Uranium Discord — Hastings on D3 Energy: wellhead economics, dry holes & seismic-after-wells
A member relays William H. Hastings' emails on D3 Energy's Nooitgedacht program — a wellhead-only revenue matrix that backs a payout measured in weeks, why a dry hole is immaterial when the well costs <$200,000 against a $600+/mcf product, why drilling ahead of seismic is defensible here, and the three things to watch on the new wells: helium content above 4%, pressure and flow.
One-line take: Hastings is "strongly positive" on D3 Energy, and this post is the arithmetic and the geology behind that. He circulated a "very very rough" Virginia Gas Field — Well and Production Revenue Analysis matrix (built at Nathan's request) that models wellhead-only economics — helium and methane $/mcf, impurity/helium/methane content, volume in MCFD, annual revenue, a wellhead OPEX estimate, operating cash flow before field costs, that cash flow haircut for an 83% success rate, well cost, and payout in months — with side-by-side "WHH most likely" and "Nathan most likely" scenario rows. Its conclusion: "Bert's 1 month figure is pretty accurate." He is explicit that facility costs (gathering, plant processing) are excluded because they aren't a wellhead expense. The framing that follows: "On the one hand we have a $600+/mcf product and on the other hand we have <$200,000 wells to get that. You are seeing the flexibility play out" — which is why, in his view, "a reasonable number of dry holes… don't matter — it's not material" when what they buy is seismic calibration and reserve definition (contrast: his $600,000-per-day, $20 million dry hole in Norway, followed by the well that found the ~700-million-barrel Alvheim field). On the sequencing question — did D3 drill without seismic? — yes, and it's "customary in a low-risk environment," legitimate here because there's an existing producing well between the new locations; the 2D seismic is shot afterwards to tie signatures to each well's producing zones, so the survey can then be used to step out further with less risk. He expects two more wells this year, further south toward the PRA, to define the fault system, and says the map of where the seismic is shot is the near-term tell for where development is heading. New well results plus the new seismic go to Sproule, and will "likely take reserves from Contingent to Proven/Probable/Possible." The tight spacing of the two new wells surprised him, which he reads as intent — fractured geology, possibly a deeper or shallower second zone the company has "quietly mentioned," and a deliberate test of whether the fault systems are pressure-connected. His watch list: helium content >4%, pressure, and flow. (Curator note, not Hastings': there appears to be little or no decline curve, with up to ~500,000 acres still to be proved up — world-class potential in size and richness.)
1. Stocks & names mentioned
A written Discord post relaying emails — no video and no (mm:ss) timestamps, so the "At" cell opens the Discord message. The stance is William H. Hastings', named in the note (this is a channel-level archive; each view is attributed to the member who held it). Research legend: QT Qualtrim · SA Seeking Alpha · STK Stock Analysis — note the ADR/OTC divergence (QT/SA carry OTCQX DNRGF, STK the ASX line D3E).
| Ticker | Name | Research | View | What Hastings said | At |
|---|
| D3E | D3 Energy | QT · SA · STK | Positive | Hastings is explicitly "strongly positive." His wellhead-only revenue matrix (built for Nathan) supports "Bert's 1 month figure" — payout of roughly a month on his most-likely case, before facility costs. The core asymmetry: "we have a $600+/mcf product and on the other hand we have <$200,000 wells to get that. You are seeing the flexibility play out" — so "a reasonable number of dry holes… don't matter — it's not material" when they buy seismic interpretation and reserve definition. Drilling ahead of seismic is "customary in a low-risk environment" and defensible here given an existing producing well between the new locations; the 2D shoot afterwards calibrates signatures to each well's producing zones so the next step-outs carry less risk — "not a cost move." He expects two more wells this year further south toward the PRA to define the fault system, reads the tight spacing of NGT245 D/E as Casey deliberately testing a quietly-mentioned second (deeper or shallower) zone and the pressure connectivity of the fault systems, and expects Sproule's interpretation of the new wells plus seismic to "likely take reserves from Contingent to Proven/Probable/Possible." Watch items: helium content >4%, pressure, flow. | read ↗ |
Not tabled (people, firms and assets, not securities): William H. Hastings (the author — a retired oil & gas executive who drilled the discovery well that led to Norway's ~700-million-barrel Alvheim field), Bert (the community member who reprints Bill's comments, and the source of the "1 month" payout figure) and Nathan (who asked for the valuation matrix); David Casey, D3's MD/CEO; Sproule, the independent reserve certifier whose interpretation drives the Contingent→2P/3P migration; and the PRA (the PR016 Production Right Application area). Hastings' spreadsheet, Well Cost v Product Analysis 3Aug26.xlsx, is distribution-restricted ("Limited to those approved by William H. Hastings") and is therefore described here but not linked or published.
2. Talking points
The valuation matrix — Nathan's ask, and Bert's one-month payout
- Hastings circulated a "very very rough stab at the valuation matrix Nathan asked about" — a Virginia Gas Field — Well and Production Revenue Analysis sheet. He hadn't run this analysis before; it's "rudimentary," the formulas are meant to be adjusted, and a pivot table could be layered on.
- Its verdict: "It does shown Bert's 1 month figure is pretty accurate" — i.e. a wellhead payout on the order of a single month on the most-likely case.
- Structure of the sheet: helium $/mcf and methane $/mcf, the impurity / helium / methane content of the stream, volume in MCFD, annual revenue, a wellhead OPEX estimate, wellhead-only operating cash flow before field costs, that cash flow adjusted for an 83% success rate, well cost in US$, and payout in months — with side-by-side "WHH most likely" and "Nathan most likely" scenario rows so a reader can substitute their own assumptions under his.
Wellhead costs only — what the matrix deliberately excludes
- "The costs are wellhead only and don't include facility costs (gathering, plant processing and such) as those are not associated with the wellhead effort."
- The discipline matters: it isolates the drill-and-produce decision from the midstream build, so the payout figure answers "is another well worth drilling?" rather than "is the whole project economic?" Facility capital has to be layered on separately before anyone calls this a project return.
The core asymmetry — a $600+/mcf product against a <$200,000 well
- "On the one hand we have a $600+/mcf product and on the other hand we have <$200,000 wells to get that. You are seeing the flexibility play out."
- "These wells are very cheap - low cost which makes things very efficient vs usual." The cheapness is not a detail — it's what buys the operator optionality on where and how often to drill.
- "And those facts will be important when it comes valuation time" — his point being that the market will eventually have to price the unit economics, not just the acreage.
Why dry holes don't matter here — and the Norway contrast
- "He (we) are blessed with pre existing well data and ultra-low cost wells. He recognizes that a reasonable number of dry holes (the latest one is not dry) don't matter - its not material - in order to get seismic interpretation for the much greater good (reserve definition and addition)."
- The scale check, from his own career: "we had a $600,000 per day dry hole ($20 million) in Norway a while back, it's all relative. (We followed with a second well that led to the 700 million barrel Alvheim field so I managed to avoid getting fired)."
- "These are some of the reasons why I've made my strongly positive comments - re printed with permission (mostly) by his eminence (Bert)."
Did they drill without seismic? Yes — and it's defensible here
- "Appears, yes, that they did drill without seismic. It is indeed customary in a low-risk environment but low risk environments are not common. You can do it when you have an existing well that produces already nearby (which they do between the new wells)."
- The sequence he describes: drill first on well control, then shoot seismic "post well to see how the seismic signatures line up with each well's producing zone / zones. You can then use the seismic to step further out distance wise to drill the next well with no corollaries thereby reducing risk."
- "Overall, I'm not concerned that 2D comes after the wells given the existing well control. It wasn't a cost move, rather a way to understand seismic better and improve future well locations that will be more risky."
The seismic map is the near-term tell
- "It will be important to see the map of where the seismic will be shot as an indicator of where this development will be going near term." Where a company spends survey money reveals where it intends to drill next.
- He expects "two more wells in the relatively near term further south toward the PRA to better define the fault system" — and those next two will matter more than the current pair, because they will have both well corollary and seismic behind them.
Sproule and the reserve migration — Contingent to Proven/Probable/Possible
- "Yes, the new well results will be interpreted by Sproule (along with the new seismic) and likely take reserves from Contingent to Proven/Probable/Possible."
- That reclassification is the value event: contingent resources are volumes believed present but not yet commercially demonstrated; proven/probable/possible reserves are what underpins a production right, a financing, and a valuation.
Reading the operator's intent from where the wells were placed
- "I was surprised a little bit that the two new wells were so close together because Casey is so experienced and good. It's an indicator of how he is thinking (this is smart move) and how he sees the play and the development and may indicate a second target (that they have quietly mentioned)."
- "Not as much as they would materially separate. But Casey knows this, so he's got a plan and a reason. This is fractured geology and he may be testing a deeper or shallower zone. They had quietly mentioned that they think they've found a new zone and the second well layout would perfectly tie in with that."
- "If they are testing that discovered zone they may have mapped out a geologic peak at this location."
Pressure as the connectivity test — and what to watch
- "What they want to do is assess pressure in the fault systems to see if and how the fault systems are connected. Thats why i believe we will see two further wells this year based on the results of these two which will be located more toward the PRA."
- "So watch helium content if >4%, pressure and flow. Over time with enough wells you can compare pressure to see how things are connected or how they are separate - both laterally and depth wise. Those assessments are taken by Sproule."
Curator note — no decline curve, and the acreage still to prove
- Stephen's own observation on the above (not Hastings', not part of the post): there appears to be no, or next to no, decline curve on these wells — for whatever reason — and up to 500,000 acres remain subject to being proved up.
- Taken together that "would suggest world class potential in size and richness" — which is the frame the rest of this archive should be read against as results land.
3. In plain English
A jargon-free summary of why this name matters. (This renders on the ticker's consolidated page.)
D3E — D3 Energy Positive
D3 Energy drills shallow wells in South Africa's Free State for helium and natural gas. Helium can't be manufactured — it's produced only as a trace component of certain gas fields, it's essential to MRI scanners, semiconductor fabs, rockets and anything cryogenic, and once released it escapes the atmosphere permanently. D3's ground has independently verified helium concentrations up to 8%, versus fractions of a percent in most helium-bearing gas, which is why the gas coming out of these wells is worth so much more per unit than ordinary natural gas.
William H. Hastings — a retired oil & gas executive who drilled the well that led to Norway's roughly 700-million-barrel Alvheim field — built a spreadsheet at another member's request to test whether the economics really are as good as the community thinks. The method is simple and worth understanding: take the price per mcf (a thousand cubic feet of gas) for the helium and the methane, multiply by how much of each is in the stream and by how many thousand cubic feet the well produces per day, get annual revenue, subtract only the wellhead operating costs, then knock the result down for the share of wells that fail (he uses an 83% success rate), and divide the well's cost by what's left to get payout in months. On his most-likely assumptions the answer is about one month — the well pays for itself almost immediately. He is careful to say this excludes the pipelines and processing plant needed to get the gas to a customer, so it's the "should we drill another one?" number, not the "is the whole business profitable?" number.
His headline framing is the reason he's "strongly positive": a product worth $600+ per mcf against wells that cost under $200,000. When wells are that cheap, occasional failures stop mattering — a dry hole here buys information (it calibrates the seismic and helps define reserves) for a rounding error. His own benchmark for perspective: a dry hole in Norway that burned $600,000 a day and $20 million total.
Two technical points he explains. First, D3 drilled these wells before shooting seismic (the survey that images rock layers by bouncing sound waves off them). That looks backwards, but it's standard when risk is low — here there's already a producing well sitting between the new locations, so you know the gas is there. The seismic is then shot afterwards and matched to each well's producing zone, giving you a calibrated picture you can use to step further out into riskier ground. Where the survey is shot is therefore a public clue about where the company plans to drill next. Second, the gas sits in fractures — cracks along fault lines — so the fault network is the reservoir, and measuring pressure across wells tells you whether those cracks are connected into one system or isolated pockets. Hastings thinks the unusually tight spacing of the two new wells means CEO David Casey is deliberately testing a deeper or shallower second zone the company has hinted at, and he expects two more wells this year further south toward the PRA (the Production Right Application area — the block D3 has asked the government for permission to produce from).
The payoff to watch for: Sproule, the independent engineering firm that certifies the numbers, will interpret the new wells plus the new seismic and is likely to move volumes from Contingent (believed to be there, not yet commercially proven) to Proven / Probable / Possible reserves — the classification that supports a production right, financing and a real valuation. Hastings' three signals to track on the current wells: helium content above 4%, pressure, and flow rate. (Curator note, not Hastings': the wells appear to show little or no decline curve — production doesn't fade the way a shale well's does — and up to ~500,000 acres remain to be proved up, which would suggest world-class potential in both size and richness.)
Analysis of a member post in a private Discord community's #general channel relaying William H. Hastings' emails, reprinted with permission. His accompanying spreadsheet is distribution-restricted and is not published here. Not investment advice.