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?"). Calibrated 2026-07-22: base 0.32, range 0.22 (friendliest observed) to 0.46 (toward the 2022 high-price spike of 0.52). The single most uncertain number in the model — its range is a main source of the projection spread.
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 (~100k bbl/month as of early 2026) between liftings.
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 ≈ 0.38 is the State's calibrated profit-oil share.
Observed history (entitlement ÷ WI production): 2021: 64.7% · 2022: 61.3% (high price → State super-profit share) · 2023: 74.0% (infill capex → cost oil recovery) · 2024: 68.4% · 2025: 70.4% · Q1 2026: 71.5%. Every move is explained by price (up → ratio down) and capex (up → ratio up). 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.
Cost lines
The three cost rows in the report tables — Operating expenses, Administrative expenses, Capex paid — named after the company's own statement lines so a bold cell can be checked against the PDF word for word. Where each is fetched from:
- Operating expenses — the earnings table (cost-of-sales note, "Operating expenses" line): the cost of running the fields. Booked when the work happens, not when the bill is paid.
- Administrative expenses — the earnings table (income-statement line): salaries, legal, travel, office. Also booked when incurred.
- Capex paid — the cash flow statement ("Purchases of property, plant and equipment"): investment money that actually left the account. Capex never appears as a cost in the earnings table — only later, sliced into depreciation over years.
All three are cash-natured: nothing non-cash (depreciation, impairments, lifting-timing bookkeeping) is inside them. Opex and admin are accrual-timed; the gap between booked and paid lands in the report's "working capital & other" line — the plug that reconciles to the disclosed cash balance in reported quarters. Depreciation appears nowhere in the model, deliberately: its job (spreading investment over time) is done by the model itself, which sees each year's actual capex. (Opex = operating expenditure; capex = capital expenditure.)
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. 2C: contingent resources — discovered volumes not yet commercial (Aje's 70.1 mmboe net is 2C, 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).
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. 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 per the thesis, along with the USD 10M share-settlement receivable from the 2023 Aje restructuring.