The Economic Analysis tool is a quick-look production flowstream calculator and cash flow analysis which is integrated with the production curve screen and the Decline Curve Analysis tool.
NOTE: ARIES RELEASE 2003.11, RELEASED IN JULY 2004, NOW IMPORTS DRILLINGINFO'S .DRI PRODUCTION DATA FORMAT.
Definitions of the required inputs are listed below with a brief explanation of each; (Also See Economic Analysis FAQ)
The Major Phase of an oil well is oil, and the Major Phase of a gas well is gas. The Decline Curve Analysis calculates the decline rate of the Major Phase only.
It is not necessary to run the Decline Curve Analysis tool prior to running Economic Analysis. However, if Decline Curve Analysis is run first, the calculated decline rate will be entered into the Economic Analysis as a default. The user can either utilize this decline rate or can enter his own decline rate. In either case, the decline rate is kept constant for the remaining life of the well. In this manner the production flowstream is calculated for the Major Phase. The Minor Phase production flowstream is then calculated by applying the GOR to the Major Phase production flowstream.
This is the user-defined, initial flowrate of the Major Phase of the well, or lease. Note that the units are BO/day (barrels of oil per day) or MCF/day (thousand cubic feet of gas per day) rather than per month, as shown on the production curve or tabular data. This is due to the fact that well production is most often discussed on a daily rate basis. To obtain the daily rate from the monthly rate, simply divide the monthly rate by the number of days in that month, or by 30.4 for an approximation.
The future production flowstream for the Major Phase is calculated by applying the Annual Decline Rate to the Initial Major Phase Flowrate. The future production flowstream for the Minor Phase production flowstream is then calculated by applying the GOR to the Major Phase production flowstream.
Typically, the Initial Major Phase Flowrate would be the average daily flowrate from the most recent month. However, the user might want to input a higher or lower value if he has more recent knowledge of a well problem or an enhancement, like putting the well on compression, artificial lift or stimulation.
Enter the expected gas price for the next fiscal year. Fiscal year in this program means today forward, or simply forward from whenever the user wishes the analysis to begin. The gas price can be escalated if desired by entering an escalation percentage after ”Escalation:”. The escalation will begin in fiscal year two and continue for the life of the well.
Enter the expected oil price for the next fiscal year. Fiscal year in this program means today forward, or whenever the user wishes the analysis to begin. The oil price can be escalated if desired by entering an escalation percentage after ”Escalation:”. The escalation will begin in fiscal year two and continue for the life of the well.
This is the heating value of the gas on a volumetric basis. BTU/SCF is the abbreviation for British Thermal Unit per Standard Cubic Foot. This information is available from gas analyses taken by the operator or purchaser. If the BTU content is unknown, the program uses a default BTU content of 1000 BTU/SCF, which is approximately that of pure methane.
Note that some refer to the heating value of gas in other units, such as MMBTU/MCF, or Million BTU per Thousand Cubic Feet. Using these units, 1000 BTU/SCF is equivalent to 1 MMBTU/MCF.
The program calculates the gas-oil-ratio (GOR) as an average from the historical production. Note that the term GOR is used for consistency on both oil and gas wells. The GOR is used to calculate the future Minor Phase flowstream, based on the declining Major Phase flowstream.
The user can enter a different GOR if desired.
The units for the GOR are scf/bbl, or standard cubic feet of gas per barrel of oil (or condensate).
Enter, in decimal form, the Working Interest (WI) owned in the lease. If an entity owns all of the lease, the working interest would be 100 % and would be entered as 1.0.
Enter, in decimal form, the Net Revenue Interest (NRI) owned in the lease. The NRI is the decimal revenue interest which is attributable to a given WI, after all royalty burdens are subtracted.
Royalty Interest (OPTIONAL):
If you wish to estimate the value of royalty interest (RI) then enter the decimal interest here. (Don’t enter the landowner’s royalty or total outstanding lease burdens just because you know it - if you don’t own it and/or don’t want to include it in your valuation, don’t include it.)
Note that in order to perform a valuation of royalty interest, you must enter the operator’s estimated WI and NRI (even though you own no WI or NRI) as well as the actual or estimated total Operating Expense. This allows the program to estimate the life of the well and then apply your royalty interest to the flowstream accordingly.
There are two options with respect to evaluating RI: Either ”Add royalty into NRI” or ”Calculate Royalty Value Only”. Shown below is an example of each situation:
Add royalty into NRI:
Example 1 &endash; Company owns WI, NRI and ORRI in a lease, wants ”composite” evaluation. XYZ Oil Company owns a 100 % WI and a 75 % NRI in the Smith lease. XYZ also owns a 2 % overriding royalty interest in the Smith lease. XYZ wants to evaluate all of their interests in the Smith lease on a ”composite” basis, so XYZ enters 1, 0.75 and 0.02 into the WI, NRI and RI boxes, respectively, and leaves the default ”Add royalty in to NRI” selected.
Example 2 &endash; Company owns WI, NRI & LORI in a lease, wants ”composite” evaluation. XYZ Oil Company owns a 100 % WI and a 75 % NRI in the Smith lease. XYZ also owns a 2 % mineral interest or ”landowner’s royalty interest” in the Smith lease. So XYZ enters 1, 0.75 and 0.02 into the WI, NRI and RI boxes, and leaves the default ”Add royalty in to NRI” selected. (same as in Example 1)
Example 3 &endash; Company owns WI, NRI & ORRI, wants estimated value of ORRI only
XYZ Oil Company owns a 100 % WI and a 75 % NRI in the Smith lease. XYZ also owns a 2 % ORRI in the Smith lease. So XYZ enters 1, 0.75 and 0.02 into the WI, NRI and RI boxes, and selects ”Calculate Royalty Value Only”.
Calculate Royalty Value Only:
Example 1 &endash; Royalty owner owns RI only, wants estimated value of RI
Mary had a little lamb, and she also had a 20 % royalty interest (RI) in the Black #1 well. She wants to estimate the value of this RI.
To do so, Mary needs to know the Operating Expenses for the Black #1 as well as the Operator’s working interest (WI) and net revenue interest (NRI) &endash; which she can perhaps obtain from the Operator, or must otherwise estimate. She needs to enter the Operator’s WI, NRI and the total Operating Expense (8/8th’s, or 100% of the Operating Expense) in the appropriate blanks on the input form.
Then Mary needs to input her RI in the appropriate blank, and she needs to select ”Calculate Royalty Value Only”.
Example 2 &endash; Geologist owns ORRI only, wants estimated value of ORRI
Basically the same as Example 1 except ORRI is used in Royalty Interest blank.
Enter the amount, in dollars per month, of the gross, or 8/8ths (100 % WI) operating expenses attributable to the well. This amount should not include ad valorem or severance taxes as these are handled separately. The operating expense can be escalated if desired by entering an escalation percentage after ”Esc.:”. The escalation will begin in fiscal year two and continue for the life of the well.
Severance and Ad Valorem (Property) Taxes:
Ad Valorem tax rates are estimated for each of several states. These are subject to change without notice, so the user should satisfy himself of the rates currently in effect. Any of these rates can be modified by the user. Note that some wells receive a severance tax exemption when they are brought back on production after a long shut-in period, or for other reasons.
The program utilizes an ad valorem tax rate of 2.5 % of gross revenue. Note that this is merely an estimate, and ad valorem taxes vary by county/school district. Also, property taxes are minimal in some states (such as WY).
Initial Capital Expenditure (OPTIONAL):
This input is OPTIONAL! This input represents an initial capital cost, such as the cost to drill and complete a well (”completed well cost”), or the cost of a proposed frac job on an existing well, the cost of a pipeline, etc. The Initial Capital Expenditure is not discounted, ie, it occurs at ”time zero”.
Note that the Payout and ROI metrics are based on the Initial Capital Expenditure. So, if the Initial Capital Expenditure is not input, then the program cannot determine a Payout or an ROI, since it has no ”investment” on which to calculate payout, or a return multiple.
Initial acquisition cost can be input as an Initial Capital Expenditure, however in most cases acquisitions are analyzed independent of the initial cost/value, rather than incorporating into the analysis. In other words, the cash flow stream of a producing property is modeled to determine a present value, then the user determines what discount rate represents his valuation of the property.
Payout occurs when the cumulative net cash flow plus the initial investment equals the Initial Capital Investment. Payout is in months from ”time zero”. Payout uses undiscounted cash flows.
Return On Investment is the cumulative net cash flow plus the initial investment divided by the Initial Capital Investment. ROI is often expressed as ”something-to-one”, i.e., three-to-one (3:1), reflecting a net cash flow (without subtracting the initial investment) of 3 times the initial investment. ROI uses undiscounted cash flows.
Future Capital Expenditure & Years in Future (OPTIONAL):
These inputs are both OPTIONAL, and they go together. DO NOT ENTER A VALUE FOR YEARS IN FUTURE UNLESS YOU ENTER THE FUTURE CAPITAL EXPENDITURE TO GO WITH IT.
A Future Capital Expenditure represents a large, capital cost that one estimates will need to be made at some time in the future. An example would be a $300,000 re-frac at the end of year 3. In this case you would enter 300000 as the Future Capital Expenditure and 3 as the Years In Future.
Years in Future does not set the length of the analysis, it only serves to place the Future Capital Expenditure at the correct time in the future.
You can save your analysis for future reference by entering a title in the text box and clicking on save.
One-Line Production and Cash Flow Summary:
One arrives at this page when a report is saved. This page serves both as an administrative page for editing, deleting or summing cash flows, and also as a convenient printable one-line summary.
To sum various cash flows, click the checkbox and then click on Sum Selected Cash Flows.
Other Program Notes/Assumptions
The program discounts cash flows as if both income and expenses occur at the end of each fiscal year, also known as year end discounting. In reality, revenue and expenses are received and disbursed on a monthly basis. Thus, on a positive cash flow well the year end discouting yields a somewhat lower discounted value than would be obtained with monthly discounting.
Cum refers to cumulative production.
RRR is an abreviation for remaining recoverable reserves, ie, what is left from the day of the analysis forward.
EUR is an abbreviation for expected ultimate recovery, which is simply the sum of the Cum and the RRR.
Different banks, corporations, individuals and other entities have different metrics for valuing oil and gas reserves. The ”Valuation Parameters” of NPV18, 50% of undiscounted cash flow and 3 year payout are offered only for the convenience of those who might use these metrics.