*Please read the disclaimers at the base of this report. The author has a short position in Pantheon. Does not constitute a recommendation to buy or sell the securities mentioned herein. Do your own due diligence. For Permitted Recipients only (UK - see disclaimers).
“There must be some way out of here
Said the joker to the thief
There's too much confusion, I can't get no relief…”
(Bob Dylan, All Along the Watchtower)
Since we last published, Pantheon, (PANR), has struggled with a poor well result at Alkaid 2, in the Alkaid ZOI, and continued reliance on ad-hoc equity market funding. Following a refresh at board level, we have seen a shift in company strategy and an Alkaid 2 recompletion in the SMD (Shelf Margin Deltaic, now rebranded the Ahpun “Topset”). Our concerns about the broader Pantheon Resources investment case have been made before, and we believe they remain valid. Disclosure around the new completion is vague and ambiguous, with no reporting of an actual “black oil” flow rate (instead using variations of the broader term “liquids”), question marks about reservoir pressure (below bubble point) and saturation (and the sustainability of oil flows over anything other than short period of time), still substantial gas production, and dubious claims about a modest liquids flow rate (the first test reported an average of 45 bbls a day over a 5 day period) being scalable to a hypothetical horizontal completion with a 30 day IP of 4000 barrels (liquids) a day (and 2mm barrel liquids EUR). Amidst all the confusing disclosures, we find it hard to give credit to the broader billion plus barrel development story Pantheon management are promoting.
Before addressing these concerns in more detail, however, it would be remiss not to acknowledge the impact of the new Executive Chairman, David Hobbs, has had on the company.
Hobbs’s Choice
Already well known in Fintwit/social media circles as a major supporter of and investor in Pantheon, David Hobbs was rapidly elevated to Executive Chairman in June last year subsequent to his appointment as a board member in March 2023, and after the disappointing Alkaid 2 test. Hobbs is a petroleum engineer whose immediate past was primarily as a consultant at CERA (Cambridge Energy Research Associates) and other energy think-tanks (most recently a Saudi based one, KAPSARC). Certainly he has “hit the ground running” and brought improvement to the operation along with his commitment to throw his personal money where his mouth is. We don’t doubt his belief in the project and commitment to seeing it progress, irrespective of our more sceptical viewpoint.
Nevertheless, credit is due to some of the positive actions that Hobbs has undertaken since coming on board:
Backed away from the excuse of a “free gas cap” at Alkaid 2 in the Alkaid ZOI, and effectively dropped focus on the Alkaid ZOI to refocus on the stratigraphically higher (younger) SMD (Shelf Margin Delta)
Shown more candour about the elevated gas component of the play (vs prior claims)
Technically split Pantheon’s holdings into a Western play termed Kodiak, (prior terminology Talitha-Theta West play or Slope Fan System and Basin Floor Fan) and an Eastern one Ahpun (Shelf Margin Delta of old), to simplify the company’s communication and move on from the Alkaid 2 disappointment.
Admitted to mistakes in the execution of the Alkaid 2 well and be more realistic about the work and capex involved to bring either Kodiak or Ahpun to FID, with a more realistic timeline.
Laid out a funding approach that appears to gravitate away from Pantheon’s traditional regular equity financings (eg external financing, vendor financing, farm out options etc)
Set out a somewhat more realistic pathway to potential development on the two plays with an acceptance of the capital required to get to FID/commercial success
Before we go too far in eulogising the new approach, it seems this new-found transparency does appear to have its limits. Much of the additional disclosure begs more questions than offering any answers. Basic questions and their implications centre around the nature and predictability of the reservoir and then test/fluids results: their nature, producibility, pressures, saturation and volume. Multiple 30 day extended well tests would be required to answer these questions, and we are still a long way from that.
We have grouped the main issues with the Ahpun SMD test at the Alkaid 2 recompletion into several broad themes, namely flow rate and flow type confusion, saturation considerations, reservoir pressure and gas lift implications, potential reservoir heterogeneity and permeability variation. Finally we consider the latest type curve forecasts the company has put out in its AGM release in January.
Confusion over test rates and fluid composition
Here are two quotes from Pantheon’s press releases
“During the flow test, after recovery of approximately 60% of the frac fluids, the oil rate (separator liquids) ranged from more than 100 barrels of oil per day ("bopd") to 30 bopd (averaging 45 bopd over the 5 days during which oil was recovered). Water cuts were 90% initially, but declined over time as a larger share of the frac fluids was recovered. As highlighted before the operation, the flow rates themselves were not expected to be material because the objective was to limit drawdown in the initial flow back.” (Press release 19/10/23)
“Pantheon reports that following incorporation of results of GeoMark analysis, the flow rate during the Alkaid-2 recompletion in the Ahpun topset was calculated to be 50-140 barrels per day ("bpd") of marketable liquids, 20-40 bpd higher than the originally announced flow rate. (AGM press release 24/1/24)”
Confusingly, for a company whose main objective is discovering oil (given Alaska’s current unsuitability for other hydrocarbon streams), in neither of these releases do we see an actual “oil rate”. In the first quote the oil rate is qualified by the parenthesised “separator liquids” which from elsewhere in the press release we guess (but can’t be sure) means heavier NGLs, condensate and black oil. No mention of actual black oil rate, however. Why?
In the second more recent quote we have a new phrase - “marketable liquids”, which again suggests NGLs as well as oil, although what fractions of NGLs and what ratio of those NGLs to underlying “black” oil rate we are not furnished with. Again – Why? The only conclusion to draw is that the underlying “black” oil rate (excluding gas liquids) is significantly lower, otherwise why not publish it?
We posit that the complex nature of the liquids/gas mix implies that what we actually have in these reservoirs is a volatile oil/gas play rather than an oil field, perhaps something that Pantheon would be reluctant to admit to given the added complexities involved in development.
Furthermore, the 100 barrels of “mystery” liquid rate a day in the first release, upgraded to 140 in the second release cannot have lasted long as the average given in the first release is not far off the lowest rate given, suggesting that the higher quoted rate was pretty shortlived: a quick “Hail Mary” on an open choke perhaps to give a good headline rate before prudently closing things up before too much pressure drawdown and therefore gas flashing occurred. Finally if we look at the first quote above it isn’t clear whether oil stopped flowing after 5 days, or the test was stopped after five days. The language is ambiguous, with the potential to be somewhat misleading.
The language on “oil” in these releases is really all over the place, darting around from oil with qualifications, to separator liquids, to marketable liquids, to C5 plus, condensate, and that’s before we get to the GOR or gas oil ratio. Further adding to the confusion is this gem of a paragraph (my bold highlights with the footnote in parenthesis):
“GeoMark's pressure-volume-temperature ("PVT") analysis of the fluid samples gathered during the test resulted in a calculated gas oil ratio ("GOR") for the Ahpun topset of 1,012 standard cubic feet per barrel of oil ("scf/bbl"), materially less than the calculated 2,000-3,000 scf/bbl which was previously reported for the Alkaid ZOI. As well as the reduced GOR, GeoMark reported oil gravity at the outlet of the separator of 35o API for the Ahpun topset, with a liquids [C5+ liquids] yield of 162 barrels of per million cubic feet ("bbls/mmcf"). This is a much richer stream than the 42o API oil with 98 bbls1/mmcf produced from the Alkaid ZOI and allows the total liquids flow rate from the topset to be recalculated to incorporate the yield of marketable liquids from the associated gas production.” (AGM press release 24/1/24)
Above, it states: “Oil gravity of 35 degrees API with a liquids yield of 162 barrels per million cubic feet”. This excerpt from the quote above is about as clear as the drilling mud that went into the original well. It is extremely odd to draft a sentence like this without saying how much oil is produced, and whether the liquids yield of 162bbl/mmcf includes or excludes this oil and is solely NGLs. It is completely confusing, and again, the motivation for doing this appears somewhat questionable, to say the least. For comparison, the previous Alkaid 2 (ZOI) press release broke down production volumes between oil, condensate and NGLs (Press release 6/3/23).
So we return to the first release where we learned (my emphasis in bold) that:
“Multiple fluid samples were gathered indicating a measured gas oil ratio ("GOR") of 3,000 - 4,000 standard cubic feet per barrel ("scf/bbl") and an API gravity of 35-36o. This compares to 12,000 - 13,000 scf/bbl measured in the deeper Alkaid ZOI. This indicates success in limiting pressure drawdown and avoiding flashing gas in the reservoir.” (Press release 19/10/23)
Assuming measured means “at the well-head” this might give us a stab at what the flow components actually consist of. If the above measured ratio is a wet gas vs oil ratio, that would mean oil is produced at a rate of 250 barrels per mmcf of wet gas at 4000scf/bl (1000mscf/4mscf = 250). We are also informed in the second release that the liquids content of the wet gas is 162 barrels per mmcf. If we apply these proportions to the second and more “generous” liquids flow rates given in the second release (50 to 140 bls a day) then the underlying oil flows we get an oil rate range of approx. 30 to 85 bls a day. But who knows, as the original release referred to a low-end number of 30 bls a day for “separator liquids”: the oil cut could be lower than this. Finally are these GORs apples to apples? We note the “topset” press releases conflate “liquids” with oil, when the previous Alkaid ZOI release more precisely stated “oil”.
Snapshot below from Pantheon’s recent (Jan 2024) AGM presentation:
As for the gas, putting aside the liquids/oil point above, the measured and calculated GOR show a superior mix than the Alkaid ZOI (the original completion at Alkaid 2), however, that is likely because Alkaid ZOI was so tight a large drawdown was needed to get any fluids to flow in the first place; which in turn would suggest that large areas of the Alkaid/Ahpun anomaly will only work for very high gas rates and limited black oil rates.
Moreover, even if gas cut is lower than previously seen at the Alkaid ZOI, 4000scf of wet gas a barrel still presents a big challenge if we “dream a little” and take Pantheon’s 4000 barrel a day IP at face value: what would happen to the 16mmcfd of gas given there is no takeaway capacity to handle it? It seems unlikely that the authorities would allow flaring for production wells, so presumably a lot of expensive reinjection wells would need to be drilled.
Saturation
Putting confusion over flow rates and liquids aside, there is bafflingly little information given on saturation. We haven’t been given coring data (or sidewall coring data – less accurate but still a snapshot). There is a mention of initial water cut, 90%, with the caveat of frac fluid flow back, but then precious little else. We don’t know or at least are not told the fraction of oil or water saturation in the reservoir, critical information for scoping the potential for development.
Pressure & Nitrogen Lift
The Ahpun “topset” test zone initial reservoir pressure is 3490 psig (below initial expectations) and the bubble point of the reservoir fluid is close at 3500 psig (25/1/24). This will be difficult to handle to avoid excessive gas production (their gas flashing). Nitrogen was used after 5 days presumably to lighten well bore load and reduce downhole pressure allowing the oil to flow freely and reduce having to drawdown below bubble point. Nitrogen is expensive and it does appear that they will have to use it from the outset to maximise oil production: the question is for how long per well.
As the company stated:
“Expectations for flow rates, water saturations and water cuts had led to plans for nitrogen lift (necessary to reduce bottom hole pressure and ensure that fluids were recovered to surface). Encouragingly, nitrogen injection was not required until the last six days of the eleven day test, resulting in the operation coming in at or below budgeted timelines and costs.”
The encouraging fact that nitrogen lift wasn’t required until the last six days of the eleven day test is perhaps balanced by the fact that the well only flowed oil for five days of the test (we don’t even know if these were the final five days). We should note that nitrogen lift is not inexpensive – it appears it was a major factor of the earlier Alkaid 2 ZOI completion running way over budget (see pumping and chemicals, below).
Snapshot from Pantheon Webinar Summer 2023:
Reservoir
Snapshot from Pantheon’s recent AGM (Jan 2024) presentation:
The Alkaid Ahpun “topset” test was in the upper topset of the lower of two prograding deltaic systems. There are several individual reservoir layers in both systems and indeed the unit tested was only 50% net of a gross 200 feet (company release 19/10/23; the “net” refers to viable reservoir over an overall gross section). This implies that the reservoir rock is heterogenous and probably heterolithic, not ideal for making broad field wide assumptions for recoverable reserves and locations (see logs in presentation 20/4/21). The company’s AVO analysis indicates they are on the margins of the main reservoir section tested where it degrades (i.e. becomes shaly - heterolithic). The main area which remains untested is to the southwest of Alkaid. The anticipation is that the reservoir will have better porosity and permeability characteristics into the core AVO anomaly and hopefully a greater net to gross. This has yet to be proven.
The total area of interest (including to Alkaid) is very approximately 50 sq. miles (130 sq km). It should be noted that over such an area reservoir heterogeneity (thinning or disappearance of individual units) will occur and cannot all be discerned by AVO analysis so even the analysis itself has an element of uncertainty attached. These individual units are not plank like consistent reservoirs over tens of miles but as in any modern delta discontinuous. In addition, the heterolithic nature of units (centimetre interbeds of shale and sand) is beyond the seismic resolution. In short many more wells are likely needed just to tie down the nature and distribution of the producible reservoir horizons. It is still (in science project terms) early days.
Permeability
The Alkaid ZOI is in effect part of the old SMD unit in that it is a growth fault bounded sand shale accumulation and is an immediate geological precursor genetically linked to the SMD. Pantheon themselves consider the units to be genetically part of the same parcel of rock (19/10/23). By their admission the Alkaid ZOI reservoirs are poor. There is no information on net to gross of the reservoir unit but permeabilities are measured in nanodarcies (possibly due to the heterolithic nature of the test zone), whereas the recent Ahpun “topset” test zone calculated 0,02 to 0.12 mD derived from pressure transient analysis. As pointed out by Pantheon this is over 100 times greater than that obtained from the Alkaid ZOI test and it is what primarily drives the better test results. However, the Ahpun topset test results (particularly permeability) cannot be assumed to apply equally to the other reservoir units in the field. They could be better, or they could be worse (like the Alkaid ZOI). One intriguing possibility is that the Alkaid ZOI and the Ahpun test higher in the SMD indicate different fluid compositions (oil API) related to the non-continuous nature of the reservoirs. In essence the Alkaid ZOI test needs to be understood in this wider context as if replicated again, it would have a negative impact on development options, especially given the possibility that the lower Ahpun reservoir units are more comparable with the Alkaid ZOI and therefore unlikely to be prospective or commercially viable. The upcoming 88 Energy Hickory 1 test just south of the Pantheon acreage boundary will be an interesting test of fluid compositions and potential incompatibilities.
Another aspect of permeability is its relationship to the fracking. There is no doubt that Ahpun frac design considerably aided the efficiency of the frac propagation (50% versus 20% in Alkaid ZOI: 22/1/24). They achieved frac propagation across the entirety of the 200’ gross (100’ net) reservoir column and laterally for 300 to 400’ (19/10/23). Without core data on hand though, the question remains as to whether calculated permeability is simply a result of the frac job; we don’t know the prior (virgin) rock matrix permeability which is fundamental to flowage from the matrix storage. With more heterolithic and heterogenous, therefore poorer reservoirs as in Alkaid ZOI, frac efficiency would have been lower anyway with the same frac design as used in the Ahpun test. In short, the frac possibly would heal and be displaced laterally in the shaly units. These relationships need to be understood more fully prior to launching a full scale development.
Fantasy Type Curves
It is hard to consider all the above, and all the uncertainties implied and square it with the follow statement in Pantheon’s 24th January release:
“Pantheon has provided an illustrative model based on Company estimates of the Ahpun topset type well performance. This results in an IP30 of 4,000 bpd of marketable liquids, with a first year average production rate of 2,000bpd, and estimated ultimate recovery of 2 million barrels ("mmbl") of marketable liquids per well. This is based on the development well design of 10,000 feet lateral length, improved frac design, and recognising the improved reservoir and fluid characteristics. Projections for cumulative cashflows and funding requirements based on these estimates reinforce the robustness of the Ahpun development strategy and the ability to deploy cashflows from the initial wells to fund the expansion to a multi-rig programme and to fund the Kodiak Field development after its FID (expected by the end of 2028).”
4000 barrels a day of “marketable liquids” for a 30 day initial production period is quite a step up. The original test averaged 45 barrels a day over 5 days (according to the October 2023 release). So presumably an IP30 of much less than 30 barrels a day. And yet, magically this vertical completion is transformed by a (heroic?!) multiplication factor of over 100. To state that this is not conservative would be an understatement, as it suggests simply plugging in a “best case” Joshi ("Augmentation of Well Productivity Using Slant and Horizontal Wells”, JPT 1998)* horizontal productivity model at long lateral lengths in a difficult reservoir environment (well productivity has been shown to decline as laterals extend). With all the questions raised earlier it is hard to give much credit to this extrapolation (and indeed the AGM presentations well programme build up highlighted below, with each well seemingly delivering to this type curve!).
Company graphic on Ahpun production build up (from recent Jan 2024 AGM presentation note: includes injector wells):
Final Thoughts
Since David Hobbs took over, the company has been more frank about the sheer amount of capex required to fully develop these plays; $100s of millions before (if!) they become self-funding and tens of billions to drill it all out. In mid-December the company had less than $8m in the bank with just over $4m to come in for financing the convertible payment in March. Offsetting that we have likely had cash burn from G&A since then, year end remuneration, payments to Geomark for their well analysis, and presumably other payments from historic payables outstanding as well as to NSAI (for the expert report to come) and perhaps also to Schlumberger. Given we haven’t had any news of non-equity financing or potential farm outs, it would seem reasonable to believe an equity raise will be necessary in the near future. That may disappoint those hoping that the years of continued equity dilution may be coming to an end, and provide a headwind to the shares in the short term, notwithstanding our longer term concerns. Those remain the same as they always have been:
1. This is the very early stage of a science project which will likely consume a large amount of capital, in a region with limited oil service availability, extreme temperatures, with high drilling and completion costs. Not easy for a company with minimal cash and liquidity on hand.
2. Results from tests so far have been of variable and generally poor quality, with vague and ambiguous disclosure
3. Oil rates have generally been low, with tight rock and reservoir pressure concerns
4. The reservoir rock appears heterolithic and heterogenous making it hard to forecast low risk scaling up of the play
5. The material gas production in a basin that doesn’t have gas offtake and frowns upon flaring adds additional serious complications to any development plan.
6. A long term production test or EWT that conclusively proves commerciality has yet to occur. In any case, as we have seen in West Texas, multiple EWTs are required to test commerciality and underpin EUR judgements
Footnote: Vertical to Horizontal Productivity assumption
*Regarding the Joshi productivity model (cited above) a number of subsequent papers (eg JERT 2011 Adesina et al “Modelling Productivity Index for Long Horizontal Well”) highlight issues with Joshi’s apparent assumption of infinite conductivity/uniform flow along the wellbore, and the potential offsetting impact of moderate pressure drawdown in the wellbore. Given stated initial reservoir pressure below bubble point and the potential varying quality (heterolithic and heterologous) of the reservoir, Pantheon’s horizontal type curve scaling appears highly optimistic. See also Cho, H. and Shah, S. N., "Optimization of Well Length for Horizontal Drilling", IPC Paper 2000-27 presented at the Petroleum Society Canada International Petroleum Conference 2000, Calgary, Canada, June 4-6, 2000.
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