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Note: Chapter PSC 116 as it existed on February 28, 2011 was repealed and a new Chapter PSC 116 was created effective March 1, 2011.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
PSC 116.01 Definitions. In this chapter:
PSC 116.01(1)
(1) “Annual fuel cost" means actual fuel cost over a plan year.
PSC 116.01(2)
(2) “Annual native system requirement" means the native system requirement in megawatthours over a plan year.
PSC 116.01(3)
(3) “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.
PSC 116.01(4)
(4) “Average annual fuel cost" means the annual fuel cost divided by the annual native system requirement.
PSC 116.01(5)
(5) “Capacity" means the continuous load–carrying ability of electric generation expressed in megawatts.
PSC 116.01(6)
(6) “Commission" means the public service commission.
PSC 116.01(7)
(7) “Energy" means the amount of electric generation over a period of time, expressed in megawatthours.
PSC 116.01(8)
(8) “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).
PSC 116.01(9)
(9) “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.
PSC 116.01(10)
(10) “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:
PSC 116.01(10)(a)
(a) Charitable contributions and other donations not related to providing utility service.
PSC 116.01(10)(e)
(e) Earnings or losses from the operation of non-utility assets and gains or losses on the sale of non-utility assets.
PSC 116.01(10)(g)
(g) 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.
PSC 116.01(11)
(11) “Fuel" means all of the following used to generate electricity:
PSC 116.01(11)(e)
(e) Any other type of material converted to electric energy, including biomass.
PSC 116.01(12)
(12) “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.
PSC 116.01(13)
(13) “Plan year" means the 12-month period identified in a fuel cost plan.
PSC 116.01(14)
(14) “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)(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:
PSC 116.02(1)(e)
(e) 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.
PSC 116.02(1)(f)
(f) 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.
PSC 116.02(1)(h)
(h) Emission allowances, including allowances for sulfur dioxide and carbon dioxide.
PSC 116.02(2)(a)(a) 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:
PSC 116.02(2)(a)1.
1. Financial transmission rights or similar related instruments transacted under a risk management plan approved by the commission.
PSC 116.02(2)(a)3.
3. Other transmission organization energy market charges and credits included in an approved fuel cost plan.
PSC 116.02(2)(b)
(b) 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;
correction in (1) (d) made under s. 13.92 (4) (b) 7., Stats., Register March 2021 No. 783. PSC 116.03(1)(1)
Annually, a utility shall file a proposed fuel cost plan as part of an application to open or reopen a general rate case proceeding or, if the utility does not file a general rate case, the utility shall file a proposed fuel cost plan as part of a proceeding limited in scope to fuel cost. A utility shall file a proposed fuel cost plan no more than 360 days or less than 150 days before the beginning of the plan year.
PSC 116.03(2)
(2) A utility shall include in a proposed fuel cost plan the following information for the plan year:
PSC 116.03(2)(c)
(c) A forecast of the annual native system requirement. In a utility's reopened general rate case proceeding or in a proceeding limited in scope to fuel cost, the applicable annual native system requirement is the same as the commission-approved forecast in the utility's most recently approved general rate case proceeding.
PSC 116.03(2)(d)
(d) Detailed input of the economic dispatch model used to forecast fuel cost.
PSC 116.03(2)(e)
(e) Detailed output of the economic dispatch model used to forecast fuel cost.
PSC 116.03(2)(f)
(f) All inputs and allocators used to calculate the forecast of the annual average fuel cost and the forecast of the annual native system requirement.
PSC 116.03(3)
(3) After hearing the commission shall approve a fuel cost plan, with any modifications or conditions the commission considers appropriate. The commission shall establish a utility's rates in accordance with the approved fuel cost plan, subject to reconciliation under s.
PSC 116.07.
PSC 116.03(4)
(4) Approval of a fuel cost plan by the commission is not a determination that the fuel cost plan is reasonable or prudent for reconciliation purposes under s.
PSC 116.07.
PSC 116.03 History
History: CR 08-070: cr.
Register February 2011 No. 662, eff. 3-1-11.
PSC 116.04
PSC 116.04 Deferral accounting. Subject to reconciliation under s.
PSC 116.07, a utility shall apply deferral accounting to all of its actual cost for items in an approved fuel cost plan and to all amounts collected or credited under ss.
PSC 116.07 and
116.08.
PSC 116.04 History
History: CR 08-070: cr.
Register February 2011 No. 662, eff. 3-1-11.
PSC 116.05(1)(1)
A utility shall file a report with the commission that includes the actual cost for items in an approved fuel cost plan, native system requirement, and the use of items in the approved fuel cost plan by item and energy source. The report shall also include the average monthly figure for each category for the plan year to date.
PSC 116.05(2)
(2) A utility shall file the report according to a schedule the commission establishes. Upon written request, the commission may grant a utility an extension of up to 30 days for the filing of a report.
PSC 116.05 History
History: CR 08-070: cr.
Register February 2011 No. 662, eff. 3-1-11.
PSC 116.06
PSC 116.06 Deferred account balance calculation. PSC 116.06(1)(1)
A deferred account balance debit shall be calculated using the following formula:
If AAFC is ≥ (AAFCF x (1+FCT))
Then DABD = WJR x [AAFC – (AAFCF x (1 + FCT))]
Where DABD = Deferred account balance debit.
WJR = Wisconsin jurisdictional share of the
annual native system requirement.
AAFC = Average annual fuel cost.
AAFCF = Forecast of the average annual fuel cost
in the approved fuel cost plan.
FCT = Fuel cost tolerance.
PSC 116.06(2)
(2) A deferred account balance credit shall be calculated using the following formula:
If AAFC is < (AAFCF x (1-FCT))
Then DABC = WJR x [(AAFCF x (1 – FCT)) – AAFC]
Where DABC = Deferred account balance credit.
WJR = Wisconsin jurisdictional share of the
annual native system requirement.
AAFC = Average annual fuel cost.
AAFCF = Forecast of the average annual fuel cost
in the approved fuel cost plan.
FCT = Fuel cost tolerance.
PSC 116.06(3)
(3) A utility's fuel cost tolerance shall be set at plus or minus two percent, unless the commission sets a different percentage when approving a fuel cost plan under s.
PSC 116.03 (3).
PSC 116.06 History
History: CR 08-070: cr.
Register February 2011 No. 662, eff. 3-1-11.
PSC 116.07(1)(1)
Annually, but no later than 90 days after the end of the plan year, a utility shall file an application for the reconciliation of actual cost for items in an approved fuel cost plan for the plan year.
PSC 116.07(2)
(2) The utility in its application shall identify and explain the following:
