SENATE BILL NO. 243
INTRODUCED BY R. JOHNSON
A BILL FOR AN ACT ENTITLED: "AN ACT ALLOWING FOR AN ORDERLY TRANSITION TO A COMPETITIVE
MARKET FOR ELECTRICITY SUPPLY WHILE FACILITATING A PROCESS THAT ENCOURAGES A
REASONABLE PRICE OF ELECTRICITY; GENERALLY REVISING THE ELECTRIC UTILITY INDUSTRY
RESTRUCTURING, CUSTOMER CHOICE, AND DEFAULT SUPPLIER LAWS; CLARIFYING THE PURPOSE OF A
BUYING COOPERATIVE; CLARIFYING THAT A CUSTOMER'S DISTRIBUTION SERVICES PROVIDER IS ALSO
THE DEFAULT SUPPLIER; ELIMINATING PILOT PROGRAMS FOR PUBLIC UTILITIES; ELIMINATING THE
DEFINITION OF "SMALL CUSTOMER"; DEFINING "RATE TRANSITION" "ENERGY RISK MANAGEMENT
PROCESS"; EXTENDING THE TRANSITION PERIOD; CLARIFYING CUSTOMER CHOICE AND DEFAULT
SUPPLIER OBLIGATIONS DURING THE TRANSITION PERIOD; ALLOWING SOME CUSTOMERS THE
FLEXIBILITY TO CHOOSE AN ELECTRICITY SUPPLIER DURING THE TRANSITION PERIOD;
ACCOMMODATING NEW CUSTOMERS DURING THE TRANSITION PERIOD; ELIMINATING THE
COMMISSION'S AUTHORITY TO EXTEND THE TRANSITION PERIOD; CLARIFYING THAT A DISTRIBUTION
SERVICES PROVIDER HAS AN ONGOING REGULATED DEFAULT SUPPLY OBLIGATION BEYOND THE END
OF THE TRANSITION PERIOD; EXTENDING COMPLIANCE DATES FOR CERTAIN PUBLIC UTILITIES;
ELIMINATING THE AUTHORITY FOR A CITY, COUNTY, OR CONSOLIDATED GOVERNMENT TO BECOME A
DEFAULT SUPPLIER; EXEMPTING CERTAIN PUBLIC UTILITIES FROM FILING A TRANSITION PLAN UNTIL
THEY CAN REASONABLY IMPLEMENT CUSTOMER CHOICE; REESTABLISHING AN EDUCATIONAL
PROCESS FOR INFORMING CUSTOMERS ABOUT CUSTOMER CHOICE OF ELECTRICITY SUPPLIERS;
AUTHORIZING THE COMMISSION TO DETERMINE WHETHER TO INSTITUTE A RATE TRANSITION;
ESTABLISHING A PROCESS FOR DEFAULT SUPPLY OF ELECTRICITY DURING THE TRANSITION PERIOD;
ELIMINATING THE DEFAULT SUPPLIER LICENSING PROVISIONS; AMENDING SECTIONS 35-19-104, 69-8-103,
69-8-201, 69-8-203, 69-8-208, 69-8-210, 69-8-211, AND 69-8-403, MCA; REPEALING SECTIONS 35-19-103, 69-8-104,
69-8-416, AND 69-8-417, MCA; AND PROVIDING AN IMMEDIATE EFFECTIVE DATE AND AN APPLICABILITY
DATE."
BE IT ENACTED BY THE LEGISLATURE OF THE STATE OF MONTANA:
Section 1. Section 35-19-104, MCA, is amended to read:
"35-19-104. Permissible purpose of incorporation. A buying cooperative may be organized under this
chapter only for the purpose of supplying electricity to small customers as a default an electricity
supplier, pursuant to 69-8-403 Title 69, chapter 8, parts 1 through 5."
Section 2. Section 69-8-103, MCA, is amended to read:
"69-8-103. Definitions. As used in this chapter, unless the context requires otherwise, the following definitions apply:
(1) "Aggregator" or "market aggregator" means an entity, licensed by the commission, that aggregates retail customers, purchases electric energy, and takes title to electric energy as an intermediary for sale to retail customers.
(2) "Assignee" means any entity, including a corporation, partnership, board, trust, or financing vehicle, to which a utility assigns, sells, or transfers, other than as security, all or a portion of the utility's interest in or right to transition property. The term also includes an entity, corporation, public authority, partnership, trust, or financing vehicle to which an assignee assigns, sells, or transfers, other than as security, the assignee's interest in or right to transition property.
(3) "Board" means the board of investments created by 2-15-1808.
(4) "Broker" or "marketer" means an entity, licensed by the commission, that acts as an agent or intermediary in the sale and purchase of electric energy but that does not take title to electric energy.
(5) "Cooperative utility" means:
(a) a utility qualifying as an electric cooperative pursuant to Title 35, chapter 18; or
(b) an existing municipal electric utility as of May 2, 1997.
(6) "Customer" or "consumer" means a retail electric customer or consumer. The university of Montana, pursuant to 20-25-201(1), and Montana state university, pursuant to 20-25-201(2), are each considered a single retail electric customer or consumer with a single individual load.
(7) "Customer-generator" means a user of a net metering system.
(8) "Default supplier" means a customer's distribution services provider or a person that has received a
default supplier license from the commission.
(9) "Distribution facilities" means those facilities by and through which electricity is received from a transmission services provider and distributed to the customer and that are controlled or operated by a distribution services provider.
(10) "Distribution services provider" means a utility owning distribution facilities for distribution of electricity to the public.
(11) "Electricity supplier" means any person, including aggregators, market aggregators, brokers, and marketers, offering to sell electricity to retail customers in the state of Montana.
(12) "ENERGY RISK MANAGEMENT PROCESS" MEANS POLICIES AND PROCEDURES REGARDING APPROPRIATE RISK LEVELS AND USE OF CERTAIN ENERGY MARKET FINANCIAL INSTRUMENTS, INCLUDING BUT NOT LIMITED TO HEDGING CONTRACTS TO MANAGE VARIATIONS IN EITHER ENERGY MARKET PRICES OR CUSTOMER LOADS.
(12)(13) "Financing order" means an order of the commission adopted in accordance with 69-8-503 that
authorizes the imposition and collection of fixed transition amounts and the issuance of transition bonds.
(13)(14) (a) "Fixed transition amounts" means those nonbypassable rates or charges, including but not
limited to:
(i) distribution;
(ii) connection;
(iii) disconnection; and
(iv) termination rates and charges that are authorized by the commission in a financing order to permit recovery of transition costs and the costs of recovering, reimbursing, financing, or refinancing the transition costs and of acquiring transition property through a plan approved by the commission in the financing order, including the costs of issuing, servicing, and retiring transition bonds.
(b) If requested by the utility in the utility's application for a financing order, fixed transition amounts must include nonbypassable rates or charges to recover federal and state taxes in which the transition cost recovery period is modified by the transactions approved in the financing order.
(14)(15) "Functionally separate" means a utility's separation of the utility's electricity supply,
transmission, distribution, and unregulated retail energy services assets and operations.
(15)(16) "Interested person" means a retail electricity customer, the consumer counsel established in
5-15-201, the commission, or a utility.
(16)(17) "Large customer" means, for universal system benefits programs purposes, a customer with an
individual load greater than a monthly average of 1,000 kilowatt demand in the previous calendar year
for that individual load.
(17)(18) "Local governing body" means a local board of trustees of a rural electric cooperative.
(18)(19) "Low-income customer" means those energy consumer households and families with incomes at or
below industry-recognized levels that qualify those consumers for low-income energy-related
assistance.
(19)(20) "Net metering" means measuring the difference between the electricity distributed to and the
electricity generated by a customer-generator that is fed back to the distribution system during the
applicable billing period.
(20)(21) "Net metering system" means a facility for the production of electric energy that:
(a) uses as its fuel solar, wind, or hydropower;
(b) has a generating capacity of not more than 50 kilowatts;
(c) is located on the customer-generator's premises;
(d) operates in parallel with the distribution services provider's distribution facilities; and
(e) is intended primarily to offset part or all of the customer-generator's requirements for electricity.
(21)(22) "Nonbypassable rates or charges" means rates or charges that are approved by the commission
and imposed on a customer to pay the customer's share of transition costs or universal system benefits
programs costs even if the customer has physically bypassed either the utility's transmission or
distribution facilities.
(22)(23) "Pilot program" means a program using a representative sample of residential and small
commercial customers to assist in developing and offering customer choice of electricity supply for all
residential and commercial customers.
(23)(24) "Public utility" means any electric utility regulated by the commission pursuant to Title 69,
chapter 3, on May 2, 1997, including the public utility's successors or assignees.
(24)(25) "Qualifying load" means, for payments and credits associated with universal system benefits
programs, all nonresidential demand-metered accounts of a large customer within the utility's service
territory in which the customer qualifies as a large customer.
(25) "Small customer" means a residential customer or a small commercial customer who has an
individual account with an average monthly demand in the previous calendar year of less than 100
kilowatts or a new commercial customer with an estimated average monthly demand of less than 100
kilowatts of a public utility distribution services provider that has opened access on its distribution
system pursuant to Title 35, chapter 19, or this chapter.
(25) "Rate transition" means a phasein from the electricity rate in effect on June 30, 2002, to the rate that
would otherwise be charged beginning on July 1, 2002, by the default supplier.
(26) "Transition bondholder" means a holder of transition bonds, including trustees, collateral agents, and other entities acting for the benefit of that holder.
(27) "Transition bonds" means any bond, debenture, note, interim certificate, collateral, trust certificate, or other evidence of indebtedness or ownership issued by the board or other transition bonds issuer that is secured by or payable from fixed transition amounts or transition property. Proceeds from transition bonds must be used to recover, reimburse, finance, or refinance transition costs and to acquire transition property.
(28) "Transition charge" means a nonbypassable rate or charge to be imposed on a customer to pay the customer's share of transition costs.
(29) "Transition cost recovery period" means the period beginning on July 1, 1998, and ending when a utility customer does not have any liability for payment of transition costs.
(30) "Transition costs" means:
(a) a public utility's net verifiable generation-related and electricity supply costs, including costs of capital, that become unrecoverable as a result of the implementation of this chapter or of federal law requiring retail open access or customer choice;
(b) those costs that include but are not limited to:
(i) regulatory assets and deferred charges that exist because of current regulatory practices and can be accounted for up to the effective date of the commission's final order regarding a public utility's transition plan and conservation investments made prior to universal system benefits charge implementation;
(ii) nonutility and utility power purchase contracts, including qualifying facility contracts;
(iii) existing generation investments and supply commitments or other obligations incurred before May 2, 1997, and costs arising from these investments and commitments;
(iv) the costs associated with renegotiation or buyout of the existing nonutility and utility power purchase contracts, including qualifying facilities and all costs, expenses, and reasonable fees related to issuing transition bonds; and
(v) the costs of refinancing and retiring of debt or equity capital of the public utility and associated federal and state tax liabilities or other utility costs for which the use of transition bonds would benefit customers.
(31) "Transition period" means the period beginning on July 1, 1998, and ending on July 1, 2002 2007, unless
otherwise extended pursuant to this chapter, during which utilities may phase in customer choice of
electricity supplier.
(32) "Transition property" means the property right created by a financing order, including without limitation the right, title, and interest of a utility, assignee, or other issuer of transition bonds to all revenue, collections, claims, payments, money, or proceeds of or arising from or constituting fixed transition amounts that are the subject of a financing order, including those nonbypassable rates and other charges and fixed transition amounts that are authorized by the commission in the financing order to recover transition costs and the costs of recovering, reimbursing, financing, or refinancing the transition costs and acquiring transition property, including the costs of issuing, servicing, and retiring transition bonds. Any right that a utility has in the transition property before the utility's sale or transfer or any other right created under this section or created in the financing order and assignable under this chapter or assignable pursuant to a financing order is only a contract right.
(33) "Transmission facilities" means those facilities that are used to provide transmission services as determined by the federal energy regulatory commission and the commission.
(35)(34) "Transmission services provider" means a person controlling or operating transmission facilities.
(35) "Universal system benefits charge" means a nonbypassable rate or charge to be imposed on a customer to pay the customer's share of universal system benefits programs costs.
(36) "Universal system benefits programs" means public purpose programs for:
(a) cost-effective local energy conservation;
(b) low-income customer weatherization;
(c) renewable resource projects and applications, including those that capture unique social and energy system benefits or that provide transmission and distribution system benefits;
(d) research and development programs related to energy conservation and renewables;
(e) market transformation designed to encourage competitive markets for public purpose programs; and
(f) low-income energy assistance.
(37) "Utility" means any public utility or cooperative utility."
Section 3. Section 69-8-201, MCA, is amended to read:
"69-8-201. Public utility -- transition to customer choice -- waiver. (1) A public utility shall, except as
provided in this section, adhere to the following deadlines:
(a) On or before July 1, 1998, Except as provided in subsection (1)(c) (1)(B), all customers with individual
loads greater than 1,000 kilowatts and for loads of the same customer with individual loads at a meter
greater than 300 kilowatts that aggregate to 1,000 kilowatts or greater must have the opportunity to
choose an electricity supplier OTHER THAN THE DEFAULT SUPPLIER.
(b) Subject to subsection (2) (1)(e), and as soon as is administratively feasible but before July 1, 2002 on or
after July 1, 2007, all other public utility customers must have the opportunity to choose an electricity
supplier.
(c) (i) A customer under subsection (1)(a) may choose to purchase electricity from the default supplier
for the period of July 1, 2002, through June 30, 2007, by notifying the commission and the default supplier
within 30 days after [the effective date of this act].
(ii) A customer under subsection (1)(a) who chooses to purchase electricity from the default supplier
shall provide to the default supplier specific load requirements.
(d) Except as provided in subsection (1)(e), during the transition period, a customer may not purchase
electricity from an electricity supplier other than the default supplier.
(e) During the transition period, all customers are eligible to choose an electricity supplier other than
the default supplier, subject to the following conditions:
(i) Customers whose combined load amounts to 5% or less of the remaining contracted load in each
successive year during the transition period may choose an alternative supplier of electricity.
(ii) Of the customers who choose an alternative supplier pursuant to subsection (1)(e)(i), the combined
load must be, to the extent possible, evenly distributed among all customers and customer classes, as
determined by the size of load, and must be distributed on a first-come, first-serve basis each year.
(iii) Except as provided in subsection (1)(g), those customers who choose an alternative supplier may not
purchase electricity from the default supplier throughout the remainder of the transition period.
(iv) The default supplier shall propose a method for compliance with this subsection (1)(e) to the
commission.
(f) If a customer under subsection (1)(a) chooses to purchase electricity from the default supplier during
the transition period and then subsequently does not purchase all or part of the load that the customer
committed to, the commission shall assess that customer an exit fee that is the customer's pro rata share
of the contracted load for electricity supply.
(B) (I) A CUSTOMER UNDER SUBSECTION (1)(A) MAY ELECT TO RECEIVE DEFAULT SUPPLY SERVICE, BUT THAT ELECTION MUST BE FOR THE ENTIRE TRANSITION PERIOD.
(II) THE PUBLIC UTILITY SHALL NOTIFY ALL CUSTOMERS UNDER SUBSECTION (1)(A) THAT THEY MAY ELECT TO RECEIVE DEFAULT SUPPLY SERVICE WITHIN 30 DAYS AFTER [THE EFFECTIVE DATE OF THIS ACT].
(III) A CUSTOMER UNDER SUBSECTION (1)(A) MAY CHOOSE TO PURCHASE ELECTRICITY FROM THE DEFAULT SUPPLIER FOR THE PERIOD OF JULY 1, 2002, THROUGH JUNE 30, 2007, BY NOTIFYING THE COMMISSION AND THE DEFAULT SUPPLIER WITHIN 60 DAYS AFTER [THE EFFECTIVE DATE OF THIS ACT].
(IV) A CUSTOMER UNDER SUBSECTION (1)(A) WHO CHOOSES TO PURCHASE ELECTRICITY FROM THE DEFAULT SUPPLIER SHALL PROVIDE THE DEFAULT SUPPLIER WITH ITS SPECIFIC MONTHLY LOAD REQUIREMENTS FOR THE ENTIRE TRANSITION PERIOD. THE CUSTOMER SHALL ANNUALLY NOTIFY THE DEFAULT SUPPLIER OF ITS LOAD REQUIREMENTS AND SHALL NOTIFY THE DEFAULT SUPPLIER AT LEAST 6 MONTHS IN ADVANCE OF ANY 10% INCREASE OR DECREASE IN ITS LOAD REQUIREMENTS.
(V) A CUSTOMER UNDER SUBSECTION (1)(A) WHO CHOOSES TO PURCHASE ELECTRICITY FROM THE DEFAULT SUPPLIER SHALL POST A BOND WITH A REPUTABLE SURETY COMPANY PAYABLE TO THE DEFAULT SUPPLIER FOR AN AMOUNT STARTING AT A LEVEL EQUIVALENT TO THE ESTIMATED MARKET VALUE OF THE CUSTOMER'S SPECIFIC PRO RATA LOAD REQUIREMENTS FOR THE TRANSITION PERIOD ADJUSTED ANNUALLY.
(VI) IF A CUSTOMER UNDER SUBSECTION (1)(A) CHOOSES TO PURCHASE ELECTRICITY FROM THE DEFAULT SUPPLIER DURING THE TRANSITION PERIOD AND THEN SUBSEQUENTLY FAILS TO PURCHASE ALL OR PART OF THE LOAD THAT THE CUSTOMER COMMITTED TO, THE CUSTOMER BECOMES IMMEDIATELY LIABLE AND IS REQUIRED TO MAKE AN EXIT PAYMENT TO THE DEFAULT SUPPLIER EQUAL TO THE CUSTOMER'S PRO RATA SHARE OF THE COSTS ASSOCIATED WITH THE DEFAULT SUPPLIER'S REMAINING CONTRACTED ELECTRICITY SUPPLY LOAD, PLUS OR MINUS ANY DEFERRED BALANCE BEING HELD BY THE DEFAULT SUPPLIER. IF THE CUSTOMER DEFAULTS ON THE EXIT PAYMENT, THE SURETY COMPANY MUST BE BILLED AND BECOMES RESPONSIBLE FOR THE AMOUNT.
(C) ON OR AFTER JULY 1, 2007, ALL OTHER PUBLIC UTILITY CUSTOMERS MUST HAVE THE OPPORTUNITY TO CHOOSE AN ELECTRICITY SUPPLIER.
(D) EXCEPT AS PROVIDED IN SUBSECTION (1)(E), THOSE CUSTOMERS SUBJECT TO SUBSECTION (1)(A) WHO CHOOSE AN ALTERNATIVE SUPPLIER MAY NOT PURCHASE ELECTRICITY FROM THE DEFAULT SUPPLIER THROUGHOUT THE REMAINDER OF THE TRANSITION PERIOD.
(g)(E) (i) During the transition period, a new customer in the category of subsection (1)(b) WHO IS NOT
SUBJECT TO SUBSECTION (1)(A) may choose to purchase electricity from the default supplier at the rates
established in the default supplier's contract for electricity supply pursuant to [section 9].
(ii) During the transition period, a new customer in the category of subsection (1)(a) shall purchase
electricity from the market unless the commission determines that the addition of the customer's
estimated load to the default supplier's electricity supply load obligation would not increase the default
supply rates RATE for all other customers.
(III) FOR PURPOSES OF THIS SUBSECTION (1)(E), "NEW CUSTOMER" MEANS AN ENTITY OR PERSON THAT INITIATES OR RENEWS OPERATIONS FOLLOWING [THE EFFECTIVE DATE OF THIS ACT], REGARDLESS OF WHETHER THAT ENTITY OR PERSON FORMERLY RECEIVED SERVICES FROM THE DEFAULT SUPPLIER.
(2) (a) Except as provided for in subsection (4), the commission may determine that additional time is
necessary for customers identified in subsection (1)(b); however, the implementation of full customer
choice may not be delayed beyond July 1, 2004.
(b) A determination by the commission that additional time is necessary for subsection (1)(b) customers
must be made at least 60 days in advance of the scheduled date and must be based on one or more of the
following considerations:
(i) implementation would not be administratively feasible;
(ii) implementation would materially affect the reliability of the electric system; or
(iii) Montana customers or electricity suppliers would be disadvantaged due to lack of a competitive
electricity supply market.
(3) The commission shall designate the public utility or one or more default suppliers to provide
regulated default service for those small customers of a public utility that are not being served by a
competitive electricity supplier. The transition advisory committee shall review and address the need for
continued default supply service and make recommendation to the 57th legislature. A distribution services
provider has an ongoing regulated default supply obligation beyond the end of the transition period.
(4)(3) Except as provided in 69-5-101, 69-5-102, 69-5-104 through 69-5-112, and 69-8-402, a public utility
currently doing business in Montana as part of a single integrated multistate operation, no portion of
which lies within the basin of the Columbia River, may:
(a) defer compliance with this chapter until a time that the public utility can reasonably implement
customer choice in the state of the public utility's primary service territory, except that the public utility
shall file a transition plan pursuant to 69-8-202 to provide transition to customer choice on or before July
1, 2002 2003, and must have completed the transition period to customer choice by July 1, 2006 2007; and
(b) petition the commission to delay the public utility's transition plan filing until July 1, 2004 2005.
(5)(4) Upon a request from a public utility with fewer than 50 customers, the commission shall waive
compliance with the requirements of 69-8-104, 69-8-202 through 69-8-204, 69-8-208 through 69-8-211, 69-8-402,
and this section."
Section 4. Section 69-8-203, MCA, is amended to read:
"69-8-203. Public utility -- customer choice -- continued service -- education of customers. (1) A customer is permitted to choose an electricity supplier pursuant to the deadlines established in 69-8-201. Public utilities shall propose a method for customers to choose an electricity supplier.
(2) If a customer has not chosen an electricity supplier by the end of the transition period, a city, county,
or consolidated government that is licensed as an electricity supplier may, upon application to and
approval by the commission, become the default supplier to residential and commercial customers of a
public utility within its jurisdiction. For customers that are not within the jurisdiction of a licensed and
approved city, county, or consolidated government electricity supplier area, a public utility shall propose
a method in the public utility's transition plans for assigning that customer to an electricity supplier. The
commission shall establish an application process and guidelines for the designation of one or more
default suppliers for the distribution area of each public utility.
(3) A public utility may phase in customer choice to promote the orderly transition to a competitive
market environment pursuant to the deadlines in 69-8-201.
(4)(2) (a) Public utilities A BEFORE JULY 1, 2007, A distribution services provider THAT IS NOT A
COOPERATIVE UTILITY shall educate their its customers about customer choice so that customers may
make an informed choice of an electricity supplier.
(b) This education process must include but is not limited to providing to customers, through the print and electronic media, detailed information about:
(i) how best to evaluate and compare electricity prices and related services offered to customers by licensed electricity suppliers;
(ii) effective methods of energy conservation to reduce a customer's demand for electricity;
(iii) methods of customer aggregation to improve customers' bargaining positions in relation to electricity suppliers; and
(iv) the GENERAL PRICING AND THE terms, conditions, and duration of any contracts that the utility
may have entered into as the default supplier WHILE MAINTAINING THE CONFIDENTIALITY OF THE
DETAILS OF THESE CONTRACTS IN A COMPETITIVE MARKETPLACE. This education process must give
special emphasis to education efforts during the transition period.
(C) THE INCREASED COSTS OF CUSTOMER EDUCATION DURING THE TRANSITION PERIOD ARE RECOVERABLE BY THE DISTRIBUTION SERVICES PROVIDER FROM ALL OF ITS CUSTOMERS."
Section 5. Section 69-8-208, MCA, is amended to read:
"69-8-208. Public utility -- distribution Distribution PUBLIC UTILITY -- DISTRIBUTION services
provider. (1) A public utility's PUBLIC UTILITY'S distribution services provider shall:
(a) file tariffs that make distribution facilities available to all electricity suppliers, transmission services providers, and customers on a nondiscriminatory and comparable basis;
(b) build and maintain distribution facilities;
(c) act as a default supplier of electricity; and
(c)(d) be an emergency supplier AS DEFAULT SUPPLIER, PROVIDE FOR AN EMERGENCY SUPPLY of
electricity and related services for ITS DEFAULT SUPPLY AND FOR customers who have chosen an
electricity supplier other than the default supplier. THIS SERVICE MAY BE PROVIDED THROUGH AN
AFFILIATED TRANSMISSION SERVICES PROVIDER. THESE COSTS MUST BE INCLUDED AND RECOVERED
AS PART OF THE COSTS OF THE DEFAULT SUPPLIER FROM THE CUSTOMER WHOSE CHOSEN ELECTRICITY
SUPPLIER HAS FAILED TO MEET ITS OBLIGATION, ONLY IF THE COSTS ARE UNRECOVERED FROM AN
ELECTRICITY SUPPLIER WHO HAS FAILED TO MEET ITS OBLIGATION THE DEFAULT SUPPLIER AN
ELECTRICITY SUPPLIER THAT HAS FAILED TO MEET ITS OBLIGATION. AN EMERGENCY EXISTS ONLY
WHEN A CUSTOMER CANNOT OBTAIN AN ADEQUATE SUPPLY OF ELECTRICITY FROM ANY OTHER
SOURCE. THE PROVISION OF THE EMERGENCY SUPPLY IS LIMITED TO A MAXIMUM PERIOD OF 60 DAYS
FROM THE COMMENCEMENT OF THE DELIVERY OF THE SUPPLY TO THE CUSTOMER.
(2) When a distribution services provider acts as an emergency supplier of electricity and related
services to customers, the electricity supplier that should have provided the electricity shall reimburse
the distribution services provider at the higher of a multiple of the cost or a multiple of the then-existing
market rate for that electricity. The commission shall determine and authorize the multiple used. The
market rate is the highest published rate for electricity purchased within the local load control area at
the time that the distribution services provider provided the emergency supply. A distribution services
provider is not required to purchase any reserve supply of electricity to fulfill this DEFAULT SUPPLY
obligation."
Section 6. Section 69-8-210, MCA, is amended to read:
"69-8-210. Public utilities -- electricity supply. (1) On the effective date of a commission order implementing a public utility's transition plan pursuant to 69-8-202, the public utility shall remove its generation assets from the rate base.
(2) During the transition period, the commission may establish cost-based prices pursuant to [section 9]
FROM JULY 1, 2002, THROUGH JUNE 30, 2007:
(A) THE DISTRIBUTION SERVICES PROVIDER SHALL PURCHASE ELECTRICITY FROM THE MARKET PURSUANT TO [SECTION 9]; AND
(B) PRICES for electricity supply service for customers that do not have a choice of electricity supply service or that have not yet chosen an electricity supplier MUST BE ESTABLISHED PURSUANT TO [SECTION 9].
(3) If the transition period is extended, then the customers' distribution services provider shall:
(a) extend any cost-based contract with the distribution services provider's affiliate supplier for a term
not more than 3 years; or
(b) purchase electricity from the market; and
(c) use a mechanism that recovers electricity supply costs in rates to ensure that those costs are fully
recovered.
(4)(3) If a public utility intends to be an electricity supplier through an unregulated division, then the
public utility must be licensed as an electricity supplier pursuant to 69-8-404."
Section 7. Section 69-8-211, MCA, is amended to read:
"69-8-211. Public utilities -- transition costs and charges -- rate moratorium. (1) Subject to the provisions of this section, the commission shall allow recovery of the following categories of transition costs:
(a) the unmitigable costs of qualifying facility contracts, including reasonable buyout or buydown costs, for which the contract price of generation is above the market price for generation;
(b) the unmitigable costs of energy supply-related regulatory assets and deferred charges that exist because of current regulatory practices and that can be accounted for up to the effective date of the commission's final order regarding a public utility's transition plan, including costs, expenses, and reasonable fees related to issuing of transition bonds;
(c) the unmitigable transition costs related to public utility-owned generation and other power purchase contracts, except that recovery of those costs is limited to the amount accruing during the first 4 years after the commission enters an order pursuant to 69-8-202(3); and
(d) other transition costs as may qualify for recovery under this section.
(2) Transition costs as determined by the commission upon an affirmative showing by a public utility must meet the following requirements:
(a) Transition costs must reflect all reasonable mitigation by the public utility, including but not limited to good faith efforts to renegotiate contracts, buying out or buying down contracts, and refinancing through transition bonds.
(b) The value of all generation-related assets and liabilities and electricity supply costs must be reasonably demonstrable and must be considered on a net basis, and methods for determining value must include but are not limited to:
(i) estimating future market values of electricity and ancillary services provided by the assets;
(ii) appraisal by independent third-party professionals; or
(iii) a competitive bid sale.
(c) Investments and power purchase contracts must have been previously allowed in rates or, if not previously in rates, must be determined to be used and useful to ratepayers in connection with the commission's approval of the utility's transition plan.
(d) Unless otherwise provided for in this chapter, only costs related to existing investments and power purchase contracts identified in subsection (2)(c) and costs arising from those investments and power purchase contracts may be included as transition costs.
(3) (a) On commission approval of the amount of a public utility's transition costs, those costs must be recovered through the imposition of a transition charge.
(b) A transition charge may not be collected from customers for:
(i) new or additional loads of 1,000 kilowatts or greater that were first served by the public utility after December 31, 1996; or
(ii) loads served by that customer's own generation.
(c) Subject to commission approval, a public utility and a customer may agree to alter the customer's transition charge payment schedule. Public utilities may file with the commission tariffs for electric service rates that foster economic development or retention of existing customers within the state, including generally available rate schedules. Transition charges are the only charges that may be imposed upon a customer class to recover transition costs under this section. A separate exit fee may not be charged.
(4) Transition charges must be imposed within a transition cost recovery period approved by the commission on a case-by-case basis. Except for transition costs recovered under subsection (1)(c), categories of transition costs may have varying transition cost recovery periods.
(5) Approval of transition costs and collection of those transition costs through transition charges is a settlement of all transition costs claims by a public utility. A public utility seeking to recover transition costs through any means not authorized by this chapter may not collect transition charges with respect to these transition costs.
(6) Except as provided in subsection (7), public utilities shall implement a rate moratorium during the
transition period as follows:
(a) From July 1, 1998, through June 30, 2000, public utilities may not charge rates higher than those rates
in effect on July 1, 1998.
(b) From from July 1, 2000, through June 30, 2002, and only for those customers subject to the provisions
of 69-8-201(1)(b),. public Public utilities may not increase that increment of rates normally allocated to
electric supply-related costs above the increment associated with electric supply-related costs reflected
in rates in effect on July 1, 1998. Beginning on July 1, 2000, public Public utilities may propose increases to
those increments of rates normally allocated to transmission and distribution costs.
(7) Excepted from the provisions of subsection (6) are:
(a) increased costs related to universal system benefits programs greater than those currently in rates, including the treatment of universal system benefits program costs as an expense;
(b) increased costs necessary to implement full customer choice, including but not limited to metering, billing, and technology. Those costs must be recovered from the customers on whose behalf the increased costs are incurred.
(c) subject to commission approval, an extraordinary event resulting in either:
(i) a 4% annual revenue requirement increase from July 1, 1998, through June 30, 2000; or
(ii) an 8% power supply-related annual revenue requirement increase from July 1, 2000, through June 30,
2002;
(d) the increase or decrease in the annual state and local property tax expense that has occurred since May 2, 1997.
(8) Notwithstanding subsections (6) and (7), during the transition period until July 1, 2002, public utilities
may not charge rates or collect costs that include costs reallocated to transition costs at a level higher
than the public utility would reasonably expect to recover in rates had the current regulatory system
remained intact.
(9) Public utilities shall apply savings resulting under 69-8-503 toward the rate moratorium pursuant to subsection (6).
(10) During the 4-year transition period Through June 30, 2002, public utilities may accelerate the
amortization of accumulated deferred investment tax credits associated with transmission, distribution,
and the general plant as an adjustment to earnings if electric earnings fall below 9.5% earned return on
average equity. The public utility may include the flow through of investment tax credits so that the
public utility's earned return on equity is maintained at 9.5%. Accumulated deferred investment tax
credits amortized under this subsection may not be reflected in operating income for ratemaking purposes.
(11) The commission shall issue the accounting orders necessary to align rate moratorium timing and requirements to actual transition bonds savings."
Section 8. Section 69-8-403, MCA, is amended to read:
"69-8-403. Commission authority -- rulemaking authority. (1) Beginning on the effective date of a
commission order regarding a public utility's transition plan, the commission shall regulate the public
utility's retail transmission and distribution services within the state of Montana, as provided in this
chapter, and may not regulate the price of electricity supply except as electricity supply may be procured
as provided in this section: provided by the default supplier.
(a) by one or more default suppliers for those customers not being served by a competitive supplier; or
(b) by the distribution function of a public utility for those customers that are not being served by a
competitive electricity supplier as provided by commission rules.
(2) During the transition period, those procurements electricity supplies procured by the default
supplier PURSUANT TO [SECTION 9] may include a cost-based MARKET-BASED COST-BASED contract
from a supply affiliate or an unregulated division.
(2) The commission shall decide if there is workable competition in the electricity supply market by
determining whether competition is sufficient to inhibit monopoly pricing or anticompetitive price
leadership. In reaching a decision, the commission may not rely solely on market share estimates.
(3)(2) The commission shall license electricity suppliers and enforce licensing provisions pursuant to
69-8-404.
(4)(3) The commission shall promulgate rules that identify the licensees and ensure that the offered
electricity supply is provided as offered and is adequate in terms of quality, safety, and reliability.
(5)(4) The commission shall establish just and reasonable rates through established ratemaking
principles for public utility distribution and transmission services and shall regulate these services. The
commission may approve rates and charges for electricity distribution and transmission services based on
alternative forms of ratemaking such as performance-based ratemaking, on a demonstration by the public
utility that the alternative method complies with this chapter, and on the public utility's transition plan.
(6)(5) The commission shall certify that a cooperative utility has adopted a transition plan that
complies with this chapter. A cooperative utility's transition plan is considered certified 60 days after the
cooperative utility files for certification.
(7)(6) The commission shall promulgate rules that protect consumers, distribution services providers,
and electricity suppliers from anticompetitive and abusive practices.
(8) The commission shall license default suppliers and enforce default licensing provisions pursuant to
69-8-416.
(9) The commission shall promulgate rules for the licensing of default suppliers on or before December
1, 1999.
(10) Until the commission has determined that workable competition has developed for small customers,
a default supplier's obligation to serve remains.
(8) (a) Prior to July 1, 2002, the commission shall determine whether a rate transition is in the public
interest.
(b) If the commission makes the determination in subsection (8)(a) that a rate transition is in the public
interest, the commission may implement a rate transition.
(11)(9)(8)(7) In addition to promulgating rules expressly provided for in this chapter, the commission may
promulgate any other rules necessary to carry out the provision of this chapter.
(12)(10)(9)(8) This chapter does not give the commission the authority to:
(a) regulate cooperative utilities in any manner other than reviewing certification filings for compliance with this chapter; or
(b) compel any change to a cooperative utility's certification filing made pursuant to this chapter."
NEW SECTION. Section 9. Default supply of electricity during the transition period. (1) The default
supplier shall, on or before July 1, 2002, contract SEPTEMBER 1, 2001, COMMENCE A COMPETITIVE BID
PROCESS for a BASE LOAD supply of electricity for all TO MEET THE REASONABLY EXPECTED MINIMAL
NEEDS of its customers for the period of July 1, 2002, through June 30, 2007. The default supplier may
contract with multiple electricity suppliers to meet load requirements. All default DEFAULT supplier
customers shall pay the same rate RATES for electricity SUPPLY AS DETERMINED BY THE COMMISSION.
Except as provided in 69-8-403(8) SUBSECTION (4), the rate may not be changed during the contract period.
(2) Before the default supplier signs a contract for a supply of electricity, the default supplier shall
submit the contract in its entirety to the commission for the commission's approval and to a joint meeting
of the senate energy and telecommunications committee and the house federal relations, energy, and
telecommunications committee for the committees' review and comment. The committees may be reconvened
for the purposes of this subsection.
(3) Before approving the contract, the commission shall make a determination that the rates, terms, and
conditions in the contract are just and reasonable and in the public interest. If the commission determines
that the rates, terms, or conditions of the contract are not just and reasonable or not in the public
interest, the commission shall direct the default supplier to attempt to renegotiate the contract in a
manner that corrects the deficiencies identified by the commission. A contract may not be entered into
that is not approved by the commission. THE COMMISSION SHALL, EXCEPT AS PROVIDED IN SUBSECTION
(7), APPROVE OR REJECT THE CONTRACTS USING THE FACTORS IN SUBSECTION (8). THE COMMISSION
SHALL APPROVE OR REJECT THESE CONTRACTS WITHIN THE MINIMUM AVERAGE TIME STATED IN THE
REQUEST FOR PROPOSALS. A BIDDER FOR ELECTRICITY SUPPLY OR SERVICES SHALL KEEP ITS BID
PRICES AVAILABLE DURING THAT TIME PERIOD STATED IN THE REQUEST FOR PROPOSALS. IF THE
COMMISSION REJECTS THE CONTRACTS, IT SHALL INFORM THE DEFAULT SUPPLIER AS TO HOW TO
CORRECT THE DEFICIENCY. A CONTRACT MAY NOT BE ENTERED INTO THAT HAS NOT BEEN APPROVED
BY THE COMMISSION. BECAUSE BIDS ARE LIKELY TO CONTAIN CONFIDENTIAL, COMPETITIVELY
SENSITIVE, AND TRADE SECRET INFORMATION, THE DEFAULT SUPPLIER SHALL PROVIDE SUMMARIES
OF THE RESULTS OF THE BIDS FOR PUBLIC DISCLOSURE.
(4) The commission shall establish a mechanism that ensures that all just and reasonable APPROVED
JUST AND REASONABLE COMMISSION-APPROVED electricity supply costs are fully recoverable in rates.
Full cost recovery may not include a fee, charge, or financial reward that is not directly related to costs
incurred to secure a supply of electricity. RATES MUST BE ADJUSTED AT LEAST ANNUALLY BY USING
THE MECHANISM THAT RECOVERS ELECTRICITY SUPPLY COSTS IN RATES TO ENSURE THAT THOSE
COSTS ARE FULLY RECOVERED. THIS MECHANISM MUST ADJUST FOR ANY COSTS OR LOAD
DIFFERENCES AND MUST INCLUDE RECOGNITION OF THE VALUE OF MONEY OVER TIME. THE
MECHANISM MUST ADJUST RATES FOR ANY UNDERCOLLECTION OR OVERCOLLECTION FOR THE
PREVIOUS RECOVERY PERIOD, INCLUDING RECOGNITION OF THE TIME VALUE OF MONEY ON THE
UNDERCOLLECTION OR OVERCOLLECTION, AND ADD THIS AMOUNT TO OR SUBTRACT THIS AMOUNT
FROM THE FORECASTED ENERGY COSTS FOR THE NEXT RECOVERY PERIOD. THE DEFAULT SUPPLIER
SHALL SUBMIT TO THE COMMISSION AND THE COMMISSION SHALL APPROVE A MECHANISM TO
ACCOMPLISH THIS PURPOSE BEFORE MARCH 30, 2002.
(5) THE DEFAULT SUPPLIER MAY CONTRACT WITH ELECTRICITY SUPPLIERS TO MEET ITS DEFAULT SUPPLY LOAD REQUIREMENTS BY ESTABLISHING A PORTFOLIO OF CONTRACTS OF VARYING LOAD SIZES AND CONTRACT TERMS. THE DEFAULT SUPPLIER SHALL SUBMIT CONTRACTS FOR AT LEAST 400 MEGAWATTS OF POWER TO THE COMMISSION FOR THE COMMISSION'S APPROVAL BY MARCH 1, 2002.
(6) THE COMPETITIVE BID PROCESS MUST BE DESIGNED TO ALLOW ALL SUPPLIERS INTERESTED IN SUPPLYING ENERGY OR SERVICES TO THE DEFAULT SUPPLIER TO SUBMIT BIDS FOR ANY AND ALL OF THE ENERGY PRODUCTS AND ASSOCIATED SERVICES DESCRIBED IN THE DEFAULT SUPPLIER'S PROCUREMENT PROCESS. THE DEFAULT SUPPLIER SHALL KEEP THE COMMISSION AND THE CONSUMER COUNSEL INFORMED AS THE COMPETITIVE BID PROCESS IS PLANNED AND IMPLEMENTED AND SHALL WEIGH THE INPUT OF THESE AGENCIES' DESIGNATED REPRESENTATIVES, BOTH IN THE DESIGN OF THE PROCESS AND IN THE EVALUATION OF BIDS.
(7) THE DEFAULT SUPPLIER MAY CONTRACT WITHOUT USING THE COMPETITIVE BID PROCESS THAT
REQUIRES COMMISSION APPROVAL DESCRIBED IN SUBSECTION (2) IN CERTAIN CIRCUMSTANCES FOR
PEAKING OR LOAD-FOLLOWING PURPOSES. IF THE DEFAULT SUPPLIER DOES NOT ACQUIRE THE SUPPLY
OR SERVICE BY COMPETITIVE BID, THE COMMISSION SHALL REVIEW THE COSTS BASED ON A
REASONABLENESS STANDARD.
(8) IN CONSIDERING WHETHER TO ENTER A SUPPLY CONTRACT, THE DEFAULT SUPPLIER AND THE
COMMISSION SHALL CONSIDER THE FOLLOWING FACTORS ONLY:
(A) THE PRICE OF THE ENERGY SUPPLY OR SERVICE AS DETERMINED BY THE BID PROCESS;
(B) FIRMNESS OF THE ENERGY SUPPLY;
(C) RELIABILITY OF THE ENERGY SUPPLY;
(D) DELIVERY COSTS OF THE ENERGY SUPPLY, INCLUDING BUT NOT LIMITED TO DELIVERY POINT, TRANSMISSION, AND CONGESTION COSTS;
(E) THE SUPPLIER'S CREDIT CAPABILITY; AND
(F) ANY OTHER FACTOR THAT CAN BE OBJECTIVELY SHOWN TO MATERIALLY AFFECT THE PRICE OF
THE DEFAULT SUPPLIER'S ENERGY SUPPLY OR THE RELIABILITY OF THAT SUPPLY THE COMMISSION
CONSIDERS RELEVANT CAN BE OBJECTIVELY SHOWN TO MATERIALLY AFFECT THE PRICE OF THE
DEFAULT SUPPLIER'S ENERGY SUPPLY OR THE RELIABILITY OF THE SUPPLY.
(9) THE COMMISSION MAY REVIEW THE PRUDENCY OF THE PROCUREMENT PROCESS. HOWEVER, BECAUSE MARKET CHANGES SUBSEQUENT TO THE SIGNING OF A CONTRACT CANNOT BE ANTICIPATED AT THE TIME OF SIGNING, MARKET CHANGES MAY NOT BE CONSIDERED BY THE COMMISSION AS PART OF A FUTURE EVALUATION OF THE CONTRACT.
(9)(10) THE DEFAULT SUPPLIER SHALL OFFER ITS CUSTOMERS AN OPPORTUNITY TO PURCHASE A
SEPARATELY MARKETED PRODUCT COMPOSED OF POWER FROM RENEWABLE RESOURCES. THIS
PRODUCT MAY BE PRICED DIFFERENTLY FROM THE STANDARD ELECTRICITY PRODUCT AUTHORIZED IN
THIS SECTION. FOR THE PURPOSES OF THIS SECTION, "RENEWABLE RESOURCES" MEANS WIND, SOLAR,
OR GEOTHERMAL RESOURCES.
(10)(11) THE ADMINISTRATION AND GENERAL COSTS AND THE COSTS OF ANY ENERGY RISK
MANAGEMENT PROCESS ACTIVITIES OF THE DEFAULT SUPPLIER MUST BE INCLUDED IN THE DEFAULT
SUPPLY RATE.
(5)(11)(12) Federal power marketing administration power or benefits acquired or received by the
default supplier must be distributed as widely and equitably as possible among customers.
NEW SECTION. Section 10. Repealer. Sections 35-19-103, 69-8-104, 69-8-416, and 69-8-417, MCA, are repealed.
NEW SECTION. Section 11. Codification instruction. [Section 9] is intended to be codified as an integral part of Title 69, chapter 8, and the provisions of Title 69, chapter 8, apply to [section 9].
NEW SECTION. Section 12. Effective date. [This act] is effective on passage and approval.
NEW SECTION. Section 13. Applicability. [This act] does not affect the determination of transition costs for utilities that have submitted a transition plan pursuant to Title 69, chapter 8, parts 1 through 5, prior to [the effective date of this act].
- END -
Latest Version of SB 243 (SB0243.05)
Processed for the Web on March 30, 2001 (3:12PM)
New language in a bill appears underlined, deleted material appears stricken.
Sponsor names are handwritten on introduced bills, hence do not appear on the bill until it is reprinted. See the status of this bill for the bill's primary sponsor.
Status of this Bill | 2001 Legislature | Leg. Branch Home
All versions of this bill (PDF Format)
Authorized print version w/line
numbers (PDF format)
(406)444-3064