Register February 2011 No. 662
Chapter PSC 116
Fuel cost plan.
Deferred account balance calculation.
Mid-year rate adjustment.
Ch. PSC 116 Note
Note: Chapter PSC 116 as it existed on February 28, 2011 was repealed and a new Chapter PSC 116 was created effective March 1, 2011.
PSC 116.01 Definitions.
In this chapter:
“Annual fuel cost" means actual fuel cost over a plan year.
“Annual native system requirement" means the native system requirement in megawatthours over a plan year.
“Associated transmission service" means the cost of transmission service incurred outside a utility's transmission organization, but not any cost associated with a purchased power contract the utility uses to meet its planning reserve requirement.
“Average annual fuel cost" means the annual fuel cost divided by the annual native system requirement.
“Capacity" means the continuous load–carrying ability of electric generation expressed in megawatts.
“Commission" means the public service commission.
“Energy" means the amount of electric generation over a period of time, expressed in megawatthours.
“Energy market purchase" means the cost of purchasing energy or capacity, or both, used to supply electricity to a customer served by the utility. The cost includes marginal energy price, associated transmission service and transmission losses and congestion. The cost excludes capacity or associated transmission service purchased to satisfy a utility's planning reserve margin, as defined in s. PSC 117.03 (16)
“Energy market sale" means an opportunity sale, as defined in s. PSC 117.03 (14)
, whether it is an in-state or out-of-state sale. The revenue from an energy market sale includes marginal energy prices, transmission loss, congestion, associated transmission service, and any other revenue resulting from the sale.
“Excess revenues" means revenues in the plan year that provide a utility with a greater return on common equity than authorized by the commission. For the plan year, the following costs and revenues are not included in the calculation of actual return on common equity for the utility:
Charitable contributions and other donations not related to providing utility service.
Earnings or losses from the operation of non-utility assets and gains or losses on the sale of non-utility assets.
Earnings, dividends, or distributions from any ownership interest that a utility may hold in a transmission company, as defined in s. 196.485 (1) (ge)
, Stats., and any gains or profits a utility may receive from the sale or other disposition of securities issued by a transmission company.
“Fuel" means all of the following used to generate electricity:
Any other type of material converted to electric energy, including biomass.
“Native system requirement" means the actual energy sold to customers, energy used by the utility, and line losses. In this subsection, “line losses" means the loss of energy in the operation of an electric system primarily attributable to the energy's transformation to waste heat in electric conductors and apparatus. “Native system requirement" does not include energy market sales.
“Plan year" means the 12-month period identified in a fuel cost plan.
“Transmission organization" means a transmission organization, as defined in 18 CFR 39.1
(in effect on March 1, 2011, that is used by a utility to serve Wisconsin retail customers.
PSC 116.01 History
History: CR 08-070: cr. Register February 2011 No. 662, eff. 3-1-11. PSC 116.02(1)
For any month or longer period of time, a utility shall calculate fuel cost as the net of the costs and credits for all of the following during the time period:
Voluntary curtailable load program, including any payment made to a retail customer under a tariff authorized under s. 196.192 (2) (a)
Direct load control program. In this paragraph, “direct load control program" means an event-based, payment-to-customers program under which a utility pays a firm customer to reduce its electric demand when system constraints threaten reliable service. The cost of a direct load control program includes all associated costs except any associated equipment cost or standard monthly credit.
Any tools to manage fuel cost price risk implemented under a risk management plan approved by the commission and included in the fuel cost plan.
Emission allowances, including allowances for sulfur dioxide and carbon dioxide.
If a utility uses a transmission organization to transact an energy market purchase, the utility shall calculate the cost of associated transmission service for that purchase as the sum of the cost of all of the following:
Financial transmission rights or similar related instruments transacted under a risk management plan approved by the commission.
Other transmission organization energy market charges and credits included in an approved fuel cost plan.
The cost of associated transmission service does not include charges for network transmission service.
PSC 116.02 History
History: CR 08-070: cr. Register February 2011 No. 662, eff. 3-1-11.