Oil and gas definitions for producing-asset decisions.

A family of empirical equations developed by petroleum engineer J. J. Arps to describe and forecast production-rate decline over time. The equations use an initial production rate, an initial decline rate and a decline exponent, or b-factor. The principal forms are exponential, hyperbolic and harmonic decline. Arps equations extrapolate observed production behavior and require engineering judgment; they are not a reservoir simulation or a guarantee of future performance.

Methods used to assist produced fluids in reaching the surface when natural reservoir energy is insufficient or when liquid loading restricts production. Artificial-lift and gas-well deliquification methods may include pumping units, gas lift, plunger lift and chemical foaming treatments such as soap. The appropriate method depends on well conditions, fluid volumes, pressure, equipment, operating cost and reliability.

The ability of wells, facilities, pipelines and related equipment to perform their intended functions safely and reliably while containing produced fluids and managing operational risk. Asset-integrity programs typically include inspection, maintenance, testing, corrosion control and repair.

A document that describes a proposed well, workover or other capital project and presents its estimated costs for approval. An AFE is a budget authorization, not a guarantee of final cost or performance.

A dimensionless decline exponent in the Arps hyperbolic equation that controls the curvature of a production forecast. A b-factor of zero corresponds to exponential decline, while a b-factor of one corresponds to harmonic decline. Higher values generally produce a slower modeled reduction in the decline rate and a longer production tail. The selected b-factor should be supported by production behavior and engineering judgment because it can materially affect forecast production and reserves.

The production expected from currently producing wells before adding the effect of new drilling, recompletions, workovers or other incremental projects. Base-production forecasts normally reflect anticipated decline and downtime.

A standardized energy-equivalent unit used to combine oil and natural gas volumes. A common conversion is six thousand cubic feet of natural gas to one barrel of oil equivalent; it is an energy conversion and does not imply equal economic value.

A large geologic area, commonly a structural depression, in which sediments accumulated over time. In the oil-and-gas context, a sedimentary basin may contain one or more petroleum systems, formations and producing fields. Basin boundaries are geologic and may cross state or national borders; they are not the same as surface-water drainage basins.

Cash generated or used during a period. The meaning depends on context and may refer to revenue less operating expenses, or to a measure that also deducts capital expenditures, interest, taxes and other obligations.

The risk that an asset’s expected revenue, costs or value may be affected by contractual terms, customer or counterparty performance, market access, transportation and processing arrangements, commodity-price differentials or other conditions governing how production is sold and delivered.

The use of financial contracts to reduce exposure to changes in oil or natural gas prices. Hedges can improve cash-flow visibility, but they can also limit participation in favorable price movements and introduce counterparty and basis risk.

The risk that changes in oil, natural gas or natural-gas-liquids prices will reduce an asset’s revenue, cash flow or value. Exposure depends on production mix, price differentials, contract terms and any commodity hedges in place.

The risk that asset value, production or cash flow depends too heavily on a limited number of wells, fields, formations, operators, customers, geographic areas or commodities. A larger and sufficiently diversified well base generally reduces dependence on any single well and can make aggregate production and cash flow more predictable. A high well count may not provide meaningful diversification when the wells share the same reservoir, infrastructure, customer or operating risk.

A forecast of future well or asset production based on historical performance, reservoir behavior and engineering judgment. Results depend on the selected methodology, data quality and assumptions regarding operations and downtime.

Reserves expected to be recovered through existing wells and facilities, or through equipment and operating methods whose required cost is relatively minor compared with drilling a new well.

An evaluation scenario that applies less favorable assumptions than the expected case to test how an investment may perform under adverse conditions. Assumptions may address production, commodity prices, costs, downtime, timing, liabilities or capital requirements.

The risk that planned operational, financial, commercial or organizational actions will not be completed on time, within budget or with the expected results. Execution risk can affect production, costs, safety, regulatory compliance and investment returns.

An Arps decline form in which production decreases at a constant percentage rate over time. It corresponds to a b-factor of zero and can be written as q(t) = qi × e^(−Di t). Exponential decline is commonly used for mature or terminal production behavior and plots as a straight line on a semilog rate-versus-time graph.

Costs associated with operating and maintaining producing properties. Lease operating expense commonly includes labor, chemicals, electricity, repairs, water handling and similar field-level costs, but the exact account composition should be confirmed for each asset.

Overhead costs associated with managing and supporting a business or asset portfolio that are not directly charged as field operating expense. G&A may include management and office personnel, accounting, legal and other professional services, information technology, office costs, insurance and corporate governance. Allocations and definitions vary among sellers and operators, so the included costs and allocation method should be reviewed. Some G&A is recurring, while transaction or transition-related amounts may be nonrecurring.

A lease status in which qualifying production maintains the lease beyond its primary term, subject to the specific lease language and applicable law.

A well-completion or stimulation process in which fluid is pumped into a subsurface formation at sufficient pressure to create or extend fractures in the rock. A solid granular material called proppant—commonly sand—is placed within the fractures to help keep them open and provide pathways through which oil or natural gas can flow to the wellbore. Hydraulic fracturing is commonly used in tight reservoirs and is distinct from drilling the well.

An Arps decline form in which the percentage decline rate decreases over time. It can be written as q(t) = qi ÷ (1 + bDi t)^(1/b), where b is the decline exponent. Values between zero and one are commonly used, subject to the production history and reservoir behavior. The selected b-factor can materially affect forecast production and reserves, so hyperbolic forecasts are often transitioned to a terminal exponential decline.

The discount rate that makes the net present value of an investment’s cash inflows and outflows equal to zero. IRR reflects both the amount and timing of cash flows, but it does not show investment scale and can be sensitive to cash-flow timing and methodology. A realized IRR uses actual cash flows through disposition; it is not a guarantee of future performance.

A statement prepared by an operator that allocates a property’s drilling, completion, operating and other shared costs among working-interest owners according to their ownership interests and the governing agreements. JIB charges should be reviewed against the applicable accounting procedure, authorizations and supporting detail.

An agreement among working-interest owners that designates the operator and establishes how wells and properties will be developed and operated. A JOA commonly addresses cost sharing, voting, authorizations for expenditure, accounting, liabilities, transfers and remedies for non-consent or nonpayment.

A field-level unit-cost measure calculated by dividing gross lease operating expense by gross production measured at the wellhead for the same period. Gross lease operating expense may include field-level administrative or overhead charges that are properly attributable to the property under the applicable joint operating agreement and accounting procedure. Lifting cost excludes corporate G&A and capital expenditures. It may be stated as dollars per Mcf for natural gas or dollars per barrel for oil or other produced liquids. A declining lifting cost generally indicates that gross production increased relative to gross lease operating expense, or that expense decreased relative to production. Additional property-level spending may be economically justified when the resulting incremental production generates sufficient incremental revenue and cash margin to more than cover the added costs; a lower lifting cost alone does not establish payout. Comparisons should use consistent expense categories, production streams and time periods.

A unit of natural gas volume equal to one thousand cubic feet measured at specified standard conditions. Mcf describes physical volume, while MMBtu describes energy content. One Mcf is often approximately one MMBtu, but the actual relationship varies with gas composition, heating value and the measurement standards used.

A unit of energy equal to one million British thermal units. Natural gas is commonly bought, sold or valued in MMBtu because gas streams with the same volume can contain different amounts of energy. Conversion between Mcf and MMBtu depends on the measured heating value of the gas and applicable contract or measurement standards.

A return multiple calculated by dividing the value or cash proceeds attributable to an investment by the capital invested. A realized MOIC is based on actual distributions and disposition proceeds relative to invested capital. MOIC does not account for how long the capital was invested, so it should be considered together with IRR and the stated calculation methodology.

The use of mechanical equipment to increase natural gas pressure so gas can move from wells through gathering, processing or transmission systems. Compression can help maintain production when well or system pressure declines, but compressor capacity, fuel use, maintenance, downtime and discharge-pressure requirements can affect volumes, costs and reliability.

Hydrocarbon liquids separated from a natural gas stream at field facilities or processing plants. NGLs commonly include ethane, propane, normal butane, isobutane and natural gasoline. Their volumes, prices and processing economics are distinct from those of pipeline-quality natural gas and crude oil.

The share of production revenue attributable to an owner after burdens such as royalties and overriding royalties, but before that owner’s share of operating expenses and other costs.

An ownership interest in a well or property for which another party serves as operator. The non-operator generally shares revenues and costs according to its interests but does not control day-to-day field operations.

A cost that is unusual, infrequent or not expected to continue as part of an asset’s normal operating run rate. Examples may include transaction and transition costs, certain casualty repairs or a specific major project. Classification depends on the asset and its operating history: an individual workover may be unusual for one well, while workovers across a large portfolio may be part of the normal cost pattern. Excluding costs as nonrecurring without adequate support can overstate normalized cash flow.

A measure of revenue remaining after selected production taxes, transportation and field operating costs. Because companies define netback differently, the included and excluded items should always be stated.

The party responsible for conducting day-to-day operations for a well or property, including field activity, regulatory reporting, cost administration and coordination with working-interest owners.

The process of permanently closing a well by isolating producing and water-bearing intervals, placing required mechanical or cement barriers, removing or cutting well equipment as required and restoring the site in accordance with applicable rules. P&A scope, timing, financial assurance and cost vary by jurisdiction and well condition.

The difference between the price received for produced oil, natural gas or natural gas liquids and a stated benchmark or reference price. A differential may be a discount or a premium and can reflect location, product quality, transportation and processing costs, market access, contract terms, timing and local supply-and-demand conditions.

An oil-and-gas property or group of properties with wells that are currently producing and generating revenue. A producing asset may also include associated leases, facilities, equipment, contracts, reserves and inactive wells or future development opportunities.

Proved developed reserves that are not currently producing. Examples may include reserves behind pipe, in temporarily shut-in wells or requiring a relatively minor operation to begin or restore production.

Proved reserves expected to be recovered from existing wells and completions that are producing at the evaluation date. PDP forecasts remain subject to decline, downtime, price, cost and operating assumptions.

Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells requiring a relatively major expenditure. Classification depends on technical certainty, an adopted development plan and applicable regulatory requirements.

The definitive contract governing an asset transaction. It typically addresses the purchase price, effective date, title and environmental procedures, representations, covenants, closing conditions and allocation of liabilities.

The estimated future net cash flows of an asset discounted to an evaluation date at the stated annual rate. Present value is sensitive to production, price, cost, timing and discount-rate assumptions and is not necessarily market value.

A cost expected to arise repeatedly as part of normal ownership or operation of an asset. Examples may include field operating expense, routine maintenance, property and production taxes, insurance, equipment or surface rentals and recurring administrative costs. A recurring expense does not have to occur every month and may vary with production, activity, inflation or operating conditions.

A subsurface body of porous and permeable rock that contains oil, natural gas or water and can transmit those fluids through connected pore space. Reservoir quality, pressure, fluid properties, drive mechanism and continuity influence well performance, recovery and development decisions.

Estimated quantities of petroleum anticipated to be commercially recoverable from known accumulations under defined conditions. Reserve classifications communicate differing levels of technical and commercial certainty.

The historical price framework prescribed by the U.S. Securities and Exchange Commission for public-company reserve reporting. It is a standardized reporting convention and may differ materially from current prices, strip pricing or an acquirer’s forecast.

The reduction in natural gas volume or energy content between the quantity entering a gathering or processing system and the residue gas remaining for sale or delivery. Shrinkage commonly results from extracting natural gas liquids, using gas as plant or compressor fuel and normal processing or measurement losses. It is not necessarily evidence of a physical leak. A shrink factor is often applied when forecasting sales volumes and revenue.

A well that is not currently producing but has not necessarily been permanently abandoned. A well may be shut in for mechanical, economic, market, regulatory or operational reasons.

The risk that subsurface, well, production, facility or engineering assumptions are incomplete or incorrect. Technical risk may arise from reservoir performance, production decline, well condition, data quality, mechanical integrity or the feasibility of planned work.

A minimum long-term decline rate applied after an initial hyperbolic or harmonic forecast period, usually by transitioning the forecast to exponential decline. The terminal decline assumption prevents the modeled decline rate from flattening indefinitely and producing an unrealistically long production tail. It is a forecasting assumption that should reflect asset behavior and engineering judgment.

An inactive well that has been secured and whose completion interval has been isolated from the wellbore in accordance with applicable requirements, but that has not been permanently abandoned. Temporary-abandonment status may preserve the possibility of future re-entry, testing, recompletion, service or production. Qualification, monitoring, testing, financial assurance and time limits vary by jurisdiction and well condition.

A reservoir with sufficiently low permeability that oil or natural gas does not flow at commercial rates without stimulation, specialized completion methods or other production assistance. Tight reservoirs may occur in sandstone, carbonate, shale or other rock and can require hydraulic fracturing, horizontal drilling or both. The term describes reservoir flow characteristics and does not by itself determine commercial quality.

The process of evaluating an investment by analyzing expected production, revenue, costs, capital requirements, liabilities, risks, financing and potential returns. The underwriting case records the assumptions used to determine an asset’s value and an acceptable investment structure.

The risk of existing or future obligations associated with owning or operating oil-and-gas assets. These may include well plugging and abandonment, site reclamation, environmental remediation, inactive or temporarily abandoned wells, equipment and pipeline integrity, regulatory compliance, unpaid royalties or taxes, contractual obligations and claims involving prior operations. The timing and ultimate cost of these obligations may be uncertain and can materially affect asset value and cash flow.

An ownership interest that bears a share of drilling, completion and operating costs and receives a share of production revenue, subject to royalties and other burdens.

Remedial work performed on an existing well to restore, maintain or improve production. Scope can range from relatively routine mechanical repairs to more substantial downhole operations.