1. A. The valuation procedure below, which provides that the presence of oil or gas or the production thereof may be included in the methodology to determine the fair market value of an oil or gas well for ad valorem taxes, covers only that portion of the well, including the well’s associated leasehold equipment or “production train” subject to ad valorem taxation. Further, the valuation procedure below provides that no further or additional tax or license shall be levied or imposed on oil, gas or sulphur leases or rights and no additional value shall be added to the assessment of land due to the presence of oil, gas or sulphur or their production therefrom.

2. B. The presence of oil or gas, or the production thereof, is to be included in the year-by-year discounted cash flow (DCF) model described below and as adopted by the Louisiana Tax Commission to determine the fair market value of an oil or gas well and its associated leasehold equipment for ad valorem tax purposes in Louisiana.

   1. 1. Production Forecast—oil and gas or other hydrocarbon production history for the well, lease or facility represented by the LUW (Lease, Unit, or Well) code is to be analyzed by the assessor for relevant trends and patterns established as of January 1 of the current tax year, using Decline Curve Analysis or other accepted empirical method. A commensurate forecast of future production, or production potential, attributable to only the working interest owner(s), is to be made by the assessor as of January 1 of the current tax year. This production forecast will consist of a Start Rate as of January 1 (daily average barrels or mcf) and up to five exponential percentage decline rates for designated periods of time in the DCF. Alternatively, a hyperbolic forecast formula may be used when appropriate.

   2. 2. Price Forecast—the forecasted oil and gas or other hydrocarbon production amounts for the well, lease or facility represented by the LUW code, attributable to the working interest owner(s), are to be factored by an oil or gas or other hydrocarbon price forecast as of January 1 of the current tax year as annually determined by the Tax Commission to result in a forecasted gross revenue stream attributable to the working interest owner(s). This price forecast is based on the following guidelines:

      1. a. the forecasted oil and gas or other hydrocarbon price forecast shall begin with the immediately previous calendar year’s monthly average price (starting price) received by the working interest owner(s) for the oil and gas or other hydrocarbons produced and sold from the lease or facility represented by the LEW code on the open market to an unaffiliated third party or otherwise at a market-oriented rate. The source of this starting price shall correspond to severance tax data as reported by the operator to the Louisiana Department of Revenue;

         1. i. this previous year average price may vary by property;
         2. ii. if oil and gas or other hydrocarbons were either not produced or not sold for one or more months of the previous calendar year, the average price for which similar oil and gas from comparable interests was selling during that month is to be used;

      2. b. the previous year average price is to be increased or decreased, whichever is appropriate, for year 1 of the discounted cashflow analysis with a Price Adjustment Factor which will be commensurate with the percentage increase or decrease, respectively, as indicated by the forecasted price in the Energy Information Administration (EIA) January STEO (Short-Term Energy Outlook) report for the current tax year, relative to the actual price shown for the immediately previous calendar year in the same publication. These two prices can be referenced in the report’s Table 2. Energy Prices:

         1. i. for oil, reference “West Texas Intermediate Spot Average” (dollars per barrel);
         2. ii. for natural gas, reference “Henry Hub Spot” (dollars per million Btu);
         3. iii. this price adjustment factor is to be used in the appraisal of each property, to the extent the property’s forecasted cash flow extends to year 1;

      3. c. the year 1 price used in the DCF appraisal is to be either increased or decreased, whichever is appropriate, in four more or less equal percentage increments to a year 5 price considered to be representative to a long-term average price available for the sale of oil and gas from the property as calculated with reference to the last 20 years of historical oil and gas price data from the Energy Information Administration (EIA);

         1. i. the long-term average price is to be calculated after removal of outlier prices, if any, within the 20-year range, defined as any historical price outside of one standard deviation from the simple average.
         2. ii. these percentages are to be used in the appraisal of each property, to the extent the property’s forecasted cash flow extends to either years 2, 3, 4, or 5.
      4. d. the year 5 price used in the DCF appraisal is to be held flat for all years thereafter in the DCF, to the extent the property’s forecasted cash flow extends past year 5;
      5. e. the five oil and gas price forecast percentages discussed above, along with the zero percent escalation for any years in the DCF past year 5, together constitute the “price forecast scenario” as established by the Tax Commission and are to be used in the DCF appraisal of each property. This oil and gas price forecast scenario will be published on the LTC website.

   3. 3. Expense Forecast—in the DCF appraisal of the property, the forecasted gross revenues attributable to the working interest owner(s) are to be reduced for the allowance of reasonable and defendable direct costs of operation, as well as, all applicable state and local tax burden, to result in a forecasted net income stream attributable to the working interest owner(s) of the specific property being appraised. This cost allowance should represent the amount and timing of recurring expense, including overhead, along with any applicable non-recurring (capital) expense(s), typical to the area and similar operations and not necessarily the exact expenses incurred in any previous year, deemed reasonable and necessary for the property to achieve the forecasted oil and gas production amounts:

      1. a. an assessor should make effort to obtain and consider actual historical expenses being incurred by the operator as documented on expense statements required to be provided to the assessor pursuant to §903.C. Absent this information, an assessor may assume a minimal amount and/or otherwise rely on their own judgement using best information available;
      2. b. the increase or decrease of direct operating expense allowance in the cash flow appraisal will correspond to the increase or decrease in forecasted price, as established by the Tax Commission;
      3. c. as a default, the percentage increase or decrease for each forecasted year of the cash flow appraisal will be calculated at one-third (1/3) of the percentage increase or decrease in price for that year relative to the previous year price, referencing the price of the property’s primary hydrocarbon being produced. However, when circumstances clearly dictate a departure from this protocol is necessary to achieve a more accurate forecast, operating expenses can be increased or decreased at a different percentage through year 5 of the cash flow;
      4. d. the provision for increase or decrease of the direct operating expense allowance does not pertain to separate allowance, if any, of capital expense(s) in the property’s cash flow appraisal.

   4. 4. Discount Rate—the forecasted net income amounts in the property’s DCF appraisal are to be discounted (reduced) to present day worth by application of a discount factor for each year of the forecasted cash flow commensurate with an appropriate discount rate:

      1. a. the discount rate may vary by property;
      2. b. base discount rates to account for the time cost of money and general industry risk are to be established by the Tax Commission. These discount rates separately extend to oil wells vs. gas wells and are shown in Table 907.C-2. This is a minimum rate whereas the assessor may use a higher rate to account for additional property-specific risks and/or other considerations as appropriate for the determination of each property’s market value;
      3. c. these discount rates applies only to the forecasted net income of the DCF appraisal. A separate discount rate is established by the Louisiana Tax Commission to be applicable to valuation of the oil and gas wells’ associated leasehold equipment (production train) and is shown in Table 907.C-2.

3. C. In the event the DCF appraisal results in a zero economic life and/or zero or negative discounted net income, a minimum amount of value will be established for the leasehold equipment (production train) associated with the oil and gas well(s) represented by the DCF, applying the appropriate schedule value in Table 907.C-3 to the average production depth of the wells represented by the DCF.

   1. 1. In the event the DCF appraisal results in a positive value but less than the minimum equipment value as derived using Table 907.C-3, the assessed value will be based on the minimum equipment value as established by Table 907.C-3.

   2. 2. Oil and Gas Well Discount Rates

      Table 907.C-2 Oil and Gas Well Discount Rates
      Primary Product	Discount Rate (%)
      Oil Well	15%
      Gas Well	15%
      Leasehold Equipment	6%

   3. 3. Minimum Leasehold Equipment Value

      Table 907.C-3 Minimum Leasehold Equipment Value
      Onshore/Offshore	Average Production Depth (feet)	Value Per Foot ($)
      Onshore	1 – 1,499	0.50
      Onshore	1,500 – 2,499	0.75
      Onshore	2,500 – 9,999	1.00
      Onshore	10,000 or greater	1.50
      Offshore *	All Depths	2.00

      *Includes production platforms/barges.

   4. 4. Serial Number to Percent Good Conversion Chart

      Table 907.C-4 Serial Number to Percent Good Conversion Chart
      Year	Beginning Serial Number	Ending Serial Number	20 Year Life Percent Good
      2025	254960	Higher	97
      2024	254511	254959	93
      2023	253984	254510	90
      2022	253176	253983	86
      2021	252613	253175	82
      2020	252171	252612	78
      2019	251497	252170	74
      2018	250707	251496	70
      2017	249951	250706	65
      2016	249476	249950	60
      2015	248832	249475	55
      2014	247423	248831	50
      2013	245849	247422	45
      2012	244268	245848	40
      2011	242592	244267	35
      2010	240636	242591	31
      2009	239277	240635	27
      2008	236927	239276	24
      2007	234780	236926	22
      2006	232639	234779	21
      2005	Lower	232638	20 *
      VAR.	900000	Higher	50

      *Reflects residual or floor rate.

4. D. Surface Equipment

   1. 1. Listed below is the cost-new of major items used in the production, storage, transmission and sale of oil and gas. Any equipment not shown shall be assessed on an individual basis.
   2. 2. All surface equipment, including other property associated or used in connection with the oil and gas industry in the field of operation, must be rendered in accordance with guidelines established by the Tax Commission and in accordance with requirements set forth on LAT Form 12- Personal Property Tax Report - Oil and Gas Property.

   3. 3. Surface equipment will be assessed in 5 major categories, as follows:

      1. a. oil and gas equipment (surface equipment not considered leasehold equipment);
      2. b. tanks (surface equipment not considered leasehold equipment);
      3. c. inventories (material and supplies);
      4. d. field improvements (docks, buildings, etc.);
      5. e. other property (not included above).

   4. 4. The cost-new values listed below are to be adjusted to allow depreciation by use of the appropriate percent good listed in Table 907.C-4. When determining the value of equipment associated with a single well, use the age of that well to determine the appropriate percent good. When determining the value of equipment used on multiple wells, the average age of the wells within the lease/field will determine the appropriate year to be used for this purpose.

      1. a. January 1, 2016 the allowance of depreciation by use of the appropriate percent good will be based on the actual age of the equipment, if known or available, and will apply only to surface equipment with an original purchase cost of $2,500 or more.
   5. 5. Functional and/or economic obsolescence shall be considered in the analysis of fair market value as substantiated by the taxpayer in writing. Consistent with Louisiana R.S. 47:1957, the assessor may request additional documentation.
   6. 6. Sales, properly documented, should be considered by the assessor as fair market value, provided the sale meets all tests relative to it being a valid sale.

   7. 7. Surface Equipment—Property Description

      Table 907.D-7 Surface Equipment
      Property Description	$ Cost New
      Actuators—(see Metering Equipment)
      Automatic Control Equipment—(see Safety Systems)
      Automatic Tank Switch Unit—(see Metering Equipment)
      Barges - Concrete—(assessed on an individual basis)
      Barges - Storage—(assessed on an individual basis)
      Barges - Utility—(assessed on an individual basis)
      Barges - Work—(assessed on an individual basis)
      Communication Equipment—(see Telecommunications)
      Dampeners—(see Metering Equipment—"Recorders")
      Desorbers—(no metering equipment included): 125# 300# 500#	141,800 156,350 177,930
      Destroilets—(see Metering Equipment—"Regulators")
      Desurgers—(see Metering Equipment—"Regulators")
      Desilters—(see Metering Equipment—"Regulators")
      Diatrollers—(see Metering Equipment—"Regulators")
      Docks, Platforms, Buildings—(assessed on an individual basis)
      Dry Dehydrators (Driers)—(see Scrubbers)
      Engines-Unattached—(only includes engine and skids): Per Horsepower	440
      Evaporators—(assessed on an individual basis)
      Expander Unit—(no metering equipment included): Per Unit	52,010
      Flow Splitters—(no metering equipment included): 48 In. Diameter Vessel 72 In. Diameter Vessel 96 In. Diameter Vessel 120 In. Diameter Vessel	25,320 33,550 51,420 73,040
      Fire Control System—(assessed on an individual basis)
      Furniture and Fixtures—(assessed on an individual basis) (Field operations only, according to location.)
      Gas Compressors-Package Unit—(Skids, scrubbers, cooling system, and power controls. No metering or regulating equipment.): 1 - 49 HP 50 - 99 HP 100 - 999 HP 1,000 - 1,499 HP 1,500 HP and Up	930 1,870 1,520 1,160 1,030
      Gas Coolers—(no metering equipment); 5,000 MCF/D 10,000 MCF/D 20,000 MCF/D 50,000 MCF/D 100,000 MCF/D	39,960 45,000 139,990 317,620 520,190
      Generators—Package Unit only -(no special installation) Per K.W.	300
      Glycol Dehydration-Package Unit—(Including pressure gauge, relief valve and regulator. No other metering equipment.): Up to 4.0 MMCF/D 4.1 to 5.0 MMCF/D 5.1 to 10.0 MMCF/D 10.1 to 15.0 MMCF/D 15.1 to 20.0 MMCF/D 20.1 to 25.0 MMCF/D 25.1 to 30.0 MMCF/D 30.1 to 50.0 MMCF/D 50.1 to 75.0 MMCF/D 75.1 and Up MMCF/D	28,050 31,280 60,310 83,910 114,220 148,520 282,110 315,130 392,030 452,340
      Heaters—(Includes unit, safety valves, regulators and automatic shut-down. No metering equipment.): Steam Bath—Direct Heater: 24 In. Diameter Vessel - 250,000 BTU/HR Rate 30 In. Diameter Vessel - 500,000 BTU/HR Rate 36 In. Diameter Vessel - 750,000 BTU/HR Rate 48 In. Diameter Vessel - 1,000,000 BTU/HR Rate 60 In. Diameter Vessel - 1,500,000 BTU/HR Rate Water Bath—Indirect Heater: 24 In. Diameter Vessel - 250,000 BTU/HR Rate 30 In. Diameter Vessel - 500,000 BTU/HR Rate 36 In. Diameter Vessel - 750,000 BTU/HR Rate 48 In. Diameter Vessel - 1,000,000 BTU/HR Rate 60 In. Diameter Vessel - 1,500,000 BTU/HR Rate Steam—(Steam Generators): 24 In. Diameter Vessel - 250,000 BTU/HR Rate 30 In. Diameter Vessel - 450,000 BTU/HR Rate 36 In. Diameter Vessel - 500 to 750,000 BTU/HR Rate 48 In. Diameter Vessel - 1 to 2,000,000 BTU/HR Rate 60 In. Diameter Vessel - 2 to 3,000,000 BTU/HR Rate 72 In. Diameter Vessel - 3 to 6,000,000 BTU/HR Rate 96 In. Diameter Vessel - 6 to 8,000,000 BTU/HR Rate	9,730 12,220 14,780 21,860 26,990 8,300 11,390 14,850 21,030 26,920 10,630 13,270 19,910 22,840 25,860 40,860 49,080
      Heat Exchange Units-Skid Mounted—(see Production Units)
      Heater Treaters—(Necessary controls, gauges, valves and piping. No metering equipment included.): Heater - Treaters - (non-metering): 4 x 20 ft. 4 x 27 ft. 6 x 20 ft. 6 x 27 ft. 8 x 20 ft. 8 x 27 ft. 10 x 20 ft. 10 x 27 ft.	21,260 27,370 28,650 36,030 45,910 53,740 60,690 71,410
      L.A.C.T. (Lease Automatic Custody Transfer)—see Metering Equipment)
      JT Skid (Low Temperature Extraction)—(includes safety valves, temperature controllers, chokes, regulators, metering equipment, etc.—complete unit.): Up to 2 MMCF/D Up to 5 MMCF/D Up to 10 MMCF/D Up to 20 MMCF/D	52,770 75,390 180,940 301,550
      Liqua Meter Units—(see Metering Equipment)
      Manifolds—(see Metering Equipment)
      Material and Supplies-Inventories—(assessed on an individual basis)
      Meter Calibrating Vessels—(see Metering Equipment)
      Meter Prover Tanks—(see Metering Equipment)
      Meter Runs—(see Metering Equipment)
      Meter Control Stations—(not considered Communication Equipment) - (assessed on an individual basis)
      Metering Equipment Actuators—hydraulic, pneumatic and electric valves Controllers—time cycle valve - valve controlling device (also known as Intermitter) Fluid Meters: 1 Level Control 24 In. Diameter Vessel - 1/2 bbl. Dump 30 In. Diameter Vessel - 1 bbl. Dump 36 In. Diameter Vessel - 2 bbl. Dump 2 Level Control 20 In. Diameter Vessel - 1/2 bbl. Dump 24 In. Diameter Vessel - 1/2 bbl. Dump 30 In. Diameter Vessel - 1 bbl. Dump 36 In. Diameter Vessel - 2 bbl. Dump	8,210 2,560 6,250 8,070 11,160 5,880 7,080 8,890 11,980
      L.A.C.T. and A.T.S. Units: 30 lb. Discharge 60 lb. Discharge Manifolds—Manual Operated: High Pressure per well per valve Low Pressure per well per valve	39,510 45,000 30,980 10,490 15,000 4,970
      Manifolds—Automatic Operated: High Pressure per well per valve Low Pressure per well per valve NOTE: Automatic Operated System includes gas hydraulic and pneumatic valve actuators, (or motorized valves), block valves, flow monitors-in addition to normal equipment found on manual operated system. No Metering Equipment Included.	56,020 18,470 39,960 13,490
      Meter Runs—piping, valves and supports—no meters: 2 In. piping and valve 3 In. piping and valve 4 In. piping and valve 6 In. piping and valve 8 In. piping and valve 10 In. piping and valve 12 In. piping and valve 14 In. piping and valve 16 In. piping and valve 18 In. piping and valve 20 In. piping and valve 22 In. piping and valve 24 In. piping and valve Metering Vessels (Accumulators): 1 bbl. calibration plate (20 x 9) 5 bbl. calibration plate (24 x 10) 7.5 bbl. calibration plate (30 x 10) 10 bbl. calibration plate (36 x 10) Recorders (Meters)—Includes both static element and tube drive pulsation dampener-also one and two pen operations. per meter Solar Panel (also see Telecommunications) per unit (10' x 10')	8,440 9,500 11,470 15,980 24,000 31,960 39,960 54,420 71,090 88,060 114,430 144,220 176,570 4,900 5,270 7,390 9,190 3,400 440
      Pipe Lines—Lease Lines Steel 2 In. nominal size - per mile 2 1/2 In. nominal size - per mile 3 and 3 1/2 In. nominal size - per mile 4, 4 1/2 and 5 In. nominal size - per mile 6 In. nominal size - per mile Poly Pipe 2 In. nominal size - per mile 2 1/2 In. nominal size - per mile 3 In. nominal size - per mile 4 In. nominal size - per mile 6 In. nominal size - per mile	24,570 33,090 42,220 72,600 106,600 13,490 18,180 23,220 39,880 58,570
      Plastic-Fiberglass 2 In. nominal size - per mile 3 In. nominal size - per mile 4 In. nominal size - per mile 6 In. nominal size - per mile NOTE: Allow 90 percent obsolescence credit for lines that are inactive, idle, open on both ends and dormant, which are being carried on corporate records solely for the purpose of retaining right of ways on the land and/or due to excessive capital outlay to refurbish or remove the lines.	20,960 35,880 61,670 90,530
      Pipe Stock—(assessed on an individual basis)
      Pipe Stock - Exempt—Under La. Const., Art. X, §4 (19-C)
      Production Units: Class I - per unit—separator and 1 heater—500 MCF/D Class II - per unit—separator and 1 heater—750 MCF/D	26,540 35,350
      Production Process Units—These units are by specific design and not in the same category as gas compressors, liquid and gas production units or pump-motor units. (Assessed on an individual basis.)
      Pumps—In Line per horsepower rating of motor	370
      Pump-Motor Unit—pump and motor only Class I - (water flood, s/w disposal, p/l, etc.) Up to 300 HP - per HP of motor Class II - (high pressure injection, etc.) 301 HP and up per HP of motor	440 540
      Pumping Units-Conventional and Beam Balance—(unit value includes motor) - assessed according to API designation. 16 D 25 D 40 D 57 D 80 D 114 D 160 D 228 D 320 D 456 D 640 D 912 D NOTE: For "Air Balance" and "Heavy Duty" units, multiply the above values by 1.30.	8,670 16,290 20,350 27,140 45,310 47,120 63,400 68,820 87,000 103,290 125,070 132,310
      Regenerators (Accumulator)—(see Metering Equipment)
      Regulators: per unit	3,470
      Safety Systems Onshore And Marsh Area Basic Case: well only well and production equipment with surface op. ssv, add Offshore 0 - 3 Miles Wellhead safety system (excludes wellhead actuators) per well production train glycol dehydration system P/L pumps and LACT Compressors Wellhead Actuators (does not include price of the valve) 5,000 psi 10,000 psi and over NOTE: For installation costs - add 25 percent	6,930 8,000 11,980 19,980 49,990 30,010 69,970 43,950 4,970 7,460
      Sampler—(see Metering Equipment—"Fluid Meters")
      Scrubbers—Two Classes Class I - Manufactured for use with other major equipment and, at times, included with such equipment as part of a package unit. 8 In. Diameter Vessel 10 In. Diameter Vessel 12 In. Diameter Vessel Class II - Small "in-line" scrubber used in flow system usually direct from gas well. Much of this type is "shop-made" and not considered as major scrubbing equipment. 8 In. Diameter Vessel 12 In. Diameter Vessel NOTE: No metering or regulating equipment included in the above.	4,220 6,020 6,860 1,960 2,560
      Separators—(no metering equipment included) Horizontal—Filter /1,440 psi (High Pressure) 6-5/8” OD x 5’-6” 8-5/8” OD x 7’-6” 10-3/4” OD x 8’-0” 12-3/4” OD x 8’-0” 16” OD x 8’-6” 20” OD x 8’-6” 20” OD x 12’-0” 24” OD x 12’-6” 30” OD x 12’-6” 36” OD x 12’-6”	6,180 6,710 9,420 12,660 20,350 30,080 31,660 42,670 62,280 74,030
      Separators—(no metering equipment included) Vertical 2—Phase /125 psi (Low Pressure) 24” OD x 7’-6” 30” OD x 10’-0” 36” OD x 10’-0” Vertical 3—Phase /125 psi (Low Pressure) 24” OD x 7’-6” 24” OD x 10’-0” 30” OD x 10’-0” 36” OD x 10’-0” 42” OD x 10’-0” Horizontal 3—Phase /125 psi (Low Pressure) 24” OD x 10’-0” 30” OD x 10’-0” 36” OD x 10’-0” 42” OD x 10’-0”	7,000 7,550 15,760 7,390 8,370 11,610 16,510 19,160 10,930 14,020 15,310 24,420
      Vertical 2—Phase /1440 psi (High Pressure) 12-3/4” OD x 5’-0” 16” OD x 5’-6” 20” OD x 7’-6” 24” OD x 7’-6” 30” OD x 10’-0” 36” OD x 10’-0” 42” OD x 10’-0” 48” OD x 10’-0” 54” OD x 10’-0” 60” OD x 10’-0” Vertical 3 - Phase /1440 psi (High Pressure) 16” OD x 7’-6” 20” OD x 7’-6” 24” OD x 7’-6” 30” OD x 10’-0” 36” OD x 10’-0” 42” OD x 10’-0” 48” OD x 10’-0” Horizontal 2—Phase /1440 psi (High Pressure) 16” OD x 7’-6” 20” OD x 7’-6” 24” OD x 10’-0” 30” OD x 10’-0” 36” OD x 10’-0” 42” OD x 15’-0” 48” OD x 15’-0” Horizontal 3—Phase /1440 psi (High Pressure) 16” OD x 7’-6” 20” OD x 7’-6” 24” OD x 10’-0” 30” OD x 10’-0” 36” OD x 10’-0” 36” OD x 15’-0” Offshore Horizontal 3—Phase /1440 psi (High Pressure) 30” OD x 10’-0” 36” OD x 10’-0” 36” OD x 12’-0” 36” OD x 15’-0” 42” OD x 15’-0”	4,150 6,180 11,760 14,250 21,710 28,120 45,000 53,080 80,360 100,500 7,240 12,660 14,700 22,690 29,030 47,350 54,890 7,080 11,390 15,530 23,900 30,300 61,510 70,940 10,930 12,220 17,790 25,320 36,490 40,780 52,550 50,140 72,750 75,920 117,830
      Skimmer Tanks—(see Flow Tanks in Tanks section)
      Stabilizers—per unit	7,760
      Sump/Dump Tanks—(See Metering Equipment -"Fluid Tanks")
      Tanks—no metering equipment Flow Tanks (receiver or gunbarrel) 50 to 548 bbl. Range (average tank size - 250 bbl.) Stock Tanks (lease tanks) 100 to 750 bbl. Range (average tank size – 300 bbl.)	Per Barrel* 48.50 37.80
      Storage Tanks (Closed Top) 1,000 barrel 1,500 barrel 2,000 barrel 2,001 - 5,000 barrel 5,001 - 10,000 barrel 10,001 - 15,000 barrel 15,001 - 55,000 barrel 55,001 - 150,000 barrel Internal Floating Roof 10,000 barrel 20,000 barrel 30,000 barrel 50,000 barrel 55,000 barrel 80,000 barrel 100,000 barrel *I.E.: (tanks size bbls.) X (no. of bbls.) X (cost-new factor.)	32.10 28.40 27.60 25.30 23.80 22.30 15.60 11.70 45.80 31.00 23.10 20.50 19.80 17.50 15.20
      Telecommunications Equipment Microwave System Telephone and data transmission Radio telephone Supervisory controls: remote terminal unit, well master station towers (installed): heavy duty, guyed, per foot light duty, guyed, per foot heavy duty, self supporting, per foot light duty, self supporting, per foot equipment building, per sq. ft. solar panels, per sq. ft.	60,310 4,520 12,890 29,400 760 60 770 150 220 70
      Utility Compressors per horsepower - rated on motor	990
      Vapor Recovery Unit—no Metering Equipment 60 MCF/D or less 105 MCF/D max 250 MCF/D max	26,390 37,700 49,760
      Waterknockouts—Includes unit, backpressure valve and regulator, but, no metering equipment. 2’ diam. x 16’ 3’ diam. x 10’ 4’ diam. x 10’ 6’ diam. x 10’ 6’ diam. x 15’ 8’ diam. x 10’ 8’ diam. x 15’ 8’ diam. x 20’ 8’ diam. x 25’ 10’ diam. x 20’	7,160 10,710 14,780 24,200 27,980 35,050 40.260 44,620 49,680 58,430

   8. 8. Service Stations

      Table 907.D-8 Service Stations Marketing Personal Property *Alternative Procedure
      Property Description	$ Cost New
      Air and Water Units: Above ground Below ground	1,680 710
      Air Compressors: 1/3 to 1 H.P. 1/2 to 5 H.P.	2,260 3,820
      Car Wash Equipment: In Bay (roll over brushes) In Bay (pull through) Tunnel (40 to 50 ft.) Tunnel (60 to 75 ft.)	60,690 94,220 205,070 274,420
      Drive On Lifts: Single Post Dual Post	11,080 12,480
      Lights: Light Poles (each) Lights - per pole unit	1,120 1,260
      Pumps: Non-Electronic - self contained and/or remote controlled computer Single Dual Computerized - non-self service, post pay, pre/post pay. self contained and/or remote controlled dispensers Single Dual	4,800 7,130 8,110 10,930
      Read-Out Equipment (at operator of self service) Per Hose Outlet	1,780
      Signs: Station Signs 6 ft. lighted - installed on 12 ft. pole 10 ft. lighted - installed on 16 ft. pole Attachment Signs (for station signs) Lighted "self-serve" (4 x 11 ft.) Lighted "pricing" (5 x 9 ft.) High Rise Signs - 16 ft. lighted - installed on: 1 pole 2 poles 3 poles Attachment Signs (for high rise signs) Lighted "self-serve" (5 x 17 ft.) Lighted "pricing" (5 x 9 ft.)	5,360 9,800 4,470 4,560 16,230 21,240 23,760 8,630 4,560
      Submerged Pumps—(used with remote control equipment, according to number used - per unit)	4,790
      Tanks—(average for all tank sizes) Underground - per gallon	2.80

      *This alternative assessment procedure should be used only when acquisition cost and age are unknown or unavailable. Otherwise, see general business section (Chapter 25) for normal assessment procedure.

NOTE: For any serial number categories not listed above, use year well completed to determine appropriate percent good. If spud date is later than year indicated by serial number; or, if serial number is unknown, use spud date to determine appropriate percent good.

NOTE: The above represents the cost-new value of modern stations and self-service marketing equipment. Other costs associated with such equipment are included in improvements. Old style stations and equipment should be assessed on an individual basis, at the discretion of the tax assessor, when evidence is furnished to substantiate such action.

Authority Note

AUTHORITY NOTE: Promulgated in accordance with R.S. 47:1837 and R.S. 47:2326.

Historical Note

HISTORICAL NOTE: Promulgated by the Department of Revenue and Taxation, Tax Commission, LR 8:102 (February 1982), amended LR 12:36 (January 1986), LR 13:188 (March 1987), LR 13:764 (December 1987), LR 14:872 (December 1988), LR 15:1097 (December 1989), LR 16:1063 (December 1990), LR 17:1213 (December 1991), LR 19:212 (February 1993), LR 20:198 (February 1994), LR 21:186 (February 1995), LR 22:117 (February 1996), LR 23:205 (February 1997), amended by the Department of Revenue, Tax Commission, LR 24:480 (March 1998), LR 25:313 (February 1999), LR 26:507 (March 2000), LR 27:425 (March 2001), LR 28:518 (March 2002), LR 29:368 (March 2003), LR 30:488 (March 2004), LR 31:717 (March 2005), LR 32:431 (March 2006), LR 33:492 (March 2007), LR 34:679 (April 2008), LR 35:495 (March 2009), LR 36:773 (April 2010), amended by the Office of the Governor, Division of Administration, Tax Commission, LR 37:1395 (May 2011), LR 38:803 (March 2012), LR 39:490 (March 2013), LR 40:531 (March 2014), LR 41:673 (April 2015), LR 42:746 (May 2016), LR 43:653 (April 2017), LR 44:580 (March 2018), repromulgated LR 44:917 (May 2018), LR 45:534 (April 2019), LR 46:561 (April 2020), LR 47:465 (April 2021), LR 48:1523 (June 2022), LR 49:1049 (June 2023), LR 50:361 (March 2024), LR 51:384 (March 2025), LR 52:962 (June 2026).