La. Admin. Code tit. 61 § V-907

Current through Register Vol. 50, No. 11, November 20, 2024

Section V-907 - Valuation of Oil, Gas, and Other Wells

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.

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. 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. 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:

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;

i. this previous year average price may vary by property;

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;

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:

i. for oil, reference "West Texas Intermediate Spot Average" (dollars per barrel);

ii. for natural gas, reference "Henry Hub Spot" (dollars per million Btu);

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;

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);

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.

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.

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;

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. 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:

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;

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;

c. the percentage increase or decrease for each forecasted year of the cash flow appraisal will be calculated at 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;

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. 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:

a. the discount rate may vary by property;

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;

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.

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. 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. 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. 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. 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
2023	253984	Higher	97
2022	253176	253983	93
2021	252613	253175	90
2020	252171	252612	86
2019	251497	252170	82
2018	250707	251496	78
2017	249951	250706	74
2016	249476	249950	70
2015	248832	249475	65
2014	247423	248831	60
2013	245849	247422	55
2012	244268	245848	50
2011	242592	244267	45
2010	240636	242591	40
2009	239277	240635	35
2008	236927	239276	31
2007	234780	236926	27
2006	232639	234779	24
2005	230643	232638	22
2004	229010	230642	21
2003	Lower	229009	20 *
VAR.	900000	Higher	50

*Reflects residual or floor rate.

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.

D. Surface Equipment

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

a. oil and gas equipment (surface equipment not considered leasehold equipment);

b. tanks (surface equipment not considered leasehold equipment);

c. inventories (material and supplies);

d. field improvements (docks, buildings, etc.);

e. other property (not included above).

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.

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. 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. 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. 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#	134,830
300#	148,660
500#	169,170
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	420
Evaporators-(assessed on an individual basis)
Expander Unit-(no metering equipment included): Per Unit	49,460
Flow Splitters-(no metering equipment included): 48 In. Diameter Vessel 72 In. Diameter Vessel 96 In. Diameter Vessel 120 In. Diameter Vessel	24,080 31,900 48,890 69,450
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.):	880 1,780
1 - 49 HP	1,450
50 - 99 HP	1,110
100 - 999 HP	980
1,000 - 1,499 HP
1,500 HP and Up
Gas Coolers-(no metering equipment); 5,000 MCF/D	37,990
10,000 MCF/D	42,790
20,000 MCF/D	133,110
50,000 MCF/D	302,000
100,000 MCF/D	494,600
Generators-Package Unit only -(no special installation) Per K.W.	280
Glycol Dehydration-Package Unit-(Including pressure gauge, relief valve and regulator. No other metering equipment.):	26,670 29,740
Up to 4.0 MMCF/D	57,340
4.1 to 5.0 MMCF/D	79,790
5.1 to 10.0 MMCF/D	108,600
10.1 to 15.0 MMCF/D	141,210
15.1 to 20.0 MMCF/D	268,230
20.1 to 25.0 MMCF/D	299,630
25.1 to 30.0 MMCF/D	372,750
30.1 to 50.0 MMCF/D	430,090
50.1 to 75.0 MMCF/D
75.1 and Up MMCF/D
Heaters-(Includes unit, safety valves, regulators and automatic shut-down. No metering equipment.):	9,250
Steam Bath-Direct Heater:	11,620
24 In. Diameter Vessel - 250,000 BTU/HR Rate	14,050
30 In. Diameter Vessel - 500,000 BTU/HR Rate	20,790
36 In. Diameter Vessel - 750,000 BTU/HR Rate	25,660
48 In. Diameter Vessel - 1,000,000 BTU/HR Rate	7,890
60 In. Diameter Vessel - 1,500,000 BTU/HR Rate	10,830
Water Bath-Indirect Heater:	14,120
24 In. Diameter Vessel - 250,000 BTU/HR Rate	20,000
30 In. Diameter Vessel - 500,000 BTU/HR Rate	25,590
36 In. Diameter Vessel - 750,000 BTU/HR Rate	10,110
48 In. Diameter Vessel - 1,000,000 BTU/HR Rate	12,620
60 In. Diameter Vessel - 1,500,000 BTU/HR Rate	18,930
Steam-(Steam Generators):	21,720
24 In. Diameter Vessel - 250,000 BTU/HR Rate	24,590
30 In. Diameter Vessel - 450,000 BTU/HR Rate	38,850
36 In. Diameter Vessel - 500 to 750,000 BTU/HR Rate	46,670
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
Heat Exchange Units-Skid Mounted-(see Production Units)
Heater Treaters-(Necessary controls, gauges, valves and piping. No metering equipment included.):	20,210
Heater - Treaters - (non-metering):	26,020
4 x 20 ft.	27,240
4 x 27 ft.	34,260
6 x 20 ft.	43,650
6 x 27 ft.	51,100
8 x 20 ft.	57,710
8 x 27 ft.	67,890
10 x 20 ft.
10 x 27 ft.
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.):	50,170 71,680
Up to 2 MMCF/D	172,040
Up to 5 MMCF/D	286,720
Up to 10 MMCF/D
Up to 20 MMCF/D
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	7,810
Controllers-time cycle valve - valve controlling device (also known as Intermitter)	2,440 5,940
Fluid Meters:	7,670
1 Level Control	10,610
24 In. Diameter Vessel - 1/2 bbl. Dump	5,590
30 In. Diameter Vessel - 1 bbl. Dump	6,730
36 In. Diameter Vessel - 2 bbl. Dump	8,460
2 Level Control	11,390
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
L.A.C.T. and A.T.S. Units:
30 lb. Discharge	37,560
60 lb. Discharge	42,790
Manifolds-Manual Operated:	29,460
High Pressure	9,970
per well	14,260
per valve	4,730
Low Pressure
per well
per valve
Manifolds-Automatic Operated:
High Pressure	53,260
per well	17,560
per valve	37,990
Low Pressure	12,830
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.
Meter Runs-piping, valves and supports-no meters:
2 In. piping and valve	8,030
3 In. piping and valve	9,030
4 In. piping and valve	10,900
6 In. piping and valve	15,190
8 In. piping and valve	22,820
10 In. piping and valve	30,390
12 In. piping and valve	37,990
14 In. piping and valve	51,750
16 In. piping and valve	67,590
18 In. piping and valve	83,730
20 In. piping and valve	108,810
22 In. piping and valve	137,130
24 In. piping and valve	167,880
Metering Vessels (Accumulators):	4,660
1 bbl. calibration plate (20 x 9)	5,010
5 bbl. calibration plate (24 x 10)	7,030
7.5 bbl. calibration plate (30 x 10)	8,740
10 bbl. calibration plate (36 x 10)	3,230
Recorders (Meters)-Includes both static element and tube drive pulsation dampener-also one and two pen operations.	420
per meter
Solar Panel (also see Telecommunications)
per unit (10' x 10')
Pipe Lines-Lease Lines
Steel	23,360
2 In. nominal size - per mile	31,470
2 1/2 In. nominal size - per mile	40,150
3 and 3 1/2 In. nominal size - per mile	69,030
4, 4 1/2 and 5 In. nominal size - per mile	101,360
6 In. nominal size - per mile	12,830
Poly Pipe	17,280
2 In. nominal size - per mile	22,080
2 1/2 In. nominal size - per mile	37,920
3 In. nominal size - per mile	55,690
4 In. nominal size - per mile
6 In. nominal size - per mile
Plastic-Fiberglass
2 In. nominal size - per mile	19,930
3 In. nominal size - per mile	34,120
4 In. nominal size - per mile	58,640
6 In. nominal size - per mile	86,080
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.
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	25,230
Class II - per unit-separator and 1 heater-750 MCF/D	33,610
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	350
Pump-Motor Unit-pump and motor only
Class I - (water flood, s/w disposal, p/l, etc.)	420
Up to 300 HP - per HP of motor	510
Class II - (high pressure injection, etc.)
301 HP and up per HP of motor
Pumping Units-Conventional and Beam Balance-(unit value includes motor) - assessed according to API designation.	8,240 15,490
16 D	19,350
25 D	25,810
40 D	43,080
57 D	44,810
80 D	60,280
114 D	65,440
160 D	82,720
228 D	98,210
320 D	118,920
456 D	125,810
640 D
912 D
NOTE: For "Air Balance" and "Heavy Duty" units, multiply the above values by 1.30.
Regenerators (Accumulator)-(see Metering Equipment)
Regulators:
per unit	3,300
Safety Systems
Onshore And Marsh Area	6,590
Basic Case:	7,600
well only	11,390
well and production equipment	19,000
with surface op. ssv, add	47,530
Offshore 0 - 3 Miles	28,530
Wellhead safety system (excludes wellhead actuators)	66,520
per well	41,790
production train	4,730
glycol dehydration system	7,100
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
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.	4,010 5,730 6,520
8 In. Diameter Vessel	1,860
10 In. Diameter Vessel	2,440
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.
Separators-(no metering equipment included)
Horizontal-Filter /1,440 psi (High Pressure)	5,870
6-5/8" OD x 5'-6"	6,380
8-5/8" OD x 7'-6"	8,960
10-3/4" OD x 8'-0"	12,040
12-3/4" OD x 8'-0"	19,350
16" OD x 8'-6"	28,600
20" OD x 8'-6"	30,110
20" OD x 12'-0"	40,570
24" OD x 12'-6"	59,210
30" OD x 12'-6"	70,390
36" OD x 12'-6"
Separators-(no metering equipment included)
Vertical 2-Phase /125 psi (Low Pressure)	6,660
24" OD x 7'-6"	7,170
30" OD x 10'-0"	14,980
36" OD x 10'-0"	7,030
Vertical 3-Phase /125 psi (Low Pressure)	7,960
24" OD x 7'-6"	11,040
24" OD x 10'-0"	15,700
30" OD x 10'-0"	18,210
36" OD x 10'-0"	10,390
42" OD x 10'-0"	13,330
Horizontal 3-Phase /125 psi (Low Pressure)	14,550
24" OD x 10'-0"	23,220
30" OD x 10'-0"
36" OD x 10'-0"
42" OD x 10'-0"
Vertical 2-Phase /1440 psi (High Pressure)
12-3/4" OD x 5'-0"	3,940
16" OD x 5'-6"	5,870
20" OD x 7'-6"	11,180
24" OD x 7'-6"	13,550
30" OD x 10'-0"	20,640
36" OD x 10'-0"	26,740
42" OD x 10'-0"	42,790
48" OD x 10'-0"	50,470
54" OD x 10'-0"	76,410
60" OD x 10'-0"	95,550
Vertical 3 - Phase /1440 psi (High Pressure)	6,880
16" OD x 7'-6"	12,040
20" OD x 7'-6"	13,980
24" OD x 7'-6"	21,570
30" OD x 10'-0"	27,600
36" OD x 10'-0"	45,020
42" OD x 10'-0"	52,190
48" OD x 10'-0"	6,730
Horizontal 2-Phase /1440 psi (High Pressure)	10,830
16" OD x 7'-6"	14,770
20" OD x 7'-6"	22,730
24" OD x 10'-0"	28,810
30" OD x 10'-0"	58,490
36" OD x 10'-0"	67,450
42" OD x 15'-0"	10,390
48" OD x 15'-0"	11,620
Horizontal 3-Phase /1440 psi (High Pressure)	16,910
16" OD x 7'-6"	24,080
20" OD x 7'-6"	34,700
24" OD x 10'-0"	38,780
30" OD x 10'-0"	49,960
36" OD x 10'-0"	47,670
36" OD x 15'-0"	69,170
Offshore Horizontal 3-Phase /1440 psi (High Pressure)	72,180
30" OD x 10'-0"	112,040
36" OD x 10'-0"
36" OD x 12'-0"
36" OD x 15'-0"
42" OD x 15'-0"
Skimmer Tanks-(see Flow Tanks in Tanks section)
Stabilizers-per unit	7,380
Sump/Dump Tanks-(See Metering Equipment -"Fluid Tanks")
Tanks-no metering equipment	Per Barrel*
Flow Tanks (receiver or gunbarrel)	46.10
50 to 548 bbl. Range (average tank size - 250 bbl.)	35.90
Stock Tanks (lease tanks)
100 to 750 bbl. Range (average tank size - 300 bbl.)
Storage Tanks (Closed Top)
1,000 barrel	30.50
1,500 barrel	27.00
2,000 barrel	26.20
2,001 - 5,000 barrel	24.10
5,001 - 10,000 barrel	22.60
10,001 - 15,000 barrel	21.20
15,001 - 55,000 barrel	14.90
55,001 - 150,000 barrel	11.20
Internal Floating Roof	43.60
10,000 barrel	29.50
20,000 barrel	21.90
30,000 barrel	19.50
50,000 barrel	18.80
55,000 barrel	16.60
80,000 barrel	14.50
100,000 barrel
*I.E.: (tanks size bbls.) X (no. of bbls.) X (cost-new factor.)
Telecommunications Equipment
Microwave System	57,340
Telephone and data transmission	4,300
Radio telephone	12,250
Supervisory controls:	27,950
remote terminal unit, well	720
master station	60
towers (installed):	730
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.	150 210 70
Utility Compressors
per horsepower - rated on motor	940
Vapor Recovery Unit-no Metering Equipment
60 MCF/D or less	25,090
105 MCF/D max	35,840
250 MCF/D max	47,310
Waterknockouts-Includes unit, backpressure valve and regulator, but, no metering equipment.	6,810
2' diam. x 16'	10,180
3' diam. x 10'	14,050
4' diam. x 10'	23,010
6' diam. x 10'	26,600
6' diam. x 15'	33,330
8' diam. x 10'	38,280
8' diam. x 15'	42,430
8' diam. x 20'	47,230
8' diam. x 25'	55,550
10' diam. x 20'

8. Service Stations

Table 907.D-8 Service Stations Marketing Personal Property *Alternative Procedure
Property Description	$ Cost New
Air and Water Units:
Above ground	1,600
Below ground	680
Air Compressors:
1/3 to 1 H.P.	2,150
1/2 to 5 H.P.	3,630
Car Wash Equipment:
In Bay (roll over brushes)	57,710
In Bay (pull through)	89,580
Tunnel (40 to 50 ft.)	194,980
Tunnel (60 to 75 ft.)	260,920
Drive On Lifts:
Single Post	10,530
Dual Post	11,860
Lights:
Light Poles (each)	1,070
Lights - per pole unit	1,190
Pumps:
Non-Electronic - self contained and/or remote	4,560
controlled computer	6,780
Single	7,710
Dual	10,390
Computerized - non-self service, post pay, pre/post pay. self contained and/or remote controlled dispensers
Single
Dual
Read-Out Equipment (at operator of self service)
Per Hose Outlet	1,690
Signs:
Station Signs	5,100
6 ft. lighted - installed on 12 ft. pole	9,320
10 ft. lighted - installed on 16 ft. pole	4,250
Attachment Signs (for station signs)	4,340
Lighted "self-serve" (4 x 11 ft.)	15,430
Lighted "pricing" (5 x 9 ft.)	20,190
High Rise Signs - 16 ft. lighted - installed on:	22,590
1 pole	8,200
2 poles	4,340
3 poles
Attachment Signs (for high rise signs)
Lighted "self-serve" (5 x 17 ft.)
Lighted "pricing" (5 x 9 ft.)
Submerged Pumps-(used with remote control equipment, according to number used - per unit)	4,550
Tanks-(average for all tank sizes)
Underground - per gallon	2.60

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.

*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.

La. Admin. Code tit. 61, § V-907

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 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), Amended by the Division of Administration, Tax Commission, LR 45534 (4/1/2019), Amended LR 46561 (4/1/2020), Amended LR 47465 (4/1/2021), Amended LR 481523 (6/1/2022), Amended LR 491049 (6/1/2023), Amended LR 50, exp. 4/30/2024(Emergency), Amended LR 50373 (3/1/2024).

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