Because of the unique character of public utility companies, the traditional approaches to valuation estimates of property (cost, capitalized income, and market) must be modified when utility property is valued. Consequently, the value of utility company property is estimated in the manner provided in this chapter.
All indicators of value must be considered to determine their validity relating to the specific property being valued. If an indicator is not demonstrated to be reliable or of value for the specific property being appraised it must not be used.
[Repealed, 31 SR 1317]
The cost factor to be considered in the utility valuation formula is the original cost less depreciation of the system plant, plus the cost of improvements to the system plant, plus the original cost of all types of construction work in progress that are installed by the assessment date, plus the cost of property held for future use, plus the cost of contributions in aid of construction. Original cost less depreciation is presumed to be equal to historical cost less depreciation. For rate-regulated companies, the commissioner must use the same type of cost that is used in the rate base calculation.
The original cost of any leased operating property used by the utility must be reported to the commissioner in conjunction with the annual utility report. If the original cost of the leased operating property is not available, the commissioner shall make an estimate of the cost by capitalizing the lease payments.
If a conflict of opinion exists regarding the character of specific property, whether it is operating or nonoperating property, assessors or utility companies may request a determination by the commissioner.
Depreciation is not allowed on construction work in progress. Depreciation is allowed as a deduction from cost in the amount allowed on the accounting records of the utility company, as such records are required to be maintained by the appropriate regulatory agency, except that depreciation may be reduced if available information indicates the amount deducted does not equal actual accrued depreciation when the current estimated remaining life is considered.
The following example illustrates how the cost indicator of value is computed for an electric company:
|1.||Utility Plant||$ 200,000,000|
|2.||Construction Work in Progress||$ 5,500,000|
|3.||Contributions in Aid of Construction||$ 250,000|
|4.||Leased Property||$ 750,000|
|5.||Total Plant||$ 206,500,000|
|6.||Book Depreciation||$ 40,000,000|
|7.||Depreciation on CIAC||$ 10,000|
|8.||Depreciation on Leased Property||$ 25,000|
|9.||Total Depreciation||$ 40,035,000|
|10.||Total Cost Indicator of Value||$ 166,465,000|
The income indicator of value is estimated by weighting the capitalized net operating earnings of the utility company for the most recent three years as follows: most recent year, 40 percent; previous year, 35 percent; and final year, 25 percent. Utilities may request the removal of nonrecurring items of income or expense. The commissioner must determine if removal of the item is appropriate. The net income is capitalized by applying a capitalization rate that is computed by using the band of investment method. This method considers:
the capital structure of utilities;
the cost of debt or interest rate;
the yield on preferred stock of utilities;
the yield on common stock of utilities; and
the risk-free rate, relative risk, and risk premiums for public utility companies.
Capitalization rates are computed for electric companies, gas distribution companies, natural gas transmission systems, and fluid pipeline companies. The rates are recalculated each year using the method described in this subpart.
The following example illustrates how the income indicator of value would be computed for a gas distribution company:
|year 1||year 2||current year|
|1.||Net Operating Income||$ 394,000||$ 450,000||$ 470,000|
|3.||Weighted Income to be Capitalized||98,500||157,500||188,000|
|4.||Capitalized Income at 9.25%||1,064,865||1,702,703||2,032,432|
|5.||Total Income Indicator of Value||$ 4,800,000|
Additional indicators of value, other than the cost and income indicators, may exist in some situations. When additional indicators of value exist, the commissioner has the discretion to use these additional indicators in computing the unit value of a utility. Additional indicators of value include, but are not limited to, the market indicator.
If the commissioner determines that the market indicator can be quantified, is reliable, and is indicative of value for a company, the commissioner has the discretion to adjust the weightings of the cost and income indicators to give weight to the market indicator in the unit value computation. If the market indicator is used, the weighting for the market indicator must not exceed five percent.
If the commissioner finds that economic or other forms of obsolescence exists, the commissioner has the discretion to adjust the weightings in the correlation process described in subpart 5 or make other adjustments in its methodology consistent with these rules and applicable statutes.
If the commissioner uses additional indicators of value, the commissioner must state in writing the findings that necessitate deviation from the default weightings of 50 percent for cost indicator and 50 percent for income indicator, as described in subpart 5.
The unit value of the utility company is equal to the total of the weighted indicators of value. The total weighting must equal 100 percent. The default weightings of the indicators are: market indicator, 0 percent; cost indicator, 50 percent; income indicator, 50 percent.
The following is an example of the computation of the unit value for a utility company when the market indicator has been determined to be a valid additional indicator of value:
|1.||Cost Indicator of Value:|
|$5,000,000 x 47.5% = $2,375,000|
|2.||Income Indicator of Value:|
|$4,800,000 x 47.5% = $2,280,000|
|3.||Market Indicator of Value:|
|$5,500,000 x 5% = $275,000|
|4.||Unit Value of Utility Company:|
|Sum of indicators = $4,930,000|
After assessment year 2007, cooperative associations have the option to irrevocably elect the method under which they are valued.
For assessment year 2007, each cooperative must be valued in the same manner as it was valued in assessment year 2006, using either the unit value method or cost less depreciation method.
Beginning in assessment year 2008, cooperative associations that were valued under the cost less depreciation method in assessment year 2007 may irrevocably elect to be valued using the unit value method described in subparts 1 to 5. Elections made by a cooperative association prior to November 1 of any year are effective the next assessment year. Such elections must be in a format prescribed by the commissioner.
Prior to November 1 of assessment year 2008, cooperative associations that were valued under the unit value method in assessment year 2007 may irrevocably elect to be valued under the cost less depreciation method. Such elections will be in a format prescribed by the commissioner. Cooperative associations that do not elect to revert back to valuation using cost less depreciation method prior to November 1 of assessment year 2008, are deemed to have irrevocably elected to be valued using the unit value method.
Cooperative associations may irrevocably elect to have their property valued using the unit value method described in subparts 1 to 5. Cooperative associations not electing unit valuation and other types of utilities which do not operate in the traditional profit-making mode, are not common carriers, or are nonregulated, must have their utility property valued on the basis of cost less depreciation. Elections made by a cooperative association prior to November 1 of any year are effective the next assessment year. Such elections must be in a format prescribed by the commissioner.
Depreciation is allowed as a deduction from the original cost in increments of 2-1/2 percent per year, but the maximum depreciation allowed must not exceed 75 percent of the cost of the utility operating property. Additions to existing utility property are depreciated 2-1/2 percent per year until they reach the 75 percent maximum. Retirements of utility property are deducted from the cost basis at the average depreciation level of all of the company's taxable property.
Cost less depreciation is calculated by using the following inputs: the total cost at the end of the year preceding the assessment year; total depreciation at the beginning of the year preceding the assessment year; total cost at the beginning of the year preceding the assessment year; and the original cost of property retired during the year preceding the assessment year.
Depreciation for the year is calculated by multiplying the total cost at the end of the year preceding the assessment year by 2-1/2 percent. Depreciation on retirements is calculated by dividing the total depreciation for the year preceding the assessment year by total cost at the beginning of the year preceding the assessment year. This number is then multiplied by the original cost of retirements for the year; the result is equal to the depreciation on retirements for the year.
Net depreciation for the year is calculated by adding the total depreciation at the beginning of the year preceding the assessment year and the depreciation for the year, and then subtracting the depreciation on retirements for the year. Net depreciated value for the year is equal to the total cost at the end of the year preceding the assessment year less net depreciation for the year. Net depreciated value for the assessment year is the total market value for all property owned by the company.
A company factor is calculated by dividing the net depreciated value for the assessment year by the total cost at the end of the year preceding the assessment year. The factor is multiplied by the cost of each individual parcel at the end of the year preceding the assessment year to derive the market value of each individual parcel.
The following example illustrates this process for an electric cooperative association electing cost less depreciation valuation under this subpart for assessment year 2006.
|Cost of individual parcels on 12/31/2005 =||$ 105,000|
|Total cost on 12/31/2005 of all property =||$ 1,140,000|
|Total depreciation on 1/1/2005 =||$ 300,000|
|Total cost on 1/1/2005 =||$ 1,100,000|
|Original cost of retirements in 2006 =||$ 6,000|
|1.||Depreciation for the assessment year 2006
($1,140,000 x .025) =
|2.||Depreciation on assessment year 2006 retirements
($300,000 / $1,100,000) x $6,000 =
|3.||Net depreciation for the assessment year 2006
($300,000 + $28,500 - $1,636) =
|4.||Depreciation Limit ($1,140,000 x .75) =||$ 855,000|
|5.||Net depreciated value for the assessment year 2006
(Total cost on 12/31/2005 - Lesser of Line 3 or Line 4)
($1,140,000 - $326,864) =
|This is the market value for all property owned by the cooperative.|
|6.||Company depreciation factor for 2006
($813,136 / $1,140,000) =
|7.||Market value of each individual parcel
($105,000 x 71.327751%) =
($520,000 x 71.327751%) =
($415,000 x 71.327751%) =
($100,000 x 71.327751%) =
[Repealed, 21 SR 749]
Utility operating property may be retired from the utility system while still in place if certain criteria are met:
The property must be physically disconnected from the utility system. In the case of electrical plants, the disconnection or dismantling of wires, cables, connectors, or transformers constitutes physical disconnection. In the case of pipelines, the disconnection of pipes, valves, or fittings is evidence of physical disconnection.
An affidavit of retirement must be filed by the utility with the commissioner at least 30 days prior to the assessment date. This affidavit must indicate the facility being retired and the date it was taken out of service.
The utility must make every effort to inform the commissioner of pending major retirements. The commissioner in turn shall notify the county assessor of impending major retirements as soon as this information becomes available to the department.
Utility real property which is retired in place must continue to be taxed for ad valorem purposes. However, its market value is not determined on the basis of its value as utility operating property.
If a utility chooses to temporarily retire a facility pending the development of an alternate fuel, greater demand, increased source of supply, or another valid reason, the cost of this facility must be transferred to the appropriate regulatory agency's account entitled "Held for Future Use." Standby facilities are not considered to be temporarily retired unless their costs are carried in this account. Temporarily retired utility facilities are valued taking into account a number of factors including age of the facility, type of facility, amount of maintenance and additional costs needed to restore the facility to operational status, length of retirement, and earning potential of the facility. A temporarily retired facility must not be valued lower than if the facility were considered nonoperating utility property.
7 SR 1797; 8 SR 2723; 10 SR 18; 11 SR 635; 12 SR 58; 13 SR 394; 14 SR 1806; 15 SR 2190; 21 SR 749; 24 SR 1106; L 2005 c 151 art 1 s 114; 31 SR 1317
June 4, 2007
Official Publication of the State of Minnesota
Revisor of Statutes