bcf per day, the rest of this year looks interesting from a supply/demand perspective (along with 2022).  Berkshire just bought a bunch of NG pipelines assets, so they know gas will be in the mix for a long time.

 

I am, although funnily enough I was wondering whether I should lighten up here. What’s your thesis behind “miles to run”?

 

Darren Gee was just on BNN the other day and stated that they will double CF in 2021.  That will put them at north of $440m this year.  From my post above, because of the low decline rate, FCF will be very strong (>$200m).  Back in 2014, they generated $662m in CF and FCF was $232m.  Needed $429m in CAPEX then compared to $200m now.  Big difference.  They will invest most of their FCF this year to grow production by 16k boe/d (+20%). 

 

 

How are you defining free cash flow? After all investments or after maintenance investments?

 

CF less maintenance capital.  Maintenance capital would be in the $180-190m range.  I rounded to $200m to be safe. 

 

Peyto needed $429m in maintenance CAPEX back in 2014 and now need much, much less.  As you know their FCF can be used to pay down debt, dividends, or grow production. 

 

What I see is their strategy as per the presentation and Gee's BNN interview is to fill the plants (100,000 boe/d), which will further improve efficiency (cash costs down 10% to ~0.90CAD/mcf).  They will then use FCF stream to further pay down debt and pay a dividend next year.  No dividends this year.

 

FCF will be among the highest in the company's history for next several years.  Once the debt overhand is gone by later this year, this stock will go much higher.  Remarkably, I have modelled their debt/EBITDA under two scenarios 1) pay down debt or 2)grow production (increasing CF), the debt to EBITDA is nearly identical after all factors are taken into consideration.  That is why many are likely confused as to why they would grow production instead of paying down debt. 

 

[petec]

Thanks!

[kevin4u2]

Thanks!

http://www.peyto.com/Files/PMReport/2021/PMR2021Feb2.pdf

 

I think this statement from the February President's Monthly Report is the most interesting. 

 

"Considering our track record over the last decade, with an ever increasing drilling speed (80% increase in 9 yrs), and a shallowing base decline, we may not be too far away from a single operating rig being able to hold us at 100,000 boe/d.  Assuming of course that holding production steady and stripping off gobs of free cashflow is still the right strategy."