Wyo. Code R. 023-0002-3
Effective Date: 07/16/2025 to Current
Rule Type: Current Rules & Regulations
Reference Number: 023.0002.3.09112025
(a) Each utility shall furnish its customers with safe, adequate and reliable service in accordance with accepted good utility practice. It shall maintain its entire plant and system in a condition enabling it to furnish required service and inspect its system and facilities in a manner and at such frequency as necessary to obtain sufficient knowledge of its current condition and adequacy.
(b) Electric utilities shall:
(i) Design and operate the electric system to maintain its voltages within the limits of ANSI 84.1;
(ii) Use portable indicating voltmeters or electronic monitors capable of recording the continuous voltage in time for testing voltage regulation and portable graphic voltmeters or electronic monitors capable of recording the continuous voltage in time for testing power quality and reliable operation. These instruments shall be of a type and capacity suited to the voltage supplied and adequate to comply with section 18 of this Chapter;
(iii) Conduct a sufficient number of voltage surveys to adequately indicate the character of service furnished to its customers and to demonstrate compliance with voltage requirements. Voltage surveys shall include measurements at the point of delivery or nearest downstream device; and
(iv) Establish per tariff standard nominal voltages as required by the unique distribution system for the service area or for each district of a divided system.
(c) Gas utilities shall:
(i) Have access to or require use of a properly maintained calorimeter or chromatograph of a standard type with all necessary accessories for the determination of the Btu value of gas delivered;
(ii) Maintain in its tariff a standard to determine gas Btu value that equates a cubic foot of gas with the amount of gas that occupies one cubic foot, dry, at 60° F at 14.73 pounds per square inch absolute;
(iii) Maintain in its tariff a standard to measure gas provided to a customer that equates a cubic foot of gas with the amount of gas that occupies one cubic foot under the conditions at the customer's meter. The real gas law shall be used to calculate any volume adjustment for the gas delivered;
(iv) Deliver gas that:
(A) Contains no more than 0.25 grains of hydrogen sulfide per 100 standard cubic feet; (B) Contains no more than 2.5 mole percent of oxygen; (C) Contains no more than seven pounds of water vapor per million standard cubic feet; (D) Has a heating value of at least 950 Btu per standard cubic foot; and (E) Has a hydrocarbon dew point compatible with normal system operating conditions.
(v) Monitor changes to tariff-established Wobbe Indices.
(A) The tariff sheets shall describe, and include a map illustrating, the distinguishable distribution area(s) in which each Wobbe Index applies, the effective dates of each Wobbe Index and each change in service with the date of its related customer notification.
(B) Unless otherwise authorized by the Commission, a Wobbe Index for a distinguishable distribution area that deviates more than 4% from the established Wobbe Index is considered a change in service. A cumulative change of 4% in the Wobbe Index or other service condition over a period of more than three consecutive calendar years may also be considered a change in service.
(C) A utility shall apply to the Commission when seeking to establish or change a Wobbe Index. The application shall include the proposed Wobbe Index for each distinguishable distribution area and shall use a calculation of the weighted mean Wobbe Index for the gas delivered to the distribution area during a representative historic 12-month period.
(d) Water utilities shall:
(i) Comply with the requirements of DEQ and/or EPA when furnishing any water for human consumption or domestic use;
(ii) Flush their system periodically, no less than semi-annually, to eliminate or minimize discoloration or other abnormal conditions. Records of the date, place and duration of all flushings shall be retained and used as a guide in determining the necessary frequency of subsequent flushings; and
(iii) Maintain a pressure gauge at a central point in the distribution system where continuous records shall be made of the pressure observed.
Section 2. Change in Service. A change in service is a substantial change made by a utility in the type of service rendered in a distinguishable distribution area that affects the efficiency of operation or requires adjustment of customer appliances. Upon a change in service, a utility:
(a) Shall notify the Commission and affected customers, in advance, if possible; and
(b) May be ordered to inspect and adjust the appliances of the affected customers in the distinguishable distribution area to the new conditions without charge, unless provided for contractually between the utility and an individual non-residential customer.
(i) The Commission may defer the inspection and appliance adjustment requirement if the circumstances warrant, or, pending the utility’s analysis of gas quality and associated safety parameters in the distinguishable distribution area.
(a) Each utility shall make all reasonable efforts to avoid interruptions of service and, when interruptions occur, shall re-establish service in a timely and safe manner.
(b) Utilities shall submit a written, confidential list of contact names and telephone numbers to be used when a service interruption occurs. The list shall:
(i) Be resubmitted each January and July, whether or not the contact person(s) have changed since the last submittal;
(ii) Be updated as soon as a contact changes;
(iii) Include contact information to communicate with individuals who are knowledgeable about service interruptions, the estimated duration and the possible causes of service interruptions; and
(iv) Include contact information to communicate with individual(s) who are available to confer with the Commission at all times.
(c) Utilities shall notify the Commission of all planned major service interruptions, defined per tariff, at least 48 hours in advance, except in emergencies.
(d) Utilities shall make reasonable efforts to provide affected customers two business days’ notice of a planned service interruption.
(e) Utilities shall make reasonable efforts to establish mutual aid agreements with other entities to assist in the recovery of large scale service interruptions, natural disasters or other significant events.
(a) Each utility shall construct, install, operate and maintain its entire plant and system (“facilities”), including structures, equipment and lines, in accordance with accepted good utility practice and in a manner that prevents injury to persons or property, promotes the safety, health, comfort and convenience of its customers, employees and the general public and eliminates interference with the service furnished by other utilities, facility operators or telecommunication companies.
(i) Electric utilities shall construct, install, operate and maintain facilities in accordance with NEC, NESC, WECC and NERC standards along with RUS standards, if applicable.
(ii) Natural gas and pipeline utilities shall construct, install, operate and maintain facilities, including conducting leak surveys and cathodic protection of distribution and service lines, in accordance with PHMSA regulations (49 CFR §§ 40; 191-193; 199).
(iii) Water utilities shall construct, install, operate and maintain facilities in accordance with the requirements of DEQ and the State Engineer’s Office.
(b) The furnishing of service by a utility to a customer shall not render the utility responsible for the customer’s facilities, installation or practices on the customer side of the point of delivery.
(c) Each point of delivery shall be metered and located as near to the customer’s utilization equipment as practicable per tariff.
(d) In determining good utility practice, the Commission may grant deviations to the standards listed in this section as well as in ANSI B31, the ASME Boiler and Pressure Vessel Code and all other applicable ANSI codes and standards.
(e) In the case of conflict between applicable codes and standards, the more stringent shall apply.
(f) Utilities and facility operators shall coordinate with telecommunication companies to avoid or eliminate any interference. The owner of new facilities interfering with existing facilities constructed in accordance with relevant and applicable standards shall bear the cost of correction and mitigation.
(a) Each utility shall, upon request, provide its customers such information and assistance as is reasonably possible and necessary in order that customers may secure safe, adequate and reliable service.
(b) The utility shall maintain a copy of its tariff at its local office for inspection by the public during normal business hours.
(c) When more than one rate is available, the utility shall advise an applicant, upon request, which rates are available to the applicant. If, at any time subsequent to the commencement of service, the customer requests assistance, the utility shall advise the customer which rates are available to the customer.
Section 6. Service Connections and Line Extensions. Each utility shall establish per tariff terms and conditions applicable to service connections and line extensions.
(a) Line extension tariff sections shall provide for new service within the utility's certificated service territory for each rate class at no cost to the customer to the extent that prospective net revenue from the new service justifies the installation and maintenance costs of the extension.
(b) In the case of temporary service for short term use (as distinguished from seasonal use), a utility may require a customer to pay all costs of service connection and disconnection, line extension and line removal after service has been discontinued. The customer shall be credited with the reasonable salvage value.
(c) Special contracts for extension of the utility's distribution system to supply commercial service, industrial service or service of indeterminate character shall be filed with the Commission.
(d) The utility may allow the customer to construct service and line extensions if authorized by the Commission per tariff. Utilities shall inspect these extension projects regularly to ensure work is progressing and completed according to applicable standards, codes and these regulations.
Section 7. Customer Deposits. A utility may require a deposit to guarantee payment. This deposit shall not be considered advance payment of bills, but shall be held as security for payment of service rendered. The utility may refuse service to an applicant or discontinue service to a customer for failure to comply with this section. Utility policies governing customer deposits shall be applied uniformly.
(a) The utility may require a deposit if:
(i) A prior service account with the utility remains unpaid and undisputed at the time of application for service;
(ii) Service from the utility has been terminated for:
(e) The utility shall provide the customer a non-assignable receipt or other record of deposit, showing the date and amount received.
(f) The utility shall calculate simple interest on deposits at the Commission Authorized Interest Rate. Interest shall apply only to deposits held for at least six months, but shall accrue from the initial date of deposit through the date the deposit is returned to the customer.
(g) The utility may accept a written guarantee from an acceptable guarantor in lieu of a deposit to pay a customer’s bill. After the utility has verified the customer’s identity, the customer shall agree to permit the utility to provide the customer’s account information to the guarantor upon the customer’s default.
(h) Deposits and any unpaid interest earned on deposits shall be applied as a credit to the customer’s bill, unless requested by the customer to be refunded, when:
(i) The accrued interest equals or exceeds $10.00. The utility shall apply the credit at least annually;
(ii) A residential customer has received 12 consecutive months of service, with no cause to disconnect and bills have been paid when due;
(iii) A commercial or industrial customer has received 12 consecutive months of service, with no cause to disconnect, bills have been paid when due and passes an objective credit screen; or
(iv) Service is discontinued. The utility shall not require the customer to provide the original receipt in order for the deposit to be returned. Any credit balance on the account after the deposit is applied shall be refunded to the customer. If the utility is unable to make the refund due to lack of knowledge of the customer’s location, additional interest will not accrue after the service discontinuation date. The utility shall manage such deposits as unclaimed property as required by Wyoming law.
Section 8. Refusal to Serve New Customers or Expand Existing Service. A utility may refuse to provide, expand or materially change service to a requesting customer when:
(a) The utility does not have adequate facilities to render the service requested and the customer is not willing to comply with the utility’s line extension tariff;
(b) The requested service appears to be unsafe or likely to adversely affect service to another customer; or
(c) The requesting customer is indebted to the utility for service previously rendered and satisfactory payment arrangements have not been made with the utility.
(i) If indebtedness for service rendered at a former location is in dispute, the requesting customer shall be provided service at the new location upon complying with the utility's deposit requirements and paying the amount in dispute. Upon settlement of the disputed amount, any balance due the customer shall be refunded with accrued interest at the Commission Authorized Interest Rate.
(ii) The utility shall not refuse service to a new customer because of debts of a previous customer at the same location.
(iii) The utility may refuse service due to unpaid line extension charges for facilities serving the location.
(a) Unless otherwise ordered by the Commission, no utility shall terminate service to any customer for violating the utility's rules and regulations or for nonpayment of bills for service until the utility has given at least seven calendar days' notice to residential customers or three calendar days' to commercial or industrial customers.
(b) Notice shall be effective when a copy is provided to the customer in person, by telephone after customer verification, or received by U.S. mail at the customer's last known mailing address. Additional notice may be provided electronically. The notice shall contain:
(i) The name of the person whose account is delinquent and the service address to be discontinued;
(ii) The rule or regulation that was violated or the amount of the delinquent bill;
(iii) The effective date of the notice and the date on or after which service is to be discontinued;
(iv) The utility's specific address and telephone number for information regarding how to avoid service discontinuation;
(v) The names of agencies or organizations that have notified the utility that they render assistance to eligible persons who are unable to pay their utility bills; and
(vi) A statement advising the customer how to contact the Commission if discontinuation is disputed.
(c) For residential customers, the notice shall inform the customer that, if prior to the initial date for the discontinuation, the customer provides the utility with written verification from a health care provider responsible for the care of a customer or his/her co-habitants stating that their health or safety would be seriously endangered if service were discontinued, the utility shall extend the date for discontinuation set forth in the notice by 15 days (22 days total) to allow for bill payment.
(d) The utility shall attempt to make actual contact with the customer either in person or by telephone after customer identity verification before discontinuing service during the cold weather period of November 1 through April 30.
(e) The utility shall also provide notice of discontinuation or account delinquency to a third party if a customer, or person acting for the customer, has requested the utility do so after customer identity verification. The utility shall establish reasonable procedures to advise customers, particularly any incapacitated customer, that the right to request third-party notification does not create third-party liability for payment.
(f) If the customer defaults, the utility shall provide the discontinuation notice to any guarantor and customer simultaneously. The guarantor's service shall not be subject to discontinuation as a result of the customer's default.
(g) The utility shall remove a guarantor when:
(i) The customer has received 12 consecutive months of service with no cause for discontinuation, bills have been paid when due and the customer passes an objective credit screen;
(ii) The guarantor has paid all amounts due for service through the date the utility receives the request to terminate the guarantor agreement; or
(iii) An additional agreement with the utility is in place.
(h) The utility may discontinue service between 8:00 a.m. and 4:00 p.m., Monday through Thursday, without further notice when:
(i) The notification period has elapsed and the delinquent account has not been paid;
(ii) Acceptable payment arrangements have not been made with the utility; or
(iii) The utility is not satisfied the customer has ceased violating the utility's rules and regulations.
(j) The utility shall not discontinue service for bill nonpayment:
(i) On a legal holiday or the day before;
(ii) During the period from December 24 through January 2, inclusive;
(iii) On any day the utility cannot reconnect service;
(iv) If the customer enters into an agreement with the utility for payment of the delinquent billing over a reasonable time and the customer complies with the payment arrangements;
(v) If the customer owes the utility money due to a meter or other billing error and the customer complies with payment arrangements;
(vi) At a previous address for a different class of service;
(vii) Of non-utility service or merchandise;
(viii) If a customer is paying bills on time, even though a former customer with an undisputed delinquent bill for service resides or conducts business at the same address;
(ix) If a utility bill is in dispute and the customer duly pays the utility bill or bill portion that is not in dispute; or
(x) If the temperature is forecasted by the National Weather Service or other reputable source to be below 32° F in the impending 48 hours, or if conditions are otherwise especially dangerous to health, and the customer is:
(A) A residential customer;
(B) A non-residential customer providing service essential for the protection of public health, safety or welfare;
(C) Unable to pay for service in accordance with the utility’s billing requirements and is actively seeking government assistance or has exhausted such assistance; or
(D) Able to pay for service in installments only.
(k) The utility shall assist elderly and handicapped persons who are unable to pay their utility bills with determining available government assistance.
(l) A utility may discontinue service to a customer without advance notice for reasons of safety, health, cooperation with civil authorities, fraudulent use, tampering with or destroying utility service facilities or customer’s failure to comply with utility curtailment procedures during supply shortage.
(m) Upon a customer’s or legally authorized person’s request, the utility shall make reasonable efforts to terminate the customer’s service as requested. Before terminating service, the utility shall inform the customer of any additional charges per tariff for after-hours service discontinuation.
When service has been discontinued for violation of the utility's rules and regulations, nonpayment of bills or fraudulent use of service; and the customer desires the service to be reconnected, the utility may require the customer to pay in full all bills due for service rendered up to the date service was discontinued, plus any reconnection charge per tariff. Upon satisfaction of reconnection requirements, the utility shall restore service as soon as practicable. If a customer requests reconnection of service after hours, the utility shall inform the customer of any additional charge per tariff for after-hours expenses prior to the reconnection. No utility shall charge to reconnect service when discontinuation was improper.
Section 12. System of Accounts. Each utility shall maintain all accounting and statistical data necessary to provide complete and accurate information regarding the utility's properties and operations.
(a) Pipeline utilities and privately owned gas and electric utilities shall maintain accounting records in accordance with FERC's Uniform System of Accounts.
(b) Water utilities shall maintain their accounting records in accordance with applicable NARUC Uniform System of Accounts for Class A, B, C and D water utilities.
(c) Any utility operating as a utility in any other state or engaged in non-utility operations shall separately maintain the accounting and statistical data that pertain to utility operation in the State of Wyoming.
Section 13. Advertising. No utility may recover from any person other than the shareholders (or other owners) of such utility any direct or indirect expenditure by such utility for promotional or political advertising.
(a) For purposes of this regulation, promotional and political advertising do not include advertising:
Section 14. Records.
(a) A meter record for all utility meters shall be retained for the life of the meter and shall indicate for each meter owned or used by a utility the identifying number, name of manufacturer, type, capacity, date of purchase or other acquisition, installation date, its current location and all results of meter tests.
(i) All required meter tests shall be properly referenced to the meter record. The record of each test made shall show:
(A) The identifying number and constants of the meter (the standard meter and other measuring devices used);
(B) The date and kind of test made;
(C) The reason for the test;
(D) The reading of the meter before the test;
(E) The error or percent accuracy at each tested load; and
(F) The test results and sufficient data to permit calculation verification.
(b) Utilities shall retain for at least three years the names and addresses of all customers with the identifying number of related meter(s).
(c) Each electric utility shall retain these records:
(i) The daily record of the load and a monthly record of the output of its plants. For stations not having operators in continuous attendance, only monthly records are required. Each utility purchasing electrical energy shall provide to the Commission, upon request, information as to the monthly purchases, including demand where measured. For stations having operators in continuous attendance, regular readings of all station instruments and meters shall be made and recorded in such detail as to indicate the character of service being rendered. These records shall be retained for a minimum of three years;
(ii) Maps and records showing the location, voltage and conductor size of transmission and primary distribution facilities, substations and switching facilities. These records shall be retained for the life of the facility.
(d) Each natural gas utility shall retain:
(i) Monthly record of the heating value (Btu) of gas provided to customers in the Wyoming jurisdiction. These records shall be retained for a minimum of three years;
(ii) Records of delivery pressure to:
(A) Distribution systems served by more than one district regulator or plant; or
(B) Distribution systems served by a single district regulator station or plant where the operator demonstrates a need for recording of pressures. These records shall bear the date and show the place where the pressure reading was taken and be retained for a minimum of three years.
(iii) Maps or other records showing the size, pipe material and location of each main, regulator, valve and customer service. These records shall be retained for the life of the facility.
(a) Each utility shall adequately meter and measure the commodity delivered into its distribution systems to determine demand capacity, losses, capacity constraints and, if applicable, voltage levels.
(b) Each utility shall measure customer commodity use by industry-recognized and approved certified meters.
(c) Each utility shall install and maintain at its own expense all equipment necessary to regulate and measure the commodity delivered per tariff.
(d) Upon a customer’s request, a utility may install and maintain an additional meter at the customer’s expense.
(e) No pre-payment meter shall be used by the utility except when a utility’s tariff permits, it is voluntarily chosen by the customer and the utility’s tariff describes discontinuation of service procedures. The customer retains the option to request regular metered service at any time, which may be subject to deposit. Customer accounts where service is provided to persons whose physical health or safety would be endangered if the utility service were discontinued are not eligible for pre-payment meter service. If a pre-payment meter is in use, the utility shall:
(i) Provide continuous customer access to account information and payment options to enable continued service; and
(ii) Inform the customer of all payment options and provide a telephone number or other electronic communication options in case of emergencies and/or service problems.
(f) Any non-metered utility service shall be governed by tariff.
(a) Meters and associated devices shall be installed in a reasonable location accessible for reading, testing, inspection, removal and where such activities will minimize interference and inconvenience to the customer and utility per tariff.
(b) No meter shall be installed in any location where the meter or associated service lines may be unnecessarily exposed to damage.
(c) The customer shall provide, without cost to the utility, a suitable location accessible for metering and installation of equipment required to receive service.
(d) Meters located inside buildings are discouraged. If so located, meters shall be as near as practicable to where the service conductor or pipe enters the building.
(e) All electric meters shall be located and installed in accordance with NEC and NESC, as applicable.
(f) Gas utilities shall:
(i) Locate all meters and service regulators in accordance with 49 CFR §192;
(ii) Provide for the shortest safe distance to the customer’s building entrance or point of utilization equipment;
(iii) Submit a plan to the Commission, upon request, to address existing residential service meters not in compliance with this section.
(g) Water meters shall be located to protect from freezing, excessive heat, temperature variations, vehicular damage and inflow of surface water.
(a) Inaccurate, improper or non-certified meters, including those for which accuracy has not been established, shall not be placed in service or allowed to remain in service. Meters that register upon zero load are considered inaccurate. New meters and serviced meters shall be in good repair and adjusted as closely as practicable to zero error. All meters shall conform to ANSI, IEC, AWWA and ISO, as applicable.
(b) All service meters shall clearly indicate the units of measurement for which the customer is charged. If the utility invoices customers in a different unit of measurement than the service meter indicates, the conversion factor shall be stated on the customer bill. Metering in the following units is required:
(i) Electric: kWh, kW or kVar depending upon service requirements;
(ii) Gas: cubic feet, dekatherms or therms;
(iii) Water: cubic feet or U.S. gallons.
(a) Each utility shall develop a meter testing program for the calibration, recertification, care and maintenance of meters, recording devices, field testing equipment and meter calibration equipment (hereinafter referred to in this section as “equipment”) in order to keep the equipment in proper working condition. The utility shall have access to a meter laboratory, standard meters, instruments, meter calibration equipment and facilities necessary to carry out its meter testing program. The facilities and equipment shall be available at reasonable times for inspection by any authorized representative of the Commission.
(f) Each water utility furnishing metered water service using portable test meters to determine the accuracy of meters in service shall recalibrate the portable test meters at sufficiently frequent intervals to ensure correct registration at the specified rates of flow.
(a) Each service meter shall clearly indicate the units of measurement. If the utility invoices customers in a different unit of measurement than the service meter indicates, the conversion factor shall be stated on the customer bill. In cases where special types of meters are used or where the readings of a meter must be multiplied by a constant to obtain the units consumed, that information shall be placed on the customer bill.
(b) Bills shall be rendered periodically and shall show the meter readings at the beginning and end of the billing period, the date of the meter readings, the units consumed, the class of service and other information necessary to enable the customer to readily re-compute the amount of the bill. Each bill shall bear upon its face the date of the bill and the latest date it may be paid without penalty. Estimated meter readings or budget billing shall be clearly identified on the bill.
(i) Electric and gas service meters shall be read monthly as nearly as possible on the same day within a billing cycle;
(ii) Water service meters shall be read at intervals authorized per tariff.
(a) If a customer requests a test of the accuracy of the utility's meter on the customer's premises, the following provisions shall apply:
(i) If the meter has not been tested within 12 months, the utility shall perform the test within a reasonable time without charge to the customer. The utility shall notify the customer of the time when the utility will conduct the test so the customer or the customer's representative may be present;
(ii) If the meter has been tested within 12 months, the utility shall notify the customer of the cost to perform the test. Upon receipt of payment, the utility shall notify the customer of the time when the utility will conduct the test;
(iii) The utility shall promptly advise the customer of the test results.
(b) If a meter is found to be in non-compliance with the utility's meter testing program, the utility shall refund the payment the customer advanced for the meter test and shall repair or replace the meter per tariff.
(a) No utility may commence new construction or an expansion of facilities or projects for which notification is required pursuant to section 21(b) until the Commission:
(i) Grants the utility a situs or non-situs certificate of public convenience and necessity; or a non-situs waiver;
(ii) Informs the utility in writing that the proposed facilities or projects in Wyoming do not require a certificate of public convenience and necessity or a non-situs waiver, following the utility's notification that explains in detail why a proposed facility or project is in the ordinary course of business or otherwise exempt. The Commission shall inform the utility whether or not the proposed facility or project requires a certificate of public convenience and necessity or a non-situs waiver within 20 business days following receipt of the utility's notice; or
(iii) Determines that waiving the requirement to obtain a non-situs certificate of public convenience and necessity is in the public interest because there exists:
(A) A clear emergency;
(B) A time-limited commercial or technical opportunity that provides value to or serves a public purpose or need of customers of the affected public utility; or
(C) Any other factor that makes waiving the requirement in the public interest.
(b) Utilities shall notify the Commission of the following proposed facilities or projects:
(i) For electric utilities, a summary of the proposed modification, construction or re-route for any project associated with any generation plant, substations or switching station 69kV and above or transmission lines 69kV and above that are greater than three miles in length, except that, no utility notification shall be required for a non-situs project if the capital investment in such facility or project that is assigned or allocated to Wyoming customers is less than one percent (1%) of the utility's total Wyoming rate base from the most recent general rate case;
(ii) For gas utilities, a summary of the proposed modification, construction or re-route for any project above 125 pounds per square inch gauge and greater than three miles in length in Class 1 Locations not designated as High Consequence Areas or one mile in length in all other locations;
(iii) For water utilities, a summary of the proposed modification, construction, diversion or re-route for any project associated with transmission lines, pumping stations, storage facilities or diversion facilities; or (iv) For pipeline utilities, a summary of the proposed modification, construction or re-route for any project above 125 pounds per square inch gauge associated with:
(A) liquid transmission pipelines greater than three miles in length unless they could impact High Consequence Areas, or one mile in length in all other locations; or
(B) gas transmission pipelines greater than three miles in length in Class 1 Locations not designated as High Consequence Areas or one mile in length in all other locations.
(c) When a utility is required to file an application for a certificate of public convenience and necessity:
(i) The application shall include:
(A) The name and address of the applicant;
(B) The type of plant, property or facility proposed to be constructed or acquired;
(C) A description of the facilities proposed to be constructed or acquired, including preliminary engineering specifications in sufficient detail to properly describe the principal systems and components, and final and complete engineering specifications when they become available;
(D) The rates, if any, proposed to be charged for the service that will be rendered because of the proposed construction or acquisition;
(E) The estimated total cost of the proposed construction or acquisition;
(F) The manner by which the proposed construction or acquisition will be financed;
(G) Documentation of the financial condition of the applicant;
(H) The estimated annual operating revenues and expenses that are expected to accrue from the proposed construction or acquisition, including a comparison of the overall effect on the applicant’s revenues and expenses;
(J) The estimated start and completion dates of the proposed construction or date of acquisition; and
(K) A statement setting forth the need for the facility in meeting present or future demands for service in Wyoming or other states within the utility’s service area.
(ii) To operate or construct a major utility facility in Wyoming, the application shall include the following information in addition to the requirements of section (21)(c)(i):
(A) A description of the proposed site, including the county or counties in which the facility will be located, with a metes and bounds description, and a description of the terrain where the facility will be constructed;
(B) A geological report of the proposed site, including foundation conditions, groundwater conditions, operating mineral deposits within a one-mile radius and a topographical map showing the area within a five-mile radius;
(C) A description of and plans for protecting the surrounding scenic, historical, archeological and recreational locations; natural resources; plant and animal life; and land reclamation, including:
(I) A general description of the devices to be installed at the major utility facility to protect air, water, chemical, biological and thermal qualities;
(II) The designed and tested effectiveness of such devices; and
(III) The operational conditions for which the devices were designed and tested.
(D) A description of any potential safety hazards;
(E) A description of the real property, fuel and water requirements, including any source of water along which the major utility facility will be constructed or from which it will obtain or return water;
(F) The acquisition status, source and location of real property, right-of-way, fuel and water requirements;
(G) The proposed means of transporting fuel and water requirements;
(H) A description of all mineral rights associated with the facility and plans for addressing any split-estate issues;
(I) A description of the commodity or service the facility will make available;
(K) A statement of the facility’s effect on the applicant’s and other systems’ stability and reliability;
(L) The status of satisfying local, state, Tribal or federal governmental agency requirements. The applicant shall immediately file all agencies' final orders.
(M) For gas utilities, when the proposed modification, construction or re-route for any project is above 125 pounds per square inch gauge and greater than three miles in length in Class 1 Locations not designated as High Consequence Areas or one mile in length in all other locations, all project documentation, including but not limited to, constructability review, project management, risk assessment, and safety management systems shall include the signature and seal of a registered professional engineer.
(d) When a utility extends service to a contiguous, unserved area as defined in Wyoming Statute § 37-2-205, the utility shall notify the Commission in writing and, if so directed, shall apply for an order conforming the certificated area to the area actually served. At a minimum, the notification shall include:
(e) A utility shall file an application and obtain Commission approval prior to discontinuing, any type of utility service currently offered to the public.
(f) A utility shall file an application and obtain Commission approval prior to abandoning, transferring, selling, leasing, discontinuing the use of, or otherwise disposing of, relinquishing complete or partial operational control of, or, in the case of an electrical generation facility, converting to the use of a different primary fuel, any utility plant or facilities used or useful in providing service to the public.
(B) A description of any impact of the proposed action on other public utilities; and
(C) A description of any anticipated cost savings to customers.
(ii) In addition to the items in § 21(f)(i), if the utility is retiring a major utility facility, the application shall include:
(A) any material state and local socioeconomic impacts or cost externalities, incurred, or likely to be incurred, by or in the state of Wyoming;
(B) the costs and a plan for decommissioning and reclamation of the facility’s site; and
(C) if applicable, any federal law mandating closure or environmental compliance expenditure that makes it no longer cost effective to operate the facility with supporting analysis.
(iii) If a utility is retiring an electric generation facility, as defined in Wyo. Stat. 37-2-134(a)(iii), in addition to § 21(f)(i) and (ii), the application shall include:
(A) a reliability study, if applicable, analyzing the proposed action upon quality of services provided, including descriptions of:
(I) the generation or other resources that will replace the capacity of the facility proposed for retirement,
(II) the effect of the proposed retirement on system reliability and resilience, including with respect to disaster preparedness,
(III) the dispatchability of the replacement generation or other facility relative to the facility proposed for retirement, and
(IV) any anticipated alterations to transmission facilities or effects on transmission system operations that would be necessary to accommodate the proposed retirement and facilities providing replacement capacity; and
(B) a detailed analysis of any potential alternatives to discontinuing, abandoning or otherwise disposing of the utility plant, facility or service.
(iv) An application shall not be required:
(A) To remove individual facilities where a customer has requested service discontinuance;
(B) For de minimis sales and dispositions of utility plant or facilities that do not affect a utility’s ability to provide safe, adequate and reliable service. De minimis sales and disposition do not include the sale or disposition of distribution facilities, major utility facilities or facilities valued at more than 1% of a utility's Wyoming gross plant in service; or
(C) For easements and rights-of-way and leases or sale of real property that do not affect a utility's ability to provide safe, adequate and reliable service, provided that such transactions shall be reported to the Commission on the 15th day of January and July each year. The reports shall include an itemized list of all transactions, their value and a description of the disposition of all funds received.
(g) A utility shall file an application prior to selling, transferring by lease or otherwise disposing of a controlling interest in the utility. The application shall include:
(A) The utility shall submit to the Commission an application describing its efforts to sell the Coal Fired Electric Generation Facility, including, but not limited to, proof of compliance with the solicitation process approved by the Commission and any offers received to purchase the Coal Fired Electric Generation Facility;
(B) The utility shall include a report detailing the reasons a sale was not accomplished. The utility shall demonstrate that:
(I) An asset purchase and sales agreement and a power purchase agreement with a prospective purchaser selected through the Commission approved Coal Fired Electric Generation Facility solicitation process, in comparison with the proposed retirement of the Coal Fired Electric Generation Facility, was not executed as it does not reduce costs and reduce risks to the utility's Wyoming customers, including any diminished environmental remediation risks;
(II) The Coal Fired Electric Generation Facility should be retired because there was no reasonable offer to purchase it through the Commission approved Coal Fired Electric Generation Facility solicitation process; or
(III) A sale could not be completed for a reason beyond the reasonable control of the utility.
(C) The Commission shall review whether the utility complied with the Commission approved processes pursuant to Section 25 and determine whether the utility has demonstrated it made a good faith effort to sell the Coal Fired Electric Generation Facility.
(D) For any Coal Fired Electric Generation Facility retired on or after January 1, 2024, the Commission shall review whether the utility has demonstrated that:
(I) The requirements of W.S. § 37-3-117(a) have been satisfied; and
(II) The utility is achieving, or has taken steps satisfactory to the Commission to achieve, the electricity generation standards established in accordance with W.S. § 37-18-102(a) and the rules adopted pursuant thereto.
(ii) Where the utility reached an agreement to sell with a prospective purchaser, the utility shall submit an application to the Commission including:
(A) An asset purchase and sales agreement to be executed between the utility and the prospective purchaser;
(B) Any power purchase agreement(s) to be executed between the prospective purchaser and the utility and/or the utility and an Eligible Retail Customer;
(C) Any partial requirements contract agreement executed between the utility and an Eligible Retail Customer;
(D) Demonstration that the prospective purchaser has acquired or is in the process of acquiring all permits necessary to operate, maintain and retire the Coal Fired Electric Generation Facility, either through transfer of existing permits, or by application to agencies with appropriate jurisdiction.
(E) A plan of operation for the Coal Fired Electric Generation Facility by the prospective purchaser demonstrating:
(I) The availability of personnel that will operate and manage the Coal Fired Electric Generation Facility, including:
(1.) A complete list of the prospective purchaser’s managers, owners, and Board of Directors including job descriptions and any relevant experience of managers, owners and key employees; and
(2.) A complete list of any labor agreements, collective bargaining agreements or other employee arrangements assumed by the prospective purchaser.
(II) An estimate of anticipated capital expenses necessary to operate the Coal Fired Electric Generation Facility for the next five years;
(III) Existence of relationships with vendors to supply fuel, reagents and other supplies and materials necessary to operate the Coal Fired Electric Generation Facility;
(IV) Familiarity with the electrical and emissions limits of the Coal Fired Electric Generation Facility; and
(V) Other aspects of a plan of operation as may assist the Commission in evaluation of the prospective purchaser’s suitability.
(F) The terms and conditions of the prospective purchaser’s proposed financing;
(G) A list of all local, state and federal taxes associated with owning and operating the Coal Fired Electric Generation Facility, along with a disclosure of adequate future performance by the prospective purchaser;
(H) Documentation of the prospective purchaser’s financial condition, including, but not limited to, audited financial statements, tax returns, corporate ratings opinions and capital ratios;
(J) Demonstration that the prospective purchaser possesses the requisite technical expertise, financial resources and managerial ability to operate, maintain, decommission and retire the Coal Fired Electric Generation Facility through the end of its useful life;
(I) If these obligations are shared with a selling utility, the joint operating agreement shall clearly and unambiguously define the obligations of each party regarding decommissioning and retiring the Coal Fired Electric Generation Facility at the end of its useful life;
(II) Decommissioning costs shall be itemized and estimated for Commission review; and
(III) The Commission may require financial assurance of the prospective purchaser sufficient to assure complete decommissioning of the Coal Fired Electric
Generation Facility and reclamation of the site.
(K) Demonstration that the purchase is in the public interest.
(j) A gas or electric utility shall file an application signed by an authorized person prior to issuing securities or creating liens.
(i) The application shall include:
(A) Documentation of authorization to issue securities or create debt, including the total amount of securities or debt;
(B) The purpose of the security issuance or debt;
(C) Copies of proposed securities or debt document, including any related terms and conditions;
(D) Copies of financial statements, work papers and financial forms showing the aggregate of the existing and proposed securities or debt and the fair value of the gas or electric utility; and
(E) Presentation of the utility’s debt-to-equity ratio before and after the proposed transaction.
(ii) Cooperative utilities shall, except as provided in (B) below:
(A) Provide their debt-to-asset ratio, operating TIER, debt service coverage ratio, the minimum debt coverage ratios and the amount of long-term debt held by the utility before and after the proposed transaction. If issuing the securities would violate any minimum ratio requirement, the cooperative utility shall provide a letter from the lender acknowledging the cooperative utility will not be in violation of loan covenants with the new securities, or;
(B) Cooperative utilities exempt from retail rate regulation pursuant to Wyo. Stat. 37-17-103, when borrowing from the United States Rural Utilities Service, CoBank, the National Rural Utilities Cooperative Finance Corporation, the National Cooperative Services Corporation or the Rural Telephone Finance Cooperative, may, in lieu of the information required in (i), above, provide:
(I) A Board of Directors' resolution identifying the proposed lender;
(II) A statement of the cooperative’s purpose of the loan; and
(III) Affirmation that the loan will not result in the cooperative’s aggregate amount of securities outstanding to exceed the fair value of the properties and business of the cooperative.
(iii) Once securities are issued, compliance documents shall be filed with the Commission that detail the final terms and conditions, including a copy of the final executed documents.
(k) Applications for tariff changes:
(i) The proposed tariff sheets shall be posted on the utility’s website and in offices and places of business in the territory affected when the proposed change is filed with the Commission. Approved tariff sheets shall be similarly posted for 30 days after their effective date;
(ii) Proposed tariff sheets shall be filed in clean and legislative formats. Legislative format shall indicate deleted material in strikeout and added material in underline. The version in legislative format shall not be part of the utility’s tariff.
(l) An electric utility shall file an application prior to making any commitment to join an energy market or a regional transmission organization.
Section 22. Construction Reports. Each utility issued a certificate of public convenience and necessity for a specific project or extension shall:
(a) Report the date construction will commence as soon as it is known, but no later than five business days prior to commencement;
(b) Submit monthly construction progress reports;
(c) Report the date construction was completed within 20 business days of completion; and
(d) Submit a report no later than 180 days following completion of construction that includes:
(i) Name of project;
(ii) Date in service;
(iii) Labor costs;
(iv) Material costs by general category;
(v) Administrative and general expenses;
(vi) Engineering costs; (vii) Right-of-way costs; (viii) Costs and rates used to calculate Allowance for Funds Used During Construction; (ix) Other costs for which the utility will seek recovery for in rates and how items (iii) through (vii) were accounted for in its books and records; (x) Proposed depreciation rates; (xi) Journal entries transferring the completed project from Construction Work in Progress to Utility Plant in Service by account number; (xii) For facility modifications, journal entries recording any plant retired and appropriate account numbers for utility plant and reserve for depreciation; (xiii) For facility modifications, journal entries recording any plant salvage values and decommissioning costs or sale of any plant retired; (xiv) Contact information for contractors that performed work; (xv) Conditions (terrain, location, weather, etc.) under which construction was performed; (xvi) Any non-standard facility feature; and (xvii) Completed project maps and engineering drawings, if changed from those previously submitted.
(a) All tariffs shall: (i) Be accompanied by a cover page stating the utility's name and the location of the utility's principal office; (ii) Include a table of contents; (iii) Describe the territory the utility serves; (iv) Include the applicable rate schedules, showing all rates and charges for the various separate classes of service and the utility's rules and regulations. All rates shall be clearly and explicitly stated in cents or dollars and cents per defined unit;
(v) Separately identify each rate schedule where more than one rate schedule is available for various classes of service;
(vi) State the area, city or other district in which the rate schedules and charges apply;
(vii) Be available for public inspection during regular office hours;
(viii) Identify the P.S.C. Wyo. Number of the tariff for electric, gas and water utilities. Subsequent tariffs filed shall continue such designation in consecutive numerical order. Utilities shall file an entire set of tariff sheets that includes rates, rules and regulations, designating a subsequent P.S.C. Wyo. Number with each general rate case. Further designation, such as “Original Sheet No. 1,” “Original Sheet No. 2,” “First Revision of Original Sheet No. 1, canceling Original Sheet No. 1” etc., shall also be included when applicable. At the bottom of the page shall be shown the date of issue, the effective date of each page, the name and title of the issuing officer, agent or employee; and
(ix) Include a summary sheet of all authorized rates for each class of service for electric, gas and water utilities. The summary sheet shall provide references to each rate’s detail sheet.
(b) Intrastate pipelines shall also:
(i) Identify the P.S.C. Wyo. Number of the tariff;
(ii) File a cover page that:
(A) Includes the name of the intrastate pipeline;
(B) Describes the territory, points and routes covered by the tariff;
(C) Specifies the commodities to which the rates apply; and
(D) Specifies whether the rates are:
(I) Local;
(II) Joint;
(III) Proportional; or
(IV) Class, commodity or both.
(a) Any entity, including receivers or trustees, proposing to acquire all or partial ownership or control of a utility, must adopt the tariff of the predecessor utility on file with the Commission and effective at the time of transfer. The transferee shall issue and file an adoption notice within 10 days of the transfer, ratifying the former utility's tariff.
(b) Within 10 days after filing an adoption notice, the transferee utility, including receivers or trustees, shall issue and file in its own name the tariff of its predecessor or its proposed revised tariff.
(a) If a utility intends to retire a Coal Fired Electric Generation Facility and seeks approval of the process required to demonstrate a good faith effort to sell the Coal Fired Electric Generation Facility, the utility shall file an application, not less than twenty-four months prior to retirement, that includes:
(i) A proposed solicitation process for retaining an Independent Evaluator, including;
(A) A description of the Coal Fired Electric Generation Facility that has been identified for retirement, its operating specifications and any associated property or property interests included in the offer of sale;
(B) The utility’s most recent integrated resource plan, including any updates or supplemental filings, demonstrating that:
(I) Retiring the Coal Fired Electric Generation Facility is consistent with the utility’s obligation to obtain the least cost, least risk resources on behalf of customers;
(II) The Present Value Revenue Requirement impact to customers assuming that the Coal Fired Electric Generation Facility is retired and, conversely, the same analysis if the Coal Fired Electric Generation Facility is sold to a third party and the utility continues to purchase the output of the Coal Fired Electric Generation Facility under a power purchase agreement; and
(III) A demonstration that retirement of the Coal Fired Electric Generation Facility will not adversely impact the reliability of service or availability of resources used to serve Wyoming customers. Such a demonstration shall account for regional as well as local reliability impacts that result from the proposed retirement of the Coal Fired Electric Generation Facility.
(C) A draft request for proposal to retain Independent Evaluator services;
(D) The required minimum qualifications and deliverables for an Independent Evaluator;
(E) The estimated cost of obtaining Independent Evaluator services; and
(F) A draft contract including the proposed terms and conditions under which the Independent Evaluator will operate.
(ii) A proposed solicitation process for the sale of a Coal Fired Electric Generation Facility, including:
(A) The proposed solicitation for the sale of a Coal Fired Electric Generation Facility with appendices, attachments and a proposed asset purchase and sale agreement;
(B) A description of the Coal Fired Electric Generation Facility that has been identified for retirement, its operating specifications and any associated property or property interests included in the offer of sale;
(C) A current accounting of the utility’s reserve for decommissioning and retiring the Coal Fired Electric Generation Facility and remediating the facility site, along with the utility’s most current estimate of the actual net cost of decommissioning the facility and remediating its site;
(D) A detailed accounting of any known environmental compliance obligations under state or federal law that will or could impact the continued operation of the Coal Fired Electric Generation Facility or its retirement in the future, and an estimate of the cost to comply with such environmental obligations;
(E) A proposed schedule for solicitation, including:
(I) Issuance of request for proposals;
(II) Bid due dates; and
(III) A date when the utility will provide an initial short-list of qualified bidders eligible for more detailed negotiations.
(F) The contact information and/or website for questions and answers on the Coal Fired Electric Generation Facility solicitation process and review;
(G) A detailed plan describing how the utility will solicit prospective purchasers for the Coal Fired Electric Generation Facility, including a list of potentially interested parties and publications to whom the utility will send notices of the solicitation;
(H) A description of the process for prospective purchasers to obtain due diligence information and, if the Coal Fired Electric Generation Facility is not wholly owned and operated by the utility, a description of the other entities that own or operate a portion of the Coal Fired Electric Generation Facility, a copy of any agreements between the utility and the other entities that own or operate a portion of the facility, and a description of any consents, approvals, or votes by other owners that would be required to finalize a sale of the facility;
(J) For Coal Fired Electric Generation Facilities where the public utility will continue to own and operate one or more units, the proposed contractual terms and conditions for sharing of costs associated with joint or common facilities and any restrictions or requirements that may arise from the sale and assignment of the utility’s share in that jointly owned facility;
(K) A proposed power purchase agreement, and a calculation of the proposed avoided cost, pursuant to subsection (c);
(L) A proposed form agreement with terms and conditions pursuant to which the utility would sell electricity on the prospective purchaser’s behalf to an Eligible Retail Customer;
(M) The proposed terms and conditions for environmental remediation, liabilities and related financial security;
(N) The proposed terms and conditions for any non-environmental liabilities that are related to the sale of the Coal Fired Electric Generation Facility;
(O) A list of the local, state, or federal permits known to the utility to be necessary for the purchaser to own and operate the Coal Fired Electric Generation Facility; and
(P) A list of criteria to be used by the utility for screening and ranking of bids, including:
(I) Requirements for prospective purchasers to demonstrate it has, or has contracted for, financial, technical and managerial abilities sufficient to reasonably:
(1.) Operate and maintain the Coal Fired Electric Generation Facility, including disclosure of any fines, violations and/or citations issued to the prospective purchaser from any regulated entity for any of its operations within a previous five years;
(2.) Decommission and retire the Coal Fired Electric Generation Facility once it ceases operation; and
(3.) Satisfy any environmental obligations to operate and maintain and, if necessary, retire the Coal Fired Electric Generation Facility.
(II) Requirements for prospective purchasers to demonstrate financial ability by providing:
(1.) A complete corporate family tree, disclosing parent and/or subsidiary entities of the prospective purchaser and indicating if the prospective purchaser is liable for any debts of related entities; and
(2.) Complete audited financial statements and tax returns for previous five years, if available, for the prospective purchaser and any parent or subsidiary entities whose credit is being offered by the prospective purchaser to satisfy any financial commitment or obligation associated with the purchase.
(i) The Commission shall issue public notice of the utility's proposed Independent Evaluator solicitation and establish timelines for public comment and Commission approval of the Independent Evaluator solicitation.
(ii) When the notice process has concluded, the utility shall issue the Commission approved Independent Evaluator solicitation.
(iii) Following the deadline for submittal of bids, the utility shall submit bids it receives from prospective Independent Evaluators in response to the Commission approved Independent Evaluator solicitation along with the utility's rankings. The Commission and intervenors shall submit analysis and comment on bids received from prospective Independent Evaluators.
(iv) The Commission shall select an Independent Evaluator. Upon selection:
(A) The utility shall engage the services of the Independent Evaluator and pay all fees and expenses associated with engaging the Independent Evaluator's services.
(B) The utility may seek recovery of the cost billed to it by the Independent Evaluator. The utility may seek to defer such costs for later recovery in a general rate case filing or propose other methods to recover the cost of the Independent Evaluator, subject to Commission approval.
(i) The Commission shall determine the avoided costs to set a maximum price for any proposed sale of energy and capacity from a Coal Fired Electric Generation Facility.
(ii) The Commission shall issue public notice of the utility's proposed avoided cost and establish timelines for public comment and Commission determination.
(iii) The following factors shall be considered as relevant when determining avoided costs for any proposed sale of energy and capacity from a Coal Fired Electric Generation Facility:
(A) The value of energy and capacity generated by the Coal Fired Electric Generation Facility, which may include:
(I) The usefulness of energy and capacity supplied from the facility during system emergencies, including its ability to separate its load from its generation;
(II) The value of energy and capacity from the facility to the utility’s system; and
(III) The capacity increments and the lead times available with the addition of capacity from the facility.
(B) The value of the Coal Fired Electric Generation Facility’s reliability benefits, which may include:
(I) The value of existing coal stockpiles at the facility;
(II) The ability of the facility to meet National Electric Reliability Corporation Blackstart Standards;
(III) The value of the facility in providing resilience to the grid in modeled weather and cyber events; and
(1.) The ability to avoid the need to add or accelerate other energy resources to cure shortfalls and meet reliability requirements; and
(2.) Transmission system reliability impacts, to the extent they can be reasonably estimated.
(C) And any other factor the Commission deems appropriate, which may include:
(I) The terms of the proposed power purchase agreement, including the duration of the obligation, termination notice requirement and sanctions for failure to perform;
(II) The lost opportunity costs and long-term pricing risks to customers based on the proposed term length for the utility’s purchase from the facility;
(III) The extent to which scheduled outages of the facility can be coordinated with scheduled outages of the utility’s facilities; and
(IV) The costs or savings resulting from variations in line losses, if measurable, from those that would exist in the absence of purchases from the facility.
(d) Coal Unit Solicitation
(i) The Commission shall issue public notice of the utility’s proposed Coal
Fired Electric Generation Facility solicitation and establish timelines for public comment and Commission approval of the Coal Fired Electric Generation Facility solicitation.
(ii) The Independent Evaluator shall:
(A) Oversee the Coal Fired Electric Generation Facility solicitation bid process to ensure it is conducted fairly, including that prospective purchasers are provided sufficient and timely access to financial information, operating data, site visits, management team members and other resources to make evaluations;
(B) Be available and responsive to the Commission throughout the Coal Fired Electric Generation Facility solicitation process; and
(C) Provide consultation and guidance to the utility as the Coal Fired Electric Generation Facility solicitation is conducted.
(iii) The utility shall issue the Commission approved Coal Fired Electric Generation Facility solicitation requesting sealed bids from prospective purchasers of the Coal Fired Electric Generation Facility.
(A) A bidders' conference, hosted by the utility, and attended by the Independent Evaluator, shall be held prior to the issuance of the Commission approved Coal Fired Electric Generation Facility solicitation.
(B) The deadline for submitting bids to acquire the Coal Fired Electric Generation Facility shall be no more than ninety days following the issuance of the Coal Fired Electric Generation Facility solicitation.
(iv) Upon receipt of offers to purchase the Coal Fired Electric Generation Facility, the utility, in the presence of the Independent Evaluator, shall unseal the bids and, in coordination with the Independent Evaluator, conduct a preliminary analysis of the bids received to determine compliance with the bid specifications.
(v) The utility shall, in consultation with the Independent Evaluator, select a winning bidder, if any. If a winning bidder is selected, the utility shall file an application pursuant to Section 21(h)(ii) within 30 days of the conclusion of the solicitation process. If there is no winning bidder, the utility shall file an application pursuant to Section 21(h)(i) within 30 days of the conclusion of the solicitation process.
(vi) The Independent Evaluator shall independently evaluate all bids, submit an analysis of the utility's scoring of the bids received and make a recommendation on whether the utility's selection for a winning bid, if any, was reasonable. If the Independent Evaluator determines that the utility's actions are unreasonable, the Independent Evaluator shall file a report within 30 days of the conclusion of the solicitation process explaining the findings and conclusions.
(vii) The Commission and interested parties may submit analysis and comment on bids received from prospective purchasers.
(viii) The Commission shall approve the utility’s selection of the successful bid, if any.
(a) Utilities may file an application to pass on known or projected commodity or commodity-related cost increases or decreases per tariff.
(i) Pass-on applications may be approved, subject to public notice, opportunity for hearing and refund, if the evidence shows recovery of the costs is in the public interest and the pass-on includes only prudent commodity or commodity-related cost increases or decreases not under the Commission’s jurisdiction.
(ii) Pass-on applications shall:
(A) Be filed at least annually and shall at least annually include documentation comparing the utility’s actual and normalized annual earnings to those last authorized by the Commission. The appropriate form and level of detail of the required supporting documentation shall be determined by the Commission on a case-by-case basis in consideration of the utility’s size, complexity, nature of operations, corporate structure and other relevant factors;
(B) Provide documentation demonstrating that costs included in the application are the most reasonable option available to the utility for safe, adequate and reliable service. Utilities may file integrated resource plans or commodity acquisition plans for Commission review. After Commission acknowledgement, these plans may satisfy this requirement for pass-on applications; and
(C) Include all information necessary to support the requested rates.
(iii) Pass-on increases or decreases shall be allocated to all retail rate classes and contract customers on an equal or proportionate basis. The Commission may consider special proportionate class allocation if requested.
(iv) Pass-on rates may be consolidated with base rates in general rate case proceedings or as otherwise ordered by the Commission.
(b) A utility may file an application to establish a CBA tariff mechanism to account for the difference between commodity or commodity-related revenues collected, based on projected wholesale costs, and the actual, prudent commodity or commodity-related expenditures the utility incurred. The utility may apply to the Commission for approval to include other costs and revenues in the CBA. Records related to the CBA shall be available for audit by the Commission at any time.
(i) Interest shall be paid on over-collected balances. Interest may be collected on under-collected balances upon a showing that it is in the public interest. Interest shall be computed at the Commission Authorized Interest Rate.
(ii) The CBA tariff shall describe in detail how the utility accounts for the components of the CBA, including:
(A) The frequency of rate adjustments to reflect cost changes;
(B) The planned method, supporting basis and time period for projecting commodity or commodity-related costs;
(C) The procedure and recordkeeping measures for tracking the difference between commodity-related revenues and expenditures;
(D) The time period for amortizing the balance of any over- or under-collection;
(E) The procedure for calculating increases or decreases in commodity or commodity-related purchases, using a measurement unit consistent with the utility’s billing practices and tariff provisions;
(F) The procedure for calculating and paying interest on over-collected balances and, if authorized, the procedure for calculating and collecting interest on under-collected balances; and
(G) The procedure and recordkeeping measures for tracking other expenditures authorized by the Commission to be included in the CBA.
(c) Utilities may apply for out-of-period adjustments.
(a) Reportable incidents that will or are likely to produce significant detrimental effects to customers, facilities or public safety shall be reported to the Commission within two hours of the incident by contacting the Commission’s Service Interruption Reporting Telephone (SIRT) number.
(b) A reportable incident is:
(i) An event that causes loss to the operator or others and results in:
(A) Estimated property damage of at least $20,000 for water utilities; or (B) Estimated property damage of at least $50,000 for all other utilities.
(ii) An event that results in death, in-patient hospitalization, damage to the property of the utility which substantially affects service to the public or is otherwise significant in the judgment of the operator or utility.
(c) Additional reportable incidents for electric utilities:
(i) Sustained single feeder outages of two hours or longer to 500 or 50% of customers, whichever is fewer or as modified in the utility’s Service Interruption Reporting Plan;
(ii) Single feeder outages to 25 or more customers for a period estimated to last eight hours or more.
(d) Additional reportable incidents for natural gas utilities:
(i) Any incident reportable to the National Response Center:
(A) An event that involves a release of gas from a pipeline, or of liquefied natural gas, liquefied petroleum gas, refrigerant gas or gas from an LNG facility, and that results in one or more of the following:
(I) A death, or personal injury necessitating in-patient hospitalization;
(II) Estimated property damage of $50,000 or more, including loss to the operator and others, or both, but excluding cost of gas lost; or
(III) Unintentional estimated gas loss of three million cubic feet or more.
(B) An event that results in an emergency shutdown of an LNG facility. Activation of an emergency shutdown system for reasons other than an actual emergency does not constitute an incident.
(ii) Any service interruption, planned or otherwise occurring, that results in:
(A) Loss of service to 25 gas meters or customers, whichever is greater;
(B) An evacuation that displaces 25 people or more.
(e) Additional reportable incidents for water utilities:
(i) An interruption of water service to the utility’s entire system;
(ii) A loss of service to 10% or more of the taps for eight hours or more.
(f) A utility shall follow up any reportable incident or incident reported to the SIRT with an email report within 24 hours of the initial SIRT notification or as otherwise directed by the Commission. Reports to the Commission shall include, but not be limited to:
(i) Location and geographic extent;
(ii) Damage assessment, explaining the risks and likely effects on the public, the utility’s customers, other utilities and telecommunications services;
(iii) Date and time the service interruption began;
(iv) Number of customers or individuals affected;
(v) Cause, if known;
(vi) Estimated time of service restoration and basis for estimate;
(vii) Any deaths or injuries;
(viii) Efforts being undertaken to restore service;
(ix) Efforts being undertaken to assist affected individuals;
(x) Other governmental agencies notified;
(xi) Contact information for reporting individual(s);
(xii) If the event is ongoing, the time interval until the Commission will be updated; and
(xiii) Any other information that may be necessary to assess threats or damage.
(a) Each utility shall report within 30 days after the end of each calendar quarter the following service interruptions, planned or otherwise:
(i) Electric utilities: all service interruptions greater than five minutes, other than meter testing or change outs;
(ii) Natural gas utilities: all service interruptions, other than meter testing or change outs;
(iii) Water utilities: all service interruptions that result in the loss of service to five or more customers or water meters, whichever is greater.
(b) These records shall be retained by the utility for a minimum of six years.
(c) Each electric utility shall annually review its Service Interruption Reporting Plan. If there are proposed modifications and definitions of major and minor service interruptions specific to the utility's system, the revised Service Interruption Reporting Plan shall be filed with the Commission by May 1. If, after the utility's review, there is no change to the Service Interruption Reporting Plan, the utility shall so notify the Commission by letter by May 1.
Section 29. Filing of Standard Forms. Each utility shall provide the Commission with copies of its billing and collection forms, including statements, past due notices, disconnect notices, door hangers, payment agreements, guarantor agreements and non-assignable certificates of deposit or receipts. When the utility prepares new forms or makes significant changes to existing forms, the utility shall provide the Commission with a copy of the new or updated forms upon completion.
Section 30. Gas Utility Quarterly Reports. Gas utilities shall quarterly report, using forms provided by the Commission:
(a) The weighted mean monthly heating value of gas supplied to each distinguishable distribution area during the quarter, including the Wobbe Index.
(b) Gas leaks.
Section 31. Filing Special Contracts. Each utility shall file all special contracts governing the utility's sale of utility service or purchase of the commodity for resale. If a utility has numerous similar sale or purchase contracts, it may request to file one or a few representative special contracts in lieu of filing all such contracts.
Section 32. Annual Reports. Each utility shall file on or before May 1st of each year an annual report for the preceding calendar year in the form prescribed by the Commission. All annual reports shall be signed by the officer, manager or agent of the utility under whose direction the annual report is prepared.
Section 33. Reserved.
Section 34. Succession Plans. The Commission may require a utility to file a Succession Plan.
Section 35. Arrangements between Electric Utilities and Qualifying Cogeneration and
Small Power Production Facilities. All electric utilities shall fully comply with this section; sections 201 and 210 of the Public Utilities Regulatory Policies Act of 1978, PL 95-617 (PURPA) and Part 292, 18 CFR Ch. I (4-1-13 edition).
(a) Filing of purchase, sale rates and contracts.
(i) All regulations, tariffs and contracts governing sales and purchases between qualifying facilities and utilities shall be filed with the Commission.
(ii) Nothing in these Rules:
(A) Limits any utility and qualifying facility from entering into a contract relating to any purchase or sale; or
(B) Affects the validity of any existing contract between any utility and qualifying facility for any purchase or sale.
(b) Any utility with sales other than resale greater than 500 million kilowatt-hours during any calendar year and legally obligated to obtain all its energy and capacity requirements from another entity shall provide, upon request, system cost data of the utility's supplying entity, including the rates at which the utility currently purchases such energy and capacity. If any utility fails to provide such information on request, the qualifying facility may apply to the Commission for an order requiring that the information be provided.
(c) Unless exempted under Paragraph (iii) of this Subsection, each electric utility shall file for approval by the Commission a method for determination of avoided costs, after public notice and opportunity for hearing.
(i) System cost data from which avoided costs may be derived shall be filed with the Commission not less than every two years or as otherwise ordered. The filing shall contain:
(A) The estimated avoided energy cost stated in blocks of not more than 100 megawatts for systems with peak demand of 1,000 megawatts or more, and in blocks equivalent to not more than 10% of the system peak demand for systems of less than 1000 megawatts. The avoided costs shall be stated on a cents per kilowatt-hour basis, during daily and seasonal peak and off-peak periods for each of the next five years;
(B) The utility's plan for the additions, acquisitions and retirements of capacity and energy by amount and source, for each of the next 10 years; and
(C) The estimated capacity costs at completion of the planned capacity additions and planned capacity firm purchases, expressed in dollars per kilowatt, and the associated energy costs of each unit, expressed in cents per kilowatt-hour. These costs shall be itemized by generating units and planned firm purchases.
(ii) The following factors shall be considered when determining avoided costs:
(A) The utility’s resource needs, as set forth in its long range planning process;
(B) The availability of capacity or energy from a qualifying facility during the system daily and seasonal peak periods, including:
(I) The ability of the utility to dispatch the qualifying facility;
(II) The expected or demonstrated reliability of the qualifying facility;
(III) The terms of any legally enforceable obligation, including the duration of the obligation, termination notice requirement and sanctions for non-compliance;
(IV) The extent to which scheduled outages of the qualifying facility can be coordinated with scheduled outages of the utility’s facilities;
(V) The usefulness of energy and capacity supplied from a qualifying facility during system emergencies, including its ability to separate its load from its generation;
(VI) The individual and aggregate value of energy and capacity from qualifying facilities on the utility’s system;
(VII) The capacity increments and the lead times available with addition of capacity from qualifying facilities;
(VIII) The ability of the utility to avoid costs; and
(IX) The costs or savings resulting from variations in line losses, if measurable, from those that would exist in the absence of purchases from a qualifying facility.
(iii) A cooperative that is an all-requirements power supply customer of a generation and transmission cooperative or other wholesale power supplier shall inform the Commission of a change to its avoided cost rate at least 30 days before the effective date of such change, or within 15 days of the cooperative’s receipt of notice if less than 45 days’ notice is provided to the cooperative, by filing a copy thereof and a revised rate sheet indicating the cooperative’s revised avoided cost rate and its effective date. Cooperatives complying with this paragraph shall not be required to file an application for approval unless ordered to do so by the
Commission.
(d) Utility purchase and sale obligations.
(i) Each utility shall sell to any qualifying facility any energy and capacity requested by the qualifying facility at the applicable tariff rates.
(ii) Each utility shall make interconnections with any qualifying facility as necessary to accomplish purchases or sales under these Rules. The obligation to pay for any interconnection costs shall be determined in accordance with subsection (l) below.
(e) Rates for purchases. For purposes of this subsection, “new capacity” means any purchase of capacity from a qualifying facility for which construction was commenced on or after November 9, 1978.
(i) Purchase rates shall be just and reasonable to the electric consumer and in the public interest. A purchase rate for purchases of new capacity satisfies the requirements if the rate equals the avoided costs determined after consideration of the factors set forth in subsection (c)(ii) above.
(ii) Nothing in this subsection requires any electric utility to pay more than the avoided costs for purchases.
(iii) The relationship to avoided costs shall be:
(A) A purchase rate (other than from new capacity) may be less than the avoided cost if the Commission determines that a lower rate is consistent with this subsection and is sufficient to encourage cogeneration and small power production.
(B) If rates for purchases are based upon estimates of avoided costs over a specific term of a contract or other legally enforceable obligation, the rates do not violate this subsection if the rates differ from avoided costs at the time of delivery.
(f) Standard rates for purchases.
(i) Each utility shall have standard rates for purchases from qualifying facilities with a design capacity of 100 kilowatts or less.
(ii) There may be standard rates for purchases from qualifying facilities with a design capacity of more than 100 kilowatts.
(iii) The standard rates for purchases under this subsection:
(A) Shall be consistent with subsections (e) and (c)(ii); and
(B) May differentiate among qualifying facilities using various technologies on the basis of the supply characteristics.
(g) Each qualifying facility shall provide:
(i) Energy as the qualifying facility determines it to be available for purchase, in which case the rates for the purchases shall be based on the purchasing utility’s avoided costs calculated at the time of delivery; or
(ii) Energy only or energy and capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term, in which case the rates for such purchases shall, at the option of the qualifying facility exercised prior to the beginning of the specified term, be based on either:
(A) The avoided costs calculated at the time of delivery; or
(B) The projected avoided costs calculated at the time the obligation is incurred.
(h) Procedures for periods during which purchases are not required.
(i) Any utility which gives notice pursuant to subsection (h)(ii) will not be required to purchase energy or capacity during any period in which, due to operational circumstances, purchases from qualifying facilities will result in costs greater than those the utility would incur if it generated an equivalent amount of energy itself.
(ii) Any utility seeking to invoke subsection (h)(i) shall provide adequate notice to cogenerators and qualifying facilities in order to allow time for their operational response. Any utility failing to do so will be required to pay the equivalent purchase of energy or capacity as would have been required had the period described in subsection (h)(i) not occurred.
(iii) The utility shall advise the Commission in advance or as soon thereafter as practicable after the event occurred.
(iv) The utility shall file with the Commission a power cost financial impact analysis within 60 days of the end of the event.
(j) Additional services shall be provided to qualifying facilities pursuant to the electric utility’s applicable tariffs:
(i) Upon request of a qualifying facility, each utility shall provide:
(A) Supplementary power;
(B) Back-up power;
(C) Maintenance power; and
(D) Interruptible power.
(ii) The Commission may waive any requirement of subsection (j)(i) if, after notice and opportunity for hearing, the Commission finds that compliance with such requirement will:
(A) Impair the utility’s ability to render adequate service to its customers; or
(B) Place an undue burden on the utility.
(k) The rate for sales of back-up power or maintenance power shall:
(i) Not be based upon an assumption (unless supported by factual data) that forced outages or other reductions in electric output by all qualifying facilities on a utility’s system will occur simultaneously and/or during the system peak; and
(ii) Take into account the extent to which scheduled outages of the qualifying facilities can be usefully coordinated with scheduled outages of the utility’s facilities.
(l) Interconnection costs.
(i) Each qualifying facility shall be obligated to pay any interconnection costs which the Commission authorizes the utility to collect from the facility, under the utility’s interconnection tariff, on a nondiscriminatory basis; and
(ii) Any reimbursement by the utility to the qualifying facility will be made in accordance with the utility’s interconnection tariff.
(m) A qualifying facility shall be required to provide energy or capacity to a utility during a system emergency only to the extent:
(i) Provided by agreement between such qualifying facility and utility;
(ii) Ordered by the Commission; or
(iii) Ordered under section 202(c) of the Federal Power Act.
(n) During any system emergency, a utility may discontinue purchases and sales when:
(i) Purchases from a qualifying facility would contribute to such emergency; and (ii) Sales to a qualifying facility are on a nondiscriminatory basis.
(o) Each utility shall promulgate rules and regulations for the interconnection of qualified facilities that address:
(i) Avoidance of unintentional continued energization of a circuit when the utility source of energy to the circuit has been disconnected, when a fault occurs on the utility circuit and when one phase of a three-phase line is lost to the interconnection;
(ii) Instantaneous (flicker) and long-term voltage regulation;
(iii) Frequency stability, harmonic suppression (wave form) and synchronization of units to the utility system;
(iv) The number, individual size and total capacity of units connected to a given circuit and the upgrading of circuits to accommodate more units;
(v) Reactive power requirements at each interconnection to a unit;
(vi) Circulating currents in delta-connected transformers;
(vii) Duplication of interconnection equipment;
(viii) Liability for damages to the utility system and equipment, to the facilities and equipment of the customers and to any other person who may be affected by the presence and operation of such units; and
(ix) The manner in which cost for accommodating such generation will be recovered.
(a) The direct sale of a utility commodity by a person without a certificate of public convenience and necessity is prohibited.
(b) A direct sale of a utility commodity takes place if a person separately charges tenants or other persons for a utility commodity.
(c) This Rule does not apply to:
(i) The provision of utility commodities in connection with the leasing or rental of facilities for less than 15 days' occupancy; or
(ii) Otherwise exempt pursuant to W.S. § 37-1-101(a)(vi)(H).
(a) A rate-regulated cooperative utility may file an expedited rate change application on an emergency basis to maintain minimum cash flow requirements.
(i) The application shall demonstrate that cash flow requirements are not being met under current authorized rates. The requested revenue increase may be no greater than that necessary to meet its minimum cash flow requirements on a normalized basis.
(ii) The application shall, at a minimum, include:
(G) An exhibit illustrating the current financial condition, normalizing adjustments, the additional revenues anticipated as a result of the proposed rate increase and the resulting normalized revenue requirement calculation;
(H) Exhibits which clearly illustrate the calculation of applicable financial parameters under both the existing and proposed rates and a demonstration of the minimum cash flow requirements; and
(J) An exhibit illustrating the proposed allocation of rate changes to each customer class.
(b) Each cooperative utility shall maintain accounting records in accordance with the requirements of the RUS.
(a) Each electric utility subject to the provisions of W.S. § 37-18-102 shall file an initial application to establish intermediate standards and requirements by March 31, 2022. The initial application shall include, at a minimum, the following:
(i) An analysis of carbon capture, utilization and storage suitability of a utility's
Coal Fired Electric Generation Facilities, owned in whole or in part with another utility or utilities subject to the provisions of W.S. § 37-18-102(a), that shall include:
(A) A description of the potential suitability of each Coal Fired Electric Generation Facility for carbon capture, utilization and storage technologies, including space requirements for the necessary equipment and other technical considerations that would support or limit implementation of any given technology for each unit;
(B) The proximity of each Coal Fired Electric Generation Facility to known sequestration locations, carbon dioxide transport pipelines, and oil fields potentially suitable for enhanced oil recovery or any other possible uses of carbon dioxide;
(C) Identification of all relevant environmental factors, including potentially applicable pollution control requirements, water availability, and a preliminary identification of all necessary permits with an estimated timeline for obtaining each permit;
(D) An estimate, on a unit basis, of the amount of annual electricity generated in megawatt-hours that would qualify as dispatchable and reliable low-carbon electricity if carbon capture, utilization and storage technology were installed;
(E) A description of the estimated impact, if any, on the operation of each unit from the installation of the carbon capture, utilization and storage technology identified as appropriate for that unit;
(F) The amount of electricity generated each year for the past five calendar years and the projected generation for the current year and each of the next two subsequent years for each unit;
(ii) A description of any public or private entities who have submitted proposals to the public utility, including pilot projects or other resources that may support the development of carbon capture, utilization and storage technology on the utility’s Coal Fired Electric Generation Facilities;
(iii) A description of any potential offsets or revenue streams, including but not limited to:
(A) Availability of any tax credits;
(B) Revenue from carbon dioxide sales; and
(C) Availability of grants.
(iv) Results of an economic analysis from the most recent integrated resource plan, or other comparable analysis, projecting the costs for equipping each unit in a utility’s Coal Fired Electric Generation Facility with any carbon capture, utilization and storage technology identified as potentially appropriate for that unit;
(v) A description of any rate recovery mechanism for incremental costs incurred to comply with the dispatchable and reliable low-carbon electricity generation standard, including:
(A) An estimate of the annual collection amount from each customer's total electric bill equal to the cap set forth in W.S. § 37-18-102(c)(iii); and
(B) Any proposal for a higher rate of return on equity.
(vi) Based on paragraphs (i) through (v) of this subsection, a utility shall establish and include in its application a plan to complete a technical analysis for carbon capture, utilization and storage technology identified to achieve the dispatchable and reliable low-carbon electricity generation standard. The plan shall include:
(A) Identification of specific unit or units at the utility's Coal Fired Electric Generation Facilities for which the utility will complete a technical analysis. The utility shall also identify any units it will not analyze and demonstrate why a technical analysis is not appropriate;
(B) A timeline and description of the technical analysis;
(C) Estimated incremental costs to complete the technical analysis and the proposed regulatory recovery method for any associated costs incurred to complete the analysis;
(D) An estimate of the generation at identified units and the associated projected costs in comparison to an energy portfolio standard set at twenty percent (20%), forty percent (40%), sixty percent (60%), and eighty percent (80%), in each case as a percentage of the utility's Wyoming load under the following scenarios;
(I) The utility's actual retail sales in kilowatt-hours in Wyoming during calendar year 2021; and
(II) A forecast of the utility's retail sales in kilowatt-hours in Wyoming for calendar years 2021 through 2030.
(E) An estimate of the highest economically feasible energy portfolio standard and identified units to meet that standard.
(vii) Any other information the Commission deems appropriate.
(b) After the initial application, each utility shall file an application providing updates to its plan annually no later than March 31. The updates shall include, where applicable:
(i) A report of all steps taken in the past calendar year to implement its plan;
(ii) A description and support for any material changes to the information required in sections (a)(i) through (iv) above;
(iii) An updated analysis for the energy portfolio standards set forth in subsection (a)(vi)(D) above; and
(iv) Any proposed amendments to the plan.
(c) No later than March 31, 2023, the utility will submit for Commission approval a final plan with its proposed energy portfolio standard for dispatchable and reliable low-carbon electricity, its plan for achieving the standard, and a target date of no later than July 1, 2033.
(i) The final plan shall, at a minimum, include:
(A) A summary, results, and supporting workpapers for technical analysis completed and approved in the initial application in paragraph (a)(vi) along with any updates;
(B) The utility’s estimation of the highest economically feasible energy portfolio standard in accordance with W.S. § 37-18-102(c)(iii); and
(C) In no case shall a portfolio standard be set at less than twenty percent (20%) of retail Wyoming sales for an identified calendar year unless the utility establishes by clear and convincing evidence that a minimum twenty percent (20%) standard is not economically or technically feasible.
(d) No application under subsection (a) of this Rule is required for any unit in a Coal Fired Electric Generation Facility where a utility subject to this Commission’s jurisdiction has a part-ownership interest in the facility with another utility or utilities, one or more of which is not subject to the Commission’s jurisdiction pursuant to W.S. § 37-1-101. If the ownership of a unit changes so that all owners are subject to Commission jurisdiction pursuant to W.S. § 37-1-101, the utility or utilities shall file a joint application as required by subsection (a)(vi) within ninety (90) days of the change in ownership.
(e) Each utility subject to the provisions of W.S. § 37-18-102(a) shall file a report annually by June 1 providing its Electric Reliability and Power Quality outcomes and describing the steps taken to determine the market for carbon dioxide from the electric generation.
(i) The initial report shall establish the utility’s baseline standard for Electric Reliability. Subsequent annual reports shall update the baseline standard.
(ii) In its discretion, the Commission may require a utility, after notice and opportunity for a hearing, to take any reasonably necessary steps to maintain reasonable levels of Electric Reliability and Power Quality.
(a) Any utility having knowledge of a direct or indirect provision of service by one utility for use in any other utility’s territory without authority shall promptly notify the Commission. Upon receipt of a Notification, Complaint, or other information indicating such unauthorized service, the Commission may:
(i) Upon request of either utility or affected customer subject to the disclosure in (a) defer action on the notification for a reasonable period to allow the utilities and affected customers an opportunity to resolve the matter by agreement. Any agreement reached under this subsection shall be subject to Commission approval.
(ii) Require either utility or the customer to install a meter at the territorial boundary, to be paid for, owned and operated as determined by the Commission after notice and opportunity for hearing, so that the quantity of energy (and demand) delivered is known from the time of installation;
(iii) After notice and opportunity for hearing, require payments between the utilities and/or additional payment by the customer involved. Payments may be either one-time or ongoing as determined by the Commission;
(iv) After notice and opportunity for hearing, take any other action that the public interest may require, including, but not limited to, revising the boundaries of Certificates of Public Convenience and Necessity.