Petroleum Project Cash Flows

To evaluate the economics of an upstream project, the first step is to construct a cash flow model that spans the entire life of the project. In simple terms, a cash flow model provides insights into the funds required to operate the venture and the revenue it generates. The model relies on specific inputs to produce economic indicators as outputs.

The process of forecasting cash flows involves estimating various components of cash inflows and outflows, which are discussed below:

• Cash inflows primarily consist of revenue and tariff income.
• Cash outflows include expenses such as capital and operating expenditures, royalties, taxes, bonuses, government profit shares, and other related costs.

In essence, cash flow is calculated as the difference between total cash inflows and total cash outflows.

Gross revenue consists of the sales proceeds from crude oil, natural gas, and condensates. It may also include tariff income generated from sharing infrastructure, such as pipelines or production facilities. Revenue is simply the product of hydrocarbon volume and sales price. To estimate revenue over the life of a field, it is necessary to forecast the production volume (or rate) for each period and project the market prices of oil and gas.

Production forecasts are determined by reservoir engineers and geologists, who provide the economist with a production profile, which is a time series of production volumes or rates over time. This production profile can also be understood as a revenue profile.

Typically, the production curve of a field follows three key phases. In the early phase, as drilling progresses, the production rate increases, resulting in an upward-sloping production curve. After a certain point, the production rate stabilizes or stops increasing. This middle phase, known as the plateau, does not last long unless additional wells, called incremental wells, are drilled to sustain production. Following the plateau, the production rate begins to decline as reservoir pressure decreases. This decline phase continues until production becomes uneconomical, at which point the field is either shut down or abandoned.

A standard production curve demonstrates these phases clearly. At the start, production ramps up as drilling progresses. Once all wells have been drilled, production stabilizes during the plateau phase. Over time, as reservoir pressure declines, the production rate decreases, marking the beginning of the decline phase. 

The production profile generated by the Geology and Geophysics (G&G) department cannot be estimated with complete certainty. There is always an element of uncertainty and risk associated with the reserve volumes and their profile. This is because the volumes deep within the Earth's crust cannot be physically verified until the hydrocarbons are actually produced.

There is often a range of possible outcomes when estimating reserves. Typically, the oil and gas industry categorizes reserves into three levels of confidence, based on the probability of occurrence. These categories are Proved, Probable, and Possible.

Upstream projects may also generate income from sources other than direct hydrocarbon sales. One such source is tariff income, which is derived from sharing production, processing, or transportation infrastructure with another company. In this case, the company using the facilities pays a ‘rent’ to the owner company. The rental fee is usually based on the volume of crude oil or gas handled by the owning company. Tariff charges are determined through negotiations between the company that owns the infrastructure and the company utilizing the facilities.

Sometimes, the tax implications of tariff income can complicate the economic analysis, particularly when the third party paying the tariff to the owner company is the same company. This situation, known as "self-to-self" tariffing, is not uncommon and can occur in certain circumstances.

For example, let’s consider a scenario where Company A has a 40% working interest in Field X and a 35% working interest in Field Y. Company A may use the processing facilities and pipelines of Field X to process and transport crude oil from Field Y. In this case, Company A would be paying a tariff to itself, which complicates the financial and tax analysis.

Another potential source of cash inflows is payments received from selling an interest in a project, also known as a "farm-out" or acquisition price.

A price forecast is essential for estimating revenue from crude oil and gas sales. Forecasting oil and gas prices is a challenging task due to the many factors that influence crude prices, ranging from supply and demand dynamics to geopolitical events. While previous price trends and estimates of future scenarios serve as a basis, price projections can span up to 20 to 30 years.

Typically, economists use various price scenarios, or "decks," for price forecasts, such as $50/Bbl, $60/Bbl, $80/Bbl, and $100/Bbl, assuming these prices remain flat (constant) over the project life. Price escalators are then applied to adjust these price scenarios to reflect the notional price on the day of analysis.

In some cases, a price differential may also need to be forecasted. Lower-quality crude oil may be sold at a discount to the benchmark market price, or it could command a premium. The price differential is typically based on the quality of the crude oil compared to the benchmark, such as WTI (West Texas Intermediate) or Brent.

For instance, if a crude oil is traded based on the Brent price but is of lower quality than Brent crude, its price will be adjusted downward according to a price discount. This discount, or potentially a premium, can be determined by a formula that links it to specific parameters of the crude quality.

 Oil prices are largely set in the international market, while gas prices are primarily determined in the local market. This difference is straightforward to understand. Unlike oil, gas is not easily transported without incurring significant costs, making it "stranded" at the location of discovery. Additionally, gas prices are often based on long-term contracts, which is another factor to consider when making gas price assumptions.

Next, we focus on the items that cause cash to flow out of the business or project. These costs are typically divided into technical costs and fiscal costs. Technical costs include items such as capital expenditures (CAPEX) and operating expenditures (OPEX). Fiscal costs, on the other hand, include royalty payments, bonuses to the government, taxes, and a share of profit oil.

The facilities and process design will dictate the actual property, plant, and equipment (PPE) required for the development and production of crude oil, gas, or both. The development plan established during the exploration and appraisal phases of the project may be preliminary and high-level. However, as the project moves from exploration to development, these plans will become more detailed, realistic, and accurate in terms of cost projections. During the development phase, various options will be analyzed, and economic models will be run to determine the most efficient path forward to maximize the project's value, measured by Net Present Value (NPV). Below, we discuss these technical and fiscal costs in more detail.

Cost estimates for both capital investment (CAPEX) and day-to-day operating costs (OPEX) are made at several stages throughout the project’s lifecycle. These estimates are regularly updated as engineers gain a better understanding of the project, drawing on both the available data and their previous experiences. The quality and accuracy of these estimates depend on the information available, as well as the expertise and experience of cost engineers.

CAPEX refers to expenditures related to physical infrastructure such as platforms, production facilities, pipelines, and wells. These costs are associated with the installation of hardware in the field. Typically, CAPEX is incurred before production starts and during the early phases of the project’s life. From an accounting perspective, any expenditure that creates an asset with a useful life of more than one year is considered a capital expenditure and is capitalized.

A typical OPEX profile for a project is shown above. It is important to note that there are no OPEX costs incurred before the start of production (i.e., prior to period 4).

Abandex refers to abandonment capital. Once a project reaches the end of its economic life, the site must be restored. Restoration or decommissioning costs may be incurred even before the project officially ends, often several years before its economic life concludes. In most cases, the contracting company is legally obligated to close and restore the operational site to its pre-existing condition. While in certain scenarios—particularly under Production Sharing Contracts (PSC)—the ownership of facilities lies with the government, the responsibility for site restoration usually ends up with the contractor.

Costs incurred for making abandonment provisions are generally tax-deductible. However, if actual abandonment occurs toward the end of the project when taxable revenue may not be sufficient to offset the costs, governments may either provide tax credits (refunds) or allow contractors to claim tax benefits at the time they start allocating funds to an abandonment relief fund.

Regardless of tax implications, Abandex is a cash outflow item that typically occurs during the last economic period of the project. Estimates for Abandex are usually prepared collaboratively by the finance and operations departments. The detailed economics of abandonment will be discussed in a separate session later.

In the early phases of a project, abandonment may not significantly impact project economics due to the heavy discounting effect of future cash outflows. However, as the project nears the end of its life, abandonment costs can become a more important factor in determining value.

In addition to CAPEX, OPEX, and Abandex, projects also incur extra costs that must be factored into cash flow calculations.

Royalty, bonus payments, taxes, and sometimes the government’s share in profits are considered fiscal costs from the contractor’s perspective.

• Royalty is a payment made on the revenue generated from oil and gas production, calculated as a percentage. This percentage may either be fixed or variable, linked to the production rate.
• Bonus payments may be due to the government at specific milestones, such as upon signing the contract and/or when production reaches certain levels.
• Taxes are levied on the project’s "Taxable Income."