(a) List the documents submitted with the filing;

(b) State the names and addresses of those to whom copies of the rate schedule have been mailed;

(c) Include a brief description of the proposed changes in service or rate and charge;

(d) State the reasons for the proposed changes;

(e) State the estimated number of customers whose cost of service will be affected and annual amounts of either increases or decreases, or both, in cost of service to such customers.

(f) Name an employee of the utility who shall be responsible for answering questions concerning the application, or for referring inquiries to appropriate members of the utility staff.

(2) Three copies of the letter of transmittal and three copies of all materials required in ARM 38.5.103 to 38.5.175 and 38.5.179 to 38.5.183, inclusive, shall be filed with the commission at the time of application. Montana consumer counsel shall receive two copies of the same materials.

(3) All or any part of the requirements of these rules may be waived by a quorum of the commission upon a showing of good cause. Waiver of any requirements, however, shall not preclude the commission from requiring the filing of specific cost data and material sufficient to support the application.

(1) The application for a rate increase shall include a statement comparing sales and services and the revenues therefrom under the rate schedules proposed to be superseded or supplemented and the proposed changed rate schedules. Such comparisons shall be applied to the transactions for the 12 months of the test period. Such comparisons should be made for each rate schedule.

This rule has been repealed.

(a) Copies of monthly financial report;

(b) Copies of accounting analyses of balance sheet accounts;

(c) Complete trial balances of all the balance sheet accounts at the beginning and end of the 12 months of actual experience used for the filing;

(d) Analyses of the various miscellaneous revenues;

(e) Analyses of surplus and capital surplus accounts.

(1) Statement C shall include a statement showing in summary form Utility Plant by functional category of electric, gas or water utility plant, as the case may be. Working papers shall also be supplied to show the change in additions and retirements with regard to balances on Statement C.

(1) Working papers shall show any significant changes in intangible plant for the test year.

(1) Working papers shall set forth the cost and description of plant carried on the company's books as utility plant which was not used and useful.

(1) Working papers shall set forth a description of the continuing property records maintained by the utility, including methods and procedures used to price retirements. Any data required by this section which has been previously submitted to the Commission by the utility, pursuant to these rules, may be incorporated by specific reference.

(a) Starting balance;

(b) Annual provision;

(c) Retirements, with cross-reference to plant schedule;

(d) Salvage;

(e) Removal costs;

(f) Adjustments, including particulars of any significant items;

(g) Ending balance.

(1) With respect to each allocation of an overall account to obtain the amounts applicable to various functional groups of plant, provide a complete explanation of the method, procedures and significant data used in making the allocation.

(1) Working papers shall set forth balances at the beginning and end of the test period for materials, supplies, and fuel stocks in such detail as to disclose, either by subaccounts regularly maintained on the books or by analysis of the principal items included in the main account, the nature of the charges included therein.

(1) Working papers shall show the computations, crossreferences and sources from which the data used in computing claimed working capital is derived.

(a) Title;

(b) Date of issuance and date of maturity;

(c) Interest rate;

(d) Principal amount of issue;

(e) Net proceeds;

(f) Amount currently outstanding;

(g) Cost of money and yield to maturity based on the interest rate and net proceeds per unit outstanding determined by reference to any generally accepted table of bond yields;

(h) If issue is owned by an affiliate, state name and relationship of owner. Furnish a copy of the latest prospectus issued by the public utility, any superimposed holding company or subsidiary companies.

(a) Title;

(b) Date of issuance;

(c) Dividend rate;

(d) Par value of stated amount of issue;

(e) Issuance expenses;

(f) Net proceeds;

(g) Cost of money, that is, the dividend rate divided by net proceeds per unit or share;

(h) Amount outstanding;

(i) If issue is owned by an affiliate, then provide the name and relationship of owner.

(a) Number of shares sold;

(b) Gross proceeds at offering price;

(c) Underwriters' discount or commission;

(d) Proceeds to the filing utility;

(e) Amount of issuance expenses;

(f) Net proceeds;

(g) Offering price per share;

(h) Net proceeds per share;

(i) Whether issue was offered to stockholders through subscription rights or to the public.

(1) Working papers shall include the following information on outstanding common stock for the five calendar years preceding the end of the test period and by months for the 12 month test period:

(a) Average number of shares outstanding;

(b) Earnings per average share for only the five years preceding the test year;

(c) Annual earnings per share for only the latest reported 12 month average;

(d) Annual dividend rate per share;

(e) Dividends listed as percent of earnings;

(f) Average market price based on the monthly high and low.

(a) Title or series;

(b) Principal amounts or par value reacquired;

(c) Reacquisition cost;

(d) Gain or loss on reacquisition;

(e) Income taxes, if any, allocable to the gain or loss, and basis of allocation.

(1) Statement G shall show the utility's operation and maintenance expenses according to each account of the Uniform Systems of Accounts for public utilities. The expenses shall be shown under appropriate columnar headings as follows for each functional classification:

(a) Operation and maintenance expense as booked, for the test period and the total for the test period;

(b) Claimed adjustments, if any, to expenses as booked;

(c) Total adjusted operation and maintenance expenses claimed.

(1) Working papers shall show the total annual cost of power or gas purchased for the 12 months test period of actual experience, the claimed adjustments thereof, if any, and the total adjusted cost for the test period detailed by major category. If any of the prices are effective subject to refund, there shall be shown by major category and by commission docket number for the test period, the rate and the amount paid subject to refund.

(2) If the utility purchases and sells power under exchange or pooling argeements, the method of recording on books, total gross receipts and deliveries exchanged, total gross dollar amounts involved for such receipts and deliveries and details of such exchanges shall be submitted.

(1) With respect to the following listed expense accounts, detail shall be furnished as designated for the 12 months of the test period and for claimed adjustments. This shall include analytical details which will clearly disclose for each account a classification of principal charges and credits with all minor items grouped.

(a) Advertising expenses shall be separated by media utilized and classification of message in accordance with applicable Montana statutes.

(b) All other Administrative and General Expense accounts shall be presented in sufficient detail to allow reasonable verification of the amounts and type of charges incurred during the test period.

(1) If the expense accounts contain charges or credits from associated companies or nonutility departments of the utility, submit for each such associated company or nonutility department work papers showing the following:

(a) The amount of the charges or credits during the test period;

(b) The account classification or classifications charged or credited;

(c) Descriptions of the specific services performed for or by the associated company or nonutility department;

(d) The basis used in determining the amounts of the charges or credits.

(2) Statement H shall also show, by rate schedule, revenues under presently effective rate schedules as well as under the proposed rate schedules filed by the utility. Said statement shall show number of customers, amount of increase and percent increase. Working papers shall also be supplied showing:

(a) The reconciliation of book revenues of the test period if differing from present revenues as set forth in Statement H;

(b) Adjustments for material and nonrecurring changes which are known and measurable to actual period revenues and sales units if appropriate.

(a) Expenses for the test period per books;

(b) Claimed adjustments, if any, to actual expense;

(c) Total adjusted expense claimed.

(2) The bases, methods, essential computation and derivation of unit rates for the calculation of depreciation, depletion and amortization expense for the test period and for the adjustments thereto shall be fully and clearly explained by working papers supporting the exhibited amount. The amounts of depreciable plant shall be shown by functions specified in the account "accumulated provisions for depreciation of plant in service" of the Uniform Systems of Accounts for public utilities.

(3) Any deviation from the rates used in disposing of the utility's last previous rate filing or determination by this Commission shall be explained, showing the rate or rates previously used together with supporting data for the new rate or rates used for this filing.

(1) Where tax depreciation differs from book depreciation, the utility shall file work papers showing the computation of the tax depreciation which will indicate the differences between book and tax depreciation.

(a) Tax expense per books for the test period;

(b) Claimed adjustments, if any, to amounts booked;

(c) Total adjusted taxes claimed.

(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.

(2) The billing impact for each customer class must be provided. This analysis must indicate how many customers on each tariff would receive bill increases or decreases of various percentages and dollar amounts.

This rule has been repealed.

(1) Statement N shall include a description of the utility's area and diversity of operations and a breakdown of sales between jurisdictional and nonjurisdictional operations.

(1) If any of the preceding statements cover major purchases or major transfers from an affiliate that is not regulated as to price, the applicant shall submit an explanation of the price associated with the purchases or transfers.

(1) To the extent that testimony and exhibits required to be filed pursuant to ARM 38.5.181 duplicate information required to be submitted pursuant to ARM 38.5.101 to 38.5.180, inclusive, such information need only be submitted with the testimony and exhibits pursuant to ARM 38.5.181.

(1) Applicant utilities that submit information in accordance with the minimum rate case filing standards for electric, gas and private water utilities shall provide pictorial exhibits, as defined below, for those items which affect the unallocated utility results of operations and the allocated costs of service/rate designs pertaining to Montana operations. Applicant utilities may provide such other pictorial exhibits as will further understanding of their filing.

(a) Each adjustment that is identified in textual or numerical information and causes a ratemaking change to the actual unallocated test year results of operations shall be presented in a flow chart or decision matrix that depicts each factor that caused the adjustment. Alternatively, adjustments may be identified and explained in a report that summarizes each adjustment.

(b) The total revenue requirements requested, both interim and permanent, shall be depicted in graphs or charts which show actual unallocated test year results of operations and each adjustment referred to in subsection (a) .

(c) Each account, excluding subaccounts, which affects the adjusted unallocated results of operations shall be shown in tabular form. The tables shall include the test year adjusted account value, the test year actual account value, the account value most recently approved by the Montana public service commission in a final rate case order and the actual account values from the previous four years. Values for functionalized categories which are accumulated from various accounts such as the distribution expense category shall be presented as bar charts. Each chart shall include the actual test year value, the adjusted test year value, and the actual value for the year preceding the test year.

(d) Applicant utilities that submit testimony and exhibits which are in response to rebuttal testimony and exhibits of other parties shall include pictorial exhibits which show the effect that the rebuttal submissions have upon the original filings. The submitted testimony and exhibits of each rebutting party shall be depicted in graphs or charts which show the actual unallocated test year results of operations and each adjustment that causes a ratemaking change to the actual unallocated test year results. The allocated cost of service/ rate design study of each rebutting party shall be depicted in charts that show each item referred to in subsection (e) .

(e) Each component of an applicant's allocated cost of service/rate design study shall be depicted in pie charts or bar charts. The charts shall include values for functionalizations by customer class of all cost categories, classifications by customer class of each functionalized cost category, moderations and rate designs by customer classes, allocators that were most recently approved by the Montana public service commission in a final rate case order and that are proposed.

(2) Each allocated cost of service and rate design application shall include an example and general explanation of each current bill format that is used by the utility for tariffed services. Copies of other billing information that are provided to large groups of customers should also be provided and briefly explained. Additional information may be provided at the discretion of the filing utility.

(3) Absent regular allocated cost of service and rate design filings, a marginal cost of service study shall be submitted to the commission for information purposes, minimally, every two years. If the utility files an integrated resource plan with the commission, cost information shall be submitted within six months following such filing, unless the cost information has been presented within the previous two years. At the time a marginal cost of service study is filed, the utility, at its own option, may submit an embedded cost of service study.

(4) A marginal cost of service study filed pursuant to this rule or in the context of a rate case must contain current allocation factors.

(5) Three copies of the letter of transmittal and three copies of all material required in ARM 38.5.176, 38.5.177 and 38.5.109 shall be filed with the commission at the time of application. Montana consumer counsel shall receive two copies of the same materials.

(6) All or any part of the requirements of these rules may be waived by the commission upon a showing of good cause. Waiver of any requirements, however, shall not preclude the commission from requiring the filing of specific cost data and material sufficient to support the application.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

(a) include a brief description of the proposed changes in service, rate, or charge; and

(b) name an employee of the carrier who shall be responsible for answering questions concerning the application.

(2) This notice shall also contain the following language: As the commission believes that competitive conditions prevail in this industry, your request for a hearing must contain a preliminary showing either that competitive conditions do not prevail with respect to this radio common carrier or that this application represents some other type of abuse by the applicant.

(3) If a request for a hearing is made that does not meet the requirements of ARM 38.5.404(2) , the commission staff will contact the person requesting the hearing to determine if either of the showings required by ARM 38.5.404(2) can be made. If the showings cannot be made, no hearing will be held.

(4) The commission shall liberally construe its rules of discovery (ARM 38.2.3301- 38.2.3305) in order to effectuate the goals of this rule.

(1) Any application for an interim grant of authority to increase utility rates must be filed in conjunction with a permanent rate case proceeding.

This rule has been repealed.

(2) For every interim rate increase request, the applicant shall file the original and eight copies of the letter of transmittal, application exhibits, certificate of service for notice of the interim application and proposed order, with the Commission; two copies of the letter of transmittal, the application and any exhibits shall be simultaneously filed with the Montana Consumer Counsel; copies of the letter of transmittal, application, and any exhibits shall also be filed with all parties to any coincident permanent rate case.

(3) Any applications for interim authority to increase utility rates to meet increased costs of a single, clearly measurable expense item (tracking cases) shall be supported by the following:

(a) Letter of transmittal

(b) Application

(c) Rate schedules - current and proposed

(d) Detail of increased expense item

(e) Summary of base cost of expense item and proposed adjustment

(f) Statements showing effects of proposed adjustment, including operating income, rate of return, and return on average equity.

(g) Most recent 12 month balance sheet and income statement.

(4) Filings made under this rule and those contemplated by ARM 38.5.507 are not subject to the standards set forth in the Commission's Minimum Rate Case Filing Standards ARM 38.5.101 through 38.5.184.

(2) The Commission shall calculate all interim rate increase requests in a general rate increase proceeding in the following manner:

(a) Test year booked net utility operating income and test year average rate base will be normalized and annualized, when such test year data is available.

(b) Any adjustments that were made in the most recent Commission general rate order of the utility will also be made using the methodology and rate of return on equity from that order, and applied to the filed test year amounts. These adjustments may be modified and other adjustments made as deemed appropriate by the Commission.

(3) Consideration of an application to increase rates on an interim basis in a tracking case will be guided by:

(a) A showing that the expense item concerned is a clearly identifiable cost to the utility;

(b) A clear showing that the proposed rate increase precisely matches the known increased expenses;

(c) A clear showing that deferred rate relief would result in irreparable financial harm to the petitioning utility; and

(d) Supporting material as enumerated in ARM 38.5.505(3) .

(4) All interim rate increase requests must be accompanied by a revenue increase figure calculated in accordance with ARM 38.5.506(2) .

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

(1) This subchapter is applicable to electric and natural gas public utilities.

(2) Except where otherwise provided, a utility shall comply with the minimum filing standards of this subchapter whenever it files for a rate schedule change pursuant to 69-3-302 or 69-3-308, MCA which incorporates changes in Montana state and local tax expense, except that this subchapter does not apply to rate schedules filed to adjust for the Public Service Commission tax or the Montana Consumer Counsel tax.

(3) Filings made pursuant to 69-3-308, MCA are exempt from the filing requirements of ARM 38.5.101 to 38.5.195.

(1) The utility shall include with the request for a rate adjustment all files in an easily readable electronic format, which, if applicable, shall have all digital links intact.

(2) The letter of transmittal with respect to a filing for a new or existing tariff to provide for an adjustment of state and local taxes and fees under 69-3-308, MCA shall:

(a) list the documents submitted with the filing;

(b) state the names and addresses of those to whom copies of the rate schedule have been mailed;

(c) include a brief description of the proposed changes in service or rate and charge;

(d) state the reasons for the proposed changes;

(e) state the estimated number of customers whose cost of service will be affected and annual amounts of either increases or decreases, or both, in cost of service to such customers;

(f) name an employee of the utility who shall be responsible for answering questions concerning the application, or for referring inquiries to appropriate members of the utility staff;

(g) include a clear statement of the relief requested;

(h) include a table or spreadsheet showing each rate affected by the rate adjustment, including the rate as it currently exists, the incremental change due to the tracker, the proposed total rate, and the portion of the rate attributable to tax; and

(i) propose revised tariffs that would be affected by the rate adjustment, including both clean and red-lined copies.

(1) The application made under 69-3-308, MCA, by a utility shall include the pre-filed testimony of a witness or witnesses. If the testimony of more than one witness is presented, the utility will identify one witness who is responsible for the completeness of the statements and work papers contained in the filing.
 

(1) The application for automatic adjustment for Montana state and local taxes and fees, excluding income taxation, provided for under 69-3-308, MCA shall include:

(a) the projected changes in taxes from the prior year;

(b) the true-up of the prior year's actual revenue attributable to taxes versus actual taxes; and

(c) the extinguishment of deferred balances.

(2) Revenues attributable to the component of existing rates attributable to Montana state and local taxes and fees shall be calculated, including the revenues earned and projected to be earned by:

(a) rates authorized by the Montana Public Service Commission;

(b) rates authorized by the Federal Energy Regulatory Commission (FERC);

(c) rates authorized by other state utility commissions, to the extent that Montana state and local taxes and fees are allocated to those jurisdictions; and

(d) charges made by the utility, its affiliates, or its parent for services which are not regulated but on which the utility is assessed Montana state and local taxes and fees, including but not limited to non-regulated gas gathering and production activities.

(1) For Montana state and local taxes and fees, excluding income taxation, allocated to rates collected under FERC tariffs:

(a) the utility shall disclose and explain the present allocation methodology of the expense to retail and wholesale customers;

(b) the utility will identify in a table a list of all property which is subject to a jurisdictional allocation between retail and wholesale customers by:

(i) FERC account;

(ii) value in rate base, on an original cost less depreciation basis; and

(iii) the total amount of tax expense for each FERC account listed.

(c) if the taxing jurisdiction does not disclose or specifically identify the amount of tax expense allocated or assessed to property by type, the utility will disclose as such and will use an appropriate allocator consistent with prior commission orders or with its own internal practice;

(d) the utility will indicate the last time it has filed at FERC a general rate case or a case specific to a service offered under its open access transmission tariff, and describe how tax expense was incorporated into its rate proposal and, if specified, the FERC's final determination of rates;

(e) the utility will present information for allocation methodologies, regardless of which is proposed or adopted for current use. These shall include at a minimum:

(i) the revenue produced under FERC rates which is attributable to Montana state and local tax and fee expense, calculated on the basis of the percentage of the last-approved revenue requirement which was attributable to this expense; and

(ii) a calculation of the usage of the assets subject to state and local taxes and fees by retail customers and by wholesale customers, with an allocation of the associated tax expense to the wholesale and retail customers of the utility on a basis consistent with that usage employing a twelve-coincident-peak methodology.

(f) the commission may request an additional study to allocate this expense on another basis; and

(g) a utility that does not collect any revenues under FERC tariffs will file a statement certifying accordingly.

(1) For Montana state and local taxes and fees and for other states' taxes, excluding income taxation, which are allocated to rates authorized by the commission and by other state utility commissions:

(a) the utility shall disclose and explain the allocation methodology of these expenses to Montana customers and to customers of other states; and

(b) the utility shall provide a statement including data for the last three years and for the coming year, which:

(i) discloses the actual tax expense attributable to each jurisdiction under the last approved allocation methodology of the commission; and

(ii) provides an estimate of the amount of revenue attributable to these taxes the utility had projected to earn based on the tax expense in rates of its last general rate case filings in those jurisdictions, inflated or deflated by the projected growth in sales volumes of units whose rates include tax-related expense.

(2) For the purposes of making findings on questions of jurisdictional separations for the purposes of including tax expense into rates, the commission, upon evaluating the information provided pursuant to this section and other information which it may possess, may find errors that lead to adjustments in rates for reasons including, but not limited to, the following:

(a) that an allocation methodology inaccurately allocates the expense or the revenue, or both, to customers of different jurisdictions; or

(b) that revenues from other jurisdictions' customers are sufficient to satisfy the utility's liability for Montana state and local taxes and fees.

(1) To account for the deductibility of tax expense from the utility's income tax liability when filing for an automatic rate adjustment for Montana state and local taxes and fees, the utility will multiply the statutory income tax rate by the incremental change in Montana state and local tax expense. The product of this multiplication is the amount of the income tax benefit, positive or negative, that results from the automatic rate adjustment for Montana state and local taxes and fees.

(2) Together with an application for a change in rate schedules filed pursuant to 69-3-302, MCA the utility shall:

(a) provide its last three annual income tax filings for both the federal and Montana jurisdictions;

(b) file a request for a protective order no later than three weeks before such a rate filing is made, if the utility desires to exercise its right under federal law to keep its income tax filing confidential; and

(c) file a statement which:

(i) discloses the amount of revenue attributable to the component of existing commission rates attributable to federal and state income taxes;

(ii) identifies the total income tax expense associated with or allocated to the customers paying those commission rates;

(iii) indicates any amount of tax benefit or liability which is normalized pursuant to federal or state laws or regulations;

(iv) indicates any amount of tax benefit or liability which is normalized voluntarily, at the utility's option, and not because it is required pursuant to federal or state laws or regulations; and

(v) provides a spreadsheet or other information documenting a cost-benefit analysis for customers regarding the utility's election for a tax treatment that prohibits flow-through and requires normalization.

(1) Together with an application for an automatic rate adjustment for Montana state and local taxes and fees under 69-3-308, MCA, a utility will identify an allocation of Montana state and local taxes and fees to plant by FERC account.

(2) In making the allocation of taxes to plant type, the utility will identify and explain its methodology, which may be informed by both the books and records of the utility company's capital investments and by the allocation of value to taxing jurisdictions by governmental authorities and by other factors the utility and the commission consider reasonable.

(3) The utility will provide FERC account balances for plant for the previous two years as of the lien date used by the Montana Department of Revenue for tax purposes.

(1) A utility will file the past two years' tax valuations from the Montana Department of Revenue.

(2) The utility will describe any informal or formal protests for its valuation or its tax expense that it has filed with any jurisdiction.

(3) For the purposes of complying with 69-3-308(2)(a)(i)(C), MCA a utility will provide a statement or table of adjustments made for the resolution of property taxes paid under protest. If there are none, it will file a statement indicating as such.

(1) A utility's application under 69-3-308, MCA, must include testimony and work papers showing the allocation of an adjustment to Montana state and local taxes and fees to each of the utility's customer classes. Testimony must include a thorough description of and justification for the allocation method(s).

(2) A utility's application must include testimony and work papers showing the derivation of rate adjustments provided for in ARM 38.5.802(2)(i). Testimony must include a thorough description and justification for the requested rate design. Work papers must include an analysis showing customer bill impacts, by customer class, for various usage levels typical for the customer class.

(1) A utility will disclose any taxes or fees assessed by taxing jurisdictions within the state of Montana which are not Montana state or local taxes or fees under 69-3-308, MCA, including, but not necessarily limited to, tribal taxes.

(1) For utility applications made pursuant to 69-3-308, MCA if a utility has not complied with the minimum filing standards of this subchapter or has otherwise failed to provide information as provided for in the proceeding to consider the filing, the commission may order within forty-five days of receipt of the utility's application that the utility address these omissions and continue the proceeding until they are addressed.

(2) For utility applications made pursuant to 69-3-302, MCA, a filing made by a utility which does not include the information required by this subchapter, the remedies provided for in ARM 38.5.184 apply.

(3) This rule does not affect the commission's ability to pursue the remedies provided for in 69-3-206 and 69-3-208, MCA.

(2) As used in this rule, "technically feasible" means that the trench through which the underground lines would run could be excavated by a conventional backhoe or trencher, with no blasting and minimal use of jackhammers or like equipment required, and the consumer unit is situated on a lot or parcel not larger than five acres.

(3) As used in this section, "economically feasible" means:

(a) If underground installation cost/unit does not exceed twice overhead installation cost/unit, underground installation is feasible and shall be constructed at the expense of the utility and the developer or the customer in accordance with the applicable rate schedule on file with the commission; and

(b) If underground installation cost/unit is more than twice overhead installation cost/unit, underground installation is economically infeasible within the meaning of 69-4-102 , MCA, and underground installation is not required in such cases.

(4) As used in the preceding subsection, "unit" means a residence or commercial structure in a new subdivision, as defined in 69-4-102 , MCA, and "distribution lines" mean all electrical lines in the subdivision used for the conveyance of electricity from a bulk power source to the consumer.

(1) Pursuant to 69-4-201, MCA, the commission is empowered to implement and enforce construction standards for utility lines and facilities and for that purpose the commission adopts and incorporates by reference the 2023 edition of the National Electrical Safety Code (NESC). A copy of the NESC may be obtained from the American National Standards Institute, 25 West 43rd Street, 4th Floor, New York, New York 10036, or may be reviewed at the Public Service Commission Offices, 1701 Prospect Avenue, Helena, Montana 59620-2601.

(a) Prior service with utility in question within the previous 12 months during which for at least 6 consecutive months service was rendered and was not disconnected for failure to pay, and no more than one delinquency notice was served upon the customer.

(b) Prior service with a utility of the same type as that of which service is sought with a satisfactory payment record as demonstrated in (a) above, provided that the reference may be quickly and easily checked by the utility and the necessary information is provided.

(c) Full-time consecutive employment during the entire 12 months next previous to the application for service, with no more than two employers, and the applicant is currently employed or has a regular source of income.

(d) Ownership of significant legal interest in the premises to be served.

(e) Furnishing of a satisfactory guarantor to secure payment of bills for services requested in a specified amount not to exceed an estimated one year bill, such estimation to be made at the time the service is established.

(f) In the case of telephone utilities, the guarantee amount shall be for the total amount of the bill.

(1) An applicant for nonresidential service may be required to demonstrate that it is a satisfactory credit risk by reasonable means appropriate under the circumstances.

(a) Where the applicant has failed to establish a satisfactory credit history as outlined above.

(b) In any event, a deposit may be required when within the 12-months prior to the application, the applicant's service of a similar type has been disconnected for failure to pay amounts owing, when due; where there is an unpaid, overdue balance owing for similar service from the utility to which application is being made or from any similar utility; or where two or more delinquency notices have been served upon the applicant by any other utility company during the 12-months previous to the application for service.

(c) Initiation or continuation of service to a residence where prior customer still resides and where any balance for such service to that prior customer is past due or owing.

(d) Where the customer has, in an unauthorized manner, interfered with the service of the utility situated or delivered on or about the customer's premises within the last five years, if the finding of unauthorized interference or use is made and determined after notice and opportunity for hearing is provided to the customer and is not in dispute.

(2) In the case of telephone utilities, the deposit may be accordingly adjusted when the actual interchange service charges are subsequently found to be more or less than those estimated.

(2) In the case of telephone utilities, the deposit is only transferable within the same exchange.

(a) Where the customer has for 12 consecutive months paid for service when due in a prompt and satisfactory manner as evidenced by the following:

(i) The utility has not initiated disconnection proceedings against the customer; and

(ii) No more than two notices of delinquency have been made to the customer by the utility.

(b) Upon termination of service the utility shall return to the customer the amount then on deposit plus accrued interest less any amounts due the utility by the customer for service rendered.

(c) Any deposit, plus accrued interest, shall be refunded to the customer in the form of a check issued and mailed to the customer no more than 30 days following the termination of service or completion of 12 months satisfactory payment as described above. Other methods of refund (e.g., cash) , if agreed to by the customer and the utility, are permitted. In the alternative, in the utility's discretion, unless the customer has specifically directed otherwise, the deposit may be applied to the customer's bill of service in the thirteenth and, if appropriate, subsequent months.

(a) Each customer posting a cash deposit shall receive in writing at the time of tender of the deposit a receipt as evidence thereof, which contains the following minimum information.

(i) Name of customer;

(ii) Address of customer;

(iii) Place of payment;

(iv) Date of payment;

(v) Amount of payment;

(vi) Identification of the employee receiving payment;

(vii) Statement of the terms and conditions governing the receipt, retention and return of deposit funds.

(b) A utility shall provide means whereby a customer entitled to a return of his deposit is not deprived of deposit funds even though he may be unable to produce the original receipt for the deposit. In such event company records shall be controlling.

(a) Any individual or business entity which has maintained service with the utility in question for the previous 24 months, and who has not had service disconnected for failure to pay, and has received no more than two delinquency notices.

(b) Any special fund approved by the commission.

(a) It shall be in writing, and if necessary shall be renewed in a similar manner annually.

(b) It shall state the terms of guarantee, the maximum amount guaranteed (such maximum not to exceed an estimated one year bill, such estimation to be made at the time the service is established) , and that the utility shall not hold the guarantor liable for sums in excess thereof unless agreed to in a separate written instrument.

(c) Credit shall be established for the customer and the guarantor shall be released upon the satisfactory payment by the customer of all proper charges for utility service for a period of 12 successive months. For purposes of this subsection, payment is satisfactory if:

(i) The utility has not initiated disconnection proceedings against the customer.

(ii) No more than two notices of delinquency have been made to the customer by the utility.

(2) The utility may withhold the release of the guarantor pending the resolution of a disputed discontinuance.

(a) only in the event of the nonavailability to the customer of any other form or source of energy from any supply, which other form of energy is predominately relied upon by the customer; or

(b) on a regular basis as the customer's predominate energy source but is subject to periodic partial or complete curtailment, at the customer's option, and replacement by another energy form or source.

(1) Any utility requesting "standby charges" before this Commission in the future shall provide adequate data supporting "standby service" costs incurred, including but not limited to:

(a) number of customers equipped with alternative, renewable energy sources who would be affected by such charges;

(b) current costs and payback periods of the major alternative energy systems with no standby charge; current costs and payback periods of the major alternative energy systems if the standby charge as requested is authorized;

(c) for proposed standby charges for electric utility service, time-of-day and load information for the various classes of customers; and for the various energy source systems employed by them;

(d) cost of service information, including incremental cost of service information broken down by cost of service to the class of customers with unlimited use backup systems and the class of customers with backup service restricted to off-peak replenishment of energy storage systems.

(2) In accordance with the information presented in response to (1) (d) proposed standby charges must distinguish between standby customers with unlimited use of the utility's service, and those with backup service restricted to off-peak replenishment of energy storage systems.

(3) Any utility requesting "standby charges" in the future must inform the Commission of the means by which the utility intends to determine which of its customers are to be subject to the standby charge if approved.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

(1) The repeal of these rules does not affect the status of any existing EAS arrangement.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

(1) "Appliances essential for maintenance of health" means any electric or gas energy-using device which is certified by a licensed physician as being essential to prevent or to provide relief from serious illness or to sustain the life of a member of the household and for which there is no reasonable alternative.

(2) "Customer" means any purchaser of gas or electric service supplied by a utility for residential purposes.   A person who requests disconnection of service at his or her current address in order to move service to his or her new address with no break in the service is an existing customer, not an applicant for new service.

(3) "Delinquent account" means an account for residential service which remains unpaid for at least 30 days after the bill is rendered.   The exact due date shall be printed on the face of the bill.

(4) "Elderly" means any residential electric or gas consumer aged 62 or older, who resides at the service address.

(5) "Handicapped" means any residential electric or gas consumer who resides at the service address and has any physicial or mental impairment which substantially limits one or more of such person's life activities, and such person:

(a) is certified as being physicially disabled by a licensed physician, or

(b) is certified as being mentally disabled by a licensed psychiatrist or registered psychologist, veterans administration, social security administration, or local board of health.

(6) "Landlord customer" means one or more individuals or an organization listed on a gas or electric utility's records as the party responsible for payment of the gas or electric service provided to one or more residential units of a building, which is occupied by a tenant.

(7) "Person unable to pay or to pay only in installments" means any purchaser of electric or gas service for residential purposes, who is a recipient of public assistance and/or has an income at or below federal poverty guidelines.

(8) "Residential building" means a building containing one or more dwelling units occupied by one or more tenants, but excluding hotels and motels not used primarily for residential purposes.

(9) "Tenant" means any person or group of persons whose dwelling unit in a residential building is provided natural gas or electricity, pursuant to a rental agreement, but who is not the customer of the utility which supplies said gas or electricity.

(10) "Termination of service" means a cessation of service effectuated by the utility and not voluntarily requested by a customer.

(a) Nonpayment of a delinquent account;

(b) Misrepresentation of identity for the purpose of obtaining utility service;

(c) Unauthorized interference, diversion or use of the utility's service situated or delivered on or about the customers premises;

(d) Failure to comply with the terms and conditions of a deferred payment agreement made in accordance with these rules;

(e) Refusal to grant a duly authorized representative of a utility access to equipment upon the premises of the customer at reasonable times for the purpose of inspection, maintenance or replacement when the utility has given the customer reasonable notice of the need for such access and the time of visitation;

(f) Violation of other rules of the commission or utility which adversely affects the safety of the customers or other persons, or the integrity of the utility's delivery system.

(1) Neither of the following shall constitute grounds for a utility to terminate service:  

(a) The failure of any person, other than the customer against whom termination is sought, to pay any charges due to the utility;

(b) The failure of a customer to pay for merchandise, appliances or other services not contained in tariffs approved by the commission.

(a) The time allowed to pay outstanding bills;

(b) A statement that arrangements for installment payment of delinquent bills can be made at any time prior to termination of service;

(c) The title and telephone number of the utility employee to which inquiries and disputes may be directed;

(d) The time allowed to initiate a dispute;

(e) Instructions for designating a third party to receive a copy of termination notices;

(f) Instructions for designating elderly or handicapped status or a medical emergency;

(g) Instructions for designating the presence of special appliances essential for maintenance of health or safety.

(h) Details of the method of termination as described in ARM 38.5.1413.

(i) Availability of a copy of the Commission's rules on termination of service.

(1) A utility may not terminate service to any residential, firm, commercial, industrial or other customer unless written notice is served.

(2) Termination notice shall be served as follows:

(a) If no response to the first notice is received within ten days of mailing, the utility must send a second notice by first class or certified mail (return receipt requested) . The second notice must be sent by the utility or personally served on the customer at least ten days prior to the date of the proposed termination.

(b) A utility may terminate utility services upon serving written notice five business days prior to the proposed termination date when a customer:

(i) remits an insufficient funds check as payment to the utility after receiving the first notice of termination, or

(ii) breaches a payment agreement made pursuant to ARM 38.5.1415.

(c) The provisions of (a) shall govern notice of termination to landlord customers, except that the first notice must be sent at least 30 days prior to the date of the proposed termination.

(d) The utility shall give written notice of the proposed termination for nonpayment to each residential unit reasonably likely to be occupied by an affected tenant of a landlord customer subject to termination. Such notice shall not be rendered earlier than five business days following initial notification to the landlord customer. However, if the landlord customer disputes the amount owing, such notice shall not be rendered until the dispute has been resolved. In no event shall such notice be served upon the tenants less than 15 days prior to the termination of service to the landlord customer on account of nonpayment. Upon affidavit, the Commission may, for good cause shown by the utility, reduce the minimum time between notification of the landlord customer and notification of the tenants.

(e) Prior to termination of service the utility must make a diligent attempt to contact the customer, either in person or by telephone, to apprise him of the proposed action. If telephone or personal contact is not made, the utility employee shall leave notice in a place conspicuous to the customer that service will be terminated on the next business day unless the delinquent charges have been paid.

(3) When service is terminated, the utility employee terminating service shall leave notice upon the premises in a place conspicuous to the customer that service has been terminated which gives the address and telephone number of the utility where the customer may arrange to have service restored. The utility shall have personnel available after the time of termination and during normal business hours authorized to reconnect service if the conditions cited as grounds for termination are corrected to the utility's satisfaction and upon payment of any reconnection charge specified in the utility's filed tariffs.

(a) The utility's statement of termination policy;

(b) An identification of the customer and service account affected by the proposed termination;

(c) A statement of reasons for termination;

(d) The date of proposed termination;

(e) The amount of the reconnection fee, if any;

(f) A summary of rights and remedies, including procedures to dispute the termination notice, provisions relating to elderly and handicapped consumers and those suffering a medical emergency, provisions for customers who are unable to pay their bills and steps necessary to make a claim of inability to pay, availability of installment payment arrangements and sources of financial assistance.

(g) Designation of the bill in question as actual or estimated;

(h) Except for notification of tenants, amount owed and time period over which amount was incurred;

(i) Instructions on how service can be restored;

(j) In the case of a landlord customer, the date on or after which the utility will notify tenants of the proposed termination.

(k) In the case of notification of tenants:

(i) The amount of an average monthly bill for utility service to the premises and the largest bill for utility service to the premises in the previous 12 months;

(ii) A statement that Commission procedures and the Laws of Montana may give the tenant certain rights with respect to which the tenant may wish to consult an attorney or Montana Legal Services.

(a) If a condition immediately dangerous or hazardous to life, physicial safety or property exists;

(b) Upon order by any court, the Commission or any other duly authorized public authority;

(c) If such service is obtained fraudulently or without authorization of the utility.

(2) In its investigation of the proposed termination or during any hearing regarding the proposed termination, the Commission may make inquiry of the parties as to the following matters, among others:

(a) The extent to which the customer has control over their source of money for payments, including such matters as the lateness of public assistance checks;

(b) Weather conditions;

(c) The existence of illness of residents in the affected residences;

(d) The ages of the persons residing in the affected units;

(e) The existence of, or potential for, termination of service by other companies.

(3) The Commission may consider and give due weight to the above matters in any decision rendered on the appeal.

(1) During the period November 1st to April 1st and on any day when the reported ambient air temperature at 8:00 a.m. is at or below freezing or if the U.S. Weather Service forecasts a snowstorm or freezing temperatures for the succeeding 24-hour period, no termination of residential service may take place if the customer establishes that he or she is unable to pay, or able to pay only installments, that he or she or a member of the household is at least 62 years old or that he or she or a member of the household is handicapped.

(2) No termination of service may take place during the period of November 1st to April 1st except with specific prior approval of the Commission.

(1) Except as provided herein� service may not be terminated to a residence where a licensed health care professional certifies to the utility that the absence of service will aggravate an existing medical condition which would threaten the health of any permanent resident. A licensed health care professional means a licensed physician� physician assistant-certified� advanced practice registered nurse� or registered nurse provided for in ARM 37.106.2805 and Title 37, MCA. All certifications must be in writing and provide the name and address of the person with the medical condition that would be aggravated by a termination of service. The certification must include the printed name, signature� office address, and telephone number of the certifying licensed health care professional. A medical condition certificate is valid for 180 days from the date it is signed and dated by the licensed health care professional� and may be renewed on a semiannual basis.

(2) To avoid the accumulation of a substantial arrearage during the term of the medical certificate, the utility and the customer, or an authorized representative of the customer, shall negotiate an equitable payment arrangement that is reasonable and consistent with the customer's ability to pay. If the customer fails to make payments as established, resulting in an arrearage of $500 or more, the customer is required to enter into and comply with a monthly payment arrangement equal to the average of the last 12 months billing plus 1/12 of the arrearage. Failure to enter into a monthly payment arrangement and make payments will result in disconnection proceedings being initiated as set out in (3).

(3) The utility must provide written notice of the initiation of disconnection proceedings to the customer. If the missed payments are not received within ten days of mailing� the utility must send a second notice. From the date of the second notice the customer must pay at least one-third of the delinquent charges to avoid termination of service. The second notice must be sent by the utility at least ten days prior to the date of the proposed termination. All written notices must be sent by first class or certified mail. Prior to termination of service the utility must make a diligent attempt to contact the customer� either in person or by telephone� to apprise the customer of the proposed action. If telephone or personal contact is not made� the utility employee shall leave notice in a place conspicuous to the customer that service will be terminated on the next business day. If the required payment is made� a new payment arrangement will be recalculated consistent with (2). Under no circumstances shall disconnection proceedings occur on accounts with an arrearage of less than $500. Nothing in this rule prevents a utility from continuing service to a delinquent medically protected account.

(4) The utility must notify the commission in writing of the proposed termination at the beginning of the disconnection process. The commission may intervene and require a different payment arrangement or delay termination of services if the circumstances warrant. Before the commission will consider approving an alternate payment arrangement, the customer must apply, if eligible, for financial aid through organizations providing utility bill payment assistance and must respond to commission requests for information. The payment arrangement set by the commission is binding upon both the customer and the utility. Failure to comply with the payment arrangement may result in disconnection proceedings being initiated as set out in (3).

(5) From November 1 through March 31, the utility may not terminate a medical exception account protected from disconnection by the criteria established in ARM 38.5.1410.

�

(2) The utility's representative (employee) shall attempt to inform the occupant of the affected residence that service is to be discontinued. The employee shall present the occupant with a statement of charges due and shall request verification that the delinquent charges have not been paid or are not subject to a dispute previously registered with the utility or the Commission. Upon the presentation of evidence which reasonably indicates that the charge has been paid or is subject to a dispute previously registered with the utility or the Commission, service shall not be terminated.

(3) The employee shall be authorized to accept payment. If payment in full of all delinquent charges is tendered, service shall not be terminated.

(4) Payment may be tendered in any reasonable manner including personal check. Payment by personal check is not reasonable if the customer has paid the utility with checks returned for insufficient funds twice or more within the previous two years.

(2) Each utility shall promptly, and in no event later than 90 days after the effective date of these rules, devise procedures reasonably designed to provide a voluntary system of third party notification for all customers. Such procedures shall be submitted by each company in writing to the Commission. The Commission may require, by a written notification, such modifications of a utility's procedures as it considers reasonably necessary to carry out the purposes of this rule.

(2) In deciding on the reasonableness of a particular agreement, the utility shall take into account the customer's ability to pay, the size of the unpaid balance, the customer's payment history, and the amount of time and reasons why the debt is outstanding.

(3) If a customer fails to make the payment agreed upon by the date that it is due, the utility may, but is not obligated to, enter into a second such agreement.

(4) No such agreement or settlement shall be binding upon a customer if it requires the customer to forego any right provided for in these rules.

(a) The amount the tenants have paid to the utility in relation to the amount equal to one month's bill, and the arrearage on any earlier bill due from tenants;

(b) The number of vacant units in the building;

(c) The extent to which the tenants have control over their source of money for rent payments, including such matters as the lateness of public assistance checks, direct rent payments by the Welfare Department to the tenants' landlord, or participation by tenants in a leased housing or rental assistance program;

(d) Whether the tenants are engaged in rent withholding against their landlord;

(e) The amount of payments recently received by the utility from the landlord and the size of the past due bill of the landlord;

(f) Whether the utility has pursued collection remedies, other than threatened termination of service, against the landlord;

(g) Weather conditions;

(h) The existence of illness of persons residing in the affected units;

(i) The ages of the persons residing in the affected units;

(j) The availability of other housing to the tenants; and

(k) The existence of, or potential for, termination of service by other companies.

(4) The Commission may consider and give due weight to the above matters in any decision rendered on the complaint.

(2) The statement of existing applicable rate schedule shall be sent at least once each year to each consumer, the initial statement to be sent within 90 days of adoption of this rule, or within 60 days of commencement of service to new consumers, whichever is later. If the applicable rate schedule is changed during the course of any year, a statement of the new rate schedule shall be sent to each consumer concurrent with the bill which reflects for the first time the change in rate.

(3) Each electric utility shall transmit to each of its electric consumers not less frequently than once each year a clear and concise summary explaining the existing rate schedules applicable to each of the major classes of its electric consumers for which there is a separate rate and shall identify each class of consumer whose rates are not summarized.

(4) The summary may be transmitted with the consumer's bill or in such other manner that each electric utility deems appropriate.

This rule has been repealed.

(1) Within 60 days of any establishment of optional or alternative rate schedules, and annually thereafter, the utility shall furnish each consumer who may be affected by them, a summary of the applicable rate schedules, together with a notice calling the attention of the consumer to the availability of alternative rate schedules for the consumer's particular class of service and stating that, upon request, the utility will assist the consumer in determining the billing for such service as is specified by the consumer under the various rate schedules.

(1) Each electric utility shall keep on file in every office of the utility where payments are received, copies of its rate schedules and rules and regulations applicable thereto. Reasonable notice shall be given consumers as to where this information is available.

NEXT PAGE 38-675

(a) "New building" means:

(i) any building the construction of which commenced six months after the effective date of these rules; and

(ii) any existing building in which the replacement of the electrical system is commenced six months after the effective date of these rules, in which there are more than one unit and the occupant of each such unit has control over a portion of the electric energy used in such unit.

(b) "Construction" or "replacement" commences at the time physical labor involved with the erection of the building or the actual replacement of the electrical system begins.

(c) "Affected electric utilities" are all electric utilities subject to the jurisdiction of this Commission.

(a) Electricity delivered to hotels, motels, hospitals, dormitories, and other similar transient lodging;

(b) Where the individual contractor or owner of a new building provides to the utility, in writing before commencement of construction or replacement, data showing that the contractor's or owner's costs of purchasing and installing facilities for separate metering, when added to the utility's costs of purchasing and installing separate meters, exceed the long run benefits.

(2) Each electric utility shall, by March 1, 1981, submit to the commission for approval the criteria by which the utility proposes to analyze utility and owner or contractor costs when a determination of whether the costs of purchasing and installing separate meters exceed the long-range benefits of separate metering is required.

(2) The affected electric utilities shall submit to the public service commission, by March 1, 1981, and semi-annually thereafter:

(a) A list of the contractors or owners of new buildings who, during the reporting period, have submitted written data to the utility to establish exception status from ARM 38.5.1602; and

(b) A list of the contractors or owners of new buildings for which the utility has recognized such exception status during the reporting period.

NEXT PAGE 38-679

(a) "Automatic adjustment clause" means a provision of a rate schedule which provides for increases or decreases (or both) , without prior hearing, in rates reflecting increases or decreases (or both) in costs incurred by an electric utility. Such term does not include an interim rate which takes effect subject to a later determination of the appropriate amount of the rate.

(1) Section 69-3-303 , MCA, which requires notice and public hearing before the commission may approve increases in utility rates of general applicability, prohibits the use of automatic adjustment clauses.

(2) It is the policy of the Montana public service commission to preserve the hearing process demanded by section 69-3-307 , MCA, and by the Montana Administrative Procedure Act, and on that ground to deny the use of automatic adjustment clauses in utility rate schedules of general applicability.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

(1) For purposes of these rules, the following definitions apply:

(a) "Avoided costs" is defined as provided in 18 CFR 292.101(b)(6).

(b) "Cogeneration facility" is defined as provided in 18 CFR 292.202(c).

(c) "Commission" means the Montana Public Service Commission.

(d) "FERC" means the Federal Energy Regulatory Commission.

(e) "Interconnection costs" is defined as provided in 18 CFR 292.101(b)(7).

(f) "Production profile" means the expected hourly generation output of a qualifying facility for a full year based on an engineering analysis of the qualifying facility’s power production capabilities and fuel use or availability.

(g) "Purchase" is defined as provided in 18 CFR 292.101(b)(2).

(h) "Qualifying facility" or "facility" means a cogeneration facility or small power production facility that meets the criteria established by FERC regulations in 18 CFR, Part 292, the requirements of 69-3-601, MCA, and has self-certified or been certified by FERC.

(i) "Rate" is defined as provided in 18 CFR 292.101(b)(5).

(j) "Resource plan" means the utility's integrated least cost resource plan, developed through the process described in Commission rules. 

(k) "Sale" is defined as provided in 18 CFR 292.101(b)(3).

(l) "Small power production facility" is defined as provided in 18 CFR 292.204.

(m) "Standard rates" means those rates for qualifying facilities with a nameplate generating capacity of 3 megawatts or less established in a Commission-approved tariff that:

(i)  in the case of purchases, are based on avoided costs to the utility, and are applicable to all contracts with qualifying facilities that do not choose to negotiate a different rate; or

(ii)  in the case of sales by a utility to a qualifying facility, are the utility's tariff schedules in effect for members of the same class as the qualifying facility.

(n) "System emergency" is defined as provided in 18 CFR 292.101(b)(4).

(o) "Utility" means any public utility, as defined in 69-3-101, MCA, which provides electric service subject to the jurisdiction of the Montana Public Service Commission.

(2) The federal regulations referred to in this rule can be reviewed at the Commission's office or online at https://www.ecfr.gov/current/title-18/chapter-I/subchapter-K/part-292?toc=1.

(1)  Any qualifying facility is eligible to participate, under these rules, in arrangements for purchases and sales of electric power with electric utilities regulated by the Commission.

(2) Any qualifying facility in Montana that produces electric energy or capacity, or both, available for purchase by any public utility regulated by the commission, shall not be considered a public utility within the meaning of 69-3-101, MCA, and shall be exempt from regulation by the commission as a public utility, except insofar as these rules or any other commission order, tariff, requirement, or rule governing the activities of public utilities may affect the facility in its dealings with such regulated utilities. Nothing in these rules is to be construed to limit the full powers of regulation, supervision, and control of public utilities vested by law in the commission.

(3) Nothing in these rules shall exempt any qualifying facility from the applicable licensing or permit requirements which may be imposed on facilities by Montana laws and regulations governing water use, land use, community development and planning, zoning, air quality, environmental protection, or any other existing pertinent law or regulation administered by state agencies other than the commission.

(4) All purchases and sales of electric power between a utility and a qualifying facility that is not eligible for standard rates shall be accomplished according to the terms of a written contract negotiated between the parties and/or terms set by the Commission pursuant to a petition under 69-3-603, MCA. The utility and the qualifying facility must attempt to negotiate an agreement, and if no agreement can be reached, either the utility or the qualifying facility may file a petition with the Commission pursuant to 69-3-603, MCA, to set the terms and conditions of the contract.

(5) All purchases and sales of electric power between a utility and a qualifying facility that is eligible for standard rates shall be accomplished according to the terms of a written contract between the parties or in accordance with the applicable standard rate tariff provisions and any applicable standard power purchase agreement approved by the Commission.  The utility shall recompute avoided costs for standard rates following submission of its resource plan.

(6) All contracts between utilities and qualifying facilities shall specify:

(a) the nature of the purchases and sales;

(b) the applicable rate schedule or negotiated rates for the purchases and sales or the Commission-determined rates pursuant to 69-3-603, MCA;

(c) the amount and manner of payment of interconnection costs;

(d) the means for measurement of the energy or capacity purchased or sold by the utility;

(e) the method of payment by the utility for purchases, and the method of payment by the facility for utility sales;

(f) any installation and performance obligations;

(g) the services to be provided or discontinued by either party during system emergencies;

(h) the term of the contract;

(i) applicable operating safety and reliability standards with which the qualifying facility must comply; and

(j) appropriate insurance indemnity and liability provisions.

(7) All purchases and sales of electric power between a utility and a qualifying facility shall be compatible with the goal of the commission's integrated least-cost resource planning and acquisition act, 69-3-1201 through 69-3-1209, MCA.

(1) Each utility shall purchase any energy and capacity made available by a qualifying facility, except that a utility is not obligated to make purchases from an interconnected qualifying facility:

(a) during system emergencies as allowed in 18 CFR 292.307;

(b) as agreed upon in the contract between the utility and the qualifying facility; or

(c) as allowed in 18 CFR 292.304(f), but only if the qualifying facility is selling its output on an as-available basis.

(2) Except as provided in this rule, each utility shall purchase any energy and capacity made available by a qualifying facility at the rate established under ARM 38.5.1905.

(3) Each utility shall sell to any qualifying facility all electricity requested by the facility.

(4) Each utility shall make such interconnections with a qualifying facility in accordance with the provisions of ARM 38.5.1904.

(5) Each electric utility shall offer to operate in parallel with a qualifying facility provided that the qualifying facility complies with any applicable standards established by the Commission, as required by 18 CFR 292.303(e). 

(6) Consistent with 18 CFR 292.303(d), any utility which is otherwise obligated to purchase energy or capacity from a qualifying facility may, if the affected qualifying facility agrees, transmit energy or capacity purchased from the facility to any other electric utility. Any electric utility subject to the commission's jurisdiction that receives this energy or capacity shall be subject to the pricing provisions contained in these rules. The rate for purchase by the electric utility to which such energy is transmitted shall be adjusted up or down to reflect line losses and shall not include any charges for transmission.

(7) Each utility shall, if required by the Commission, include installation and performance incentive provisions in any contract with a qualifying facility. Such provisions shall offer a maximum dollar amount per kw per month for any month in which the facility's energy output meets or exceeds specified levels of performance.

(8) Each utility shall, upon initial contact with a potential qualifying facility, provide the potential qualifying facility with one (1) copy of:

(a) these rules;

(b) if it appears the qualifying facility is eligible for the utility's Commission-approved standard rate tariff, a copy of that tariff and any applicable Commission-approved power purchase agreement; 

(c) if the utility's Commission-approved standard rate tariff is not provided under (8)(b):

(i) a list of all information required to provide an initial calculation of avoided costs pursuant to ARM 38.5.1910; and

(ii) upon the request of the qualifying facility and the receipt of all required information, an initial calculation of avoided costs pursuant to ARM 38.5.1910;

(d) the Commission's standard complaint procedure; and

(e) the utility's Commission-approved standard power purchase agreement, as applicable.

(1) A qualifying facility shall specify in its contract with a utility the nature of the purchases undertaken in the contract, including:

(a) The technology used in the production of energy or capacity by the qualifying facility;

(b) The qualifying facility's best estimate of the facility's energy and/or capacity supply characteristics, including its dispatchability and availability during utility system daily and seasonal peak periods and during system emergencies.

(2) A qualifying facility that sells all of its generation to the interconnecting utility shall be fully responsible for interconnection costs and shall:

(a) Submit, for written approval prior to actual installation equipment specifications and detailed plans to the utility for the installation of its interconnection facilities, control and protective devices, and facilities to accommodate utility meter(s) .

(b) Provide and install necessary meter socket and enclosure equipment at or near the point of interconnection, unless the utility has agreed to install the equipment and the facility has agreed to pay for this service; and

(c) Fund or reimburse the utility for interconnection costs, as defined in 18 CFR 292.101(b)(7). Such reimbursement may be accomplished by means of amortization over a reasonable period of time within the term of the contract and such costs must be reasonable according to industry standards.

(3) Interconnection costs undertaken by the utility shall be reimbursed by the qualifying facility on a nondiscriminatory basis with respect to other customers with similar load characteristics.

(4) A qualifying facility shall be required to provide power to a utility during a system emergency only to the extent specified in the contract between the facility and the utility, unless the qualifying facility is able to supply additional power and agrees to do so.

(1) Each utility shall purchase available power from any qualifying facility at:

(a) the standard rate determined by the Commission to be appropriate for the utility;

(b) the rate determined following a petition pursuant to 69-3-603, MCA; or

(c) at the rate which is a negotiated term of the contract between the utility and the qualifying facility.

(2) The rate paid by the utility for any purchase shall not exceed the utility's avoided costs. Avoided costs will be calculated as provided in this rule, unless the utility and the qualifying facility agree upon a different rate.

(a)  For as-available purchases, the avoided cost of energy and capacity will be calculated at the time of delivery of the facility's energy or capacity.

(b)  For purchases subject to an established legally enforceable obligation, the avoided cost of capacity will be calculated at the time the legally enforceable obligation was formed, and the avoided cost of energy will be calculated at the time of delivery of the facility's energy.

(3) When required by FERC regulation and to the extent practicable, the Commission's determination of avoided costs will take into account the factors described in 18 CFR 292.304(e).

(4) If a qualifying facility has provided in its contract with a utility that measurement of facility energy input to the utility system and measurement of facility load will be accomplished with one meter, the utility shall pay the purchase rate only for the facility's input to the system which is in excess of the facility's load.

(5) If the qualifying facility has agreed in its contract with a utility that measurement of facility input to the utility system shall be accomplished by metering separate from that measuring the facility load, the qualifying facility may receive payment for all of the energy it supplies to the utility according to the applicable schedule of standard rates for purchases. Unless the qualifying facility has contracted for a different rate, the standard rate is applicable regardless of whether the qualifying facility is simultaneously served by the utility for the facility's load, and regardless of the rate charged by the utility for such simultaneous sales.

(2) The standard rates for sales of power to interconnected qualifying facilities shall be each utility's current applicable tariff schedules approved by the commission.

(1) Each qualifying facility shall, in the design, installation, interconnection, maintenance, and operation of the facility, comply with the requirements of the National Electrical Safety Code, as incorporated by reference in ARM 38.5.1010.

(2) Each qualifying facility seeking parallel operation with any utility shall provide such control and protective devices as required by the utility for such operation.

(3) Each utility shall have the right:

(a) To enter the premises of the qualifying facility at reasonable times and with reasonable notice for inspection of the facility's protective devices; and

(b) To disconnect without notice if a hazardous condition exists in the generation or other equipment of the qualifying facility, and such immediate action is necessary to protect persons, utility facilities or other customers' facilities from damage or interference imminently likely to result from the hazardous condition.

(4) The Commission shall have the same power to investigate accidents occurring in the operation of any qualifying facility which result in death or serious injury to any person as it has under 69-3-107 , MCA, with respect to public utilities.

(1) Pursuant to initial contact with a potential qualifying facility, each utility shall provide the Commission with one electronic copy of the utility's initial written response.

(2)  No later than July 1 of each even-numbered year, each utility shall file with the Commission the following cost data:

(a)  the estimated avoided cost of energy as required by 18 CFR 292.302(b)(1);

(b)  the electric utility's latest resource plan, including any supplements, as required by 18 CFR 292.302(b)(2); and

(c)  the estimated capacity costs as required by 18 CFR 292.302(b)(3).  These costs shall represent the avoidable resources in the utility's resource plan.

(1) A legally enforceable obligation is created when a qualifying facility has demonstrated, based on objective and reasonable criteria, commercial viability and a financial commitment to construct its facility. A qualifying facility has demonstrated commercial viability and a financial commitment when:

(a) It has obtained qualifying facility status from FERC pursuant to the certification procedures in 18 CFR part 292;

(b)  It has provided to the utility the following:

(i)  a description of the location of the project;

(ii) an estimate of the energy production for the project, produced through industry-accepted engineering methods, that includes the kilowatt-hours or megawatt-hours to be produced by the qualifying facility for each month and year of the entire term of the qualifying facility's anticipated power purchase agreement;

(iii) an interconnection application, including any application fees;

(iv) a power purchase agreement executed by the qualifying facility; and

(v) a deposit, paid in full, to cover the estimated costs for a system impact or facilities study;

(c) It has taken meaningful steps to obtain site control adequate to commence construction of the project at the proposed location and operate the facility, throughout the term of the contract;

(d) It has submitted applications, including filing fees, to obtain all necessary permits, licenses, and approvals necessary to construct and operate the facility, and has provided copies of the same to the utility; and

(e) If the qualifying facility seeks payment for an avoided cost of capacity, it has requested to be studied for interconnection as a network resource.

(1) Upon a request from a qualifying facility, a utility shall provide the information required by ARM 38.5.1908(2).

(2) The utility must provide an initial avoided cost calculation within 21 days of receipt of a qualifying facility's resource information, including generating technology, size, location, and production profile, at no cost to the qualifying facility.

(3) Upon a request from a qualifying facility, the utility must provide all data, inputs, and assumptions it will use to calculate avoided costs. The utility must provide additional data and information that the qualifying facility may reasonably request to calculate avoided costs with the qualifying facility's preferred methodology.

(4) If any party uses a proprietary model to calculate avoided costs, the following rules apply:

(a) Each party may request one calculation using another party's model with customized inputs and assumptions, at no cost to the requesting party. The responding party must make the results accessible to the requesting party within 21 days of the request. The requesting party must have adequate access to the model to verify that the customized inputs and assumptions were used. Such access must be provided for at least 21 days.

(b) Each party must accommodate reasonable requests to conduct additional avoided cost calculations using the party's proprietary model and may charge the requesting party a reasonable price for the use of the model beyond the single avoided cost calculation identified in (4)(a).

(c)  Nothing in this rule shall require a party that uses proprietary modeling software to provide copies of proprietary modeling software or source code to the requesting party.

(5)  Any party may seek sanctions for failure to adhere to this rule, including fines pursuant to 69-3-206 and 69-3-209, MCA, as applicable.

(1) The Commission adopts and incorporates by reference 18 CFR, Part 292, as effective August 5, 2022, which sets forth general requirements and criteria for cogeneration and small power production facilities which are eligible for consideration under section 201 and 210 of the federal Public Utility Regulatory Policies Act of 1978, Pub. L. 95-617. A copy of this incorporated material may be obtained from the Commission, 1701 Prospect Avenue, P.O. Box 202601, Helena, MT 59620-2601, or online at https://www.ecfr.gov/current/title-18/chapter-I/subchapter-K/part-292?toc=1.

(1)  Before the filing of a petition, a utility and qualifying facility may mutually agree to request voluntary mediation through a Commission-appointed mediator.  The utility and qualifying facility must equally share the cost of any contracted mediator.  Requests for mediation must be signed by authorized representatives of the utility and qualifying facility and filed pursuant to ARM 38.2.1203.

(2)  Upon receipt of a request for voluntary mediation, the Commission's presiding officer may appoint a mediator. The appointed mediator may not be a member of Commission staff.

(3)  Requests for mediation must be served on the Montana Consumer Counsel.

(4)  Unless the parties and appointed mediator otherwise agree, the voluntary mediation will proceed as follows:

(a)  Within seven days of the appointment of the mediator, each party must submit to the mediator an opening mediation statement, including a complete copy of each party's proposed power purchase agreement and a list identifying each disputed contract term.

(b)  Within seven days of the submission of an opening mediation statement, each party may submit to the mediator a response statement.

(c)  The parties and mediator will use reasonable efforts to schedule mediation within 60 days from the date of the request for voluntary mediation.

(5)  The filing of a request for voluntary mediation will not affect the formation of a legally enforceable obligation under ARM 38.5.1909.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

This rule has been repealed.

(1) Integrated least-cost resource planning and acquisition is an ongoing, dynamic, and flexible process that: 

(a) manages the consequences of risk and uncertainty;

(b) integrates demand-side, distribution-side, and power resources to minimize the long-term total cost of service;

(c) considers a broad range of attributes in the evaluation of alternative resources and their cost-effectiveness;

(d) engages stakeholders and the public; and

(e) is transparent and reasonably understandable to stakeholders, the public, and the Commission.

(2) The goal of integrated least-cost resource planning and acquisition is to ensure public utilities meet their customers' needs for adequate, reliable, and efficient energy services at the lowest long-term total cost while managing risks and remaining financially sound. To achieve this goal, utilities shall plan to meet future customer demand and energy requirements through timely acquisition of a diverse mix of cost-effective resources, and shall actively pursue and acquire all cost-effective demand-side resources.  The cost-effectiveness of all resource acquisitions will be evaluated with respect to long-term total costs, including scenarios based on societal costs.

(3) These rules implement the policy of the State of Montana concerning integrated least-cost resource planning and acquisition. Electric utilities are required to file resource plans and conduct planning and acquisition processes as outlined in the rules.

(4) The rules implement the Commission's regulatory objective of ensuring an efficient allocation of society's resources to provide adequate, reliable electricity services and just and reasonable rates for consumers at the lowest long-term total cost. In furtherance of this objective, utilities shall operate existing resources and acquire new resources only when needed and in a manner consistent with these rules.

(5) The rules establish requirements for resource planning and acquisition processes but do not specify planning and acquisition outcomes or mandate investment decisions. The rules identify ways for utilities to reduce and manage the risk of resource acquisition to shareholders, customers, and society.

(6) Utilities shall acquire resources through transparent, independently administered competitive resource solicitations whenever practicable, subject to 69-3-1207, MCA.

(7) Integrated least-cost resource planning consistent with the rules may demonstrate that previously rate-based resources should be abandoned and replaced by new resources. If such situations occur, the Commission will determine the appropriate recovery of undepreciated, rate-based capital costs in separate, contested case proceedings.

(8)  Evaluations of potential demand-side resources shall consider those resources cost-effective up to 110 percent of the utility's long-term avoided cost.

(9) Resource decisions have a significant impact on the public. Public utilities can best meet the respective goals of shareholders, customers, and society by meaningfully involving the public in resource planning and acquisition processes. The rules facilitate such involvement by requiring public utilities to conduct transparent planning and acquisition processes and thoroughly document the results of those processes in a manner that is reasonably understandable.

(1) "Action plan period" means the five-year period beginning with the calendar year after the filing of a resource plan. 

(2) "Adequate" means, with respect to an electric system owned or controlled by a utility, the ability to supply the aggregate electrical demand and energy requirements of the utility's customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.

(3) "Affiliate" means, for purposes of this rule, a parent, subsidiary, division, or the like, regardless of designation, owning or controlling the utility, owned or controlled by the utility, under common ownership with the utility, or under common control with the utility.

(4)  "Assessment" means a documented process used by a utility to make informed judgments regarding elements of a resource plan and action plan based on the careful consideration of quantitative and qualitative information and the input of stakeholders, the public, and the advisory committee required in 69-3-1208, MCA.

(5) "Cost" means the actual or forecast costs incurred to own, operate, and manage existing and potential new resources sufficient to provide adequate and reliable services over the planning period including, but not limited to, costs for: 

(a) capital recovery;

(b) shareholder returns;

(c) debt;

(d) operations and maintenance;

(e) fuel and associated fuel delivery services or infrastructure;

(f) insurance;

(g) taxes, including tax credits;

(h) environmental remediation;

(i) permitting;

(j) land use and rights of way;

(k) decommissioning, abandonment, and securitization;

(l) contractual power purchases, however structured;

(m) incremental transmission and distribution, including losses and congestion;

(n) administration; and

(o) externalities.

(6) "Cost-effective" means that a project or resource is forecast:

(a) to be reliable and available within the time it is needed; and

(b) to meet or reduce the electric power demand of the intended consumers at an estimated incremental system cost no greater than that of the least-cost similarly reliable and available alternative project or resource, or any portion thereof.

(7)  "Environmentally responsible" means explicitly recognizing and incorporating into resource plans, resource planning processes, and resource procurement the policy of the State of Montana to encourage utilities to acquire resources in a manner that will help ensure a clean, healthful, safe, and economically productive environment.

(8) "Externalities" has the meaning in 69-3-1203(6), MCA.

(9)  "Long-term" means a time period at least as long as the planning period.

(10)  "Planning period" has the meaning in 69-3-1203(9), MCA.

(11) "Reliable" means a power system that is adequate and can withstand sudden disturbances, such as electrical short circuits or unanticipated loss of system elements.

(12)  "Resources" includes all of the following:

(a) "Demand-Side resources" means any material, device, technology, educational program, rate design, practice, or facility alteration designed to result in reduced peak demand, increased energy efficiency, energy conservation, or shifting or management of electricity demand and energy consumption and includes combined heat and power used to displace space heating, water heating, or another load.

(b) "Distribution-Side resources" means electrical generation or storage equipment located within a utility's distribution system, including real and personal property owned and controlled by utility customers and non-utility producers.

(c) "Power resources" means wholesale power transactions, including bilateral contracts, tolling agreements, and spot purchases, and plants and equipment, including storage equipment, owned, leased, or controlled, in whole or in part, by a utility.

(13)  "Service" means required and optional electricity and/or electricity-related products or services provided by a utility to retail customers including metering, billing, distribution, transmission, generation, and generation-related services. Services include, but are not limited to, traditional electricity supply and delivery service, renewable energy-sourced offerings, interconnection and integration of distribution side and customer generators, net metering, demand and/or bill management programs, information-based services such as energy audits, transmission ancillary services, street lighting services, and other services for which a utility has filed or would be required to file a tariff.

(14)  "Societal cost" means all costs to a utility plus externalities.

(15)  "Stakeholder" means a member of the public (individual, corporation, organization, group, etc.) who may have an interest in, or may be affected by, these rules.

(1) Resource plans shall contain at least the following information: 

(a) A description of any changes a utility has made to the content of its plan or its planning process in response to the Commission's comments on its last plan and how the changes affect the current plan, along with reasoned explanations for any Commission comment with which the utility disagrees. Cross-references shall be provided for all changes. 

(b) Annual electricity demand and energy forecasts for each year of the planning period for each major rate or service class; an explanation of the forecasting method(s) and assumptions; and the historical customer counts, population data, load data, and end-use data used in the forecasting process, as applicable. Changes to the forecasting method(s) and assumptions used in the prior plan must be thoroughly explained. 

(c) A description and graphical presentation of daily and seasonal electric demand and energy requirements for each major rate or service class, the variability of those requirements, and how the utility assessed historical trends, and the potential for future changes in the timing and variability of electric demand and energy requirements in the development of the plan.

(d) A description of the electric generating capability and characteristics of each of the utility's existing resources. The description must include the generator type and fuel source, nameplate capacity, effective load carrying capability or other probabilistic capacity contribution estimate, expected annual energy production, storage capability, capacity factor, forced outage rate, annual emissions of carbon dioxide, online date, and expected retirement date. The description must include any historical data used to develop the reported generating capabilities and characteristics. The description may be in table form with accompanying explanatory text, as necessary.

(e) A description of the current average annual variable cost or contract price for each of the utility's existing power resources, including storage resources, and the expected or projected average annual variable cost or contract prices at 5-year increments for the planning period. The description may be in table form with accompanying explanatory text, as necessary.

(f) A description of the aggregate load-serving capability and characteristics of existing programmatic demand-side resources within the utility's system and a forecast of aggregate capability over the planning period. The description must address each demand-side resource program offered and its total load-serving capabilities. The description may be in table form with accompanying explanatory text, as necessary.  The description must provide the following historical information for each year since the utility's last plan: 

(i) program expenditures;

(ii) incentive payments;

(iii)  demand and energy savings and the methods and assumptions used to estimate the savings;

(iv)  measures of the cost-effectiveness of the program, including avoided costs, and the techniques used to estimate those costs;

(v)  annualized cost of saved energy and capacity and the techniques used to estimate those costs; and

(vi) estimates of the net economic benefit of the programs. 

(g) A resource adequacy assessment based on existing resources and a description of the nature of the need for additional resources to achieve industry-standard adequacy standards or reserve margin requirements. The plan must completely and thoroughly describe the method(s) and assumptions used in the assessment, including the basis for the adequacy standard or reserve margin requirement and computer modeling and model validation procedures. The assessment must document energy and capacity deficits, their duration, frequency, and timing, given the energy and demand forecasts in (b) and resource capabilities in (d) and (f). In addition, the assessment must document energy and capacity deficits for scenarios that involve higher and lower forecasts of energy and demand requirements; alternative load profiles; and alternative performance levels for existing resources to account for the effects of, among other things, extreme weather events; demand-side and distribution-side resources; electrification; and price response. 

(h) A description of a wide range of plausibly cost-effective resources that could be acquired to satisfy the need for additional resources identified in the results of the resource adequacy assessment in (g), including those that may become available through transmission system investments that enhance access to broader markets for power resources. The description shall include the electricity generating or load serving capabilities and characteristics of the resources including the technology; size; service life or contract length; performance attributes; costs including estimates of potential fuel delivery infrastructure and transmission system interconnection and network upgrade costs, and tax credits; and environmental impacts including water and land use and emissions. The description must explain the method(s) and assumptions used to identify potential resources and define their costs, generation or load serving capabilities, and other attributes. The description may be in table form with accompanying explanatory text, as necessary.

(i) An evaluation of the full range of cost-effective means of combining the resources in (h) with the continued or discontinued operation of existing resources to satisfy the need for additional resources identified in (g) at the lowest long-term total cost. The evaluation must consider a broad range of future customer electricity demand and energy requirements and risks related to uncertainty about future loads, resource costs and performance, and changes in public policy and environmental regulations.  The evaluation must be designed to allow for a comparison of the long-term total costs and risks of acquiring alternative resources, or combinations of resources, to address the need identified in (g). The evaluation must include at least two scenarios that rely on increased renewable energy resources and demand-side resources pursuant to 69-3-1204(2)(a)(vi), MCA. The plan must completely and thoroughly describe the results of the evaluation and document and justify the method(s) and assumptions used in the evaluation, including method(s) and assumptions used to determine cost-effectiveness and computer modeling and model validation procedures.

(j) For computer modeling used to perform the evaluation in (i):

(i) a thorough description of the basic design and purpose of the model;

(ii) a thorough description of the inputs and how the model uses inputs to produce outputs;

(iii)  a thorough description of the decisions that were informed by the modeling and questions that were examined or answered by the modeling;

(iv)  comprehensive descriptions of and data for modeling outputs and results;

(v)  comprehensive, understandable explanations of the modeling results; and

(vi)  a thorough description of the process by which a stakeholder can obtain inputs electronically in order to conduct alternative modeling.

(k) A description of the utility's plan for demand-side resource acquisition over the planning period, to the extent such resources are not directly included in the evaluation in (i). The description must include the utility's assessment of the cost-effective demand-side resource potential on its system, including the method(s) and assumptions used to determine cost-effectiveness.

(l) A description of the advisory committee required in 69-3-1208, MCA, a complete and thorough documentation of how the utility designated members and engaged the advisory committee to review and evaluate technical, economic, and policy issues related to the utility's system and the planning process, including all recommendations of the advisory committee and the utility's responses, and a copy of the work plan required in ARM 38.5.2023.

(m) A description of the public meetings conducted pursuant to 69-3-1205(1), MCA, including a summary of comments, concerns, or other input received and how the utility responded.

(n) A description of the comments received on the draft plan published pursuant to ARM 38.5.2023 and how they were considered, including a thorough description of modifications made to the draft plan in response to the comments or the reasons for making no modifications.

(o) A near-term action plan describing the steps the utility intends to take based on the results and conclusions of the planning process, including the evaluations in this rule. The action plan must describe the process the utility intends to use to acquire any resources or resource types, including the use of competitive solicitations.

(p) A description of how information about the mix of resources used to provide the demand and energy requirements of customers will be disseminated to them, including information about emissions and other environmental impacts, using itemized labeling, reporting, or other mechanisms as appropriate.

(2) Plans that do not satisfy the requirements of this rule and 69-3-1204(2)(b), MCA will be deemed deficient and returned to the utility pursuant to 69-3-1204(3), MCA.

(1) A utility shall designate and engage with an advisory committee according to 69-3-1208, MCA. The utility shall meet with the advisory committee on a regular basis as it prepares resource plans. Utilities shall open meetings with the advisory committee to the public whenever possible, but may close meetings or portions of meetings when proprietary information is discussed or when necessary to enable the committee to provide a more complete review, evaluation, or recommendation. A utility shall engage with the committee before deciding to close a meeting to the public.  

(2) In addition to the advisory committee, a utility shall engage stakeholders and the public during the process of preparing a resource plan. A utility must publicly notice engagement events at least 14 days in advance and provide meeting materials in advance to the greatest extent possible. A utility shall present to stakeholders in a transparent, understandable manner the results of completed steps in the planning process and plans for subsequent steps and shall provide an opportunity to comment on or request items to be addressed in a plan. A utility may combine meetings with the public, stakeholders, and the advisory committee. 

(3) A utility shall engage a broad cross-section of its customers (based on demographic, geographic, and service classification characteristics), including representatives of customer segments with low, moderate, and fixed incomes and highly impacted communities, on issues related to future service and resources that may be of interest to non-experts.

(4) At the start of each planning cycle, a utility shall engage with the advisory committee and stakeholders to develop a work plan and timeline, including the frequency of meetings with the advisory committee, for completing the assessments and preparing plan contents required in ARM 38.5.2022.  The work plan must include a structured process for submission of written inquiries and comments to the utility during the planning process and written responses by the utility.  The work plan shall also address procedures for access by the advisory committee to the utility's planning model during the planning process.  

(5) A utility shall publish a draft of its resource plan at least 70 days before filing the resource plan with the Commission and accept comments on the draft resource plan for at least 55 days.

(6)  A utility shall file a resource plan every three years.

(1)  A utility's resource procurement processes shall be guided by the policy in 69-3-1202, MCA, input from the public and the advisory committee provided for in 69-3-1208, MCA, and comments of the Commission on the utility's most recent resource plan. 

(2)  Utilities shall use transparent, independently administered competitive solicitations to acquire needed resources whenever practicable, subject to 69-3-1207, MCA, and the Commission's rules. Utilities shall document decisions regarding the types of procurement processes used for later submission in applications for rate recovery where the prudence of procurement processes and resource decisions is examined.  

(3) A utility shall notify the Commission of a decision to issue a competitive solicitation. The notice shall precede release of a draft of the solicitation by at least 20 days. Before issuing the solicitation, the utility shall submit a draft of the solicitation to the Commission in accordance with 69-3-1207, MCA, with a thorough description of the input and recommendations of the advisory committee regarding the solicitation process and how the utility modified the solicitation process in response to the advisory committee's input and recommendations or, alternatively, the basis for not modifying the process.  Upon notification of a utility's intent to issue a solicitation, the Commission will open a docket for purposes of receiving the draft solicitation and accepting public comment on the draft solicitation.  The Commission shall provide notice to the public of the receipt of the draft solicitation and provide 45 days for interested persons to file written comments.  The utility shall not issue the final solicitation until at least 70 days after submitting the draft solicitation. Upon issuing the final solicitation, the utility shall concurrently submit the solicitation to the Commission in the docket assigned to the draft solicitation.

(4)  A utility shall provide all proposed and final scoring criteria and metrics in the draft and final competitive solicitations filed with the Commission.

(5) Utilities shall consider the usefulness of competitive solicitations for identifying and acquiring demand-side and distribution-side resources, but should also leverage their unique knowledge of their customers' demand characteristics to evaluate cost-effective resource potential and design programs for acquisition. 

(1)  A competitive solicitation issued by a utility shall treat similarly situated bidders similarly and fairly, use understandable processes, and result in decisions and outcomes that are transparent and understandable to bidders, stakeholders, and the Commission. 

(2) A competitive solicitation issued by a utility shall contain:

(a) specific minimum bidder requirements for credit and capability;

(b) standard form contracts or contract provisions the utility intends to use;

(c) specific explanations of bidders' ability to negotiate mutually agreeable final contract terms that are different from the standard form contracts;

(d) clear and complete descriptions of the resources, products, and services the utility seeks to acquire;

(e) a description of how the solicitation aligns with a resource need shown by the utility's most recent resource plan or a subsequently identified need resulting from a change in circumstances;

(f) specific bid evaluation and bidder qualification standards and criteria including a sample evaluation rubric that quantifies, where possible, the weight the utility will give each criterion during the bid ranking procedure; and

(g) clear and complete descriptions of how the utility will share information about bid scores, including what information about the bid scores and bid ranking will be provided to bidders and when and how it will be provided.

(3) A utility's process for evaluating offers or bids in competitive solicitations shall:

(a) apply bidder qualification standards and bid evaluation criteria fairly and consistently;

(b) allow all bidders to adjust their bids in the event the utility or third-party administrator revises any evaluation standards or criteria;

(c) apply a transparent and systematic rating methodology to objectively rank bids with respect to price and, as appropriate, non-price factors. Non-price factors must be objectively quantifiable where practicable.  The rating methodology shall be based on information and analyses from a utility's most recent resource plan, any Commission comments on the plan, input from the advisory committee, public comments on the utility's draft solicitation, if applicable input from a third-party administrator, and industry best practices;

(d) use the following approach to develop price and non-price scores:

(i)  price scores must be based on the prices submitted by bidders and calculated using units that are appropriate for the resources, products, or services sought and technologies expected to be employed in responsive bids.  A third-party administrator may adjust price scores on review of information submitted by bidders;

(ii)  non-price scores must, when practicable, primarily relate to resource characteristics identified in the utility's most recent resource plan or supplement to the plan and may be based on conformance to standard form contracts.  Non-price scoring criteria must be based on a clear, objective rubric that reasonably enables bidders to self-score;

(iii)  non-price score criteria that seek to identify minimum thresholds for a successful bid and that may readily be converted into minimum bidder requirements must be converted into minimum bidder requirements;

(iv)  scoring criteria may not be based on renewal or ownership options, except insofar as these options affect costs, revenues, benefits, or prices.  Any criteria based on renewal or ownership options must be explained in sufficient detail in the solicitation to allow for public comment and Commission review of the justification for the proposed criteria;

(e) document subjective judgments of the utility or the third-party administrator regarding bid scoring and ranking with sufficient detail to enable the utility to demonstrate in a transparent, understandable manner the decision-making process in subsequent regulatory proceedings involving rate recovery;

(f) identify a shortlist of offers from bidders with which the utility will pursue contract negotiations. Due diligence regarding bidder qualifications, bidder credit worthiness and experience, and project feasibility  shall be completed before selecting an offer for the shortlist. A bidder shall not be informed that its offer is being considered for the shortlist while the utility is performing due diligence. If any bidders on the shortlist are allowed to refresh or supplement their bids in any way, all bidders on the shortlist shall be allowed to do so;

(g)  conduct and incorporate into the selection of a final short list a sensitivity analysis of bid rankings to evaluate the degree to which the rankings are sensitive to:

(i)  changes in non-price scores; and

(ii)  changes in assumptions used to compare bids or portfolios of bids, such as assumptions used to extend shorter bids for comparison with longer bids, or assumptions used to compare smaller bids or portfolios with larger ones;

(h) prevent the utility or bidders from reassigning or "flipping" offers from the original bidding entity to another entity;

(i) prevent public disclosure of information related to individual bids, including price, before the solicitation process is complete and contracts with the winning bidder(s) have been executed; and

(j) facilitate public disclosure of information about the solicitation that is not confidential as defined in ARM 38.2.5001.

(4) A utility shall obtain and consider input from the advisory committee regarding the appropriate use and selection of a third-party administrator in a competitive solicitation process, including whether the third-party administrator should be selected through a competitive solicitation.  When using a third-party administrator in the competitive solicitation process, a utility shall:

(a) consult with the third-party administrator on preparation of the solicitation;

(b) empower the third-party administrator to oversee the solicitation process to ensure that it is conducted fairly, transparently, and objectively. The utility is responsible for engaging the services of a third-party administrator and for all fees and expenses associated therewith. The utility may request recovery of fees and expenses associated with engaging a third-party administrator in customer rates; and

(c) empower the third-party administrator to:

(i)  assess the reasonableness of bidder qualification and bid evaluation and scoring criteria;

(ii)  evaluate bids;

(iii)  select the initial shortlist; and

(iv) assess the reasonableness of the utility's final bid selection(s).

(5) If a competitive solicitation allows bids by the utility or an affiliate of the utility, or bids that may result in a resource owned by the utility, the process must be administered by an independent third-party administrator.  The third-party administrator must open, consider, independently evaluate, and score bids received in the solicitation, and assess the unique risks and advantages of utility-owned resource options compared to contractual alternatives considering the following factors:

(a) potential for construction delays and cost over-runs (considering contractual guarantees, cost and prudence of guarantees, remaining exposure to ratepayers for cost over-runs, and potential benefits of cost under-runs);

(b)  projected forced outage rates;

(c) projected end effect values;

(d) projected emissions costs;

(e) projected operation and maintenance costs;

(f) projected capital additions costs; and

(g) projected performance regarding output, heat rate, and power curve.

(6)  A utility shall inquire and determine whether a bidder is an affiliate or will contract with any affiliate. When an affiliate of a utility submits an offer in the utility's competitive solicitation, the following requirements shall be incorporated into the evaluation process:

(a) Information shall not be provided to an affiliate regarding bid evaluation criteria, bidder qualification criteria, due diligence, or any other relevant resource procurement information unless the same information is simultaneously provided to all other prospective bidders.

(b) Any individual who participates in the development of the solicitation or the evaluation or scoring of bids on behalf of the utility shall not be allowed to participate in the preparation of any offer by an affiliate or to discuss the solicitation process with an affiliate or its representatives in a non-public setting.

(c) A utility or third-party administrator shall not disclose the contents or results of a solicitation, including information about competing bids, to personnel involved in developing an offer by an affiliate unless such information has been disclosed to the public. Protections against improper disclosure of solicitation information shall be explained in solicitation documents.

(7)  If a utility acquires resources involving affiliate transactions it shall be subject to the following filing requirements in any subsequent application regarding cost recovery under 69-3-301 through 69-3-310, MCA:

(a) a demonstration that the utility has not subordinated its service obligations in favor of an affiliate;

(b) a demonstration that all costs associated with any affiliate transactions are just and reasonable and in the public interest based on a lower of cost or market standard applied at the time of contract execution;

(c) a demonstration that costs and revenues are accurately and properly segregated between regulated and non-regulated affiliated entities;

(d) an affirmation that books of account and related records of any affiliate transacting business with the utility shall be available for audit and review by the Commission. As reasonable and necessary and when lawful, the Commission will protect affiliate information from public disclosure; and

(e) proof that a code of conduct has been implemented to guide management and other employees regarding standards for day-to-day business activities with affiliates and to guard against self-dealing, gaming, and resulting subsidies.

(8)  A third-party administrator must file a closing report in the docket opened in ARM 38.5.2024 after the utility has determined a final shortlist. The closing report must include an overall assessment of the competitive solicitation process including whether selected resources achieve the objective of minimizing costs to customers, considering risks, and whether the process was fair to all bidders. 

(9) The consumer counsel should consider the following guidelines when it decides to engage an independent monitor pursuant to 69-3-1207(4), MCA:

(a)  notify the Commission as soon as practicable following notice by a utility of a decision to issue competitive solicitation if the consumer counsel intends to retain an independent monitor; and

(b) provide information needed and requested by the Commission to establish the process by which the Commission will charge a fee to the utility to pay costs incurred by the consumer counsel related to the independent monitor.

(10) When the consumer counsel engages an independent monitor the utility and the third-party administrator shall allow access by the independent monitor to all information related to the solicitation and the evaluation of offers. 

(11) An independent monitor may file comments addressing the items in 69-3-1207(4)(c), MCA and/or prepare and file a closing report pursuant to 69-3-1207(4)(c)(iv) in the docket initiated in ARM 38.5.2024.

(12) When a utility acquires resources by means other than a competitive solicitation, it shall thoroughly document the alternative acquisition process, including the assumptions and methods used to assess cost-effectiveness and all factors considered in, and the rationale for, its decision not to use a competitive solicitation.

(2) The edition of the code applicable at the time of maintenance shall be that in effect by statute or rule at the time of construction of the electric utility line or facility unless, without undue expense, the edition in effect by statute or rule at the time of maintenance can reasonably be complied with.

(1) The standards of product and service for each public utility providing electric service subject to the jurisdiction of the commission shall, whether established by ordered tariff provision or administrative rule, allow for a nominal voltage and permissible range of variation as specified in American National Standards Institute (ANSI) C84.1 2020. A copy of ANSI C84.1 may be obtained from the American National Standards Institute, Operations, 25 West 43rd Street, 4th Floor, New York, New York 10036, or may be reviewed at the Public Service Commission Offices, 1701 Prospect Avenue, Helena, Montana 59620-2601.

(2) This rule shall not apply:

(a) to transmission systems not used to directly serve customers;

(b) where customers specifically request a voltage other than standard nominal system voltages as specified in ANSI C84.1; or

(c) in instances where voltage is in excess of 34,500 volts.

(1) The commission adopts and incorporates by reference the U.S. Department of Transportation (DOT) Pipeline Safety Regulations, Code of Federal Regulations (CFR), Title 49, chapter 1, subchapter D, parts 191, 192, and 193, including all revisions and amendments enacted by DOT on or before November 17, 2023. A copy of the referenced regulations may be obtained from United States Department of Transportation, Office of Pipeline Safety, Western Region, 12300 West Dakota Avenue, Suite 110, Lakewood, Colorado 80228, or may be reviewed at the Public Service Commission Offices, 1701 Prospect Avenue, Helena, Montana 59620-2601.

(1) The commission, its employees, or authorized agents, have the power to investigate all methods and practices of pipeline owners and operators; to require the maintenance and filing of reports, records and other information in the form and detail as the commission may prescribe; to enter upon and to inspect the property, buildings, plants, and offices of pipeline owners and operators; and to inspect books, records, papers and documents relevant to enforcement responsibilities under the NGPSA.

(2) The commission, a staff member thereof, or some person appointed by it, may investigate and make inquiry into every incident occurring in the operation of any intrastate gas pipeline located in this state. The commission, in its discretion, may also investigate any other accident or event involving the operation of a pipeline.

(2) The order to show cause shall include a statement of the laws, regulations or orders which the pipeline owner or operator is alleged to have violated and a statement of the evidence upon which the allegations are based.