Crude oil: From discovery to extraction

The series of processes that culminate in the delivery of refined petroleum products at the pump is a clear testimony to the earth’s vast natural endowment, technological and technical progress over the years, and the ability of various economic agents to coordinate complex activity across the value chain. This piece examines some of the key economic decisions and activities involved in the discovery and exploitation of liquid hydrocarbon (crude oil) resources.

Generally, crude oil is not discovered by accident. It is deliberately and systematically prospected for with at least many months and more commonly years of advance planning on where, when and how to direct the search efforts. Significant legal, engineering, and economic issues have to be addressed through legislation, negotiations and contracts.

Because the search for oil is conducted by specialist entities (often called exploration and production or E&P companies) who also engage other specialist entities (upstream oil-field services firms), it’s always important that the burden and benefits from oil search be understood and properly allocated in terms of the costs, risks, and revenues if search efforts are successful. Arrangements to be followed when search efforts are unsuccessful are also defined. Key accounting issues have to be addressed as well.

The set of laws, rules, regulations that govern the legal, economic, high level-engineering and financial aspects of oil exploration activities is generally referred to as oil and gas fiscal regimes. These rules provide at least, one clear economic framework for the exploitation of natural fossil fuels. Many countries have two or three sets of contractual arrangements. Very importantly, the contract specifies how the host country and the E&P company’s share of the proceeds from crude oil sales are computed. These shares described in industry parlance as ‘host country’s take’ and the ‘E&P’ company’s take.’

The most popular contract types are the joint venture contract (or JV), the production sharing contract (PSC) and the service contract (SC) which include a variant called the risk-service contract. Details of each of these arrangements will be addressed in a later post. For now, it is sufficient to note that the main activities of the oil majors, also called IOCS (International Oil Companies or International Operating Companies) in Nigeria (e.g. Shell, Chevron, Mobil, and Total) are carried out under Joint Venture (JV) arrangements whereby, for example Chevron Nigeria Limited is jointly-owned by Chevron International (40%) and NNPC (say 60%).

The equity stake of NNPC in each of the JVs varies from one IOC to another and each JV is governed by a Joint Operating Agreement (JOA) which recognizes the IOC as the “Operator” or “Operating Partner” while the NNPC is recognized as an investor. In addition to JVs, many oil exploration and production activities in Nigeria, including some ‘ring-fenced’ operations of the IOCs are undertaken as production sharing contracts and pure service contracts.

After preliminary studies have provided indication of the presence of hydrocarbons over a wide geographical area (land, swamp, or sea), the large area is divided into smaller parts known as ‘blocks’ or acreage. Industry standard measure of block or acreage is between 10 and 20 square kilometres. It is these blocks that are offered to interested bidders (E&P companies, including small, independent producers) as oil prospecting licenses (OPL) or oil mining lease (OML). Different countries adopt different approaches for awarding prospecting or mining licenses but the standard is open, transparent, bidding process where the highest bidder (rather than an opaque ‘preferred’ bidder) wins the right to conduct detailed exploration for oil or to commence actual production of oil from a block whose reserve characteristics are already known.

In this regard, important reserve characteristics include the quantum of oil reserves in place, the depth at which the reserve is located (usually hundreds or thousands of meters) below the surface, the grade (viscosity and sulphur content) of the crude, and the physical characteristics of the rocks, water or sediments above the oil reserves. The quantity of gas occurring/mixed with the oil (called ‘associated gas’) is also important. For an oil prospecting license, the immediate task of the E&P company is to determine these and other important parameters.

Completed exploration studies provide a clear picture of the technical and economic costs of extracting oil reserves for sale. These costs are compared with the expected revenues or proceeds from crude oil sales and this analysis of expected cash flows take account of the host-country’s take (which could be as high as 65/70%) and use very conservative crude oil price scenarios (as low as $14-20$) to determine whether producing oil from a field, giving it’s characteristics, is a likely to be worthwhile venture.

Following the award of a license to explore, an E&P company engages oil-field service companies which include firms with capabilities in the acquisition and processing of seismic data. The work of these companies (such as Schlumberger, Halliburton, and Integrated Data Services Limited (IDSL), a wholly-owned subsidiary of NNPC) helps to determine or ascertain reserve estimates from a block or a combination of blocks. Other oil-field services include drilling (exploration drilling and production drilling) and provision of logistics and hard infrastructure (such as crude oil pipelines) for development, production, maintenance and shut-down of oil wells.

While E&P companies make strategic decisions of where to operate, which assets (reserves) to acquire, produce or exit, much of the services (equipment inclusive) required to implement those decisions are provided by oil-field services companies. As the price of crude oil fluctuates in the international market so does the production activities of E&P companies, because production generates lower profits during low price markets, oil producers tend to delay, or suspend field development and production activities during such markets.

This cut-back of production activities results in reduced demand for the assets and services of oil-field service companies who, in the face of equipment and redundancy are forced to reduce daily charge rates for equipment. For example a rig that is hired for five hundred thousand dollars a day during $75-100 a barrel market may go for as low as two hundred and fifty thousand dollars per day. The reduction in charge rates may also influence the decision of an oil producer to produce, rather than maintain its oil in reserves.

Finally, reserves are the vital assets of E&P companies and they are classified as proven reserves, probable reserves, and possible reserves. Hence the value of an oil producer is largely a function of its production profitability and the value of its reserves. The profitability of production is a function of the company’s internal efficiency, its field cost structure, the quantum of production, and market prices. The value of reserves is based on the volume and certainty of those reserves (including the physical properties of the crude) and the market price of crude oil.

David Adeoye, CFA