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, this cash flow model provides insights into the funds required to operate the venture and the revenue it generates, which is crucial for understanding upstream project economics. The model relies on specific inputs to produce economic indicators as outputs.

The process of gross revenue forecasting 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, playing a crucial role in gross revenue forecasting for upstream project economics. It may also include tariff income generated from sharing infrastructure, such as pipelines or production facilities. Revenue is simply calculated as the product of hydrocarbon volume and sales price. To estimate revenue over the life of a field, it is essential to forecast the production volume (or rate) for each period and project the market prices of oil and gas, which is a vital component of any cash flow model.

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, which introduces an element of uncertainty and risk into the cash flow model associated with reserve volumes. This uncertainty arises because the volumes deep within the Earth's crust cannot be physically verified until the hydrocarbons are actually produced. When it comes to gross revenue forecasting, there is often a range of possible outcomes when estimating reserves. The oil and gas industry typically categorizes reserves into three levels of confidence, based on the probability of occurrence: Proved, Probable, and Possible, all of which play a crucial role in upstream project economics.

Upstream project economics may also generate income from sources beyond direct hydrocarbon sales. One such source is tariff income, which contributes to the cash flow model by sharing production, processing, or transportation infrastructure with another company. In this scenario, the company utilizing the facilities pays a ‘rent’ to the owning company. This rental fee typically depends on the volume of crude oil or gas handled, and tariff charges are established through negotiations between the owner of the infrastructure and the company making use of the facilities, which can also play a role in gross revenue forecasting.

Sometimes, the tax implications of tariff income can complicate the economic analysis of upstream project economics, 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 under 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, especially when developing a cash flow model.

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, which can play a significant role in gross revenue forecasting.

A price forecast is essential for estimating revenue from crude oil and gas sales, playing a crucial role in gross revenue forecasting. 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 in the context of upstream project economics.

Typically, economists utilize various price scenarios, or 'decks,' for price forecasts, such as $50/Bbl, $60/Bbl, $80/Bbl, and $100/Bbl, assuming these prices remain constant (flat) over the project's life. Price escalators are then applied to adjust these scenarios to reflect the notional price on the day of analysis, which is crucial for an accurate cash flow model.

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. Understanding these dynamics is crucial for developing a cash flow model and for gross revenue forecasting in relation to upstream project economics.

Next, we focus on the items that cause cash to flow out of the business or project, which are essential for a comprehensive cash flow model. These costs are typically divided into technical costs and fiscal costs. Technical costs encompass items such as capital expenditures (CAPEX) and operating expenditures (OPEX), while fiscal costs 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 transitions from exploration to development, these plans will become more detailed and accurate in terms of cost projections, which are crucial for gross revenue forecasting. 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 within the context of upstream project economics.

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, utilizing 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, which play a crucial role in cash flow model development and gross revenue forecasting for the project.  

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 and are typically incurred before production starts, particularly 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, impacting the upstream project economics.

A typical OPEX profile for a project, which is crucial for understanding upstream project economics, 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), as indicated in the cash flow model, which also plays a role in gross revenue forecasting.

Abandex refers to abandonment capital, which is a crucial aspect of upstream project economics. Once a project reaches the end of its economic life, the site must be restored to its original condition. Restoration or decommissioning costs may be incurred even before the project officially concludes, often several years prior to the end of its economic life. Typically, the contracting company is legally obligated to close and restore the operational site. In certain scenarios, particularly under Production Sharing Contracts (PSC), while the ownership of facilities may lie with the government, the responsibility for site restoration usually falls to 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 adequate to offset these costs, governments may provide tax credits or allow contractors to claim tax benefits when they begin allocating funds to an abandonment relief fund. 

Regardless of tax implications, Abandex is a cash outflow item that typically impacts the cash flow model during the last economic period of the project. Estimates for Abandex are usually prepared collaboratively by the finance and operations departments, and 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 on future cash outflows. However, as the project nears the end of its life, abandonment costs become an increasingly important factor in gross revenue forecasting and determining overall project value.

In addition to CAPEX, OPEX, and Abandex, projects also incur extra costs that must be factored into cash flow models for accurate cash flow calculations. From the contractor's perspective, fiscal costs include royalty payments, bonus payments, taxes, and sometimes the government’s share in profits. Royalty is a payment based on the gross revenue generated from oil and gas production, calculated as a percentage that 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. Additionally, taxes are levied on the project’s taxable income, which is crucial for upstream project economics.