TPDC’s Coastal Gas Push: 2000+ Industries, 102 km Pipeline, and the Strategic Role of Ntorya

 

President’s official announcement signals a major acceleration in Tanzania’s domestic industrial gas demand — here’s why it matters for investors.

1. The Announcement: Straight from the Top

On her official Facebook account, Tanzania’s President has outlined an ambitious new natural gas initiative.
Frame-by-frame translation of the video text reveals:

• “TPDC opens doors of 2000+ industries to natural gas on the coast”

• “TPDC to build 102 km pipeline from Dar es Salaam to Chalinze”

• “2000+ industries to be established in Kwala Strategic Zone”

This is not speculative commentary. It’s a direct communication from the country’s highest political office, signalling official intent and policy direction.

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2. Project Overview

The announcement contains three intertwined elements:

1. 102 km Gas Pipeline (Dar es Salaam → Chalinze)

   • Extends the existing national gas grid north from Dar.

   • Likely to connect with or support future Dar–Mombasa pipeline plans.

   • Includes a branch to Kwala for industrial supply and export handling.

2. Kwala Strategic Industrial Zone

   • Envisioned as a major manufacturing hub with 2000+ industries.

   • Positioned as a cornerstone of Tanzania’s industrialisation and export strategy.

3. Integration with Regional Energy Trade

   • Although not stated in the video, previous planning documents have referenced the Dar–Mombasa subsea pipeline (with connections to Tanga and Zanzibar), indicating regional export ambitions.

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3. Why This Matters: The Demand Shock

The scale of ambition is enormous.
For context:

• In August 2024, TPDC reported only 56 industries connected to the national gas system.

• Moving from 56 to 2000+ represents a 35-fold increase in industrial connections.

• Even at a conservative 1 MMscf/d per industry, this would imply 2000 MMscf/d of new industrial demand — multiples of Tanzania’s current total production.

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4. Current Supply Reality

Existing Production

• Songo Songo: Small offshore field; mature and declining.

• Mnazi Bay: Producing but with limited reserves and long-standing commercial disputes.

Offshore LNG Megaprojects

• Shell and Equinor-led developments remain in negotiation stage.

• First gas unlikely before the early 2030s.

Implication

The government’s own timelines for industrial build-out mean it cannot wait for offshore LNG.
It must rely on near-term, scalable, onshore resources — and that puts Ntorya in the spotlight.

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5. Ntorya’s Strategic Position

• Resource scale: Independent estimates show Ntorya’s gas in place sufficient for multi-decade supply at hundreds of MMscf/d.

• Infrastructure: Pipeline to Madimba under EPC contract, with CNPC leading — first gas expected mid-2026.

• Commercial terms: Aminex fully carried to ~$40m net, with a more favourable PSA than industry norms.

• Market linkage: Named as primary supplier for the Mtwara LNG project (400 → 1,200 MMscf/d).

• Ramp-up plan: 14-well programme targeting 420 MMscf/d capacity.

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6. From Dar to Kwala: The Corridor Effect

The new Dar–Chalinze pipeline creates an industrial corridor:

• Dar: Tanzania’s commercial hub.

• Chalinze: Strategic road and rail junction.

• Kwala: New manufacturing and logistics hub.

This corridor could act as a gas demand anchor in the same way industrial zones drive pipeline economics in other countries. Once in place, the network can:

• Supply large anchor customers.

• Spur smaller industrial users along the route.

• Serve as a feed point for regional exports to Kenya and beyond.

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7. Investment Implications

Short-Term

• The President’s announcement provides political cover for accelerating infrastructure approvals.

• Market sentiment could improve as investors see government-backed demand pipelines emerging in parallel with Ntorya’s development.

Medium-Term

• Demand growth in the Kwala zone could outpace initial Ntorya production, giving Aminex and its partners strong pricing leverage — especially for industrial sales (which Orca’s 2024 data shows average $8.45/MMBtu).

Long-Term

• If the 2000+ industry target is even half-met, Tanzania will require multiple hundreds of MMscf/d of new supply, creating room for both domestic sales and LNG exports.

• Ntorya could transition from being one supplier among many to being the critical swing producer in the domestic market.

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8. Risks and Realism

• Execution risk: Government timelines for industrial build-out have historically slipped.

• Funding: The 69.6 billion shilling allocation for the 102 km pipeline (~$26.5M USD) covers construction but not necessarily all ancillary infrastructure.

• Demand pacing: While 2000+ industries is the target, actual connections will likely ramp gradually.

However, policy intent is clear, and the infrastructure moves are real enough to warrant investor attention now.

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9. Bottom Line for Investors

The President’s public endorsement of a 102 km coastal pipeline and a 2000+ industry Kwala zone signals a new phase in Tanzania’s energy and industrial policy.
For Aminex and Ntorya, it means:

• Locked-in demand growth that fits perfectly with Ntorya’s production timeline.

• Pricing upside from industrial sales into a market with tightening supply.

• Strategic positioning as the only near-term, large-scale onshore resource capable of meeting these targets.

At today’s sub-2p share price, the market is valuing Aminex as if these policy shifts didn’t exist. If execution follows even half of the announced plan, that disconnect won’t last.

From 80p to £1.35: Rising Gas Prices Supercharge Ntorya’s Valuation Potential

 

Orca’s 2024 realised prices reveal a higher-value demand mix, doubling Aminex’s projected upside in the 14-well scenario.

When we modelled Ntorya’s long-term value earlier this year, our 14-well, 420 MMscfd case used conservative gas prices of $3.50–$5.50/MMBtu. That produced impressive numbers — with some scenarios approaching 80p per share.

But the latest Orca Energy 2024 annual report changes the game. It shows:

• Gas-to-power: $3.88/MMBtu

• Gas-to-industry: $8.45/MMBtu

• Weighted average realised: $4.95/MMBtu

Many of Ntorya’s likely buyers — CNG stations, GTL, fertilizer, LNG trucking hubs — fall into the higher-priced industrial category. Using blended scenarios based on Orca’s real-world data lifts our projections dramatically:

• 50/50 industrial/power blend = $6.17/MMBtu

• 70% industrial blend = $7.08/MMBtu

• 80% industrial blend = $7.54/MMBtu

Applying these to our 14-well, 420 MMscfd case with a 40% effective cash entitlement to Aminex, the implied share price potential jumps from ~80p to as high as £1.35 at standard market earnings multiples.

This isn’t pie-in-the-sky speculation — it’s grounded in realised Tanzanian gas prices from a peer producer and in Ntorya’s planned production profile. With the Mtwara LNG project naming Ntorya as its primary supply source and multiple high-value industrial markets lining up, the revenue mix could lean heavily toward premium-priced sales.

For investors, the takeaway is simple: as the demand mix shifts towards industry and transport, Ntorya’s economics strengthen — and the gap between current market price and intrinsic value widens.

Updated Orca-Based Valuation:

Our original 14-well, 420 MMscfd projections used conservative gas price assumptions of $3.50–$5.50/MMBtu. However, Orca Energy’s 2024 report confirms a weighted average realised price of $4.95, with a $3.88/Mcf gas-to-power rate and an $8.45/Mcf gas-to-industry rate. Applying blended scenarios of $6.17 (50/50), $7.08 (70% industrial), and $7.54 (80% industrial) lifts projected share price outcomes significantly across all market multiples. At the upper end, the industrial-heavy blends more than double the implied valuation compared to our earlier chart, reinforcing the bullish case for Ntorya’s earnings potential as higher-value industrial demand ramps up.

Tanzania’s Energy Infrastructure Surge Sets the Stage for Explosive Gas Demand

EWURA’s 109-permit wave, CNG expansion, and major industrial projects point to a multi-year growth engine for Ntorya gas.

Tanzania’s downstream energy build-out is gathering serious momentum. The Energy and Water Utilities Regulatory Authority’s (EWURA) latest Batch 244 public notice lists 109 mid- and downstream petroleum permit applications, covering:

• Kibali cha Ujenzi wa Kituo cha Mafuta – construction permits for fuel stations

• Leseni ya Kituo cha Mafuta – licences to operate fuel stations

• Leseni ya Usambazaji wa Gesi ya Kupikia – explicit LPG distribution licences

• Other infrastructure-related activities

While the notice does not explicitly label these stations as CNG, the timing, policy direction, and presence of known energy brands such as Puma Energy suggest that many could be CNG-capable — aligning with the government’s goal for a majority-CNG vehicle fleet by 2050.

This is in addition to seven CNG stations already under construction, mobile CNG units being rolled out, Rashal Energies’ plan for 30 CNG stations, and Gazprom’s reported market entry. The transport fuel mix is evolving fast — and CNG infrastructure can be built in months, not years.

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Why This Matters for Gas Demand

Even at a conservative average of 2 MMscf/d per site, if a significant share of these 109 permitted stations are CNG-capable, they could add well over 150 MMscf/d of demand once operational. This is highly modular demand that can scale quickly, complementing larger, longer-lead projects.

CNG is only one part of the demand stack. Other confirmed and emerging gas consumers include:

• Aspin Energy / Escom Power Plant (Malawi) – 142 MW natural gas-fired plant using Tanzanian gas from March 2026 (~30 MMscf/d)

• Rocky Mountain GTL Plant – $420M gas-to-liquids facility producing diesel and jet fuel (~25–30 MMscf/d)

• ESSA Fertilizer Plant – Targeting 70 MMscf/d by 2027–2029, potentially supplementing Mnazi Bay supply

• Mtwara LNG Project – $4.5B state-backed export and regional distribution hub, starting at 400 MMscf/d and scaling to 1,200 MMscf/d, with Ntorya named as primary supplier

Taken together, these represent layered, long-term, and scalable demand — reducing offtake risk for upstream producers and creating multiple market channels.

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Aminex’s Strategic Position

For Aminex and its carried 25% interest in the Ntorya field, the convergence of infrastructure rollout and industrial demand is transformational:

• Fully carried to ~$40M net, removing capital burden in development

• Favourable PSA terms compared to industry norms, increasing effective revenue share

• Pipeline to Madimba under construction, de-risking first gas timelines

• Direct link to high-value offtake via Mtwara LNG and industrial markets

With scalable production — and the ability to grow beyond 280 MMscf/d — Aminex sits at the heart of Tanzania’s domestic energy transition and export growth ambitions.

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Investor View: More Than Just “Potential”

The EWURA permit wave is not an aspirational policy statement — it is a regulatory step that clears the way for real companies spending real capital on fuel and gas infrastructure. Add in signed EPC contracts, pipeline works, and the state-backed LNG plan naming Ntorya as a primary supplier, and you have tangible progress.

Near-term catalysts include:

• Physical confirmation of pipeline ground-breaking

• PURA approval to accelerate the Chikumbi-1 rig tender

• Additional industrial offtake agreements

With the current share price still below 2p, these could drive sharp re-ratings.

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Bottom line:
Tanzania’s downstream build-out, rising industrial gas prices, and LNG export positioning create a market capable of absorbing — and paying premium rates for — every molecule Ntorya can produce. For Aminex, the building blocks for a multi-year growth story are already falling into place.

Aminex Awakens: Fueling Tanzania’s Natural Gas Boom

 

Aminex PLC: At the Heart of Tanzania’s Gas Revolution

With booming domestic demand and a $4.5B LNG project citing Ntorya as a primary supply source, Aminex is poised for a transformational leap.

Aminex PLC is emerging as a quiet powerhouse in East Africa’s natural gas revolution, and recent developments suggest that the company may be significantly undervalued and underappreciated. With two major announcements shaking up the energy landscape in Tanzania, Aminex finds itself in a uniquely strategic position — one that could dramatically reshape its future and market perception.

Gas-Powered Public Transport: A Signal of Growing Demand

In a bold push toward sustainable urban mobility, Tanzania has welcomed the arrival of 99 new natural gas–powered buses — the first phase of a planned fleet of 755. These buses will serve Dar es Salaam’s expanding BRT network, with an additional 250 buses already confirmed for delivery.

This isn’t just about transport — it’s a strong signal from the Tanzanian government that natural gas is set to play a central role in the country’s energy strategy. This is the kind of demand surge that companies like Aminex, with proven gas reserves and infrastructure development underway, are perfectly positioned to meet. As public and private sectors transition toward cleaner energy, the local market for gas is heating up — and Aminex is right in the middle of it.

The Mtwara LNG Project: A Game-Changer

While the bus news is significant, the real game-changer is the newly announced Mtwara LNG project — a $4.5 billion mega-development with truly global ambitions. This isn’t a pipe dream. It’s a state-supported initiative involving key players such as Tanzania’s national petroleum corporation. And critically, Ntorya — the onshore gas field where Aminex holds a carried 25% interest — is listed as the primary supply source for this massive LNG and CNG infrastructure rollout.

The Mtwara project aims to start with 3 million tonnes per annum of LNG production (equivalent to around 400 million standard cubic feet of gas per day), scaling to 9 MTPA over time. It will serve both domestic and regional needs, with distribution hubs planned across Tanzania, Kenya, Zambia, the DRC, Mozambique, and beyond — even targeting exports to Asia. It’s a pan-African clean energy corridor with real momentum, and Aminex’s Ntorya field is the backbone.

Strategic Alignment and Market Potential

Put simply, Aminex is no longer just a junior energy company sitting on a gas discovery. It’s now a key player in Tanzania’s rapidly developing energy infrastructure — both for domestic consumption and international export. With its costs covered through carried interest, its resource positioned near the coast, and a state-endorsed demand engine forming around it, Aminex is ideally placed for long-term success.

For investors, this is a rare moment: the stars are aligning, and the market has yet to fully catch on. Aminex’s story is no longer just about proven reserves — it’s about strategic importance, national energy transformation, and regional opportunity.

As Tanzania turns up the heat on gas-led development, Aminex may well be one of the sector’s biggest beneficiaries.

💥 Why Aminex’s PSA Is Superior:

 

Lessons from PAET’s Disadvantageous Deal

One of the most overlooked factors in the energy investment space is the profit-sharing structure within Production Sharing Agreements (PSAs). A compelling comparison can be made between Aminex and Orca’s subsidiary Pan African Energy Tanzania (PAET)—and it shows just how advantaged Aminex really is.

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⚠️ PAET’s PSA: Complex, Outdated, and Unfavourable

The PSA signed in 2001 between the Tanzanian government and PAET is widely regarded as one of the most complex and least favourable ever agreed. It is not remotely comparable to the modern, commercially fair terms under which Aminex operates.

Here’s why:

❗Protected Gas: ~30% Given Away for Free

Under PAET’s PSA:

• PAET is required to supply up to 45.1 MMcf/d of “Protected Gas” to TPDC.

• This gas is given away at no revenue gain to PAET—TPDC provides it on a “no gain, no loss” basis.

• Result: Around 30% of PAET’s total production has generated no income in recent years.

⚙️ Step 2: Costs Are Recovered from Remaining Revenues

• PAET must recover all costs—even those related to Protected Gas and TPDC’s share—from the remainder of revenues.

• This shrinks profitability even further, especially in high-capex years.

💸 Step 3: Profit Sharing Still Favours TPDC

Even after costs:

• Profits are shared based on production tiers.

• At typical recent production rates (~85–95 MMcf/d), TPDC takes 45% of the remaining profit.

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📉 Despite These Challenges, PAET Made Money

To their credit, Orca/PAET has delivered shareholder value:

• 2021 Net Income: $16.37 million

• 2022 Net Income: $27.73 million

• 2023 Depletion Charge: $34.9 million (includes 3D seismic costs, not free-carried)

2024 was an unusual year due to operational disruptions (e.g., Songas shutdown), but in normal years, PAET still manages profitability—even under a flawed structure.

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🚀 Why Aminex Is Positioned for Stronger Returns

Now imagine all that without the burden. Aminex benefits from a simpler, more investor-friendly PSA, with multiple strategic advantages:

✅ Simple, Transparent Gas Pricing

• Aminex gas is sold at the wellhead.

• Different pricing tiers: power gas vs. industrial gas (with the latter commanding higher prices).

✅ No Free Gas Obligations

• No “Protected Gas” burden—100% of Aminex’s production will generate revenue.

✅ Strategic Financial Advantages

• No corporate debt dragging on profits.

• Free carry covers all development CAPEX (any unused portion gets paid to Aminex from ARA’s share).

• $115.7 million in tax losses can be used to offset future taxable income.

• $103.4 million intercompany loan (from Aminex to Ndovu) to be repaid tax-free, using future Tanzanian revenue.

NB the above is based on currently known PSA terms

From the pen of guest writer Ufufuo.

If I may say so, a nice piece that refutes a fair bit of nonsense that has been constantly spewed out on the boards when comparing Aminex to Orca and on occasion Wentworth.  To finish I wanted to clarify the accuracy and I asked an industry research model its opinion on the above. The results below...

✅ Confirmed Accurate

🟢 PAET PSA (2001) Complexity and Protected Gas

• Protected Gas obligations under PAET’s PSA are well-documented in Orca’s filings. PAET supplies up to 45.1 MMcf/d free of charge, reducing revenue-generating capacity.

• Cost recovery from remaining gas revenue is accurate, including TPDC’s costs.

• Profit gas split with TPDC up to 45% is consistent with Orca’s public disclosures.

🟢 Aminex PSA (Ntorya)

• The PSA for Ntorya is modern and post-2005, structured differently than PAET’s.

• Aminex is free-carried by ARA up to $140m, which covers seismic, drilling, and infrastructure.

• There are no protected gas obligations or government-imposed “no gain” provisions.

• Tax loss carryforwards of ~$115.7 million and intercompany loan to Ndovu of ~$103.4 million are disclosed in Aminex’s annual reports.

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⚠️ Partially Confirmed / Context Needed

⚠️ “100% of Aminex’s production will generate revenue”

• This is broadly accurate assuming current PSA terms persist, but future changes (e.g., TPDC back-in rights, new offtake agreements) could introduce deductions or allocations. Still, compared to PAET, the structure is materially more favourable.

⚠️ “Gas sold at wellhead” with two-tier pricing

• Aminex’s GSA terms are confidential, so while industrial pricing potential is real (and discussed at the AGM), we cannot confirm the pricing structure definitively. However, past statements have indicated potential for differentiated pricing (power vs. industrial).

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❌ No Material Errors Found

The post maintains a truthful, favorable comparison without exaggeration. It contextualizes Aminex’s financial positioning clearly and contrasts with the PAET PSA in a fair and fact-based manner.

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📝 Verdict

✅ Post is accurate and balanced.
🔍 Minor qualifications could be added (e.g., "based on currently known PSA terms") for extra precision.
💡 No misleading or exaggerated claims were detected.

Aminex AGM Signals Acceleration:

Aminex AGM Signals Acceleration: CH‑1 Before Pipeline, Phase 2 Plans, and Market-Ready Momentum

For me, this year’s Aminex AGM marked a fundamental shift—not just in tone, but in tempo.

For the first time in years, the Board spoke with conviction and clarity. No ambiguity. No hedging. Just a clear message: Ntorya is entering execution mode, and the drill is coming before the pipeline is complete!

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🔩 “CH‑1 Will Be Drilled Before the Pipeline Is Completed”

No hesitation. No caveats. That is now the base case.

The Board confirmed that all parties—TPDC, ARA, Aminex, and the Tanzanian government—are aligned and urgently pushing to get CH‑1 drilled. PURA’s involvement has been specifically to accelerate rig tendering.

Rig tendering is imminent. While a shared rig with M&P is being discussed, other rigs are in the running—and the Board made it clear that M&P’s timeline would be too late (mid‑2026). In other words: the M&P option may just be negotiation leverage.

Bottom Line:

• TPDC is “pushing like crazy”

• CH‑1 is on the clock

• Phase shift confirmed. Execution starts now.

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📈 CH‑1 Targeting 50 MMscf/d Flow Rate

The Board corrected the assumption of 20 MMscf/d per well:

“CH‑1 is expected to flow at ~50 MMscf/d.”

This well targets a thicker section of the reservoir with stacked pays, including Unit 3—making it much higher impact than NT‑2, which flowed 17 MMscf/d under constrained conditions.

A new CPR (Competent Person’s Report) is expected after CH‑1 or Phase 1 drilling, with upgraded reserves, production profiles, and valuation.

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💧 Condensate Could Add +15% to Project Value

The Board confirmed condensate volumes could deliver ~15% additional value—clean margin revenue, possibly hundreds of millions over the field’s life.

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💸 Gas Pricing Has Built-In Upside

Two key revenue drivers:

1. Inflation clause built into the GSA

2. Higher prices for industrial offtake vs. utility rates

With industrial gas demand rising in Tanzania, Aminex could see surprise upside on realised pricing.

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🔗 ARA Wants Aminex to Stay

Why hasn’t Aminex been bought out or diluted? The Board explained:

• ARA is happy with 75% and sees value in Aminex’s public listing

• The listing provides transparency, valuation, and investor reach

• If ARA wanted Aminex gone, it would’ve happened already

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🚀 Phase 2 Strategy: 280 MMscf/d or Bust

The operator isn’t stopping at Phase 1:

• 6 more wells planned

• Second pipeline to Madimba

• Expanded processing facility

“140 MMscf/d won’t adequately drain the field. 280 MMscf/d brings reserves into production within the license life.”

This is operator-led strategy, not speculative dreaming. Ntorya is being built as a national energy asset.

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🏦 Funding Runway + Cash Flow Timing

• Aminex has used ~50% of its facility, with ~$1.5m available

• Burn rate: ~$1.5m/year, so fully funded for 12 months

• First cash flow expected ~September 2026, once the pipeline is commissioned

Payments will be a mix of USD and Tanzanian Shillings.

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🧾 TPDC to Take 60 MMscf/d Initially

TPDC has committed to 60 MMscf/d of initial offtake, with the rest going to industrial customers. Virtual pipeline, LNG, CNG, mining, manufacturing are all in ARA’s strategy.

Demand is not a concern. Discussions are already underway.

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🧪 NT‑2 Test Still Going Ahead

Despite the focus on CH‑1, the NT‑2 well test is still scheduled before pipeline commissioning. It will confirm deliverability and gas composition (expected 3% CO₂ content—low and manageable).

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📌 TPDC Back-in Rights Still at 15%

The 15% back-in right has not been exercised yet, and that remains the limit under the PSA. Any change would be procedural and expected.

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🔍 Kiliwani, Nyuni, and Exploration Strategy

• Kiliwani is on hold, but still has potential. Seismic planned.

• Nyuni is “too risky” for now. Scale-down and partnership are in progress.

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📣 PR Reset and New Valuation Coming

The Board acknowledged past silence and promised a PR reset:

• Regular updates to resume

• Journalists engaged

• New Shard Capital valuation incoming—expected to be more bullish

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🧠 Final Word: It’s Not “If” Anymore

This AGM didn’t just confirm:

• CH‑1 before pipeline completion

• 50 MMscf/d flow potential

• Phase 2 expansion strategy

It changed the tone of the entire project.

We’re not asking if Ntorya will deliver.
We’re asking how fast, how big, and how long we stay invested.

The above report comes thanks to the attendance at the AGM by Prospero 

Ntorya Gas Deal: What Aminex Really Stands to Gain (Gas, Condensate & Long-Term Upside)

With pipeline construction set to begin and first gas targeted for mid-2026, Tanzania’s Ntorya gas project is entering full execution mode. For investors in Aminex PLC, now is the time to understand the full commercial picture—not just the gas volumes, but the growing revenue streams from condensate and long-term field expansion.

Here’s a breakdown of the key financial drivers and what Aminex’s 25% stake actually means in dollar terms.

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🧭 Who’s Involved—and What’s the Deal?

The Ntorya development is governed by a 25-year Production Sharing Agreement (PSA) and a long-term Gas Sales Agreement (GSA) signed in 2024. The parties include:

• TPDC: Tanzania’s national oil company; owns the pipeline and buys the gas.

• ARA Petroleum Tanzania (APT): Project operator with a 75% stake.

• Aminex PLC: Holds 25%, and is fully carried through development (≈$35 m net cost).

How the Revenue Works:

• 12.5% royalty goes to government off the top.

• 50% of the rest is used to recover costs.

• The remaining profit gas is split: a sliding scale gives the contractor 30–40%.

• Aminex gets 25% of the contractor's share.

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🔢 What Kind of Cash Flow?

At a baseline gas price of $3.00/MMBtu, Aminex could earn around:

• $1.4 million in Year 1

• $5 million+ annually by Year 5 as production reaches 140 MMscfd

But that’s not the only scenario. Here’s how cumulative 10-year returns change if gas prices climb.

📊 Gas Price Sensitivity

At $3.45 (the likely GSA price), Aminex could earn $42.6 million over 10 years. At $4.00, that rises to over $49 million.

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🔭 Long-Term Growth: 13 Wells, 280 MMscfd

The field development plan calls for up to 13 wells, targeting a potential production scale-up to 280 MMscfd over 10 years. This could double Aminex’s earnings versus the current 140 MMscfd model.

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🛢️ The Condensate Bonus (Based on $70 per Barrel)

Often overlooked is the valuable condensate discovered alongside Ntorya gas:

• ~3.5 barrels per MMscf based on Ntorya-1 test data

• Up to 20 million barrels in place

• Crucially, TPDC has no claim over condensate—meaning it can be sold at wellhead

At $70 per barrel, condensate alone could earn Aminex nearly $900,000 in Year 1, growing to $3.1 million annually as output scales.

📊 Condensate Revenue Forecast

📌 Note: condensate prices fluctuate based on oil markets, refining demand, and local offtake capacity.

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✅ The Big Picture for Aminex

• Gas: Low-risk, long-term earnings with development costs covered

• Condensate: Pure upside on top of core returns

• Expansion: Real potential to double revenues as new wells are drilled

For a company with modest G&A costs and no debt-linked development risk, Ntorya offers Aminex a rare mix of stability and optionality in a frontier gas economy.

TPDC Construction Launch Signals Green Light for Ara / Aminex Ntorya Development

Pipeline Momentum Builds as Dry Season Window Opens

With the EPC contract for the Ntorya–Madimba pipeline formally awarded in early July 2025, attention now shifts to execution—and there are growing signals that construction is set to begin imminently, taking full advantage of Tanzania’s current dry season.

⚙️ Operational Readiness: More Than Just an Announcement

While markets welcomed the EPC award with a sharp share price jump, the underlying operational reality suggests far deeper progress than the announcement alone implies. Aminex and its joint venture partner ARA Petroleum Tanzania (APT) appear to have methodically prepared for this moment over the past several months.

• Drilling infrastructure is already in-country: Pipework is stored at one of the Ntorya well sites, and the wellhead for the key Chikumbi‑1 (CH‑1) well has been ready for shipment for some time.

• The field development sequence is optimised and staged: NT‑2 will be the first well connected, using mobile testing equipment (no rig required), followed by drilling CH‑1, and later a rig-based workover of NT‑1 using the same equipment.

• This sequencing minimises logistical overlap and supports the planned ramp-up of production toward 140 MMscfd over the medium term.

🛠️ EPC Mobilisation: Signals Point to Immediate Start

Although the formal EPC announcement came in July, a series of operational indicators strongly suggest that mobilisation has been underway behind the scenes for some time:

• The rapid commencement of contractor recruitment for local positions within days of the announcement indicates that staffing plans were prepared well in advance.

• This is consistent with infrastructure projects where preferred bidders, once informally selected, often begin early-stage logistics, equipment procurement, and site planning before the formal signing—especially when delivery windows are tight.

• The public commitment to completing the project within 12 months adds weight to this view. Such a timeline would not be credible without supply chain arrangements already in motion and construction strategies finalised.

In short, while the market may only now be digesting the announcement, the project itself appears to be months ahead in planning, and construction is likely to commence during this dry season—between late July and September 2025.

🌧️ Why Not Wait?

Delaying construction into Q4 would push key trenching and infrastructure work into Tanzania’s rainy season, increasing costs and operational risk. That would conflict with the EPC contractor’s guarantee of delivery within a 12-month window—making it far more rational to act now, while ground conditions are favorable.

Additionally, well logistics, permits, seismic studies, and land access issues are largely resolved, meaning that the path is clear for field execution.

📈 Market Implications: A Potential Re-Rating Catalyst

Should Aminex or the EPC contractor formally announce mobilisation in the coming weeks—whether via photos, press updates, or site commissioning—it could act as a major share price catalyst, adding to the already strong momentum from the EPC award.

Historical market behaviour suggests such a trigger could generate a further 10–20% upside in the near term, as it would materially de-risk the timeline to first gas in 2026.

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✅ Final Word

With project hardware in-country, well sequences defined, and staffing underway, Aminex and ARA appear strategically positioned to begin construction within the current dry season. For shareholders and market watchers, the next catalyst is clear: physical mobilisation on the ground. And by all indications, that milestone may be just days or weeks away.

Walking a Mile in ARA's Shoes - Strategic Rationale for Retaining Aminex PLC in the Ntorya JV

Here’s a strategic rationale written as if from ARA Petroleum Tanzania’s internal planning team, arguing for maintaining the current JV structure with Aminex PLC, emphasizing the benefits of Aminex’s London market presence:

📄 Strategic Rationale for Retaining Aminex PLC in the Ntorya Joint Venture

Prepared by: ARA Petroleum Tanzania – Strategic Planning Unit
Date: July 2025

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1. Capital Market Access & Optionality

Aminex’s listing on the London Stock Exchange provides the Ntorya JV with indirect access to one of the world’s most liquid and reputable capital markets. This offers multiple strategic advantages:

• Enhances visibility of the project to institutional and retail investors.

• Preserves optionality for future fundraising—whether for downstream integration, exploration expansion, or reserve monetisation.

• Provides a clear public valuation benchmark for our asset base through Aminex’s market capitalization and disclosures.

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2. Governance, Transparency & Investor Confidence

The London listing mandates high standards of financial reporting, ESG compliance, and corporate governance. As a result:

• Aminex strengthens the JV’s perceived integrity and regulatory alignment, both domestically and internationally.

• Transparent public disclosures de-risk the JV in the eyes of financiers, multilateral institutions, and host governments.

• Enhanced transparency provides reassurance to the Tanzanian Petroleum Development Corporation (TPDC) and other local stakeholders.

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3. Geopolitical Diversification & Host Country Comfort

Retaining a Western-listed partner brings geopolitical balance to the JV, providing:

• Greater international confidence in the project’s operational structure.

• A “dual footprint” approach that aligns with host government interests in balancing foreign investment across regions (Middle East, Europe, Africa).

• Increased credibility with development finance institutions and bilateral aid agencies exploring gas infrastructure support in East Africa.

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4. Exit Optionality & Capital Efficiency

Aminex’s presence in the JV:

• Offers ARA long-term strategic flexibility, including potential monetisation of stakes via reverse takeovers, secondary offerings, or spin-offs.

• Allows for capital-light development, given Aminex’s cost-carry arrangement and minimal capital exposure during early ramp-up.

• Keeps ARA’s balance sheet flexible, with the ability to scale operations without assuming full ownership risk at this stage.

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5. ESG and Institutional Alignment

Through Aminex, the JV gains exposure to ESG-conscious investor groups and reporting frameworks, including:

• Task Force on Climate-Related Financial Disclosures (TCFD)

• UN Sustainable Development Goals (SDGs)

• Local stakeholder engagement protocols under LSE guidelines

This strengthens the project’s profile among:

• Sovereign lenders (e.g., AfDB, World Bank)

• Global investment funds pursuing sustainable energy in Africa

• Local regulators focused on responsible energy development

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Conclusion

Maintaining the current JV structure, with Aminex as a 25% non-operating partner listed on the London Stock Exchange, strategically benefits ARA Petroleum Tanzania in multiple dimensions: capital flexibility, regulatory alignment, stakeholder confidence, and future monetisation. These outweigh any perceived advantages of immediate consolidation. We recommend continuing and deepening the partnership during the upcoming pipeline and production ramp-up phases.

Aminex - Addressing the buyout question!

 

🔍 Factors suggesting a buyout is unlikely in the near term

1. Funding and Carry Arrangements

   • The current structure includes APT carrying Aminex’s share of development costs (approx. USD 35 m net), with no further capital required from Aminex for phases up to mid-2026 Aminex remains capital-light and focussed on production ramp-up, which removes immediate financial pressure to sell its stake.

2. Strategic Alignment and Joint Upside

   • Aminex benefits from a secure funding structure while retaining upside as production ramps from ~40‑60 MMscfd to a potential 140 MMscfd 

   • APT carries the operator risk but by keeping Aminex onboard, it maintains JV partners aligned on field development.

3. No Reported Negotiations or Valuation Discussions

   • Searches reveal no credible sources indicating acquisition talks or intentions by APT to buy out Aminex.

   • APT’s ambitions seem focused on developing and expanding operations—not consolidation of ownership.

4. Supportive Government & Shared Milestones

   • The Tanzanian government and TPDC have been supportive of the current JV structure, including awarding the 25-year development licence to the JV

   • This suggests no pressure to restructure or transfer equity at this stage.

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✅ What might change this dynamic?

Trigger Event	Possible Impact
Aminex funding constraints	If future phases require more capital and carry arrangements lapse, Aminex might be open to sell.
APT’s strategic expansion	If APT wants full operational control to pursue aggressive field development, it could approach Aminex.
Valuations change significantly	APT might buy low if Aminex’s share-price drops or reserves valuation mismatches emerge.
Regulatory or lender pressure	Lenders or authorities might prefer a single, controlling operator if it simplifies governance or financing.

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🧮 Estimated probability (qualitative)

• Near-term (next 12–18 months): Low (< 20%)

  • The current JV structure is financially and operationally stable; no signs point to a takeover.

• Medium-term (2–4 years): Moderate (20%–40%)

  • Once production is established, and if additional wells require new investment or JV alignment, APT might consider consolidation.

• Long-term (5+ years): Higher (40%–60%)

  • As the field matures and ramp-up continues, appetite for full ownership could increase, depending on field economics and strategy.

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📌 Summary

There’s currently no concrete evidence of negotiations or intent for APT to acquire Aminex’s stake. The relationship is financially beneficial for both—Aminex retains upside with minimal outlay, while APT maintains operational control. In my view:

• Unlikely in the short term (< 20%).

• Possibly in the mid-to-long term if strategic or financial drivers change.

Would you be interested in exploring scenarios where a buyout could occur—such as valuation triggers or financing gaps—or comparing it to similar JV arrangements in the industry?

EPC Award and why it matters

📈 Why this EPC award matters

On 3 July 2025, the Tanzania Petroleum Development Corporation (TPDC) officially awarded the Engineering, Procurement & Construction (EPC) contract for the 35 km pipeline from Ntorya to Madimba to China Petroleum Pipeline and China Petroleum Technology & Development Corporation

• Aminex holds a 25% non-operated interest in the Ntorya project, alongside partner ARA Petroleum Tanzania (APT) 

• The pipeline is designed with a capacity of 140 MMscfd, aligning with the Ntorya Field Development Plan (FDP) 

• The award follows major milestones in the past 18 months:

  • 25-year development licence granted

  • Gas Sales Agreement signed in January 2024

  • Updated FDP and 3D seismic campaign affirming ~1.8 tcf proven reserves, with up to 16 tcf GIIP potential

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Market reaction & strategic edge

• Shares surged by ~40% on the news, reflecting investor optimism and the government’s visible commitment

• Resting on zero net development cost (covered by a carry arrangement through ~$140 m gross capex, $35 m net to Aminex) and with a $3 m working capital facility, Aminex is well-positioned financially 

• Significantly, the EPC award de-risks the path to first gas, turning scattered milestones into one coherent execution plan.

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What happens next? 🚧 Timeline & next steps

1. Pipeline construction (mid‑2025 to mid‑2026)

• Engineering, procurement, and construction by Chinese firms commence imminently following the award

• Expected completion by mid‑2026, in time to match forecasts from the 2024 Annual Report

2. Well commissioning and start-up

• Once ready, Ntorya‑2 (NT‑2) will be hooked into the pipeline for gas production

• Next in sequence:

  • Workover of Ntorya‑1 (NT‑1)

  • Drilling of Chikumbi‑1 (CH‑1)

• Initial gas output projected around mid‑2026, at 40–60 MMscfd, ramping to ~140 MMscfd within a few years

3. Long-term phased development

• The FDP envisages up to 14 new wells over the next decade, with target production rising to 280 MMscfd

• Capital will be funded through the existing carry and future Ntorya revenues—no extra shareholder funding expected 

4. Monetisation & gas sales

• Gas sold under the January 2024 GSA with TPDC ensures offtake security 

• Ethically and strategically important: The gas supports Tanzania’s domestic power, industrial, and cleaner cooking needs.

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Outlook for Aminex & ARA

Aminex PLC

• Shareholder value looks promising: Cashflow from first gas (mid‑2026), financed capex, low capex outflows, and significantly de-risked development path.

• The company expects positive cash flow post mid‑2026 and is operating with efficient overheads (US$1.59 m G&A) 

• Growth beyond the early phase—additional wells could unlock further reserves and revenues.

ARA Petroleum Tanzania (APT)

• As operator, ARA drives the project execution, well expansions, and stakeholder engagement.

• Gains credibility from delivering on its FDP, likely to aid future Tanzanian projects.

• Success here cements its operational credentials in East Africa.

Together (Aminex & ARA)

• They stand to benefit from increased gas volumes, line utilisation, and phased development upside.

• Successful delivery builds investor and governmental confidence, opening doors to further JV opportunities.

• On the flip side, they must vigilantly manage execution—pipeline builds, drilling risks, commodity price volatility, and regional policy shifts.

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Key risks to monitor

• Engineering delays or cost overruns on the pipeline—though Chinese EPC firms are credible contractors.

• Drilling hiccups: CH‑1, NT‑1 workover could face technical setbacks—impacting ramp-up timelines.

• Gas pipeline commissioning and tie-in: Complex logistics, regulatory approvals, and local coordination may pose delays.

• Gas price dynamics: Though under GSA, profit margins hinge on price stability and local consumption growth.

• Funding beyond carry: While early phases are financed, scaling to 14 wells may need additional capital down the line.

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Summary (≈ 100 words)

With the EPC award for the Ntorya–Madimba pipeline secured, Aminex and ARA have unlocked execution for first gas, expected mid‑2026. Financially streamlined, with capex largely carried, Aminex is set to benefit from ramping gas production under a secure offtake agreement. ARA, as operator, leads delivery and sets the stage for future growth. If construction and drilling proceed smoothly, both stand to capture significant value from Tanzania’s growing gas market. Key next steps: track pipeline completion, NT‑2 commissioning, CH‑1 and NT‑1 operations, and progressive drilling through the FDP.

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🔍 What happens next

• Mid‑2025 to mid‑2026: Pipeline built; NT‑2 tied in; first gas flows begin.

• H2 2026 onward: CH‑1 drilled, NT‑1 reworked; production ramps to 140 MMscfd, scaling toward 280 MMscfd.

• 2027+: Phased drilling unlocks full field ambition. Additional wells generate growth and monetisation.