Oil Gas Upstream Model

The model's operating engine starts with gross production split across crude oil, natural gas, and natural gas liquids. Crude and gas volumes follow a hyperbolic decline profile, where an initial production rate and a curvature factor determine how quickly output falls over time.

• New wells are added through a drilling schedule, while legacy wells decline continuously, so reported volumes combine both. Net revenue interest then converts gross volumes into the net share the company actually sells.
• Each commodity is priced separately. Realised prices begin with benchmark references such as WTI or Henry Hub, adjusted by basis differentials that reflect transportation and quality.

NGLs are typically priced relative to crude or a composite barrel. This layered approach means small changes in drilling pace, decline assumptions, or differentials can materially shift the revenue outlook.

Costs are modelled in two broad groups. Variable costs include lease operating expenses, gathering and transportation fees, and severance taxes, all of which scale with production or revenue.

• Because much of LOE is fixed per well, unit costs tend to rise as wells age and volumes decline. G&A and exploration expenses sit at the corporate level.
• On the capital side, drilling and completion spending drives the well schedule, with maintenance capex needed simply to hold production flat and growth capex adding incremental volumes. Depletion is handled through the unit-of-production method, tying DD&A to remaining reserves.

The debt schedule captures reserve-based lending drawdowns, repayments, and interest, which feeds both the income statement and the cash flow statement.

The income statement moves from revenue through operating costs, DD&A, interest, and taxes to net income, with EBITDAX shown as a key industry metric. The cash flow statement then follows the indirect method, adjusting net income for non-cash items such as depletion and working capital changes, and separating operating, investing, and financing activities.

• Free cash flow is simply operating cash flow less total capex. For valuation, the model calculates a net asset value using discounted cash flows over a defined horizon, with a terminal value annuity capturing the long tail of production beyond the explicit forecast.
• Discounted at a specified rate, this yields a PV-10 style metric. A balance sheet and validation checks sit alongside, ensuring that assets equal liabilities and equity and that production reconciles to the sum of legacy and new wells.

In practice, the template is used to test how commodity prices, drilling pace, and cost inflation interact over a five-year forecast and beyond. The multi-year price deck allows each year to carry its own benchmark price and basis differential, rather than assuming a flat price forever.

• Key relationships worth noting: net production equals gross production times NRI; net revenue equals net production times realised price; DD&A equals net book value divided by remaining reserves, multiplied by period production; and debt-to-EBITDAX provides a leverage check against covenant limits.
• These relationships make the model sensitive to assumptions about decline rates, capital efficiency, and fiscal terms, helping users evaluate whether an asset can generate sufficient cash flow to justify development or acquisition.