Oil and Gas Upstream: Exploration and Production

The upstream business finds oil and gas, proves that it can be produced, builds the wells and facilities to produce it, and sells it at a price nobody in the business controls. It is the largest single pool of profit in energy and the most cyclical: the same barrel sold for a negative price on 20 April 2020 (WTI's May contract settled at −$37.63/bbl) and for more than $115/bbl on Brent in March 2026, when the war with Iran effectively closed the Strait of Hormuz (reported). Two facts organise the industry. First, its central asset is a forecast: reserves are estimates of what can be produced from rock no one can see, and whether they are reported under the US Securities and Exchange Commission's rules or the industry's Petroleum Resources Management System (PRMS) changes the number. Second, every barrel has a place on a cost curve: Gulf onshore fields that cost a few dollars a barrel to lift, Guyana and Brazilian pre-salt deepwater developments with full-cycle breakevens reported at ~$30–40/bbl Brent, US shale wells that need ~$60–70/bbl WTI to justify drilling a new well (Dallas Fed survey, 2025, reported), and older, costlier barrels that survive only in high-price years. Upstream value is created when a company holds barrels low on that curve, develops them on time and budget, under fiscal terms that leave it a fair share, with a licence that lasts; it is destroyed by buying acreage at the top of the cycle, by overstated reserves, and by projects that arrive late into a price collapse. This section explains reserves and resources, exploration risk, the three main resource types (conventional, deepwater, shale), decline curves, breakevens, fiscal regimes (royalties, taxes and production-sharing contracts), the split between international and national oil companies, and the oilfield-services industry. A worked example models a deepwater development under a PSC and under a royalty-and-tax regime; a checklist covers diligence on reserves and E&P companies.