In short: 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.
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.)
In short: Operational success at Nooitgedacht (ER315, Free State, South Africa): NGT245 E drilled to 363 m total depth "on time and budget without any safety incidents," the target gas zone successfully intersected and gas flowed to surface before the rig moved off for logging; the second well NGT245 D spudded 30 July and is already at 80 m with surface casing set. Both target faults/fractures in the Ventersdorp and Witwatersrand formations to test deliverability and gather helium and methane concentration data; each is budgeted at ~A$200,000, and NGT245 D will be production-tested to inform well interference, spacing and future Production Right applications. A 2D seismic program at Nooitgedacht begins in the coming weeks. CEO David Casey: the back-to-back spuds "highlight the very low-cost efficient nature of drilling these wells," a "very good first step" toward extending the ER315 reserve base 40 km north of the existing PR016 application area.
D3 Energy is an Australian-listed explorer drilling for helium and natural gas in South Africa's Free State province — near the town of Virginia (a South African town, not the US state). Helium is a genuinely scarce industrial gas — it can't be manufactured, it's needed for MRI machines, semiconductor fabs, rockets and cryogenics, and when it escapes it's gone for good — so a field that produces it in high concentration is rare. D3's ground has independently verified helium concentrations of up to 8%, which is extraordinary; most helium in the world is stripped out of natural gas streams at a fraction of a percent.
This post is a company announcement, and it's about execution rather than opinion. D3 finished its first well at Nooitgedacht, NGT245 E, at 363 metres — shallow, on schedule and on budget — hit the gas zone it was aiming at, and gas flowed to surface, meaning the rock actually gives up gas rather than just holding it. Days later the rig had already spudded the second well, NGT245 D. Each well costs roughly A$200,000, which for an oil-and-gas well is close to a rounding error (a single offshore well can cost a hundred times that). Cheap, fast wells mean the company can afford to be wrong sometimes and still learn quickly — the whole programme is about collecting enough data to convert exploration ground into producing ground.
What the drilling is really for: D3 already has reserves booked 43 km to the south at Bloemskraal, which support a Production Right Application (PR016) — the government permission needed to actually produce and sell the gas, currently being assessed by South Africa's petroleum regulator. These new wells step out north along the same fault trend to prove the field is bigger than the piece already applied for. The gas here sits in fractures — cracks created where the earth broke along the Homestead and Virginia faults — so the fault system is the reservoir, and each well tests whether the cracks connect. A 2D seismic survey (sound waves bounced off rock layers to image the subsurface) follows in the coming weeks and will be calibrated against these wells before picking the next locations.
Scale of what's still untouched: the current production-right application covers just 15% of the ER315 permit and about 9% of D3's total 479,409 acres. (Curator note, not from the announcement: the wells appear to show little or no decline curve — that is, production doesn't fade quickly the way a shale well does — and up to ~500,000 acres remain to be proved up, which would suggest world-class potential in both size and richness. See the 2026-AUG-04 post for William H. Hastings' reasoning on the economics.)
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