ComboCurve: Report Columns Breakdown

ComboCurve: Report Columns Breakdown

Report Columns Breakdown

Overview

Once you have filled out your assumptions in the Scenario Table and clicked Run Scenario, you will be prompted to configure your output reports. The Columns tab allows you to specify which metrics to include across your reports. This article covers every available column and its definition, organized by category, as a reference for building and interpreting your economic output.



You can select which columns to display in your One-Line Summary and Monthly reports by checking the respective boxes. Note that checking the Cumulative box will add cumulative volumes as additional columns within your Monthly report.

Columns

Gross Volumes

  • Gross Oil Well Head Volume: Total unadjusted oil production forecast directly from the well, prior to any surface losses.
  • Gross Gas Well Head Volume: Total unadjusted gas production forecast directly from the well, prior to any surface losses.
  • Gross BOE Well Head Volume: Barrels of Oil Equivalent at the wellhead.
    • Calculation: Converts wellhead gas to equivalent oil barrels and adds it to wellhead oil. Note: The default conversion ratio is 6 Mcf per 1 bbl (6:1), adjustable in General Options.
  • Gross MCFE Well Head Volume: Thousand Cubic Feet Equivalent at the wellhead.
    • Calculation: Converts wellhead oil to equivalent gas and adds it to wellhead gas. Note: The default conversion ratio is 1 bbl per 6 Mcf (1:6), adjustable in General Options.
  • Gross Water Well Head Volume: Total unadjusted water production forecast at the wellhead.
  • Gross Oil Sales Volume: Actual volume of oil available for sale at the surface facility.
    • Calculation: Gross Oil Well Head Volume minus shrinkage and loss defined in Stream Properties.
  • Gross Gas Sales Volume: Actual volume of gas available for sale at the surface facility after processing.
    • Calculation: Gross Gas Well Head Volume minus loss, flare, and shrinkage defined in Stream Properties.
  • Gross NGL Sales Volume: Natural Gas Liquids recovered from the gas stream, available for sale.
    • Calculation: Applies the NGL Yield defined in Stream Properties.
  • Gross Drip Condensate Sales Volume: Condensate recovered at surface facilities prior to gas processing, available for sale.
    • Calculation: Applies the Drip Condensate Yield defined in Stream Properties.
  • Gross BOE Sales Volume: Total Barrels of Oil Equivalent available for sale at the surface facility.
    • Calculation: Sums Gross Oil Sales, NGL Sales, Drip Condensate Sales, and Gas Sales (converted to BOE).
  • Gross MCFE Sales Volume: Total Thousand Cubic Feet Equivalent available for sale at the surface facility.
    • Calculation: Sums Gross Gas Sales and all liquid sales (Oil, NGL, Drip Condensate) converted to MCFE.

Ownership

  • Ownership and Reversion Model Name: The name of the Ownership assumption model applied to the well in your scenario.
  • WI - Oil / Gas / NGL / Drip Condensate: The initial Working Interest (WI) percentage, owner's share, for each respective phase.
  • First Reversion WI - Oil / Gas / NGL / Drip Condensate: The Working Interest percentage, owner's share of income and production, for each phase after the first reversion event is triggered.
  • NRI - Oil / Gas / NGL / Drip Condensate: The initial Net Revenue Interest (NRI) percentage for each respective phase.
  • First Reversion NRI - Oil / Gas / NGL / Drip Condensate: The Net Revenue Interest percentage for each phase after the first reversion event is triggered.
  • Lease NRI: The total amount of revenue interest available on the case.
  • Original Lease NRI: The initial Net Revenue Interest of the lease prior to any reversions, burdens, or ownership model adjustments.

Carbon

  • Gross - CO2e / CO2 / CH4 / N2O Mass Emitted: The total mass of emissions (in metric tons) generated for each respective greenhouse gas. CO2e (Carbon Dioxide Equivalent) is the standardized metric expressing the combined impact of all modeled greenhouse gases.
  • WI - CO2e / CO2 / CH4 / N2O Mass Emitted: The Working Interest share of the emissions in metric tons.
    • Calculation: Multiplies the Gross Mass Emitted by the applicable WI percentage.
  • NRI - CO2e / CO2 / CH4 / N2O Mass Emitted: The Net Revenue Interest share of the emissions in metric tons.
    • Calculation: Multiplies the Gross Mass Emitted by the applicable NRI percentage.

Net Volumes

Note: In this section, "WI" refers to the Working Interest share, while "Net" refers to the Net Revenue Interest (NRI) share.

  • WI - Oil / Gas / NGL / Drip Condensate / Water Sales Volume: The Working Interest share of the actual volume available for sale at the surface facility.
    • Calculation: Multiplies the respective Gross Sales Volume by your WI percentage.
  • WI - BOE / MCFE Sales Volume: The Working Interest share of your equivalent sales volumes.
    • Calculation: Multiplies the Gross BOE / MCFE Sales Volume by your WI percentage.
  • Net - Oil / Gas / NGL / Drip Condensate / Water Sales Volume: The Net Revenue Interest share of the actual volume available for sale at the surface facility.
    • Calculation: Multiplies the respective Gross Sales Volume by your NRI percentage.
  • Net - BOE / MCFE Sales Volume: The Net Revenue Interest share of your equivalent sales volumes.
    • Calculation: Multiplies the Gross BOE / MCFE Sales Volume by your NRI percentage.
  • Net - Oil / Gas / Water Well Head Volume: The Net Revenue Interest share of the unadjusted production forecast directly from the well.
    • Calculation: Multiplies the respective Gross Well Head Volume by your NRI percentage.
  • Net Gas Sales Volume (MMBTU): The Net Revenue Interest share of the gas sales volume, expressed in heating value (Millions of British Thermal Units).
    • Calculation: Multiplies the Net Gas Sales Volume by the BTU factor defined in Stream Properties.

Stream Properties

  • Stream Properties Model Name: The name of the Stream Properties assumption model applied to the well in your scenario.
  • NGL / Drip Condensate Yield: The assumed volume of liquids recovered from the gas stream, typically expressed in BBL/MMscf.
  • Oil / Gas Shrinkage: The percentage reduction in volume from the wellhead to the sales point. For gas, this is primarily due to the extraction of natural gas liquids. For oil, this accounts for volume changes resulting from pressure and temperature drops at the surface.
  • Oil / Gas Loss: The percentage of production lost prior to the sales meter due to surface operational factors.
  • Gas Flare: The percentage of gas intentionally flared at the surface.
  • Unshrunk / Shrunk Gas BTU: The heating value of the gas stream, measured in BTU. Unshrunk represents the raw gas before processing; Shrunk represents the residue gas after liquids have been extracted.

Compositional

This group breaks down volumes, revenue, and pricing by individual fluid component. There are 21 specific components available for reporting. The columns follow a consistent structure — using C1 as an example:

  • Comp C1 NGL Gross Volume & Comp C1 Gas Gross Volume: The total unadjusted volume of C1 within the NGL or Gas stream.
  • Comp C1 NGL WI Volume & Comp C1 Gas WI Volume: The Working Interest share of the C1 volume.
    • Calculation: Multiplies the Gross Volume by your WI percentage.
  • Comp C1 NGL Net Volume & Comp C1 Gas Net Volume: The Net Revenue Interest share of the C1 volume.
    • Calculation: Multiplies the Gross Volume by your NRI percentage.
  • Comp C1 NGL Net Revenue & Comp C1 Gas Net Revenue: The net revenue generated from the sale of C1 within the respective stream.
    • Calculation: Multiplies the Net Volume by the C1 Realized Price.
  • Comp C1 NGL Realized Price & Comp C1 Gas Realized Price: The actual price received per unit of C1 after applying your pricing models and differentials.

Price

  • Differentials Model Name: The name of the Differentials assumption model applied to the well in your scenario.
  • Input Oil / Gas / NGL / Drip Condensate Price: The base benchmark price for each phase before any differentials or adjustments are applied.
  • Oil / Gas / NGL / Drip Condensate Differential 1, 2 & 3: The specific adjustment values applied at each of the three differential tiers defined in your assumptions.
  • Realized Oil / Gas / NGL / Drip Condensate Price: The final price received per unit of production.
    • Calculation: Input Price adjusted by the total sum of all applied differentials.
  • Oil / NGL / Drip Condensate Differentials Input ($/BBL) & Gas Differentials Input ($/MMBTU): The total calculated dollar value of differentials applied to the base price for each respective stream.

Revenue

  • Pricing Model Name: The name of the Pricing assumption model applied to the well in your scenario.
  • Net Oil / Gas / NGL / Drip Condensate Revenue: The net revenue generated from the sale of the respective phase.
    • Calculation: Multiplies the respective Net Sales Volume by its Realized Price.
  • Total Net Revenue: The total revenue generated across all production streams.
    • Calculation: Sums the net revenue from Oil, Gas, NGL, and Drip Condensate.

Expense

  • Expense Model Name & Expense Description: The name and description of the Expenses assumption model applied to the well.
  • Oil / Gas / NGL / Drip Condensate G&P / OPC / TRN / MKT / Other Expense: The specific variable costs calculated for each phase, broken out by category: Gathering & Processing (G&P), Operating Costs (OPC), Transportation (TRN), Marketing (MKT), and any custom "Other" expenses defined in your assumptions.
  • Total Oil / Gas / NGL / Drip Condensate Variable Expense: The total variable cost for each respective phase.
    • Calculation: Sums the categorized variable expenses (G&P, OPC, TRN, MKT, Other) for that specific fluid.
  • Total BOE / Fluid Variable Expense: Total variable expenses aggregated by Barrels of Oil Equivalent or total fluid volumes.
  • Water Disposal Expense: The total calculated cost associated with disposing of produced water.
  • CO2e / CO2 / CH4 / N2O Expense: The calculated cost associated with emissions of each respective greenhouse gas, based on the carbon pricing defined in your assumptions.
  • Total Carbon Expense: The sum of all individual carbon emission expenses.
  • Total Variable Expense: The grand sum of all variable expenses, including all fluids, water disposal, and carbon.
  • Fixed Expense 1 through 9: The specific fixed costs (e.g., monthly overhead, annual fixed costs) defined in your Expenses assumptions.
  • Total Fixed Expense: The sum of all applied fixed expenses.
  • Total Expense: The absolute total operating cost.
    • Calculation: Sums Total Variable Expense and Total Fixed Expense.
  • Total Oil / Gas / Water / NGL / Drip Condensate Variable Expense Input ($/BBL or $/MCF): The calculated total unit cost applied to the volume of each phase.

Production Tax

  • Production Taxes Model Name: The name of the Production Taxes assumption model applied to the well in your scenario.
  • Oil / Gas / NGL / Drip Condensate Severance Tax: The calculated severance tax applied to production of each respective phase, based on the rates defined in your assumptions.
  • Total Severance Tax: The sum of severance taxes across all production streams.
  • Ad Valorem Tax: The calculated ad valorem (local property/county) tax applied to the well, based on your tax assumptions.
  • Total Production Tax: The grand total of all production-related taxes.
    • Calculation: Sums Total Severance Tax and Ad Valorem Tax.

CAPEX

This group breaks down your capital expenditures. Costs are divided into Gross (8/8ths total cost) and Net (your Working Interest share), across 53 specific categories. Available categories include standard operations (Drilling, Completion, Pad Facility, Tie-in Facility, Facility, Abandonment, Salvage) as well as 48 Custom categories (Custom 1 through Custom 48) that you can define in your assumptions. The columns follow a consistent structure — using Drilling as an example:

  • CAPEX Model Name: The name of the CAPEX assumption model applied to the well in your scenario.
  • Gross Drilling: The total unadjusted capital expense for the drilling phase.
  • Net Drilling: The Working Interest share of the drilling expense.
    • Calculation: Multiplies the Gross Drilling cost by your WI percentage.
    • Note: This Gross / Net structure repeats for every category — Completion, Pad Facility, Abandonment, all 48 Custom categories, etc.
  • Total Gross CAPEX: The grand sum of all Gross capital expenses across every applied category.
  • Total Net CAPEX: The grand sum of all Net capital expenses across every applied category.

Cash Flow

  • NPI Cash Flow: The cash flow allocated to a Net Profits Interest owner, deducted from the Working Interest owner’s Before Income Tax Cash Flow. NPI is a contractual right to receive a share of net profits (revenue minus defined costs) from the well, and is paid only when the defined profit threshold is positive.
  • Net Operating Income: Total revenue remaining after operating expenses and production taxes are deducted, but before capital expenditures.
    • Calculation: Total Net Revenue minus Total Expense minus Total Production Tax.
  • First / Second Discount Net Operating Income: The present value of Net Operating Income, discounted to the As Of Date using the first or second discount rate specified in assumptions. Reflects the time-value-adjusted worth of operating cash flows before capital expenditures.
  • Before Income Tax Cash Flow: The total cash flow generated by the asset before accounting for federal or state income tax obligations.
    • Calculation: Net Operating Income minus Capital Expenditures.
  • Reversion Amount: The specific dollar value or cumulative cash flow threshold required to trigger a change in working or net revenue interest.
  • First / Second Discount Cash Flow: Total before-tax cash flow adjusted by the first or second specified discount rates.
  • Discount Table CF 1 through 16: Cash flow values calculated based on the sequential discount rates defined in the project's discount table.

AFIT Economics

  • Tax Credit: Direct dollar-for-dollar reduction in tax liability based on qualifying investments or activities.
  • Tangible / Intangible / Total Depreciation: The recovery of capital costs for physical (tangible) and non-physical (intangible) assets over time, and the combined total.
  • Tangible / Intangible Cost Depletion / Percentage Depletion / Total Depletion: Tax deductions for the reduction of mineral reserves, including cost-based and statutory percentage methods, and the total value.
  • Total Deductions: The combined value of all tax-shielding items (Depreciation, Depletion, etc.) applied to reduce taxable income.
  • Taxable Income: Undiscounted cash flow for which income taxes are applied.
  • State / Federal Tax Rate: The statutory percentage rate applied to taxable income for the respective jurisdiction.
  • State / Federal Income Tax: The calculated dollar amount of tax owed to state and federal authorities.
  • After Income Tax Cash Flow: The final net cash flow available after all state and federal income tax obligations are met.
  • AFIT First / Second Discount Cash Flow: After-tax cash flow adjusted by the first or second specified discount rates.
  • AFIT Discount Table CF 1 through 16: After-tax cash flow values calculated based on the sequential discount rates defined in the assumptions discount table.
  • After Tax Income ROI: Return on Investment measured after taxes. Provides variations for undiscounted values and first/second discount rates, using either discounted or undiscounted CAPEX as the denominator.
  • After Tax Income Undiscounted / First Discount PVR (Discounted CAPEX): The Present Value Ratio calculated after taxes, comparing the present value of future cash flows to the capital investment.
  • After Tax Income IRR: The Internal Rate of Return calculated based on the after-tax cash flow stream.
  • After Income Tax Payout Date & Duration: The specific date or total duration required to reach a cumulative after-tax cash flow of zero. Includes options for undiscounted and discounted (First/Second) scenarios.

Additional One-Line Summary Options

  • Econ First Prod Date: The projected first date of commercial production used for economic calculations.
  • Forecast Name: The name of the production forecast applied to the scenario.
  • Dates / Risking / Operations Model Name: The name of the assumption model applied to the well for the respective tab.
  • As Of Date: The effective date for the start of economic calculations and discounting.
  • Discount Date: The date to which future cash flows are discounted.
  • Econ Well Life: The total economic producing lifespan of the well.
  • Abandonment Date: The projected date the well reaches its economic limit and is shut in.
  • Interest Reversion Date: The date when a change in working or net revenue interest is triggered.
  • Oil / Gas / Water Forecast Volumes Start Date: The date when forecasted production begins for the respective phase.
  • Oil / Gas / NGL / Drip Condensate / Water Scenario Risk Factor: The percentage risk applied to the respective phase at the scenario level.
  • Oil / Gas / Water Forecast Risk Factor: The percentage risk applied to the respective phase at the forecast level.
  • TC Normalization Applied: Indicates whether type curve normalization factors have been applied to the asset.
  • Oil / Wet Gas / Dry Gas / NGL / Drip Condensate BOE Conversion: The specific ratio used to convert the respective phase to Barrels of Oil Equivalent.
  • Oil / Gas / Water Production to As Of Date: Historical cumulative production for the respective phase up to the specified As Of Date.
  • Undiscounted / First Discount / Second Discount ROI: Before-tax Return on Investment, with variations for undiscounted values and first/second discount rates, using either discounted or undiscounted CAPEX as the denominator.
  • Undiscounted / First Discount PVR (Discounted CAPEX): The before-tax Present Value Ratio, comparing the present value of future cash flows to the capital investment.
  • IRR: The Internal Rate of Return calculated based on the before-tax cash flow stream.
  • Undiscounted / First Discount / Second Discount Payout Date: The specific date required to reach a cumulative before-tax cash flow of zero at the specified discount rate.
  • Payout / First Discount Payout Duration: The total length of time required to reach payout at the specified discount rate.
  • GOR: Gas-Oil Ratio — the volume of gas produced per barrel of oil, expressed in Mcf/bbl.
    • Calculation: Gross Gas Well Head Volume (Mcf) divided by Gross Oil Well Head Volume (bbl).
  • WOR: Water-Oil Ratio — the volume of water produced per barrel of oil, expressed in bbl/bbl.
    • Calculation: Gross Water Well Head Volume (bbl) divided by Gross Oil Well Head Volume (bbl).
  • Water Cut: The ratio of water produced relative to the total volume of liquids produced, expressed as a percentage.
    • Calculation: Gross Water Well Head Volume divided by (Gross Oil Well Head Volume + Gross Water Well Head Volume), expressed as a percentage.
  • Oil / Gas Break Even: The flat realized price at which the asset’s total undiscounted cash flow (revenue minus expenses, production taxes, and capital expenditures) equals zero over its producing life. Reported separately for oil ($/bbl) and gas ($/MCF), holding all other prices and costs constant.
  • Original WI Oil / Gas / NGL / Drip Condensate: The initial Working Interest percentage for each phase prior to any reversions.
  • Original NRI Oil / Gas / NGL / Drip Condensate: The initial Net Revenue Interest percentage for each phase prior to any reversions.
  • Consecutive Negative Cash Flow Months: Identifies periods where net cash flow is negative over successive months.
  • First / Last Consecutive Negative Cash Flow Month: The specific start and end months of a continuous negative cash flow period.
  • Consecutive / Total Negative Cash Flow Month Count: The duration of the longest sequential negative cash flow period, or the total count of negative cash flow months over the well's producing life.
  • First / Second / Third / Fourth Discount Rate: The specific percentage rates defined in the project assumptions used to calculate the present value of future cash flows.
  • 1 Year / 3 Year / Well Life Capital Efficiency Attribute: A designated metric used to evaluate capital performance over a 1-year, 3-year, or full well life timeframe.

Production Analytics

Every column in this section is a combination of three parts: a Timeframe, an Ownership Share, and a Base Metric (for example: 6 Mo Cum + Net + Oil Sales Volume). Here is how each part is defined:

1. Timeframes

These define the continuous period over which production is accumulated.

  • Months: 1, 3, and 6
  • Years: 1, 2, 3, 5, and 10
  • Recent: Last 1 and Last 3 months

2. Ownership Shares

  • Gross: The total unadjusted 8/8ths volume.
  • WI: Your Working Interest share of the gross volume.
  • Net: Your Net Revenue Interest share of the gross volume.

3. Base Metrics

  • Oil / Gas / NGL / Drip Condensate Well Head Volume: The unadjusted physical production forecast directly from the well, prior to surface losses.
  • Oil / Gas / NGL / Drip Condensate Sales Volume: The actual physical volume available for sale at the surface facility, after processing, shrinkage, and loss.
  • BOE / MCFE Well Head Volume: The total equivalent volume at the wellhead.
  • BOE / MCFE Sales Volume: The total equivalent volume available for sale at the surface facility.

Forecast Parameters

Every column in this section is built by combining three elements: a Fluid Phase, a Segment, and a Forecast Model (for example: Oil First Segment P50 or Gas Last Segment Best Fit). Here is how each part is defined:

1. Fluid Phases

  • Oil / Gas / Water: The specific physical production stream being forecast.

2. Segments

  • First Segment: The forecast parameters defining the initial decline phase of the curve.
  • Last Segment: The forecast parameters defining the final (terminal) decline phase of the curve.

3. Forecast Models

  • Assigned P Series: The specific probabilistic series (e.g., Proved, Probable, Possible) actively assigned to the well in the scenario.
  • P10 / P50 / P90: The standard probabilistic confidence intervals applied to the forecast.
  • Best Fit: The decline curve mathematically optimized to best match the historical production data.

8/8ths EUR - Econ Limit Applied

All columns in this section represent the Gross (8/8ths) Estimated Ultimate Recovery, truncated at the well's economic limit.

  • Oil / Gas / Water WH EUR: The total unadjusted 8/8ths EUR forecast directly from the wellhead, prior to surface losses.
  • Oil / Gas / NGL Shrunk EUR: The 8/8ths EUR available after shrinkage, extraction, or processing at the surface facility.
  • Drip Condensate EUR: The 8/8ths EUR of condensate recovered at the surface facility prior to gas processing.
  • Oil / Gas / Water WH EUR/PLL: The unadjusted wellhead EUR normalized by perforated lateral length.
    • Calculation: Divides the respective WH EUR by the well's perforated lateral length.
  • Oil / Gas / NGL Shrunk EUR/PLL: The processed (shrunk) EUR normalized by perforated lateral length.
    • Calculation: Divides the respective Shrunk EUR by the well's perforated lateral length.
  • Drip Condensate EUR/PLL: The Drip Condensate EUR normalized by perforated lateral length.
    • Calculation: Divides the Drip Condensate EUR by the well's perforated lateral length.

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