Guide to Upstream Oil & Gas KPIs

The analysis of cost structure provides critical insights into the margin of safety and a company’s ability to withstand volatility in benchmark prices. Some of these costs are unique to this industry and are presented on a “per unit basis” (e.g., cost per BOE), which facilitates cross-company comparisons. Here are some of the key cost components of E&P companies:

Production cost is the aggregation of three key operating costs: (1) rent and lease expenses, (2) gathering and transportation expenses and (3) production taxes. Rent and lease expenses together with gathering and transportation expenses form lifting costs. These are direct cash operating costs related to the production of hydrocarbons from the wells. Comparing these metrics helps illustrate the quality of each company’s assets.

Oil exploration spending includes the costs associated with searching and finding new oil and gas fields. Due to the complex nature of identifying oil and gas reserves, companies can often end up drilling a dry well (a well without meaningful oil and gas reserves). Oil exploration expenses (charged to the P&L account) include costs associated with these dry wells along with other searching costs. In the case of the discovery of new oil and gas reserves, all the exploration costs relating to those wells are capitalized and charged to the balance sheet. The capitalized costs, which are associated with recoverable developed reserves, are then allocated to the income statement proportionately based on production during the period.

Finding & development costs represent the total costs of adding new reserves. This is a capital expenditure and includes exploration costs, capital expenditures and acquisition costs. Similar to other cost metrics, this cost is also computed on a per unit basis; however, in this case, the denominator represents gross additions to reserves instead of production volumes. F&D costs provide valuable insight into management’s operating capabilities.

Profitability

Investors typically look at EBITDAX as one of the key measures of profitability for E&P companies, in addition to other standard profitability metrics such as free cash flow (FCF). EBITDAX is defined as earnings before interest, taxes, depreciation, amortization and exploration expenses. It is an E&P industry-specific metric equivalent to EBITDA with an adjustment for exploration expenses. This metric normalizes the volatility in exploration expenses across periods and companies.

Leverage

Given the highly capital intensive nature of the business, the upstream oil and gas industry uses relatively higher amounts of debt to finance projects and to boost shareholders’ returns. Leverage can cut both ways, providing superior returns in good times while bankrupting companies during periods of market turmoil. Analysts typically measure leverage using net debt/EBITDA or a debt/equity ratio.

Reserves Schedule

The reserve schedule is a list of operating metrics that explains the factors behind changes in reserves for a company over a given period of time, reconciling the difference between opening and closing reserves. Investors analyze this schedule to understand the useful life of the reserves, the rate of reserve depletion, the source of new reserves (organic vs. acquisition) and the operating capabilities of management, all of which are critical in determining the intrinsic value of an E&P company.

The reserve schedule starts with the opening balance of reserves – last year’s closing balance – and then adjusts for the addition of new reserves through new discoveries, upward or downward revisions in existing deposits, the acquisition or divestment of deposits and finally the depletion of reserves through production to arrive at a closing balance of reserves. Depletion in the reserve schedule is the same as production volume in the revenue model. These components are used in estimating F&D cost per unit, which is a critical operating metric in evaluating the efficiencies of a company.

There are two key ratios investors focus on in this schedule:

• Reserve life represents the estimated life in years of the reserves and is computed by dividing ending reserves by production volume.
• Reserve replacement ratio (RRR) is calculated by dividing the net proved reserves added through discoveries, revisions and net acquisitions for a given period by the total production volume for the same period. This ratio helps illustrate management’s ability to replace production volume with new reserves. A ratio of greater than 100% means the company is not only successfully replacing depleted production volume with new reserves but also is able to increase the closing balance, which translates to a higher reserve life.