Rule: 38.5.176 Prev     Up     Next    
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Subchapter: Minimum Rate Case Filing Standards for Electric, Gas, and Private Water Utilities
Latest version of the adopted rule presented in Administrative Rules of Montana (ARM):

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(1) Statement L shall present the cost of service results in detail for every customer class. Written testimony shall describe the development of these cost of service results. Included shall be the following:

(a) A general discussion of the purpose of the filing with goals and objectives of the allocated cost of service proposals. Industry standard terminology shall be used to describe and define allocated cost of service proposals. Where unique terms are used, they shall be defined in a separate glossary to be included as part of the filing.

(b) A benchmark allocated cost of service comparing the last commission-approved filing to the current filing. Any substantive deviation in procedures and/or methods used to prepare the current filing compared to the last commission-approved filing will be summarized and explained in the cost of service testimony.

(c) A generic allocated cost of service model which provides a basic understanding of the allocated cost of service study. The public service commission currently recognizes allocated cost of service based on marginal cost principles. Any utility testimony and exhibits on allocated cost of service should follow the format of the generic marginal cost model as described below.

(2) A generic marginal cost model shall also be provided. Marginal cost of service shall be determined for each of the following functions:

(a) Generation, transmission, substation, distribution, and customer for electric filings.

(b) Supply, storage, transmission, distribution, and customer for natural gas filings.

(3) Marginal costs shall be determined using the following additional steps:

(a) Classify the functionalized costs as energy (commodity) , capacity, reactive power and/or customer related and compute the associated marginal unit costs.

(b) Multiply classified marginal unit costs by allocation factors to compute total marginal cost.

(4) Allocation factors, annualization factors, and adjustment factors (d) to (j) below, may be used at various times throughout the cost of service study. These do not necessarily apply to all utilities. An example is seasonal costs since not all utilities have seasonal differences in costs. Inputs and factors include:

(a) Select the relevant time periods and compute relevant allocation factors;

(b) Select methods to determine and then compute relevant seasonal and time-of-day costs;

(c) Select methods to compute annualized costs and compute annualization factors;

(d) Select a loss method, compute loss percentages and then apply such loss estimates to energy and capacity cost estimates;

(e) Compute spatial energy and/or capacity transportation rates for the associated products;

(f) Select operation and maintenance marginal cost methods and compute factors;

(g) Select administrative and general marginal cost methods and compute factors;

(h) Select general and common plant marginal cost methods and compute factors; and

(i) Select price adjustments and indexes.

(5) The following models shall be followed when preparing a generic marginal cost model.

(a) Model 1. Generic electric marginal cost study model.

(b) Model 2. Generic natural gas marginal cost study model.

(6) In addition to the use of the generic model, the following allocated cost of service guidelines should be followed:

(a) Year's dollars for computing costs of service should reflect costs two years beyond January 1st of the year in which the filing is submitted. For example, if a cost of service study is filed any time in calendar year 1992, costs will be computed in January 1, 1994 dollars.

(b) Relevant market value sources should be reflective of opportunities available to the utility's system. For example, electric generation and gas supply cost functions ought to reflect a resource's highest foregone use in the markets opened up by transmission access.

(c) Relevant time horizon for costs depends on the cost function and applications.

(d) Carrying charges should be used for the development of the marginal costs.

(e) Capacity and energy losses reflective of the utility's system should be developed and used to adjust relevant marginal costs.

(f) Proxy cost estimates, as necessary and appropriate, may be used for the marginal costs.

(g) If a production cost model is used by the utility, it should be identified and explained and its relative merit justified (e.g., chronological versus probabilistic) .

(h) Distribution/customer costing should be reflective of the utility's system and included as appropriate. Line extension policies should be described and any changes explained.

(i) Administrative and general, operation and maintenance and general and common adders should be reflective of the utility's system and included as appropriate.

(j) Allocation of costs to customer classes should use allocation factors that reflect cost causation.

(k) Seasonal or time-of-day cost allocation should be supported in sufficient detail to fully analyze the result.

(l) The method of reconciliation used should be identified and explained. Model 1. Generic Electric Marginal Cost Study Model

Model 2. Generic Natural Gas Marginal Cost Study Model

History: Sec. 69-3-103, MCA; IMP; Sec. 69-2-101, MCA; NEW, Eff. 7/5/77; AMD, 1993 MAR p. 1669, Eff. 7/30/93.


MAR Notices Effective From Effective To History Notes
7/30/1993 Current History: Sec. 69-3-103, MCA; IMP; Sec. 69-2-101, MCA; NEW, Eff. 7/5/77; AMD, 1993 MAR p. 1669, Eff. 7/30/93.
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