Company glossary — PetroNor E&P
Terms and acronyms specific to PetroNor. Project-wide vocabulary lives in CONTEXT.md.
WI
Working interest. PetroNor's economic share of the PNGF Sud licence: 16.83%, held indirectly — subsidiary HEPCO owns a 20% licence interest, and PetroNor's effective share of that is 16.83%. "Net WI production" = gross field production × 16.83%.
PSC
Production sharing contract. The licence agreement with the Congolese State that governs how each barrel is split between the State and the contractors. See Entitlement ratio.
Tax gross-up
An accounting-presentation trap: the cash flow statement shows "Income taxes paid" of ~$31M (2025), but no tax cash leaves the company — the Congo tax is settled in oil (tax oil), and the accounts inflate revenue by its value and show the same amount as tax paid, netting to zero. The Norwegian parent pays no recurring cash tax (holding company; only one-off, e.g. the 2023 Guinea-Bissau sale gain). In the economic view, tax = the State's barrels, already inside the State's take.
Royalty
The State's first bite: a fixed 15% of gross production, paid in kind (oil, not cash).
Cost oil
Barrels allocated to contractors to recover their investments and operating costs under the PSC. More capex (e.g. infill campaigns) → more cost oil to the contractor side for a while → higher entitlement ratio. Statutory ceiling: 50% of production (Congo Hydrocarbon Code 2016, art. on "cost stop"); our reconstruction peaked at ~40% (2023), so the cap has never bound.
Profit oil
Barrels remaining after royalty and cost oil, split between State and contractors per the PSC. Super profit oil: when oil prices exceed contractual thresholds, the State's share of profit oil increases. Corporate income tax is settled entirely through the State's profit-oil share — no cash tax is paid ("tax oil").
Theta (θ)
The State's share of profit oil — of every 100 profit-oil barrels, the State takes θ×100, PetroNor keeps the rest. Not disclosed anywhere public; solved from reported history ("which θ makes the formula match the actuals?").
Recalibrated 2026-08-29 on 14 quarters (2023 Q1 – 2026 Q2) rather than five annual figures: base 0.435, range 0.375–0.495, measured on the accounts basis. The quarterly reconstruction lands within 5.2%, and inside 3% for most recent quarters.
It does not move much with price. Across those quarters θ correlates −0.214 with the oil price — if anything slightly negative. Super profit oil exists (the company states the State's share rises above certain price thresholds) and the best fit puts it near $94/bbl worth +0.04 on θ; that is carried because the mechanism is stated, not because the data demands it, since it improves the fit by 0.13 percentage points. What θ had really been absorbing is cost recovery — see the cost-pool rule there.
Entitlement oil
The oil that is PetroNor's to lift and sell after the State has taken royalty, tax oil, and its profit-oil share in kind. Builds at the Djeno terminal between liftings — the company guides ~100k bbl/month, but the rate depends on the oil price: Q2 2026 built only ~60k/month at a $116 realisation, against ~101k/month in Q1, because a high price shrinks both cost-oil barrels and PetroNor's share of profit oil.
Entitlement ratio
Entitlement oil ÷ net WI production — the observable summary of the whole fiscal take. Not a model driver: it is computed from the PSC mechanics (decision 2026-07-22):
> entitlement = WI production − 15% royalty − θ × profit oil, where cost oil = (opex + capex) ÷ realized price, profit oil = production − royalty − cost oil, and θ is the State's profit-oil share — itself a function of the price (see theta).
Observed quarterly history on the accounts basis (2023 Q1 → 2026 Q2): 50.5% to 70.1%, averaging 59.7%, with the most recent quarter — Q2 2026, at a $116 realisation — the lowest of the fourteen at 50.5%. The moves track cost recovery far more than price: across those quarters the State's share correlates −0.214 with the oil price and +0.386 with the cost-oil share. Watch the quarterly build vs the computed value — a persistent gap means θ or the cost-recovery timing needs recalibration. Note: the swinging effective tax rate in annual reports (38% in 2025 vs 20% in 2024) is a lifting-timing artifact, not a fiscal change — tax accrues on production while revenue books on lifting.
One basis now. Entitlement, royalty, opex and capex all come from the consolidated accounts, which carry the licence's full 20% interest; the production disclosure is PetroNor's 16.83% economic share. Since 2026-08-29 the model grosses production up so the whole calculation sits on the accounts basis, and the minority's 15.85% is removed once, visibly, in the earnings. On that consistent footing the observed ratios are 50.5–70.1%, averaging 59.7% — the figures above, computed across the two bases, read about 19% high.
Lifting
A cargo sale of accumulated entitlement oil — PetroNor sells one to two cargoes per year (via a lifting contract with ADNOC), which is why reported revenue is lumpy while production is steady (project-wide: see ADR-0005). Overlift: lifting more than accumulated entitlement (borrowing against future entitlement) — the record April 2026 lifting of 964,593 bbl included >500k bbl overlift, repaid from subsequent monthly entitlement build.
bopd
Barrels of oil per day. bbl = barrel; MMbbls = million barrels; mmboe = million barrels of oil equivalent (includes gas converted to oil terms).
2P / 1P / 3P
Reserve confidence classes: 1P proved, 2P proved + probable (the standard planning number), 3P proved + probable + possible. Reserves are decision-conditional, not geological: 2P counts only barrels recoverable under development already sanctioned and paid for — when a new infill campaign is decided, volumes move from 2C into 2P (Litanzi 2019, Tchendo, Tchibeli, Tchibeli NE, Tchibouela East all converted this way, at ~$11/bbl added). 2C: contingent resources — discovered, technically recoverable volumes waiting on a development decision (PNGF Sud net 2C: 7.2 MMbbls; PNGF Bis: 2.1; Aje's 70.1 mmboe net is 2C since the 2025 reclassification, which is why the model values it at zero). PetroNor net 2P at PNGF Sud: 14.6 MMbbls (31 Dec 2025, audited by THREE60 Energy) — replacement ratio 93% in 2024 (five wells sanctioned), 14% in 2025 (nothing sanctioned), ~250% cumulative since 2017: the floor moves when capex moves it.
PNGF Sud
The producing licence complex offshore Congo-Brazzaville (fields incl. Tchibouela, Tchibouela East, Tchibeli, Litanzi): ~2.3 bn bbls in place, ~500 MMbbls recovered to date, gross production ~31,000 bopd. Licence group (Tchibouela II, Tchendo II, Tchibeli-Litanzi II) awarded January 2017 for 20 years — runs to 2037, beyond the model window and the 2P reserve life. Operated by Perenco (PetroNor is non-operator). PNGF Bis: adjacent undeveloped licence opportunity. Djeno terminal: the onshore terminal where entitlement oil accumulates.
HEPCO
Hemla E&P Congo SA — the subsidiary holding the 20% PNGF Sud licence interest. Hemla Africa Holding (HAH): PetroNor's 100% indirect subsidiary and majority owner of HEPCO — HAH is the entity indicted by Økokrim.
Økokrim
The Norwegian National Authority for Investigation and Prosecution of Economic and Environmental Crime. In January 2026 indicted Hemla Africa Holding for suspected corruption committed in Congo by individuals formerly associated with the company — and simultaneously dropped the suspected market-manipulation charges against PetroNor. Company categorically contests. Court commences 23 Nov 2026; initial outcome expected Q1 2027; appeals could extend to Q4 2028. Separate matter: the US DoJ inquiry into the same complex was closed with no action.
Guinea-Bissau earn-out
PetroNor's contingent asset from selling the Sinapa (Block 2) and Esperança (4A & 5A) exploration licences to Apus Energia (completed Dec 2023): USD 30M on government approval of a Field Development Plan + USD 30M on continuous production. Apus drilled Atum-1X (Sept 2024) — no commercial discovery announced; carried at USD 1.88M fair value (31 Dec 2025). Valued at zero in the model; tracked in the dossier.
OML 113 / Aje
PetroNor's Nigerian licence containing the Aje field — a gas-weighted redevelopment project (500 BCF gas + condensate/LPG/oil, 70.1 mmboe net 2C after the New Age acquisition). Interest structure: 20.89% participating, 52.2% cost-bearing, 39.17–52.2% economic. Not producing meaningfully; advisor appointed 2026 to find "commercial options" (a sale). Valued at zero in the model (policy recorded in the dossier's contingent-assets section), along with the USD 10M share-settlement receivable from the 2023 Aje restructuring.