Unconventional vs. Conventional Production

Introduction

The US upstream industry has been defined by the unconventional revolution for over 15 years, but the distinction between unconventional and conventional production remains essential context for energy banking. Virtually all new US onshore drilling today is unconventional (horizontal wells into tight rock formations, stimulated through hydraulic fracturing), and the production characteristics of these wells create the economic dynamics that drive E&P business models, valuation methods, and M&A activity. Understanding how unconventional production differs from conventional production is important for accurately modeling cash flows, interpreting decline curves, and evaluating the capital intensity of different asset types.

Conventional production comes from reservoirs where hydrocarbons are trapped in porous, permeable rock (typically sandstone or limestone) beneath an impermeable cap rock. The natural permeability of the reservoir allows oil and gas to flow relatively easily through the rock's pore spaces to the wellbore. Conventional wells are typically vertical (drilled straight down into the reservoir) and require minimal stimulation. Conventional reservoirs are found globally, from the giant fields of the Middle East (Ghawar in Saudi Arabia, Burgan in Kuwait) to mature North American plays (the conventional Permian formations that preceded the shale revolution, Gulf of Mexico deepwater fields, Alaska's North Slope).

Unconventional production comes from reservoirs where hydrocarbons are trapped in rock with very low permeability (tight sandstone, shale, or carbonate formations). The rock cannot deliver oil or gas to the wellbore without technological intervention. Two technologies made unconventional production commercially viable.

Horizontal Drilling

A drilling technique where the wellbore is turned from vertical to horizontal within the target formation, extending laterally for 5,000-15,000 feet through the productive zone. Horizontal drilling maximizes the contact area between the wellbore and the reservoir (a 10,000-foot lateral contacts roughly 30x more formation than a vertical well penetrating the same zone), dramatically increasing per-well productivity. Combined with hydraulic fracturing, horizontal drilling is the enabling technology behind the US shale revolution and the dominant drilling method in all major US onshore basins.

Hydraulic fracturing complements horizontal drilling (pumping millions of gallons of water, sand, and chemicals at high pressure to create fractures in the rock that provide pathways for hydrocarbons to flow to the wellbore).

Hydraulic Fracturing (Fracking)

A well stimulation technique in which water, sand (proppant), and chemical additives are pumped at high pressure into the wellbore to create fractures in the target rock formation. The fractures provide conductive pathways for oil and gas to flow from the low-permeability reservoir to the horizontal wellbore. A typical unconventional completion involves 30-60 fracturing stages along the lateral, each requiring 200,000-500,000 gallons of water and 200,000-500,000 pounds of proppant. Hydraulic fracturing is the enabling technology that made shale oil and gas production commercially viable and transformed the US into the world's largest oil and gas producer.

The most important distinction for energy banking is the dramatically different decline curve profiles between unconventional and conventional wells.

Unconventional wells decline steeply. A typical horizontal shale well produces at its highest rate in the first month (IP30 of 500-1,500 BOE/d depending on the basin) and then declines rapidly: 60-80% in the first year, another 30-40% in the second year. After five years, the well may produce only 10-15% of its initial rate. The steep decline reflects the physics of tight rock: the hydraulic fractures provide initial flow paths, but as the pressure differential between the fracture network and the surrounding rock equalizes, flow rates drop quickly. Total EUR for an unconventional well is typically 500,000-1,200,000 BOE, produced over 20-30 years, with the majority of volume front-loaded in the first 3-5 years.

Conventional wells decline gradually. A typical conventional well has a much lower initial production rate (50-500 BOE/d) but declines slowly: 5-15% per year, and sometimes even less for wells supported by water injection or gas lift. A well in a high-quality conventional reservoir might produce for 20-40 years at economically attractive rates, generating EUR of 500,000-5,000,000+ BOE with a much more evenly distributed production profile.

The steep decline characteristic of unconventional wells is the most consequential difference for E&P economics.

The production type fundamentally changes how the NAV model is constructed.

For unconventional assets, the NAV model is built bottom-up from individual well type curves. Each PDP well has its own decline projection. Each PUD location is assigned a type curve with specific IP rate, decline parameters, and EUR. The development schedule specifies how many new wells are drilled each year, and the model aggregates production across all wells and cohorts. Because most production comes in the first few years of each well's life, the near-term cash flows are relatively predictable, but the long-term forecast depends heavily on the development schedule and type-curve assumptions for future wells.

For conventional assets, the NAV model often uses field-level production forecasts rather than individual well projections, because conventional fields may have hundreds or thousands of wells that interact through shared reservoir pressure. Decline rates are lower and more predictable, making production forecasts more reliable over longer time horizons. However, conventional assets may also require ongoing investment in secondary recovery (waterflooding) or enhanced oil recovery (CO2 injection, steam injection) to maintain production, which introduces a different type of capital expenditure that unconventional models do not typically include.

For M&A advisory, the unconventional vs. conventional distinction affects everything from valuation methodology (type-curve-driven NAV vs. field-level reserve analysis) to buyer identification (PE firms prefer unconventional assets with development upside; income-focused investors prefer conventional assets with stable cash flow).

For reserve-based lending, unconventional PDP reserves receive the same advance rates as conventional PDP, but the steeper decline means the PDP base depletes faster, requiring the company to continually convert PUD to PDP through drilling to maintain the borrowing base. A conventional company with stable PDP production has a more sustainable borrowing base without requiring continuous new investment.

For comparable company analysis, mixing unconventional and conventional companies in the same peer set can be misleading because their capital intensity, decline profiles, and free cash flow characteristics are fundamentally different. Energy bankers typically compare unconventional operators against other unconventional operators and use separate frameworks for conventional production.