Upstream Oil and Gas Production Performance Metrics

Upstream Performance Metrics

In the Upstream Production Performance Metrics lesson, we’ll explore some of the key financial and operational metrics related to upstream exploration and production, or E&P operations.

These are areas of focus for company management, but are also of interest to investors, analysts and lenders.

We’ll also explore some related topics around how a company manages costs and secures financing for exploration and oilfield development projects.

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Capital expenditures

Spending by an E&P operator to acquire, find and develop reserves is known as capital expenditures, or CAPEX.

Upstream capital expenditures are divided into four major categories:

Proved property costs for the acquisition of properties with proved reserves.
Unproved property costs related to the acquisition of acreage and leases.
Exploration costs, commonly known as finding costs, related to identifying and proving a prospective location that may contain oil and gas reserves. This includes geological and geophysical costs and the costs to drill exploratory wells.
And finally, development costs, which are the costs of obtaining access to proved reserves. This includes costs for drilling development wells and the installation of surface facilities needed for production.

An operator’s finding and development costs, called F&D, are an important capital efficiency measure to the financial community and are discussed in more detail later.

An E&P company’s CAPEX can vary significantly year to year. Spending can be impacted by oil and gas prices, changes in supply and demand and the emergence of new technologies, like the success of the shale oil and gas plays in the US.

Operating expenditures

Operating expenditures, called OPEX, for an E&P operator are incurred as part of day-to-day operations.

These include direct field related production costs along with non-cash charges such as depreciation, depletion, and amortization expense and property impairments.

Let’s discuss production costs in more detail.

Production costs

Production costs include lifting costs, gathering and transportation costs and various taxes and royalties.

Lifting costs are associated with operating and maintaining the wells and related production equipment and facilities. This includes labor, materials, utilities, supplies and fuel consumed during operations along with repair and maintenance costs.

Lifting costs are also called lease operating expenses or LOE.

Severance (or production) taxes are paid to the government based on the value or volume of oil and gas production.

Ad valorem (or property) taxes are paid to counties, school districts and other taxing entities based on where the production occurs.

In the US, royalties are paid to property owners that have mineral rights, under the terms of the lease. In other parts of the world the minerals are owned by the national governments.

Gathering and transportation costs are the costs to aggregate oil and gas production in the field and transport it to either storage, a processing facility or shipping point.

Production costs will vary based on the complexity of a company’s operations. The number of wells, leases, and locations are key factors.

Unconventional onshore reserves and offshore deepwater reserves tend to have higher production costs due to severe operating environments and the use of newer technologies.

In addition, the use of enhanced oil recovery techniques, called EOR, to maximize the life of a well also increase production costs.

High oil and gas prices also impact production costs, because power and steam used at the wellsite is generated by produced oil and gas. Additionally, production taxes based on the value of oil or gas produced will be higher.

Now that we’ve covered common expenditures for an oil and gas company, let’s look at how a company monitors and approves significant costs.

To manage CAPEX and multiple projects an E&P operator uses a tool called an authority for expenditure, or AFE. This form represents a project budget against which actual expenditures are compared.

An AFE is prepared before a well is drilled and includes estimates for drilling costs, completion costs for a successful well, and decommissioning costs in the event the first well is dry.

A subsequent AFE is needed for the series of wells to develop the field if the first well is successful.

An AFE is also prepared for other projects, such as a major workover or EOR project.

Authorization for expenditure

AFEs are used in joint ventures as evidence that the joint interest owners have agreed to participate in the project and approve the expenditures.

The summation of all proposed AFEs becomes the capital budget for an E&P company in any fiscal year.

Next, we’ll look at some of operational metrics that are commonly used to evaluate an E&P company.

What is the difference between upstream and downstream?

Finding and development costs per BOE

Finding and development costs, also known as F&D costs, are used to estimate a company’s costs to find and develop new reserves.

This measure is reported as a ratio on a per barrel of oil equivalent, or BOE, basis. Changes in natural gas reserves are converted to “oil equivalent barrels” at a ratio of 6 Mcf to one barrel of oil.

Mcf or millions of cubic feet is the standard production measure for natural gas around the world. For an operator that primarily produces gas, production may be reported on an MCF equivalent, or MCFE, basis using the same conversion factor.

While methods can vary, a common calculation includes unproved property costs, exploration costs and development costs in the numerator.

Reserves changes from extensions and discoveries, improved recovery and revisions are used for the BOE denominator.

Production costs per BOE

Production costs are also commonly analyzed on a per BOE or per MCFE basis. Here production costs for the period are divided by combined oil and gas production volumes.

Industry financial analysts may allocate production costs between oil and gas using relative production weightings, with oil today generally receiving a greater share of the cost.

This is done because at the field level, liquids are normally more expensive to produce and process than an equivalent amount of gas.

Production replacement ratios

The production replacement ratio, also known as reserves replacement ratio, is used to measure the extent to which an E&P company replenishes its reserve base as it is depleted by production.

These ratios are calculated as a percentage of reserves additions in a period divided by the total production in the same period, generally a fiscal year. The components of reserves additions included in this ratio calculation can vary. Common methods include:

All sources – which includes the total net change in reserves for the period.
F&D additions – which include extensions and discoveries, improved recoveries and revisions, but excludes any purchases and sales of proved reserves. An F&D rate greater than 100% indicates that a company is adding to its reserves base by “the drill-bit,” rather than by acquisition.

A company that is not adding annual reserves that are at least equal to its annual production is effectively liquidating the company if this trend continues.

As oil gets harder to find, this becomes a real challenge for an E&P company with large production volumes.

The operational measures we’ve addressed thus far – F&D costs per BOE, production costs per BOE and production replacement rates – can be analyzed on an annual basis.

But they are often reported using a three-year or five-year average to smooth out any anomalies in the data.

Reserves-based lending

The volume and value of proved reserves are key to a company’s ability to arrange external financing to fund exploration and development projects.

This is especially true for numerous independent E&P operators that do not have the internal financial resources of major oil company like ExxonMobil, Shell, BP or Chevron.

A bank will typically provide reserves-based lending, where an E&P company’s proved reserves serve as collateral. The company’s borrowing base, or amount the bank will lend, is based on the value of these reserves.

The borrowing base is redetermined twice a year. Periods of low commodity prices can present a significant challenge to a company as the value of its reserves, and subsequently its borrowing base may be lowered.

Additional loan repayments may be required and the E&P company may need to defer or cancel projects because funding is not available.