DOI: 10.5281/zenodo.14927890
title: SPARTAN DELTA CORP

description: Description

 

Spartan Delta is a highly attractive E&P company with a three year 113% return using strip pricing and a 10% FCF/EV exit multiple, equivalent to a  29% IRR over that time period. My thesis rests on 3 points.

-          Management is phenomenal, having already made cash distributions to shareholders worth multiples of what they have raised over the last 5 years, using their acquire, develop, and sell approach.

 -          In the past year they have quietly assembled a new oil/condensate land base that 2 other industry players have recently gone all-in on. This will move them from a primarily gas producer to a more balanced liquids weighting of 40% over time, vastly improving netbacks and free cash flow.

-          While I model everything on forward strip, there is a reasonable case to be made that AECO is grossly mispriced. With Canada’s first LNG facility coming online in the next few months (export capabilities of 11% of western Canads total production), the discount to Henry Hub should narrow back to transportation costs, repricing LT AECO from $3 cad to $4. If this were to occur the upside return is 222% on a 3-year basis.

 

Cap Table and Target Price:



 

History:The Spartan management team has been together for 15  years in a few different vehicles (see appendix), but this iteration of Spartan Delta (SDE) started in December 2019. Since that time they have raised $537mm of equity from investors while returning $1,809mm via dividends and special distributions, and still having equity value of $761mm. In total that equates to a 4.8x MOIC.  A quick timeline for SDE: 

-          Dec 2019, initial equity raise in a shell at $1.00 per share

-          May 2020, buy Bellatrix deep basin assets out of bankruptcy, raise equity at $2.00. SDE uses these assets to get to scale and harvest cash flows

-          May 2021 buy Montney footprint, August 2021 acquire Velvet to finish Montney footprint. Shares issued $4.35 and $5.05

 

SDE proceeded to grow and derisk their acquired Montney assets for the next 1.5 years before selling them to Crescent point for $1.7 billion. Post closing, SDE paid out a $9.50 special distribution to shareholders and issued 1 share of newco Logan Energy, worth 70c at the time. Shareholders also kept their SDE shares, now worth about $3.50. With a prior $1 per share distribution made in 2022 you can see how well shareholders who bought in via the equity raises have done.

One of the co-founders of SDE moved over to Logan while remaining Chairman of SDE. His partner, Fotis Kalantzis remained at SDE along with most of the senior team.

 

 

New Duvernay Play:

 

Since that 2023 distribution and spin, SDE has been quietly building up a new land play in the Duvernay, while using the original deep basin assets for cash flow and scale. Same game plan.

-          Nov 2023 announced west shale Duvernay land buys for $25mm. Comes with 400 boe/d (who cares) And 137,000 acres of land (interesting)

Management says at the time “After over a decade of development, Spartan believes the Duvernay is poised to offer repeatable, economic results with a significant depth of inventory. Similar to Spartan’s entry into the up-dip oil window of the Montney in 2021, the Company views its timing on the entry into the West Shale Basin Duvernay as optimal as the fairway is fragmented, undercapitalized and supports growth with available egress and existing underutilized infrastructure. Additionally, the West Shale Basin Duvernay possess geotechnical attributes comparable to the Kaybob Duvernay and the East Shale Basin Duvernay. Recent activity and new top-tier well results from bordering operators demonstrate the commerciality and scalability of the play”

-          May 2024 announced a Willesden Green Duvernay acquisition for $53 million. Comes with 1,600 producing BOE/D and 38,000 acres. This is on top of small tuck ins over prior months bringing acreage to 240,000 net.

 

Initial well results on SDE Duvernay lands have been promising, but there have also been two recent transactions of comparable producers going all-in on the play.

 

Model:Let’s take a quick look at the model before jumping into the new play.

 

 

We see in 2024 almost all production is coming from the deep basin/legacy assets (gas and lower value liquids). Over time as Duvernay wells are drilled the company economics (netbacks) on strip pricing improve greatly.

 

Here’s how I get there on new well drilling:

 

Quick note: stay-flat deep basin capex should be about $100mm a year to maintain 35k boe/d of production (mostly gas).

 

Crux of my thesis then comes down to the assumptions on the new Duvernay wells. Before that, using above assumptions heres how cash flow evolves.

 

 

I get to my target price by using a 10% forward UFCF/EV on Dec 31 2027, so on a 3 year timeframe.

 

New Duvernay Play:

 

The key assumptions above are the Initial Production 365 metrics, cost per well and condensate rate. For those less familiar, condensate is a natural gas liquid that is primarily used in Alberta as a mixer for heavy oil to become less viscous so it can flow on pipes. Alberta is a net importer of Condensate, so it is normally priced at WTI +- a couple dollars. With current usd/cad fx rates at 1.44 spot is currently $105 cad a barrel



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SDE has 390 net sections of land and estimates 300 net locations for drilling (which I think is low and will go higher over time). In my assumptions above you can see I start them off at 8 Duvernay wells drilled this year trending to 12 in 2027. So in my outyear they would still have ~ 24 years of drilling inventory.

 

To date they have brought on stream 2 wells. The first was drilled by the previous owner in 2019 and only completed in 2024. IP30 rates were ,1394 boe/d coming out 82% liquids and 58% condy. The second well hit issues when drilling and completing so was only 60% of the normal well length. Despite that the well produced 937 boe/d IP30 coming out 92% liquids and 80% condy.

 

They have drilled another 2 wells which were likely brought on stream in December and we should get a first look at results in the coming weeks. Well costs were at the high end of the $11.5mm-$13.5mm range but should trend down towards 12mm over time as the play begins to get productionzied.

 

The 2 wells detailed above, which adjusted for well 2 completion issues, averaged 1,477 IP30 and support an IP365 assumption of 600 boe. However 2 wells is a very small sample size. Luckily a comparable, Paramount Resources, has just gone all-in on the play and has provided more details on the play.

 

Paramount Resources (POU) announced on November 14th that they would be selling their Montney lands for $3.3 billion which is 2/3rds of their production. Paramount is using the proceeds to make a $15 cash distribution to shareholders and to go all-in on developing the Willesden Green Duvernay.

 

“The sale of the assets represents a pivotal milestone for Paramount as it continues to successfully execute its strategy of early-stage resource capture, delineation and development followed by strategic value realization. Following closing of the transaction, Paramount will focus on the development of its Duvernay assets at Willesden Green and Kaybob North, which have significant growth potential and production that all flows through company-owned-and-operated infrastructure.”

 

Post close Paramount plans to use their large cash balance to grow Duvernay production aggressively, taking total production from 30k boe/d today (only a small amount Duvernay) to 60k boe/d in exit 2026 (most of the growth being Duvernay). Here’s what they said“Paramount's production immediately following closing of the transaction will be approximately 30,000 Boe/d (barrels of oil equivalent per day) (46 per cent liquids), substantially all of which flows through company owned and operated infrastructure. The company expects that the post transaction budget will result in average 2025 sales volumes of 37,500 Boe/d to 42,500 Boe/d (48 per cent liquids), driven primarily by fourth quarter production growth at Willesden Green, and a 2025 exit rate in excess of 45,000 Boe/d.

Approximately $560-million of the posttransaction budget, at the midpoint, is allocated to the Willesden Green Duvernay development. Capital activities will include the completion of the first phase of the company's new Alhambra plant, with start-up expected in the fourth quarter of 2025, as well as the continued execution of the drilling program to feed the plant on start-up. In addition, Paramount is, conditional upon completion of the transaction, accelerating the second phase of the Alhambra plant, with start-up of this phase expected to occur in the fourth quarter of 2026. Each phase of the Alhambra plant will provide 18,000 Boe/d of raw handling capacity (comprising 50 MMcf/d (million cubic feet per day) of raw gas handling and 10,000 Bbl/d (barrels per day) of raw liquids handling) upon completion.

Expenditures in the Kaybob region, primarily related to development at Kaybob North Duvernay, constitute the majority of the remaining portion of the posttransaction budget. Capital has also been allocated to continuing appraisal activities at the company's early stage assets, including Sinclair.

The company expects that similar levels of capital expenditures in 2026 to those contemplated in the posttransaction budget would enable it to exit 2026 with production in excess of 60,000 Boe/d (50 per cent liquids).”

Pre-deal, here are some slides from Paramount’s corporate presentation

 

 

With them announcing the sale of the Karr and Wapiti assets a few weeks after this chart was produced, clearly the Willesden Green is the next play for them. Also worth noting in past 12 months they have moved it from the appraisal to develop section of that graph.

 

They also had this chart showing the potential for Wilesden Green Duvernay to support a large production base over the long term. Note POU has 249k acres of Willesden Green lands vs SDE of ~180k acres. However, POU states 700 drilling locations vs 300 for SDE offering some evidence that SDE is being conservative in their locations estimates.

 

 

Paramount has released more results from adjacent lands which gives me confidence in my 600/boe IP365 assumption. From Nov corp presentation:

“The three wells that were recently brought onstream averaged gross 30-day peak production per well of 1,254 Boe/d (2.3 MMcf/d of shale gas and 865 Bbl/d of NGLs) with an average CGR of 371 Bbl/MMcf. ”

 

Again, 1,254 is similar (actually a little worse) than what SDE has released to date, and it seems likely these wells exit after a year of production around 400 boe/d meaning IP365s closer to 800 than 600. In fact that’s exactly what POU is forecasting for the play

 

 

If I use the same assumptions (828 boe IP365 and $13.3mm cost per well) and hold everything else the same my model equates to a $13.67 Dec 31 2027 price, good for a 280% return.

Final note on POU is valuation. Post distribution, POU is trading for a $2.5 billion marketcap and $1.5 billion EV. For that you get 30k boe of production today and the Duvernay play.

SDE is trading for an EV of $784mm with 40k of production today, and you get 2/3rds of the same land play on top.

 

Westbrick Energy (private) is the second player to go all in on the Willesden Green in the past 2 months. On December 23rd 2024 they announced the sale the company (their Deep Basin assets directly adjacent to SDE deep basin lands) for $1.1 billion. Press release details state this acquisition should produce 50k boe/d in 2025, presumably because there is some shut in wells currently. Nonetheless we can use the 21k boe/d flowing asset sale price on the Deep Basin assets as a marker for a SDE valuation sanity check.Westbrick is spinning off their Duvernay lands to existing shareholders as stated in the press release. “The acquisition excludes undeveloped Duvernay rights on approximately 300,000 (290,000 net) acres of land, which will be retained by the shareholders of Westbrick.”

 

Here is a map showing the Westbrick Deep Basin assets in relation to SDEs deep basin assets

 

 

 

 

Valuation:

 

On strip pricing we get the below

 

The improvement in FCF from 2024 to 2028 partially comes from AECO gas pricing rebounding from $2/mcf to $3/mcf but the biggest driver is Oil/Condy production moving from 2,200 BOE/D in 2024 to 9,634 BOE/D in 2028. This is all driven by the condy rich Duvernay wells.

The development capex should be all self funded with excess FCF ramping materially from 10mm in 2025 to 123mm  in 2027. SDE should go net cash some time in 2027, though I expect some more land acquisitions or share buybacks before that happens. Point is debt at .7x 2025 AFFO is not an issue.

 

As a sanity check on valuation we can use the Westbrick acquisition and the POU asset sale.

Westbrick sold off neighbouring deep basin production for $21k per flowing barrel. Using the same for SDEs 35k flowing Deep Basin production would return $735mm vs todays EV of $784mm. ie we are basically getting the good assets for free.

Those good Duvernay assets will be producing about 7k boe/d in 1 years time and at 50k per flowing would be worth $2 a share. Together that’s 56% up from todays price in a year.

We can also look at POU and see what they are trading for net of the coming distribution. In 2025 they plan on overspending free cash flow substantially to speed up Duvernay development. They will exit 2025 with 45k producing barrels and an implied EV of $2.1 billion. This works out to 46k flowing BOE for what will be 1/3 Duvernay 2/3rds more gassy lands. Using a blended 30k per flowing barrel on SDE exit 2025 production get us a share price of $6.27, good for 75% in a year.

Again, I prefer to just use FCF on strip pricing for my E&P investments, but sanity checking using direct land comps is always helpful.

 

AECO gas recovery upside:

While this isn’t necessary to make the stock work, I do think that current AECO (Albertas main gas pricing hub) strip is going to be very wrong over the next 12 months and should rerate higher.

Heres’s current AECO strip pricing and this is what I use in my model 

Henry Hub is currently priced around $3.50 USD in 2025 and $3.75 thereafter. The current USD/CAD exchange rate is 1.44 meaning 2026+ HH gas is $5.40 vs 3$ for Canada!

The cost to ship gas from Alberta to the gulf coast should be around $1 per mcf and in an efficient market, that would be the differential. But there have been export constraints for the past number of years which means the differential often blows out.



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This quote is from August 2022 but it’s the same idea today. “Analyst Jeremy McCrea of Raymond James said that typically, the price differential should be between 75 cents and $1 per mcf to account for transportation costs to ship Alberta gas to the U.S. Gulf Coast. “Now it is just hitting astronomical proportions,” McCrea said of the discount.”However LNG Canada is about to come online and bring 2.1 BCF a day of export capacity to the western Canadian market. Compared to western Canada production of 19 BCF/D this is 11% more export capacity.

LNG Canada is fully built with first shipments targeted for mid 2025. Is it in the middle of testing activities including flaring which is normally part of the late stages of testing. This leads me to believe a March/April COD is more likely than summer 2025.

https://boereport.com/2024/08/19/analyst-says-lng-canada-likely-to-start-exports-before-year-end/

 

This extra 2.1 BCF of export capacity should normalize the AECO market, which is under even more pressure currently as LNG Canada producers like Shell have ramped their production in advance of first shipments and that production is depressing the market.

I also don’t believe it will be 2 years of relief and then similar issues. LNG Canada, like most LNG facilities, was designed to be built modularly. The second 2.1 BCF of export capacity is already approved and should have a quicker construction timeline. In fact the Coastal Gaslink Pipeline that was completed in 2023 to service LNG Canada was built with 4.9 BCF/d of capacity and LNG Canada management has told me in closed door meetings that the economics only really work with both phases factored in. 

Therefore, it is highly likely we see 2.1 BCF a day of takeaway capacity added in the coming months with another 2.1 BCF a day of takeaway capacity added in 2028/2029. In total 4.2 BCF on a 19 BCF base is fairly significant and should lead to the AECO/HH price differential narrowing to the long-term economics of $1 USD.

Using $3.75 HH and $1 transportation costs gets us to about $4 AECO in 2026 and beyond imo. Plugging that gas price into my model gets to a $11.56 share price in 3 years, good for 222% or a 48% IRR.