Tariff

The Cooperative will review the rate classification and assignments annually to determine if the customer is being billed on the correct rate schedule for their type of service and usage. The Cooperative may change the rate classification and assignment of a customer to properly insure the application of each rate.

Effective January 1, 2017

A. Application

Applicable to Customers with a peak demand of less than 50 kW for the twelve month period ending with the current billing period taking electric service supplied at one point of delivery and measured through one meter used for residential, farming and ranching, and small commercial uses.

B. Type of Service

Single- or three- phase service at the Cooperative’s standard secondary distribution voltages, where available. Where service of the type desired by Customer is not already available at the point of delivery, additional charges under the Cooperative’s line extension policy and special contract arrangements may be required prior to service being furnished.

C. Monthly Rate

Each billing period the Customer shall be obligated to pay the following charges:

Service Availability Charge: $29
All kWh, per kWh: $0.109

D. Monthly Minimum Charge

The minimum monthly bill shall be the greater of the following:

1. Each billing period the Customer shall be obligated to pay the Service Availability Charge, whether or not any energy is actually used.
2. The amount stated in the Agreement for Electric Service.
3. $1.00 per kVa of installed transformer capacity.

E. Billing Adjustments

This rate is subject to all billing adjustments.

F. Agreement

An agreement for electric service with a fixed term may be required by the Cooperative. This rate schedule may be changed by order or consent of regulatory authorities having jurisdiction, or, if none, by the Cooperative’s Board of Directors. Service hereunder is subject to the Cooperative’s tariffs and rules and regulations for electric service.

Effective January 1, 2017

A. Application

Applicable to customers who install a cooperative approved electric thermal storage (ETS) system taking electric service supplied at one point of delivery and measured through one meter used for residential, farming and ranching, and commercial uses. An electric thermal storage system is defined as a primary source space heating system, which utilizes off-peak electricity to heat a storage medium (ceramic bricks, water, etc.) whereby stored heat is released during on-peak hours (includes ETS and geothermal storage). After January 1, 2013, the General Service Time-Of-Use rate is available only to ETS installations approved prior to December 31, 2012.

B. Type of Service

Single- or three- phase service at the Cooperative’s standard secondary distribution voltages, where available. Where service of the type desired by Customer is not already available at the point of delivery, additional charges under the Cooperative’s line extension policy and special contract arrangements may be required prior to service being furnished.

C. Monthly Rate

Each billing period the Customer shall be obligated to pay the following charges:

Service Availability Charge: $29
On-Peak kWh, per kWh: $0.109
Off-Peak kWh, per kWh: $0.056 z

D. Off-Peak, On-Peak kWh

Off-Peak, On-Peak hours will be the time generally established by Tri-State Generation and Transmission Association.

January thru December:
Off Peak 10:00 p.m. to 3:00 p.m.
On Peak 3:00 p.m. to 10:00 p.m.

The Cooperative reserves the right to change selected off-peak hours.

E. Monthly Minimum Charge

The minimum monthly bill shall be the greater of the following:

1. Each billing period the Customer shall be obligated to pay the Service Availability Charge as a minimum, whether or not any energy is actually used.
2. The amount stated in the Agreement for Electric Service.
3. $1.00 per kVa of installed transformer capacity.

F. Billing Adjustments

This rate is subject to all billing adjustments.

G. Agreement

An agreement for electric service with a fixed term may be required by the Cooperative. This rate schedule may be changed by order or consent of regulatory authorities having jurisdiction, or, if none, by the Cooperative’s Board of Directors. Service hereunder is subject to the Cooperative’s tariffs and rules and regulations for electric service.

Effective January 1, 2017

A. Application

Applicable to Customers with a peak demand of more than 25 kW but less than 50 kW for the twelve month period ending with the current billing period taking electric service supplied at one point of delivery and measured through one meter used for commercial uses.

B. Type of Service

Single- or three- phase service at the Cooperative’s standard secondary distribution voltages, where available. Where service of the type desired by Customer is not already available at the point of delivery, additional charges under the Cooperative’s line extension policy and special contract arrangements may be required prior to service being furnished.

C. Monthly Rate

Each billing period the Customer shall be obligated to pay the following charges:

Service Availability Charge: $50
Demand Charge, per billing kW: $5.45
1st 300 kWh per billing kW, per kWh: $0.087
Over 300 kWh per billing kW, per kWh: $0.077

D. Billing Demand

The billing demand shall be the maximum kilowatt (kW) demand established by the consumer for any period of fifteen (15) consecutive minutes during the month for which the bill is rendered, as indicated or recorded by a demand meter and adjusted for power factor.

E. Monthly Minimum Charge

The minimum monthly bill shall be the greater of the following:

1. The Service Availability Charge plus the Demand Charge.
2. $1.00 per kVa of installed transformer capacity.
3. The amount stated in the agreement for electric service.

F. Billing Adjustments

This rate is subject to all billing adjustments.

G. Agreement

An agreement for electric service with a fixed term may be required by the Cooperative. This rate schedule may be changed by order or consent of regulatory authorities having jurisdiction, or, if none, by the Cooperative’s Board of Directors. Service hereunder is subject to the Cooperative’s tariffs and rules and regulations for electric service.

A. Application

Applicable to Customers with a peak demand of 50 kW or greater for the twelve month period ending with the current billing period taking electric service supplied at one point of delivery and measured through one meter used for commercial and industrial uses.

B. Type of Service

Single- or three- phase service at the Cooperative’s standard secondary distribution voltages, where available. Where service of the type desired by Customer is not already available at the point of delivery, additional charges under the Cooperative’s line extension policy and special contract arrangements may be required prior to service being furnished.

C. Monthly Rate

Each billing period the Customer shall be obligated to pay the following charges:

Service Availability Charge: $100

Demand Charge, per billing kW: $5.45

First 300 kWh per billing kW, per kWh: $0.088

Over 300 kWh per billing kW, per kWh: $0.078

D. Billing Demand

The billing demand shall be the maximum kilowatt (kW) demand established by the consumer for any period of fifteen (15) consecutive minutes during the month for which the bill is rendered, as indicated or recorded by a demand meter and adjusted for power factor.

E. Power Factor

The Customer agrees to maintain unity power factor as nearly as practicable. Demand charges will be adjusted for consumers with 50 kW or more of measured demand to correct for average power factors lower than 90% and may be so adjusted for consumers if and when the Cooperative deems necessary. This power factor adjustment shall be accomplished by increasing the measured kW demand by one percent (1%) for each one percent (1%) by which the average power factor is less than 90% lagging.

F. Primary Service

Primary metering is available to all large power customers located on or near the Cooperative’s three-phase lines for all types of usage, with demands greater than 2,500 kW, subject to the established rules and regulations. The service will be three-phase, 60 hertz, at standard voltages. If service is furnished at the Cooperative’s primary line voltage, the delivery point shall be the point of attachment of the Cooperative’s primary line to the Customer’s structure unless otherwise specified in the service contract. All wiring, pole lines, and other electrical equipment (except metering equipment) on the load side of the delivery point shall be owned and maintained by the Customer. All wires, apparatus, and equipment on the Customer’s side of the service shall be maintained by qualified electrical personnel and comply with the standards of the National Electric Safety Code (NESC), current edition, and also with the regulations of any governmental authority having jurisdiction. The Customer shall indemnify, hold harmless, and defend the Cooperative against all claims, demands, costs or expense, for loss damage or injury to persons or property, in any manner directly or indirectly resulting from this provision of electric service to the Customer.

The monthly rate shall be reduced as follows:

1. Demand Charge shall be reduced by 3%; and
2. Energy Charge (kWh charges) shall be reduced by 3%.

The Cooperative shall have the option of metering at secondary voltages and adding the estimated transformer losses to the metered kWh and kW demand.

G. Monthly Minimum Charge

The minimum monthly bill shall be the greater of the following:

1. The Service Availability Charge plus the Demand Charge.
2. $1.00 per kVa of installed transformer capacity (except this minimum is not applicable to primary metered service if distribution transformers are owned by the Customer).
3. The amount stated in the agreement for electric service.

H. Billing Adjustments

This rate is subject to all billing adjustments.

I. Conditions of Service

Motors having a rated capacity exceeding 150 HP may require auto-starters or other starting devices of suitable type to limit starting current.

J. Agreement

An agreement for electric service with a fixed term may be required by the Cooperative. This rate schedule may be changed by order or consent of regulatory authorities having jurisdiction, or, if none, by the Cooperative’s Board of Directors. Service hereunder is subject to the Cooperative’s tariffs and rules and regulations for electric service.

Effective January 1, 2017

A. Application

Applicable to Customers with a peak demand of 500 kW or greater for the twelve month period ending with the current billing period with a recording meter and monitoring equipment as required by the Cooperative, and where consumer takes electric service supplied at one point of delivery and measured through one meter used for commercial and industrial uses.

B. Type of Service

Single- or three- phase service at the Cooperative’s standard secondary distribution voltages, where available. Where service of the type desired by Customer is not already available at the point of delivery, additional charges under the Cooperative’s line extension policy and special contract arrangements may be required prior to service being furnished.

C. Monthly Rate

Each billing period the Customer shall be obligated to pay the following charges:

Primary Level Service:

Service Availability Charge per meter: $200

Non-Coincidental Peak (NCP) Demand Charge, per NCP billing kW: $5.10
(NCP = your highest kW usage over a 15-minute interval during the entire billing period)

Wholesale Coincidental Demand and Energy Cost:
Coincidental Demand Cost: $19.34 / kW - your usage measured during the 1/2 hour MPE coincidental peak (the single half hour during the month that the entire MPE system peaks) from 12 PM - 10 PM Monday through Saturday

Energy Cost: $0.04204 per kWh

Discount on Primary Service (applied to Energy & Coincidental Demand Cost): 3 percent

Secondary Level Service:

Service Availability Charge per meter: $100

Non-Coincidental Peak (NCP) Demand Charge, per NCP billing kW: $5.10
(NCP = your highest kW usage over a 15-minute interval during the entire billing period)

Wholesale Coincidental Demand and Energy Cost:
Coincidental Demand Cost: $19.34 / kW - your usage measured during the 1/2 hour MPE coincidental peak (the single half hour during the month that the entire MPE system peaks) from 12 PM - 10 PM Monday through Saturday

Energy Cost: $0.04204 per kWh

NOTE: The NCP demand shall be the customer’s maximum kilowatt demand for any period of fifteen (15) consecutive minutes during the month for which the bill is rendered, as measured by the Cooperative’s demand meter and adjusted for power factor. The kW demand for wholesale power cost shall be the customer’s coincident kW demand as measured by the Cooperative’s recording meter at the time of the Cooperative’s monthly 30 minute integrated peak demand interval during Tri-State’s on peak periods and adjusted for power factor. Tri-State’s on-peak, off-peak periods are defined as follows:

January through December

Off Peak: 10:00 p.m. to 12:00 a.m. (noon)

On Peak: 12:00 a.m. (noon) to 10:00 p.m.

D. Power Cost

The cost of power to serve the Customer is the cost incurred by the Cooperative to serve the consumer including but not limited to charges for demand, capacity, ancillary, delivery, energy, and fuel charges for the billing period plus adjustments applied to the current monthly billing to account for differences in actual purchased electricity costs billed in previous periods. The power cost will be calculated using the billing units defined in the same manner as defined in the Wholesale rate to the Cooperative including any ratchet provisions in the wholesale rate.

If available from the wholesale power supplier, the Customer may receive interruptible or special load service by complying with the Cooperative’s wholesale supplier’s requirements for such service including but not limited to equipment and contract term. The Customer shall reimburse the Cooperative for any equipment required for such service.

E. Non-Coincident (NCP) Billing Demand

The non-coincident (NCP) billing demand shall be the maximum kilowatt demand established by the consumer for any period of fifteen (15) consecutive minutes during the month for which the bill is rendered, as indicated or recorded by a demand meter and adjusted for power factor.

F. Power Factor

The Customer agrees to maintain unity power factor as nearly as practicable. Demand charges will be adjusted for consumers with 50 kW or more of measured demand to correct for average power factors lower than 90% and may be so adjusted for consumers if and when the Cooperative deems necessary. This power factor adjustment shall be accomplished by increasing the measured kW demands (NCP and coincident demand) by one percent (1%) for each one percent (1%) by which the average power factor is less than 90% lagging.

G. Primary Service

Primary metering is available to all large power customers located on or near the Cooperative’s three-phase lines for all types of usage, with demands greater than 2,500 kW, subject to the established rules and regulations. The service will be three-phase, 60 hertz, at standard voltages. If service is furnished at the Cooperative’s primary line voltage, the delivery point shall be the point of attachment of the Cooperative’s primary line to the Customer’s structure unless otherwise specified in the service contract. All wiring, pole lines, and other electrical equipment (except metering equipment) on the Customer side of the delivery point shall be owned and maintained by the Customer. All wires, apparatus, and equipment on the Customer’s side of the service shall be maintained by qualified electrical personnel and comply with the standards of the National Electric Safety Code (NESC), current edition, and also with the regulations of any governmental authority having jurisdiction. The Customer shall indemnify, hold harmless, and defend the Cooperative against all claims, demands, costs or expense, for loss, damage or injury to persons or property, in any manner directly or indirectly resulting from the provision of electric service to the Customer under this paragraph G. The Cooperative shall have the option of metering at secondary voltages and adding the estimated transformer losses to the metered kWh and kW demand.

H. Monthly Minimum Charge

The minimum monthly bill shall be the greater of the following:

1. The Service Availability Charge plus the Demand Charge.
2. $1.00 per kVa of installed transformer capacity (except this minimum is not applicable to primary metered service if distribution transformers are owned by the Customer).
3. The amount stated in the agreement for electric service.

I. Billing Adjustments

This rate is subject to all billing adjustments.

J. Conditions of Service

Motors having a rated capacity exceeding 150 HP may require auto-starters or other starting devices of suitable type to limit starting current. Customers shall furnish for the Cooperative a telephone line to the meter for the purpose of collecting interval data.

K. Agreement

An agreement for electric service with a fixed term may be required by the Cooperative. This rate schedule may be changed by order or consent of regulatory authorities having jurisdiction, or, if none, by the Cooperative’s Board of Directors. Service hereunder is subject to the Cooperative’s tariffs and rules and regulations for electric service.

Effective January 1, 2023

A. Application

Applicable to all Customers for permanent outdoor area lighting. Not applicable for temporary, construction, or shared service.

B. Type of service

Dusk-to-dawn controlled security or street lights mounted on the Cooperative’s wood poles with energy usage un-metered.

C. Monthly Rate and Estimated kWh Usage With Ballast Losses

Each billing period the Customer shall be obligated to pay the following charges:

New Installations: Type, Monthly kWh, Monthly Charge per Light

40-watt Security LED: 15 kWh, $7.15/month
70-watt Security LED: 26 kWh, $8.83/month
Universal LED Street Lights: 25 kWh, $14.41/month
Additional Poles: $4.40 per pole/month

No Longer Available for New Installations: Type, Monthly kWh, Monthly Charge per Light

175-watt Mercury Vapor: 63 kWh, $12.32/month
250-watt Mercury Vapor: 90 kWh, $17.15/month
400-watt Mercury Vapor: 144 kWh, $21.97/month
100-watt High Pressure Sodium: 36 kWh, $12.32
250-watt High Pressure Sodium: 90 kWh, $21.97
400-watt High Pressure Sodium: 144 kWh, $27.82
40-watt LED Street Light: 15 kWh, $6.94
115-watt LED Street Light:  42 kWh, $11.30
Non-Metered Ornamental Seasonal: $0.109 per kWh
Non-Metered Street Lighting: $0.109 per kWh

D. Conditions of Service

1. The Cooperative will install its standard outdoor luminaries, wood pole mounted, and so connected that energy usage will not be metered.
2. The cost of all equipment and appurtenances including additional poles installed by the Cooperative will be paid for by the Customer. The above rate shows the additional charge per pole for any additional poles required.

A.  Application
Applicable to Customers with a peak demand of more than 50 kW but less than 499 kW for the twelve month period ending with the current billing period with a recording meter and monitoring equipment as required by the Cooperative, and where consumer takes electric service supplied at one point of delivery and measured through one meter used for commercial or industrial uses.

In addition to the above requirements, to be eligible for this rate, customers must have a Load Factor of less than 10%.  Load factor is defined as the customer's average demand for the month divided by their 15-minute peak demand or demand measured by a demand meter for the month.

B.  Type of Service

Single- or three- phase service at the Cooperative's standard secondary distribution voltages, where available. Where service of the type desired by Customer is not already available at the point of delivery, additional charges under the Cooperative's line extension policy and special contract arrangements may be required prior to service being furnished.

C.  Monthly Rate

Each billing period the Customer shall be obligated to pay the following charge (for secondary level service):

Service Availability Charge, per meter:
$1.50 per installed kW

Wholesale Power and Energy Cost:
At cost

kW Charger per Peak kW demand:
$19.34

kWh Charge per kWh:
$0.04204/kWh

D.  Billing Adjustments

This rate is subject to all billing adjustments.

E.  Agreement

An agreement for electric service with a fixed term may be required by the Cooperative. This rate schedule may be changed by order or consent of regulatory authorities having jurisdiction, or, if none, by the Cooperative's Board of Directors. Service hereunder is subject to the Cooperative's tariffs and rules and regulations for electric service.

A. Application

Applicable to the Municipal Sub-District, Northern Colorado Water Conservancy District for all electric power and energy required for the operation of their Windy Gap pumping plant generally located along U. S. Highway 40, west of the Town of Granby, Colorado, pursuant to the agreement dated April 1, 1992, between Municipal Sub-District, Northern Colorado Water Conservancy District, Mountain Parks Electric, Inc. (Cooperative) and Tri-State Generation and Transmission Association, Inc. (Tri-State) (Contract No. TS-92-0003).

B. Monthly Rate

The charge for electric service shall be the amounts charged by Tri-State for capacity and energy used at the pumping plant to the Cooperative plus an 8.7% surcharge. If any wheeling costs are charged for SLCAIP entitlements, the 8.7% surcharge will not be added to that portion of the charges by Tri-State to the Cooperative.

C. Determination of Billing Demand

The billing demand shall be calculated in accordance with the Agreement as measured by the 138 kV meter, and the 480 volts meter increased by 4% to compensate for two stages of line losses and adjusted for power factor as follows.

D. Power Factor

The Customer agrees to maintain unity power factor as nearly as practicable. The billing demand shall be adjusted to correct for average power factor lower than 90%; such adjustments shall be made by increasing the billing demand by 1% for each 1% that the average power factor is less than 90% lagging.

E. Monthly Minimum Charge

Each billing period the Customer shall be obligated to pay the greater of the power costs plus 8.7% surcharge as described above or $50.00.

F. Billing Adjustments

This rate is subject to all billing adjustments.

G. Rules and Regulations

Service under this Schedule is subject to the Rules and Regulations of the Cooperative, Tri-State, and to the terms and conditions of this agreement.

A. Application

Applicable for customers served under any Mountain Parks Electric, Inc. rate.

B. Conditions of Service

1. Customers electing to participate in this program will specify the amount of Green Power energy they wish to purchase in $1 increments.
2. All Green Power charges will be in addition to the customer’s regular monthly bill.
3. Customer must enter into a commitment for at least one (1) year.

A. Application: Available to Customers not subject to Tariff 202.02 General Service Time-of-Use
who:

1) Voluntarily select this tariff for a minimum 24-month period and;
2) Whose peak demand is less than 50 kW for the 12-month period ending with the current billing period and;
3) Who take electric service supplied at one point of delivery and;
4) Whose electric usage is measured through one meter used for residential, farming and/or ranching. 

B. Type of Service

Single- or three-phase service at the Cooperative’s standard secondary distribution voltages, where available. Where service of the type desired by Customer is not already available at the point of delivery, additional charges under the Cooperative’s line extension policy and special contract arrangements may be required prior to service being furnished. 

C. Monthly Rate & On- and Off-Peak Hours

Each billing period the Customer shall be obligated to pay the following charges:       

Service Availability Charge:  $29
On-Peak kWh, per kWh:  $0.21
Off-Peak kWh, per kWh:  $0.07                   

January thru December:
Off  Peak         10:00 p.m. to 5:00 p.m. Monday through Saturday.                       
                        All day on Sundays.
 
On Peak          5:00 p.m. to 10:00 p.m. Monday through Saturday.

The Cooperative reserves the right to change on- and off-peak hours. Notwithstanding anything to the contrary herein, if the Cooperative changes the monthly rate or the on/off peak hours, the Customer may opt out of this rate.

D. Monthly Minimum Charge

The minimum monthly bill shall be the greater of the following:

1. Each billing period the Customer shall be obligated to pay the Service Availability
               Charge as a minimum, whether or not any energy is actually used.
   2)       The amount stated in the Agreement for Electric Service.
   3)       $1.00 per kVa of installed transformer capacity.                        

E. Billing Adjustments

This rate is subject to all billing adjustments.        

F. Agreement

An agreement for electric service with a fixed term may be required by the Cooperative. This rate schedule may be changed by order or consent of regulatory authorities having jurisdiction, or, if none, by the Cooperative’s Board of Directors. Service hereunder is subject to the Cooperative’s tariffs and rules and regulations for electric service.

Energy conservation/solar generation/electric vehicle charging stations

 A.             Availability

Service under this Rider shall be applicable in all territory served by Mountain Parks Electric, Inc. (MPEI) and shall be subject to MPEI’s established tariffs and policies. This Rider is an optional and voluntary tariff available to members who receive service under    any rate schedule for eligible energy efficiency improvements, solar installations and electric vehicle charging stations within MPEI’s service territory. Projects that address upgrades to existing buildings deemed unlikely to be habitable or to serve their intended purpose for the duration of service charges will not be approved unless other funding can affect necessary repairs.

B.             Application

A monthly Electrify Everything (EE) charge will be applied to any metered account subject to this tariff where upgrades are installed. Members owning the premises where the account is located shall pay the EE charge until all MPEI costs have been recovered. MPEI will recover the costs of its investments, including any fees allowed, in this tariff. Charges will be set for a duration not to exceed ten (10) years. The EE charge and duration of payments will be included in the Electrify Everything Agreement between MPEI and the member.

C.             Agreement Terms

1. Equipment and Installation Costs
The equipment and installation cost of the approved energy efficiency measures will be paid by MPEI, up to the maximum amount established for each EE measure.

2. Repayment Obligation
The repayment obligation shall be assigned to the meter at the premises and will survive changes in ownership.

3. Binding Agreement
Until MPEI has been repaid for the full cost of the EE , the terms of this tariff shall be binding on the metered structure and any future member who shall receive service at the location.

4. Monthly EE Charge
Program costs shall be recovered through a monthly EE charge on the electric bill.

5. Down payment and Interest Rate Charges
Members participating in this tariff are required to make a minimum down payment of 10 percent toward the total cost of the measure. Annual interest rate for EE projects are as follows:

• 1 percent for electric vehicle charging stations, heat pumps, solar plus heat pumps and insulation upgrades
   
• Up to 2 percent for solar projects

6. EE Non-Payment
Without regard to any other MPEI rule or policy, the EE charge shall be considered as an essential part of the member’s bill for electric service, any payment shall be applied first to the EE charge and next to other charges for electric service, and MPEI may disconnect the associated electric meter for non-payment of the EE charge under the same provisions as for any other electric service.

 7. Tariff Acceptance
A member’s signature on the EE Agreement shall constitute acceptance of this tariff.

8. Discontinuance of Tariff
Once MPEI has been repaid for the costs for EE investments at a specified location, the monthly charge shall no longer be billed.

9. EE Charge
The EE charge will be based on the actual cost of the proposed measure(s) plus applicable interest and administration fees (per below) minus the down payment amount, capital credits (if applicable) and any rebates received.

10. Annual Interest Rate
The annual interest rate used to calculate the EE charge shall be no more than two percent (2%).

11. Administration Fee
Applicants will be charged a $100 administration Fee for completed projects.

12. Number of Payments
The number of monthly periods for which the EE charge will apply at the premises, unless otherwise specified, shall not exceed the estimated life of the measure, or ten (10) years, whichever is less.

13. Project Cost
The project cost will include (1) the final amount billed by the installation contractor and paid by MPEI, subject to the terms of this policy and the EE Agreement, (2) applicable county fees and (3) MPEI filing fees. 

Approved Contractor
Should the member proceed with implementing a qualified EE measure, MPEI shall calculate the appropriate monthly EE Charge described above. The member shall sign the EE Agreement and select a licensed contractor.

Quality Assurance
When the energy efficiency upgrades are completed, the contractor shall be paid by MPEI, following on-site, telephone or a written report inspection and approval of the installation by the Member and MPEI. MPEI does not guarantee the performance of the installed EE upgrades or the quality of work of any contractor.

Uneconomic Measures
Subject to MPEI approval, a member may elect to “buy down” the implementation cost of an EE measure so that the EE Charge will be less than the average estimated monthly savings. In this case, MPEI must be notified in advance of (and approve) the payment.

New & Existing Structures
Subject to MPEI approval, a member may utilize this Rider to install high efficiency equipment or measures in new structures. At its sole discretion, MPEI may determine a property is ineligible for this Rider and does not qualify for it if:

• The structure has an expected life shorter than the payback period, or
   
• The structure does not meet applicable public safety or health codes

Responsibilities
Responsibilities, understandings and authorizations of members, MPEI and Participating Contractors shall be outlined in written agreements, notifications and disclosures/consents.

Transition Roles
Payments due pursuant to an EE Agreement are based upon the meter serving each     property participating under this tariff. Failure by the Member to provide notification to a         buyer of the property shall not affect MPEI’s ability to collect from the account             associated with the property pursuant to this tariff.

Other

1. This Rider only applies to measures permanently installed as fixtures at the premises. Portable efficiency products do not qualify under this Rider. MPEI will determines eligibility of measures or products in its sole discretion.

2. In its sole discretion, MPEI may determine the maximum program investment in any year.

3. MPEI will determine the eligibility of a member based on the member’s bill payment history with the cooperative, projected energy savings and program capacity.

All bills shall be adjusted by the amount of any sales tax or other tax attributable to the sale of electric service to the Customer.

The monthly charge for electric service as determined from the Cooperative’s applicable rate schedule shall be increased to each customer receiving electric service within a municipality wherein the Cooperative pays franchise fees, by the appropriate percentage as set forth in the franchise agreement between the Cooperative and the municipality.

If a meter is found to be outside the accuracy standards established by the American National Standards Institute, Inc., proper correction shall be made of previous readings for the period of six (6) months immediately preceding the removal of such meter from service for test, or from the time the meter was in service since last tested, but not exceeding six (6) months, as the meter shall have been shown to be in error by such test, and adjusted bills shall be rendered. No refund is required from the Cooperative except to the Customer last served by the meter prior to the testing. If a meter is found not to register for any period, unless bypassed or tampered with, the Cooperative shall make a charge for units used, but not metered, for a period not to exceed six (6) months based on amounts used under similar conditions during a period or periods preceding or subsequent thereto, or during corresponding periods in previous years.

Except as provided in these rules, the Cooperative shall charge a fee for each trip to Customer’s premises which is requested by the Customer or reasonably required under these rules (e.g., trip to Customer’s premises for collection of a bill, read the meter, to make disconnection, or for a missed appointment by the Customer). The trip fee shall be billed to the Customer in the next regular billing cycle of the Cooperative.

The trip fee shall be based on the Journeyman Lineman hourly rate in effect on January 1st of the current year, plus 40% for overhead costs, rounded to the next highest dollar amount.

Trips to Customer’s premises made outside of the Cooperative’s normal working hours shall be charged for at overtime rates of one and a half times the average hourly rate as calculated above, plus 40% for overhead costs, rounded to the next highest dollar amount.

If Customer requests that the Cooperative make an investigation of any outage or service irregularity and if Customer reports or causes to be reported a service outage or irregularity and the Cooperative determines that such outage or irregularity was caused by Customer, his facilities, equipment or installation, then the Cooperative may charge the Customer a trip fee as established above.

The Cooperative shall charge a fee on each occasion it is necessary to change its records, for the purpose of setting up a new electric service account. This charge applies to the Customer if the Cooperative receives a meter reading through the normal read cycle or receives the reading through an automatic reading device. If a trip to read the meter is requested by the Customer, in addition to the change of records fee, a trip fee will be charged. The change of records fee shall be based on 25% of the average of the employees classified as Customer Service Representatives hourly rate in effect on January 1st of the current year, plus 40% for overhead costs, rounded to the next highest dollar amount.

Each Customer receiving electric service will be charged a Service Availability Charge through the application of the minimum requirements of the rate tariff for the type of service to be received as a minimum monthly billing, unless otherwise stated. As a guarantee of revenue for the Cooperative to maintain idle services for service readiness, the minimum bill requirements, including the Service Availability Charge, will be billed to the Customer after a request for service discontinuation has been received by the Cooperative until one of the following events occur:

A new application for the service is received which assumes responsibility for the Service Availability Charge; the service is transferred to the owner of the property at the date requested for discontinuance; or the owner requests in writing that the service be removed.

If at the conclusion of six (6) months any of the Service Availability Charges and the minimum bill requirements is unpaid, the Cooperative will notify the owner of record that the electric service will be scheduled for removal. In order to retain service, the unpaid charges shall be paid as a reconnect fee in addition to other charges that might apply. Should the service be removed, a new line extension charge will be required to restore the service.

The Cooperative shall charge $20.00 for each check or other negotiable instrument that is dishonored or returned to the Cooperative.

No charge shall be made for a meter test except as provided in this rule. If Customer’s meter has been tested at Customer’s request and within a period of two years the Customer requests a new test, the Cooperative shall make the test but if the meter is found to be within the accuracy standards established by the American National Standards Institutes, Inc., the Cooperative may charge the Customer a fee that reflects the cost to test the meter. The Fee shall be based on 50% of the current hourly wage rate in effect for the Senior Meter Technician, plus 40% for overhead costs, rounded to the next dollar.

The Cooperative may assess, and the Customer shall be responsible for, an administrative fee of $10.00 on any amount not paid when due.  In addition to the administrative fee, the Cooperative may assess, and the Customer shall be responsible for, interest of one and one-half percent (1.5%) per month on all amounts not paid when due.

This tariff number has been reserved for possible future use.

Any person requesting a copy of all or any portion of the tariffs of the Cooperative shall pay in advance the reasonable cost of reproduction.

When the Customer requests relocation of Cooperative facilities or temporary facilities the Customer will abide by the Cooperative’s policy on line extensions.

The Cooperative shall collect the following deposits and fees for engineering services:

A.  Deposits for Line Extension Engineering Estimate.

The Cooperative shall collect a deposit to provide one engineering cost estimate for contract pricing of new services, line extensions, subdivision developments, conversions, relocations, and other projects based on a site visit and detailed plans furnished by the owner. The deposit will be applied toward the construction charge if the extension is made within one year of the estimate. Such deposits are non-refundable. Engineering deposits are as shown in the Cooperative’s Electric Service Construction Standards.

B.  Subdivision Re-Design 

Developers are responsible to finalize subdivision plats and engineering development plans prior to initiating design work for electric utility infrastructure. Developers shall be financially responsible for the estimated labor expenses incurred by the Cooperative when design or subdivision name changes require engineering re-work. The cooperative may require advance payment of estimated re-design cost.

C.  Subdivision Re-Construction Fees

Developers shall also be financially responsible for re-work on construction costs incurred when grade is changed or when other plat changes are made after installation of electric lines. All such work shall be done under a special work order at time, material, and indirect costs to be paid by the developer. The Cooperative reserves the right to discontinue utility work in the subdivision until such re-construction costs are paid.

If the Customer cancels any agreement for the provision of electric service after acceptance by the Cooperative but before service is initiated, he may be charged the actual costs incurred by the Cooperative.

If the Customer cancels the contract for electric service after service has been established, he may be liable for the monthly minimum bill which includes the Service Availability Charge for the number of month remaining on the contract for service under a Revenue Guarantee clause.

The Cooperative will charge a metering tampering charge of:

First occurrence:  $80

Each additional occurrence:  $150 plus charges for repair or replacement of damaged equipment and for usage as described below.

The term “meter tampering” as used herein applies to any instance in which a meter assigned to a Consumer shows any evidence of having been entered by a person, firm or corporation other than a Cooperative employee in furtherance of the Cooperative’s business and includes, but is not limited to, those instances in which the seal is broken in which a meter has been jumper-ed so as to bypass the meter and serve energy to a point of delivery, or any instance in which the meter has been reversed so as to impair or defeat its capacity to accurately measure energy delivered through the meter and/or to a delivery point, or any other act whether specifically covered herein which interferes with the meter’s effectiveness to gauge the consumption of electric energy.

In cases of meter tampering or bypassing of meter, electric energy consumed, but not metered, may be estimated by the Cooperative based on the amounts used under similar conditions during preceding years. Where no previous usage history exists or is considered unreliable due to meter tampering or bypassing of meter, consumption may be estimated on the basis of usage levels of similar customers and under similar conditions. The Cooperative may charge for all labor, materials, and equipment necessary to repair or replace all equipment damaged due to the meter tampering or the bypassing of meter.

A 200-amp service meter pedestal installed within 20 feet of the Cooperative source is considered a "Simple Service." For Simple Services, the customer shall pay the Cooperative an amount equal to the average cost of installation of Simple Services, as determined by the Cooperative. The Cooperative may update the cost as frequently as quarterly. There will be no reconciliation of actual construction charges for Simple Services.

For services other than Simple Services, the Cooperative will implement a site-specific line extension contract tailored to each project. Contract charges will be based on the Cooperative’s engineering estimate of construction costs and indirect costs, and actual construction charges will be reconciled with the contract payment upon completion of all work in accordance with contract terms. Applicable capacity charges shall be paid in addition to this construction charge.

Transformer costs (direct plus indirect) will be fully charged for all commercial and multi-family projects, as well as for residential lots over 2-acres, and for all other services where the transformer is installed to supply only that one service as determined solely by the Cooperative’s employees. Transformer costs for single-family lots where the transformer will supply services to adjacent lots in the future will be pro-rated based on the number of adjacent lots (up to four) that can be served from that transformer location as determined solely by the Cooperative’s employees. Transformer costs for small indeterminate commercial loads that the Cooperative  determines can be supplied by transformers serving other customers will be pro-rated based on the Cooperative’s estimate of load multiplied by the pro-rated cost per kVa, with a minimum estimated load of 5 kVa. The Cooperative will base pro-rated transformer costs on the prior calendar year’s actual costs and publish those in the current edition of the Cooperative’s “Electric Service Construction Standards.”

Shared residential transformers are typically sized for non-electric space heating assumed for future services to adjacent lots. For electric heat or other high-capacity new service to a single-family residential lot to be supplied from an existing shared transformer, the customer will be charged the full cost for upgrading the transformer plus their pro-rated amount for the existing transformer, less the current cost of the existing transformer. For additions or upgrade to an existing single-family residential service supplied by a shared transformer, the customer will be charged the full cost of the new transformer less the current cost of the existing transformer. The Cooperative shall determine the appropriate transformer rating for all cooperative owned transformers. 

For addition or upgrade to an existing commercial service, the customer will be charged the full cost of the new transformer less the current cost of the existing transformer.

The indirect costs of the Cooperative that will be included to determine construction charges for site-specific line extension contracts shall be an annually determined percentage of direct labor costs and an annually determined percentage of direct material costs. The Cooperative will base these percentages on the prior calendar year’s actual costs and publish those percentages in the current edition of the Cooperative’s “Electric Service Construction Standards.”

Any person desiring to receive electric service from the Cooperative shall apply for such service by properly completing, signing, and filing an Application for Electric Service.  A separate Application for Electric Service is required for each location where delivery of electric energy is desired, whether or not for initiation or renewal of service.  An Application for Electric Service is filed when it is received by a Cooperative employee at any office of the Cooperative.  Applications for Electric Service that are mailed to applicant must be returned to the Cooperative within ten (10) working days of the date of mailing.

The Application for Electric Service must be in the name of the person or legal entity applying for electric service.  The Cooperative may require suitable identification.

Each applicant for electric service shall become a member of the Cooperative.

Upon compliance with the provisions of Sections 301.01 and 301.02, applicant has made an offer to purchase electric energy from the Cooperative, the terms of which are contained in the Application for Electric Service and these tariffs.

The provision of electric service constitutes an agreement under which the user receives electric service and agrees to pay the Cooperative therefore in accordance with the applicable rate tariff, rules and regulations.  Each person who resides at the premises to which service is delivered shall be deemed to receive benefit of service supplied and shall be liable to the Cooperative for payment, subject to conditions hereinafter stated, whether or not service is listed in his/her name.  The primary obligor for payment is the applicant or user in whose name service with the Cooperative is listed.  The Cooperative is obligated to pursue reasonable and timely efforts to effect payment by or collection from a user who is not the applicant or user of record by transfer of an account.

At any time before the Cooperative has taken action upon the offer to purchase electric service, applicant may revoke such offer by notifying the Cooperative.

Rate tariffs shall be on file at the offices of the Cooperative and available to applicants for service.  If there are two or more rate tariffs applicable to any class of service the Cooperative will, upon request of applicant, explain and assist in the selection of the rate tariff most suitable for the conditions, character of installation or use of service most suitable for applicant’s requirements.

Appropriate charges to customers will be made at the time service is instituted or reinstated, or in the event that service at a specific location is transferred from one customer to another.  Charges will also be made to customers for all service work performed for customers on customer’s premises except for gratuitous services provided by the Cooperative.  Charges are set forth in Tariff 204.00 Service Fees.  These charges are to offset the Cooperative’s costs for such service work and transactions and are in addition to all other customer charges for utility service, deposits, or line extensions.

If applicant for residential service satisfactorily establishes credit by one of the following means he/she shall not be required to pay a deposit:

A. Payment History

If it is undisputed that applicant has been a customer of the Cooperative or another utility providing electric service within the last 12 months, and the applicant has not been delinquent in the payment of any such utility service account during the last twelve (12) consecutive months of service, and applicant did not have more than two occasions in which a bill for such utility service was paid after becoming delinquent and never had a service disconnected for nonpayment; or,

B. Guarantee

If the applicant for residential service furnishes in writing a satisfactory guarantee from another Customer, with a current satisfactory payment history of one year or more, to secure the payment of bills for electric service; or,

C. Other Means

If the permanent residential application demonstrates a satisfactory credit rating by appropriate means, including, any of the following:

1. A credit reference from a prior electric utility, received directly from the prior utility by the Cooperative, that reports applicant would be in compliance with item A. above;
2. Applicant is or has purchased a home, for which service is being requested and prior credit history with Cooperative has been acceptable;
3. Proof that the Applicant has remitted current and consecutive payments for twelve (12) months in an owner-renter agreement to the Cooperative.

If the credit of an applicant for any type of service has not been established satisfactorily to the Cooperative, the applicant shall be required to make a deposit.  Any deposit as required herein is not to be considered as advance payment or partial payment of any bill for service.  The deposit is security for payment of service.

In addition to Rule 302.1 the Cooperative will require a deposit on Applicants for the following:

A. Act of Subterfuge

Subterfuge includes, but is not limited to, the use of a fictitious name or address by applicant for service to avoid paying prior or future indebtedness to the Cooperative, or an application for service is made for a given location in the name of another party by a customer whose account is delinquent and who continues to reside at the premises.

B. Diversion of Electric Service

The Customer has in an unauthorized manner tampered with, diverted or interfered with the service within the last five (5) years.

The required deposit for residential service shall not exceed an amount in excess of one-fourth (1/4) of the annual billings as determined by the previous usage history or as estimated by Cooperative personnel based on the service load sheet.

The Cooperative may require additional security by increasing the amount of the existing deposit or requesting a new deposit on current accounts that have more than two (2) delinquencies in the last twelve (12) month billing periods, or one (1) or more insufficient fund checks in the last twelve (12) month billing periods, or accounts that continually carry an open balance on account in excess of the deposit held for four (4) months out of a twelve (12) month period, or where a person or entity, responsible for payment of the account, jointly or severally, files a petition of bankruptcy.

Any first-time applicant for commercial, small power, or large power service shall be required to make a deposit of an estimated ninety days’ bill.  Any applicant who is a former customer of the Cooperative but who did not have commercial, small power, or large power service for at least twenty-four (24) months within the last three (3) years shall be considered a first-time applicant.  A former commercial, small power, or large power customer of the Cooperative whose previous service was provided for twenty-four (24) months within the last three (3) years and whose payment history was satisfactory, shall not be required to make a deposit.

Any applicant for commercial, small power, or large power service at additional locations will be required to make a customer deposit of an estimated ninety (90) days’ bill at the new location.  If said applicant has maintained a satisfactory payment record on all other commercial, small power, or large power accounts the deposit will be waived.

Satisfactory payment history shall consist of no discontinuance of service for nonpayment, and not more than one (1) Notice of Discontinuance being incurred on any account during the most recent twelve (12) months’ period of which none were mailed within the most recent six (6) months, and no petition for bankruptcy has been filed.

If a Customer has been required to make a deposit, the Cooperative shall pay interest on such deposit at an annual rate as established by the Public Utility Commission

Payment of the interest to the Customer shall be added to their deposit amount when the deposit is refunded.

The deposit shall cease to draw interest on the date it is returned or credited to the Customer’s account.

The Cooperative shall promptly refund the deposit plus interest to the Customer in the form of cash or a credit to the Customer’s bill when the Customer has paid the billing for service for twelve (12) consecutive residential billings or for twelve (12) consecutive commercial, small power, or large power billings, without having more than one (1) occasion in which a bill was delinquent, and the Customer is not delinquent in the payment of the current bill.  If the Customer does not meet the refund criteria, then the deposit and interest will remain in force with the Cooperative.

Every applicant who previously has been a member of the Cooperative and whose service has been discontinued for nonpayment of bills, meter tampering, or owes an undisputed amount to the Cooperative for a prior electric service, before service is rendered, will be required to pay all amounts due the Cooperative or execute a deferred payment agreement, if offered, unless the undisputed amount is discharged in a bankruptcy proceeding.

The Cooperative may grant an application by having its authorized officer or employee sign the Application for Electric Service on behalf of the Cooperative or by initiating service.

The grant of an application shall operate as an acceptance of Applicant’s offer to purchase electric service and forms a contract, the terms of which are the Application for Electric Service and these tariffs.  Upon the granting of an application and initiation of service the applicant shall be a member and customer of the Cooperative.

As conditions precedent to the performance or obligation to perform any part of the contract for electric service by the Cooperative or the provision of any electric service, Applicant/Customer shall:                  

A. Comply with the Law

Applicant/Customer shall comply with state, county, and municipal regulations governing the service applied for and provide the Cooperative with a copy of any approval required by law or ordinance; and

B. Comply with Service Rules

Applicant/Customer shall comply with the Service Rules and Regulations of the Cooperative governing the service applied for; and

C. Customer’s Installation

Applicant’s/Customer’s installation shall be constructed in accordance with all applicable codes and regulations and applicant/customer shall provide the Cooperative with any approval or other certificate that may be required by law or ordinance; and

D. Easement

A contract for electric service, or receipt of service by Customer, will be construed as an agreement granting to the Cooperative an easement for electric lines, wires, conduits, and other equipment of the Cooperative necessary to render service to Customer.  If required by the Cooperative before service is connected, the Applicant/Customer shall grant to the Cooperative at Customer’s expense an easement, the form and content of which is satisfactory to the Cooperative, for service to the Applicant/Customer’s property, including a looped underground system (Section 305.3. C). If service to the Applicant/Customer’s property requires crossing of an adjacent property, the Applicant/Customer shall secure to the Cooperative, at Customer’s expense, an easement for such crossing, the form and content of which is satisfactory to the Cooperative.

In the event the Applicant/Customer is not able to secure an easement acceptable to the Cooperative after reasonable attempts with the owner of the adjacent property, the Cooperative may exercise its power of eminent domain pursuant to Colorado Rev. Statute 38-5-104.  If the Cooperative seeks to acquire an easement by eminent domain the Cooperative does not guarantee an easement will be so acquired.  Any costs associated with the acquisition of an easement, whether by eminent domain or not, shall be borne by the applicant/customer, including but not limited to payment of just compensation, expert fees, appraisal fees, surveying costs, reasonable attorney fees and court costs if an eminent proceeding is commenced.

The Cooperative may at its discretion vacate an easement on Customer’s premises at Customer’s request and expense provided the Customer has provided a satisfactory easement for all existing or new facilities on said property and no equipment belonging to the Cooperative is located in the easement area to be vacated. The Cooperative retains the right to refuse to vacate an easement if the easement may be necessary to extend service beyond said property or for any other reason the Cooperative deems the need to retain the easement. If the Cooperative agrees to vacate an easement, the Applicant/Customer shall provide the Cooperative with a Quit Claim Deed or similar instrument, the form and content of which is satisfactory to the Cooperative, for the vacation of the easement on the Applicant/Customer’s property.

E. Construction Charges

Applicant/Customer shall fulfill all obligations for the payment of construction charges in the manner prescribed in service rules and regulations governing line extension.

The Cooperative may refuse service if:

A. Fulfillment of Conditions Precedent

If Applicant/Member has failed or refused within a reasonable time to fulfill any condition precedent to performance contained in Section 303.03; or

B. Indebtedness

If Applicant has failed or refused to pay any indebtedness to the Cooperative for previously provided electric service which has not been discharged in a bankruptcy proceeding; or

C. Credit

Applicant has failed or refused to satisfactorily establish credit in accordance with the provisions of Section 302.00 of these rules; or

D. Hazardous Conditions

If Applicant’s installation or equipment is known to be hazardous or of such character that satisfactory service cannot be given.

E. An Act of Subterfuge

The Applicant has applied for service in a fictitious name to avoid paying a prior indebtedness to the Cooperative or an application in the name of another party by a customer whose account is delinquent and who continues to reside at the premises.

F. Definition of An Applicant

“Applicant” shall include a person or entity who is a 10% or more owner of the entity applying for service, or a 10% or more owner of a customer or former customer who has failed to pay an indebtedness to the Cooperative.

A. Delinquency in payment for service by a previous occupant of the premises to be served; or

B. Failure to pay for merchandise, or charges for non-utility service purchased from the Cooperative; or

C. Failure to pay a bill to correct any previous under-billing due to misapplication of rates more than six months prior to the date of application; or

D. Violation of the Cooperative’s rules pertaining to operation of nonstandard equipment or unauthorized attachments which interferes with the service of others, or other services such as communication services unless the Customer has first been notified and been afforded reasonable opportunity to comply with the rules; or

E. Failure to pay a bill of another customer as guarantor thereof, unless the guarantee was made in writing to the Cooperative as a condition precedent to service; or

F. Failure to pay the bill of another customer at the same address except where the change of customer identity is made to avoid or evade payment of a utility bill.  A customer may request a supervisory review if the Cooperative determines that the evasion has occurred and refuses to provide service.

The Cooperative extends its distribution facilities to customers in accordance with the following line extension provisions. Refer to the current edition of the Cooperative’s “Electric Service Construction Standards” for customer/electrician guidance on planning and installing new or upgraded electric service.

As a result of the fire hazard created by danger trees killed by the pine beetle epidemic or otherwise in the Cooperative’s territory, starting January 1, 2008 new primary line extension contracts shall require installation of underground electric lines in all areas except where determined in the sole judgment of the Cooperative that one or more of the following conditions are met to prevent all future trees becoming hazardous to the line:

A.   Overhead line extensions may be allowed in rural areas across open ground where trees have not normally grown in the past.

B.   Overhead line extensions may be allowed in rural areas if the project owner initially clears and secures easements with rights specifically granted to the Cooperative to clear cut trees for a minimum width of 60-feet on both sides of the centerline (or higher width as required by the Cooperative up to expected mature tree height in the sole opinion of the Cooperative).  Such tree clearing rights shall be in addition to the 10 or 15 foot conventional electric utility line easement restrictions on each side of the line.

C.   Overhead line extensions may be allowed in towns and other areas with no forest growth where the existing electric system is overhead and the extension is considered a grandfathered area acceptable from public fire safety point of view in the sole opinion of the Cooperative.

D.   Any overhead line extension is subject to restrictions by local jurisdictional authorities (e.g. county or town government).

The Cooperative shall retain the options to rebuild existing overhead lines or install new overhead lines where funding for construction and annual operating and maintenance expenses are borne by the Cooperative.

A.        Point of Delivery-Permanent Service

The Cooperative extends its electric facilities only to the point of delivery, which shall be on the property to be served or immediately adjacent to it. The customer shall install and be solely responsible for wiring of the installation and all service entrance wiring beyond the Cooperative’s point of delivery.

The Cooperative may at its sole discretion accept a delivery point that is remotely sited from the property to be served.  This will be limited to business customers e.g. other utility or telecommunications companies or railroads, who may need to deliver very small amounts of power over a very long distance and who are routinely acquiring their own right of way easements.

B.        Point of Delivery-Temporary Construction Service

The Cooperative realizes that some customers may need to take temporary construction service at a point of delivery on a neighbor’s property. In these cases, the customer shall provide the Cooperative a copy of a letter signed by the landowner granting permission for such temporary service.

The Cooperative will extend its overhead/underground distribution system to serve permanent customer installations under the following provisions.

A.        Applicability

The facility to be served shall be a permanent installation; see 305.04 for temporary extensions. Permanent installations may include new subdivisions, residential units, shops/garages, commercial/industrial developments, and similar permanent improvements.

B.        Construction Charges

All costs to extend electric utility lines shall be paid by the customer as a construction charge, to include, but not be limited to the following costs:

1.   Direct costs of the Cooperative including labor, materials, equipment, travel time, contracted services, permits, fees, right of way acquisition, and any costs directly chargeable towards the line extension work.

2.   Indirect costs of the Cooperative including the distribution of all payroll overhead based on direct labor cost allocation, including indirect labor, inventory stores allocation, and operating equipment transportation cost allocations.

Refer to Tariff Section 205 for additional information on construction charges for new or upgrades to existing residential or small commercial services, construction charges for site-specific line extensions, subdivisions, and other projects, and indirect costs.

C.        Looped Underground System

The Cooperative may at its sole discretion require facilities for a  looped distribution system be installed as part of the customer paid underground line extension of new permanent services. By enabling switching to an alternate source, a looped underground system will minimize outage times to all customers in an area in the event of cable failure, dig-in, or other problems.

The Cooperative will extend its overhead/underground distribution system to serve temporary customer installations.  For temporary service, the customer shall be required to pay in advance as a non-refundable aid to construction 100% of the direct and indirect costs of all line extension construction, plus the cost of removal, less salvage value. If a transformer is installed to provide temporary service, the salvage value of the transformer will be the direct cost of a new transformer minus rent on use of the transformer. Rent for annual use of a transformer is calculated as the direct cost of the new transformer multiplied by the Cooperative’s annual fixed cost percentage multiplied by the years of temporary service, and rent on use of the transformer is prorated to the number of months used.

Customers desiring to have the Cooperative’s existing overhead facilities installed underground may request the Cooperative to make changes.  If at the discretion of the Cooperative it is determined that such conversion can reasonably be made, the Cooperative will convert the facilities after the customer pays a non-refundable construction charge for the estimated costs of the new facilities plus the cost to remove existing facilities less salvage value. The customer shall be responsible for the actual cost of construction and actual cost of removal.

The customer requesting conversion shall obtain all easements and pay the cost of all permits and environmental work required by the Cooperative. The customer shall also separately contract with an excavator to install conduits and vaults as specified and furnished by the Cooperative. If the existing overhead facilities are near the end of their useful life in the sole opinion of the Cooperative; such, that replacement has been identified in the Cooperative’s work plan, the Cooperative may contribute the estimated cost of replacing with overhead facilities discounted by the cooperative’s present worth value factor.

The Cooperative may at its discretion relocate its facilities on customer’s premises at customer’s request provided customer has provided a satisfactory easement for the new facilities and paid in advance an estimate of all costs for construction of new facilities plus the removal of the facilities less salvage value.  If the Cooperative determines it is necessary to move its facilities because Customer fails or refuses to allow the Cooperative access to Cooperative’s facilities at any time then Customer may be billed the construction charge for relocation.  If the Customer requests or the Cooperative determines an upgrade of facilities is reasonably necessary, the Customer will be required to pay the construction charge as well as applicable capacity charges.

The Cooperative will prepare a contract for all line extensions, electric services, upgrades and relocations.  The contract will specify the terms, the scope of work to be performed, and the construction charge or estimated cost.

When it is necessary to make line extensions or reinforce distribution lines to provide service where, in the sole judgment of the Cooperative, the estimated revenue is insufficient under the Cooperative’s rate tariff’s to operate, maintain, and eventually replace facilities, the Cooperative may require an additional monthly charge for such costs under a special contract.  The additional charge will be based on operation and maintenance (O&M) as a percent of the cost of the extension not to exceed the percentage of annual O&M costs divided by total utility plant plus 3% of the cost of the extension annually for replacement.

The Cooperative may require a Customer pay the initial cost of a spare transformer when in the sole judgment of the Cooperative such a purchase is necessary to provide a replacement for the unique size or type of transformer that is required for that Customer’s service needs.

For large load additions where there is insufficient substation and feeder capacity to supply the customer’s planned load addition(s), the Cooperative will require the customer to pay construction charges for Cooperative owned facilities including transmission lines, substations, and distribution feeder lines in lieu of capacity charges. The Cooperative will refund to the customer paying for these new substation and feeder lines all capacity charges collected during the initial five years of operations of these facilities for any new or upgraded services that would be served by the upgraded facilities.

Upon the Cooperative’s acceptance the Cooperative shall retain the ownership of all material and facilities installed on the Cooperative’s side of the point of delivery whether or not the same have been paid for by the Customer.

Posters, banners, placards, radio or television antennas, or other objects will not be allowed to be attached to poles of the Cooperative. The Cooperative may enter into written joint pole use agreements.

Meters and service switches in conjunction with the meter shall be installed in accordance with the Cooperative’s “Electric Service Construction Standards”, and will be readily accessible for reading, testing and inspection.  Customer shall provide, without cost to the Cooperative, a suitable and easily accessible location, sufficient and proper space for installation of meters and other apparatus of the Cooperative.

The Cooperative shall provide, install, own, and maintain all meters necessary for the measurement of electrical energy.  Such meters shall be of a standard type which meets industry standards. Special meters not conforming to such standards may be used for investigation or experimental purposes.

If Applicant/Customer has satisfied all conditions and performed all obligations contained in the foregoing service rules, the Cooperative shall provide electric energy to Customer at the point of delivery.  The Cooperative may limit the amount of electric energy furnished as capacity and usage conditions warrant.

A.   Standard Voltages And Special Requirements.

The following voltages and system descriptions are available, at Cooperative’s option, from Cooperative.  Normally only one nominal secondary voltage distribution system is available in a given location. A different voltage at that location may require special arrangements.  The voltage designations are nominal and the actual delivery voltages may vary from the ratings.

Nominal Secondary Voltage         Distribution System

240/120                                         three wire single phase

208/120                                         three wire two phase (network)*

208Y/120                                      four wire three phase

480Y/277                                      four wire three phase

* Only available up to 200-amps at multi-unit housing projects supplied by a 3-phase transformer.

Nominal Primary Voltage             Distribution System

14400                                            two wire single phase

24900GY/14400                           four wire three phase

These voltage designations are nominal design voltages and the actual normal delivery voltages, so far as practicable, will be maintained within industry standards for residential and commercial service at the point of delivery.

Cooperative will provide service to Customer at a single voltage in the amount of capacity required to each point of delivery requested by Customer in accordance with the extension provisions set out above.  Additional service voltages required will be provided by Customer if beyond the point of delivery.

B.   Frequency.

The Cooperative’s wholesale power supplier controls the frequency of current provided by the Cooperative. The Cooperative provides alternating current at a standard frequency of 60 cycles per second. Except for periods of outage and for infrequent and unavoidable fluctuations, this standard is maintained within one-tenth (1/10) of a cycle per second.

Electric service is generally available to Customers throughout the Cooperative’s service area from overhead distribution facilities. The Cooperative, however, may refuse to provide overhead service in any area where the Cooperative has or expects substantial investment in underground distribution facilities.

Electric Service from underground distribution facilities is available to Customers requesting such service.  In areas served by the Cooperative’s underground distribution system, phase and voltage of electric service may be limited to that which can be provided from existing facilities. The location and routing of underground distribution facilities is to be determined by the Cooperative.

In mobile home parks or similar installations, the Cooperative will provide electric service through individual meters to each space for each consuming facility.  Underground service will be installed and the metering points will be banked in a central location at the owner’s expense.

Individually metered units shall remain individually metered for the life of park/similar installation.

If master metered, the owner(s) shall follow all Colorado State laws and Public Utilities Commission regulations.

Service supplied through a master meter to a mobile home park containing three (3) or more units shall be billed in accordance with the following provisions:

1. Mobile Home Parks containing Three (3) or More Mobile Homes sites – for   the purpose of billing under the General Service Rate, the Service Availability Charge and the kWh blocks (if more than one block of usage) shall be multiplied by the number of units served through the master meter.
2. “Master Metering” will be limited to existing installations. (Master metered prior to December 31, 2015)

Electric service is provided through individual meters for each living unit or through one master meter at each point of delivery for any number of living units. If individually metered, the metering will be banked in a central location. If master metered, the owner(s) shall follow all Colorado State laws and Public Utilities commission regulations.                                                                                       

Individually metered units shall remain individually metered for the life of the building.

Buildings containing Three (3) or more units – for the purpose of billing under the General Service Rate, the Service Availability Charge and the kWh blocks (if more than one block of usage) shall be multiplied by the number of units served through the master meter.

Electric service is provided through individual meters for each living unit with one meter installed on the outside of each unit and electric service lines routed outside the building within utility easements or on the property served without encroaching on adjacent lots. Additional platted utility easements are required for banked metering.

Electric service is provided through individual meters for each living unit with one 2-position meter bank installed on the outside near a common wall. If a duplex is subdivided into two lots with separate owners, an additional utility easement is required.

The Cooperative uses reasonable diligence under standard utility practices to provide reasonably continuous and adequate service in accordance with the standards set forth in these rules.

Service interruptions may occur.  The Cooperative shall make reasonable efforts to prevent service interruptions.  When interruptions do occur the Cooperative shall re-establish service within the shortest possible time.

The Cooperative may interrupt service to provide necessary civil defense or other   emergency service in the event of a national emergency or local disaster.  The Cooperative may also interrupt service as necessary for maintenance, repairs, construction, moving of buildings or over-sized objects, relocation or changes of facilities, to prevent or alleviate an emergency which may disrupt operation of all or any portion of the Cooperative’s system, to lessen or remove risk of harm to life or property, and to aid in the restoration of electric service.

Irregularities in service such as voltage surges may occur. The Customer is responsible for installing and maintaining devices that protect his/her installation, equipment, and processes during periods of abnormal service conditions. Normal utility operation may result in the loss of voltage to one or more phases; the Customer is responsible to install and maintain single-phasing protection for three- phase motors and other customer owned equipment supplied by three-phase service.

The Cooperative makes reasonable investigation of service interruptions and irregularities reported by a Customer. Such investigation normally terminates at the point of delivery. If standard service voltage exists at this point and the Cooperative’s service facilities are in good condition the customer shall be so advised. The Cooperative shall not be obligated to inspect customer’s conductors, installation, or equipment.

The Cooperative shall not be liable for either direct or consequential damages resulting from failures, interruptions, or voltage and wave form fluctuations occasioned by causes reasonably beyond the control of the Cooperative, including, but not limited to, acts of God or public enemy, sabotage and/or vandalism, accidents, fire, explosion, labor troubles, strikes, order of any court or judge in any bona fide legal proceedings or action, or any order of any commission, tribunal or governmental authority having jurisdiction.

The Cooperative anticipates occasional disruptions in the delivery of electric service beyond the control of the Cooperative.  The Cooperative shall advise Customers who have notified the Cooperative that it requires uninterruptible electric service that it is the obligation of the Customer to provide for uninterruptible power supply (UPS).  The UPS shall be the property of and maintained by the Customer and installed in such a manner as to not be a safety hazard to employees of the Cooperative or other customers of the Cooperative.

In case of an emergency, the Cooperative shall have the right to grant preference to that service, which, in its opinion, is most essential to the public welfare.

In the event of a shortage of supply resulting from any cause whatsoever, the Cooperative shall have the right to put into effect such curtailment means as are necessary, which may include involuntary rotating blackouts on any part of the Cooperative’s electric system.

A.            Exclusive Use

The Customer may not connect his lines to another source of electric energy in a  manner that may permit electric energy to flow into Cooperative’s system from   such source without a written agreement with the Cooperative.  For experimental purposes to aid in the orderly development of additional sources of energy, or in conjunction with providing service under any rate in its tariff, the Cooperative may permit the Customer-produced electric energy to be fed back into Cooperative’s system, provided that the Customer has paid for the necessary added metering and protective equipment.

B.            Customer’s Installation.               

The Customer shall at all times maintain his/her installation in accordance with the National Electrical Code as well as other applicable standards that may be imposed by law, ordinance or regulation.

C.            Liability For Injury and Damages.

The Customer assumes full responsibility for electric energy furnished to him at and past the Point of Delivery and will indemnify the Cooperative against and hold the Cooperative harmless from all claims for both injuries to persons, including death resulting there from, and damages to property occurring upon the premises of the Customer arising from electric power and energy delivered by Cooperative

A.            Permitted Uses

Electric energy provided through Cooperative facilities shall be used by the Customer exclusively for the purpose or purposes specified in the applicable clause of the rate schedule under which the Customer is receiving service and being billed. 

B.            Resale Prohibited

The Customer shall not resell electric energy unless specifically provided for in   writing by the Cooperative.

C.            Extension of Customer’s Wiring.

The Customer may not extend the Customer’s installation across or under a public street or alley, or other lands not owned or leased by the Customer without the written consent of Cooperative and then only where energy is to be used by Customer in installations located on two or more sites separated only by a dedicated street or alley.  However, such sites are to be located in such a manner that the Customer’s conductors will not occupy a dedicated street or alley opposite land owned by others.

D.            Uses Prohibited by Law.

The Customer shall not use electric energy for any unlawful purpose or in such a manner that it may endanger life or property.

A.            Load Balance

Cooperative requires Customer to control the use of electric energy so that Cooperative’s electrical load at the point of delivery is in reasonable balance.

B.            Motor Starting Requirements

All motors shall be installed in conformance with the National Electrical Code. Cooperative permits across the line starting of electric motors where Cooperative determines that its facilities are adequate and the frequency of starts are such that service to other customers will not be adversely affected. When Cooperative determines that the operation of electric motors with full voltage starting adversely affects electric service, Customer shall provide suitable, reduced voltage starting devices or other corrective equipment.  Motors, or groups of motors starting simultaneously, shall be subject to disconnection if service to the motor(s) creates objectionable voltage fluctuation, interference or distorted wave forms that   adversely affect the Cooperative’s electrical system or its service to other Customers.

C.            Intermittent Electrical Loads

Electric service to equipment such as large spot and arc welding machines, X-ray machines, arc-furnaces, elevators, dredges, locomotives, shovels, feed grinders, etc., whose use of electricity is intermittent and subject to noticeable fluctuations,shall be served by a transformer dedicated solely to that equipment and served as a separate account.  Customers contemplating the installation of such equipment are to make specific prior arrangements with Cooperative.

D.            Equipment Necessary to Limit Adverse Effect

Cooperative may require Customer to provide  at Customer’s expense suitable apparatus to limit the effect of voltage fluctuations caused by electric equipment in Customer’s installation where Customer is found to be operating electric equipment which produces voltage fluctuation, harmonics, interference or distorted wave forms which adversely affect the Cooperative’s electrical system or its service to other Customers.

In lieu of requesting Customer to install such suitable or special equipment limiting such adverse effect, Cooperative may, at its option, install at Customer’s cost additional transformer capacity or other equipment specially designed to reasonably limit such adverse effect.

Customer’s nonlinear loads, e.g. variable speed drives, which may create harmonic problems, shall be specified to include filters and other performance features as required to meet IEEE Standard 519 (latest revision), “IEEE Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems.” Customers shall pay all consulting engineering costs that may be incurred to investigate problems and all costs to implement solutions for excessive harmonics caused by their loads.  The Cooperative shall have the right to disconnect service to loads creating harmonics problems until required limits are met and all associated costs are paid.

E.             Voltage and Wave Form Sensitive Equipment

A customer planning the installation of electric equipment such as computers,  communication equipment, electronic control devices, etc., whose performances may be adversely affected by voltage fluctuations, harmonics, and distorted 60 hertz wave forms are responsible for providing and installing the necessary facilities to limit these adverse effects.

F.            Change in Customer’s Electrical Load.

Customer shall notify Cooperative when Customer’s electrical load is to be changed substantially in order that Cooperative may ensure its facilities are adequate.

If the power factor of Customer’s load is less than ninety percent (90%), Cooperative may require customer to install appropriate equipment to maintain a unity power factor or at Cooperative’s option, to reimburse Cooperative for installing the necessary equipment. This provision shall be applicable only to Customers with a connected load greater than 50 kW.

Access will be admitted to Customer’s premises at all reasonable hours to personnel authorized by Cooperative to inspect, install, remove, or replace Cooperative’s property; to read Cooperative’s meter; and to perform other activities necessary to provide electric service, including tree trimming and tree removal where such trees in the opinion of Cooperative constitute a hazard to Cooperative personnel or facilities, or jeopardize the providing of continuous electric service.Refusal on the part of Customer to provide reasonable access for the above purposes may, at Cooperative’s option, will be sufficient cause for discontinuance of service.

Customer shall use reasonable diligence to protect personnel authorized by Cooperative or by law to have access to such facilities.

In the event of loss of, or damage to, Cooperative facilities on Customer’s premises caused by or arising out of carelessness, neglect, or misuse by customer or unauthorized persons, Cooperative may require Customer to reimburse the Cooperative of the cost of such damage.

The Cooperative’s meter, equipment or other property, whether on Customer’s premises or elsewhere, are not to be tampered with or interfered with for any reason. The Cooperative is not liable for injury to any person or persons resulting from tampering with or attempting to repair or maintain any of the Cooperative’s facilities.

Bills for service will be rendered monthly. The term “month” for billing purposes means the period between any two consecutive regular readings by the Cooperative of the meters at the customer’s premises, such reading to be taken as nearly as may be practicable every thirty days.

The Cooperative will install, own and maintain suitable metering and other equipment necessary for measuring the electric energy supplied. Each rate class of electric service supplied will be metered and billed separately. All service to a customer under one applicable rate schedule at each point of delivery will be measured by a single meter and meter readings will not be combined for billing purposes.

Usage of electric energy will be expressed as kWh. Electric energy usage is measured at the metering point regardless of whether or not it is the same as the point of delivery.

The Cooperative shall use reasonable diligence to read all meters on a monthly basis.

Usage as well as demand may be estimated by the Cooperative where there is good reason for doing so, such as inclement weather, personnel shortage, or equipment failure.

No service watt-hour meter that has an incorrect register constant, test constant, gear ratio or dial train, or that registers upon no load shall be placed in service or allowed to remain in service without proper adjustment and corrections.No service watt-hour meter that has an error in registration of more than plus or minus two percent (2%) at light or heavy load shall be placed in service. Demand meters may have an allowable error of not more than two percent (2%) of full-scale deflection except that the allowable error for thermal type meters may be three percent (3%). Meters exceeding these limits must be corrected.

Light load shall be construed to mean approximately five percent (5%) to ten percent (10%) of the nameplate rated test capacity of the meter. Heavy load shall be construed to mean not less than sixty percent (60%) nor more than one hundred percent (100%) of the nameplate rated test capacity of the meter.

All new meters shall be tested and certified by the manufacturer to register accurately to within the above limits.

Upon request of a Customer the Cooperative shall make without charge a test of the accuracy of Customer’s meter in the customer’s presence. The test shall be made during the Cooperative’s normal working hours at a time convenient to the Customer. The test will be conducted at the Cooperative’s office or at an independent test laboratory as determined by the Customer and the Cooperative. Following completion of testing, the Cooperative shall promptly advise the Customer of the result of the test.

If the meter has been tested at the customer’s request and within a period of twenty- four (24) months the Customer requests a new test, and if the meter is found to be within the accuracy standards established by the Cooperative, the Cooperative may charge a fee as established in Tariff 204.06, Meter Test Fee. Also the Customer shall be responsible for the test cost incurred to have an independent test facility perform the meter testing.

If a test of any service watt-hour meter made upon the request of the Customer is found to be more than two percent (2%) fast at any load, additional test shall be made to determine the average error of the meter. The average error of the meter in tests made at the request of the Customer shall be defined as the arithmetic  average of the percent registration at light load and at heavy load, giving the heavy load registration a weight of four and the light load registration a weight of one.

When a meter is found to have a positive average error in excess of two percent (2%) in tests made at the request of the Customer, the Cooperative shall refund to the Customer an amount equal to the excess charged for the kilowatt-hours incorrectly metered for a period equal to one-half of the time elapsed since the last previous test, but not to exceed six (6) months.

When a meter is found to have a negative average error in excess of two percent (2%) in tests made at the request of the Customer, the Cooperative shall make a charge to the Customer for the kilowatt-hours incorrectly metered for a period equal to one-half of the time elapsed since the last previous test, but not to exceed six (6) months.

If a meter is found to have an incorrect register ratio or multiplier, the error shall be corrected. Where the error is adverse to the customer, the Cooperative shall refund to the customer an amount equal to the excess charged for the kilowatt-hours incorrectly metered for the period of time the meter was used in billing the customer. Where the error is adverse to the Cooperative, the Cooperative may make   a charge to the customer for the kilowatt-hours incorrectly metered for the period of time the meter was used in billing the customer.

If a meter is found not to register, to register intermittently, or to partially register for any period, the Cooperative shall estimate a charge for the kilowatt-hours used by averaging the amounts registered over similar periods, or over corresponding periods in previous years.

The basic periodic testing of meter shall not be longer than provided as follows:

Refer to Section 203.

The Cooperative will install, own, and maintain suitable metering and other equipment necessary for the measurement of the electric demand supplied (the rate at which electric energy is used).

Member shall maintain unity power factor as nearly as practicable. Demand charges may be adjusted to correct for average power factors lower than ninety percent (90%). Measured demand may be adjusted by multiplying the maximum demand by ninety percent (90%) and dividing by the lagging power factor at the time of such maximum demand.

The customer will pay a minimum charge as per the applicable rate schedule or agreement for electric service, whichever is greater, irrespective of the amount of electricity consumed, even if none is consumed.

A full month’s minimum charge will be made when a new meter is connected and then disconnected within any one billing period.

Refer to 204.4.

Each bill for utility service(s), regardless of the nature of the service(s), is due upon receipt of the billing. If full payment is not received in the office of the Cooperative or at any agency authorized by the Cooperative to receive payment on or before the date designated on the customer’s billing, the account will be considered delinquent and subject to disconnection in accordance with these rules.

In the event of a dispute between a Customer and the Cooperative regarding any bill for electric utility  services, the Cooperative shall make such investigation as shall be required by the particular circumstances, and report the results thereof to  the Customer. In the event the dispute is not resolved, the Cooperative shall inform the Customer of the complaint procedures of the Cooperative.

Customers shall not be required to pay the disputed portion of the bill which exceeds Customer’s average monthly usage at current rates pending the resolution of the dispute, but in no event more than sixty (60) days. For purposes of this rule only, the Customer’s average monthly usage at current rates shall be the average of the Customer’s gross utility service for the preceding 12-month period. When no previous usage history exists, consumption for calculating the average monthly usage shall be estimated on the basis of usage levels of similar customers and under similar conditions.

The Cooperative may at its discretion enter into a deferred payment plan for any amount owed to the Cooperative or any portion thereof.

The Cooperative may offer upon request a deferred payment plan to any residential customer who has expressed an inability to pay all of his or her bill.

A.      Every deferred payment plan entered into due to the Customer’s inability to pay the outstanding bill in full shall provide that service will not be discontinued if the Customer pays current bills and a reasonable amount of the outstanding bill, and agrees to pay the balance in reasonable installments until the bill is paid. A payment of not more than one-third of the total deferred amount may be required as a reasonable amount under this paragraph.

B.      The Cooperative is not required to enter into a deferred payment agreement with any Customer who is lacking sufficient credit or a satisfactory history of payment for previous service when that Customer has had service from the present Cooperative for no more than three months. In cases of meter tampering, bypass, or diversion, the Cooperative may, but is not required to, offer a Customer a deferred payment plan.

C.      A deferred payment plan may include a five percent (5%) penalty for late payment but shall not include a finance charge.

D.      If a Customer has not fulfilled terms of a deferred payment agreement, the Cooperative shall have the right to disconnect service pursuant to the disconnection rules herein and under such circumstances, it shall not be required to offer subsequent negotiation of a deferred payment agreement prior to disconnection.

Commercial service who have had no pending Notices of Discontinuance of Service may elect to pay monthly bills for service on a Budget billing Plan beginning with any billing month.

Any Customer electing the Budget Billing Plan will pay a monthly amount equal to the total of the Customer’s most recent twelve (12) months’ bills multiplied by a current calculation factor of 105% divided by 12. This calculation factor is subject to change by the Cooperative as conditions warrant. Said monthly payment shall be made for eleven (11) months with the twelfth month’s payment being a settlement amount equal to the difference between the total of the prior eleven (11) month’s payments and the actual billings for the twelve (12) month period.

The Cooperative shall compare the said initial monthly payment to a monthly payment calculated based upon the most recent twelve (12) month’s actual bills. These comparisons will be made at six months and nine months from the initial contract month. The difference between the initial monthly payment amount and the then currently calculated monthly payment amount shall be the Customer’s variance. Company may revise the initial monthly payment to the then currently calculated monthly payment if the Customer’s variance is more than the variance factor. The variance factor is subject to change by the Cooperative as conditions warrant, but will neither exceed twenty-five (25) percent, nor be less than fifteen (15) percent.

If the settlement amount is a credit balance the Cooperative will issue a check to the Customer in the amount of the credit balance, or the Customer may elect to have the credit applied to future billings. If the settlement amount is a debit balance owed by the Customer the total balance will be due and payable on the due date shown on the bill for the settlement month, except that in the event the debit balance exceeds twenty (20) dollars, the Customer may elect to pay the debit over a two (2) month period with at least one half of the total debit balance payable in the settlement month.

The customer may continue on the Budget Billing plan for succeeding years, in which case the settlement month for each year will occur in twelve (12) month cycles starting with the beginning month. If a Customer electing the Budget Billing Plan fails to pay the budget billing obligation in any month, normal collection procedures shall be applicable for the outstanding budget billing amount. Upon termination of service of a Customer on the Budget Billing plan, the Customer is subject to removal from the plan and the entire outstanding amount of the account for actual usage shall be due and payable.

The monthly budget billing amount will be adjusted for changes in the Cooperative’s base rates.

If billings for electric service are found to differ from the Cooperative’s lawful    rates for the service being purchased by the customer, or if the cooperative fails to bill the customer for such service, a billing adjustment shall be calculated by the Cooperative. If the customer is due a refund, an adjustment shall be made for the entire period of the overcharges. If an overcharge is adjusted by the Cooperative within three (3) billing cycles of the bill in error, interest shall not accrue. Unless otherwise provided, if an overcharge is not adjusted by the Cooperative within three billing cycles of the bill in error, interest shall be applied to the amount of the overcharge at the rate set by the Public Utilities Commission annually for a calendar year. Interest on overcharges that are not adjusted by the Cooperative   within 3 billing cycles of the bill in error shall accrue from the date of payment unless the Cooperative chooses to provide interest to all of its affected customers from the date of the bill in error. All interest shall be compounded annually. Interest shall not apply to leveling plans or estimated billings that are authorized by statute or rule. Interest shall not apply to undercharged amounts unless such amounts are found to be the result of meter tampering, bypass, or diversion by the customer. Interest on undercharged amounts shall also be compounded on an annual basis and shall accrue from the date the customer is found to have first tampered, bypassed or diverted. If the customer was undercharged, the Cooperative may back bill the customer for the amount under-billed. The back-billing is not to exceed six months unless the Cooperative can produce records to identify and justify the additional amount of back billing or unless such undercharge is a result of meter tampering, bypassing, or diversion by the customer. However, the Cooperative may not disconnect service if the customer fails to pay charges arising from an under-billing more than six months prior to the date the Cooperative initially notified the customer of the amount of the undercharge and the total additional amount due unless such undercharge is a result of meter tampering, bypassing, or diversion by the customer. If the under-billing is $25 or more, the Cooperative shall offer the customer a deferred payment plan option for the same length of time as that of the under-billing. In cases of meter tampering, bypass, or diversion, the Cooperative may, but is not required to, offer a customer a deferred payment plan.

A.            Facilities for Providing Electric Service

The Cooperative maintains at each of its business offices and makes available to applicants and others entitled to such information a set of maps showing the facilities available for service.

B.            Cost of Providing Service

If a prospective residential applicant requests service, the Customer shall be informed of the lowest priced service alternatives available. The cooperative shall so advise the applicant giving consideration to equipment options and installation charges, if any.

C.            Tariff

At each of its business offices, the Cooperative maintains and makes available for inspection a copy of its current tariffs including all rate schedules and rates relating to service. A copy of any applicable portion of the tariff will be provided upon request. Notice of the availability of such tariffs is posted in each business office in the same area where applications for service are received.

D.            Meter Reading

Upon request, the Cooperative advises its Customers of the method of reading meters.

A.      Upon complaint to the Cooperative by a Customer either at its office, by letter or by telephone, the Cooperative shall promptly make a suitable investigation and advise the complainant of the results thereof.

B.       In the event the complainant is dissatisfied with the Cooperative’s report, the Cooperative must advise the complainant of the Cooperative’s complaint process. The cooperative complainant process is included in Section IV of these tariffs, along with the applicable forms and process to be followed.

C.       Upon receipt of a complaint by letter from the Public Utilities Commission (PUC) on behalf of a Customer, the Cooperative shall make a suitable investigation and advise the PUC of the results thereof. Initial response to the PUC must be made within the time set forth by the PUC.

D.       The Cooperative shall keep a record of all complaints which shall show the name and address of the complainant, the date and nature of the complaint and the adjustment or disposition thereof for a period of two years subsequent to the final settlement of the complaint. Complaints with reference to rates or charges that require no further action by the Cooperative need not be recorded.

Net metering is applicable to Customer-Generators (Customers) who install an eligible energy resource system and whose Net Meter Interconnection Agreement is approved by the Cooperative. Net metering is also applicable to customers who purchase a property with an existing, approved net metering system. Net metering is subject to provisions of this policy and applicable law.

“Customer-Generator” means an end-use electricity Customer of the Cooperative that generates electricity on the customer’s side of the meter using an eligible energy resource system. “Net Metering” is the offsetting of the Customer’s consumption from the Cooperative by the excess electricity generated from eligible energy resources by a Customer-Generator on the Customer-Generator’s side of the meter and delivered to the Cooperative. Some of the Customer’s generated electricity is delivered to the Customer’s own load without passing through the Cooperative’s meter.

“Eligible Generating System” is an electric generating system which:

1. Has a total aggregate nameplate generating capacity, from single or multiple generators for systems up to 25 kW as follows:

a. For residential customers, up to twenty-five kilowatts (25 kW).

b. For commercial or industrial customers, up to twenty-five kilowatts (25 kW); and

2. Uses as its energy resource qualified renewable energy sources, including solar, wind, geothermal, biomass, and hydropower. A fuel cell using hydrogen derived from an eligible energy resource is also an eligible electric generation technology; and

3. Operates in parallel with the Cooperative’s electric distribution system; and

4. Meets all safety and performance requirements of the Cooperative and applicable regulations and standards.

The Cooperative will provide and install at the Customer’s expense, as well as own, operate and maintain a single meter (or meters) to measure electric energy flow in each direction as necessary to bill net metered energy.

The Customer shall be responsible for all costs associated with the interconnection and its eligible generating system and shall also be responsible for all costs related to any modifications to the generating system that may be required by the Cooperative for purposes of interconnectivity, safety, and quality of service.

A. The rates and charges for retail electric service to the Customer shall be based on the Cooperative’s applicable rate tariff for the Customer’s premises. The Customer shall be billed monthly for demand and service availability (or other applicable monthly minimum) charges, plus the energy charge using net metered energy (Cooperative furnished energy less Customer generated energy resource delivered to the Cooperative).

B. Monthly energy billing offset: The Cooperative will deduct the energy delivered by the Customer’s generation each month from the energy supplied by the Cooperative up to a limit of the monthly energy supplied by the Cooperative. Any monthly excess generation not so deducted, shall be accumulated month to month and credited in future monthly energy billing offsets at a ratio of one kilowatt-hour of generation for one kilowatt-hour of consumption up to the limit of monthly energy delivered by the Cooperative each month.

C. Annual excess generation: Within sixty (60) days after the end of March each year, or within sixty (60) days after the Customer-Generator terminates its retail service, the Cooperative shall credit the Customer for any excess energy generation accumulated in excess of monthly energy billing offsets. The amount of credit shall be calculated at the avoided average cost of power to the Cooperative from its power supplier for the previous 12 months. Any remaining unused credit balance shall be paid to the Customer.

D. Time-of-Use Service: For Customer-Generators billed under a time-of-use tariff, off-peak generation will receive off-peak credit and on-peak generation will receive on-peak credit. Annual excess generation, whether off-peak or on-peak, will be credited as specified in C above.

The Customer shall pay all costs incurred by the Cooperative for equipment or services that are necessary to meet the safety and performance standards as authorized by Colorado Revised Statutes 40-2-124, as follows:

A. The Cooperative shall have the right to disconnect generators at any time if necessary to restore quality of service to other customers, e.g. for steady state/transient voltage, reliability, harmonics, or other problems that are suspected to be the result of defective generating system equipment. The Cooperative shall also have the right to disconnect service to any facility having an unauthorized interconnection of a parallel source.

B. The net metering system shall meet all applicable standards and guidelines for safety and performance as established by the Cooperative, the National Electric Code, the National Electric Safety Code, the Institute of Electrical and Electronics Engineers, and the Underwriters Laboratories, Inc.

C. All interconnection equipment shall be approved by the Cooperative prior to installation and shall be accessible to the Cooperative at all times.

The Cooperative and the Customer-Generator shall indemnify, defend, and save the other party harmless from any and all damages, losses, or claims, including claims and actions relating to injury to or death of any person or damage to property, demand, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties, arising out of or resulting from the other party’s action or failure to act in relation to any obligations under this net metering policy or under Colorado Revised Statute § 40-9.5-118, except in cases of gross negligence or intentional wrongdoing by the indemnified party.

An agreement for electric service with a fixed term may be required by the Cooperative. This rate schedule may be changed by order or consent of regulatory authorities having jurisdiction, or, if none, by the Cooperative’s board of directors. Service hereunder is subject to the Cooperative’s tariffs and rules and regulations for electric service.

Service for Purchase of Power, Energy, or Both from Qualifying Facilities with a Maximum Generating Capacity of Greater Than 25 kW and Equal to or Less Than 250 kW (See Net Metering for Capacity Less Than or Equal to 25 kW).

These Rules and Regulations shall apply to all qualifying Facilities (QFs) generally defined as small power production or co-generation Facilities interconnecting with the Cooperative’s electric distribution systems and making available power, energy, or both to the Cooperative.

Definition

Standard service for purchase from QFs of 250 kW or less maximum generating capacity is defined for purposes herein as the purchase of all power, energy, or both made available to the Cooperative by QFs interconnected with the Cooperative’s electric distribution system.

340.01.1  “Biomass” means any organic material not derived from fossil fuels.

340.01.2  “Waste” means by-product materials other than biomass.

340.01.3  “Purchase” means the purchase of electric energy or capacity or both from a qualifying facility by an electric utility.

340.01.4  “Sale” means the sale of electric energy or capacity or both by an electric utility to a QF.

340.01.5  “System emergency” means a condition on a utility’s system which is likely to result in imminent significant disruption of service to customers or is imminently likely to endanger life or property.

340.01.6  “Rate” means any price, rate charge, or classification made, demanded, observed or received with respect to the sale or purchase of electric energy or capacity, or any rule, regulation, or practice respecting any such rate, charge, or classification, and any Contract pertaining to the sale or purchase of electric energy or capacity.

340.01.7  "Avoided costs" means the incremental or marginal costs to an electric utility of electric energy or capacity or both which, but for the purchase of such energy and/or capacity from qualifying facility or qualifying Facilities, such utility would generate itself or purchase from another source.

340.01.8  "Interconnection costs" means the reasonable costs of connection, monitoring, switching, metering, transmission, distribution, safety provisions and administrative costs incurred by the electric utility directly caused by the installation and maintenance of the physical Facilities necessary to permit interconnected operations with a qualifying facility, including the costs of installing equipment elsewhere on the utility's system necessitated by the interconnection, to the extent such costs are in excess of the corresponding costs which the electric utility would have incurred if it had not engaged in interconnected operations, but instead generated or purchased an equivalent amount of electric energy itself.

340.01.9   "Supplementary power" means any electric energy or capacity supplied by an electric utility and regularly used by a qualifying facility.

340.01.10  "Backup-power" means electric energy or capacity supplied by an electric utility to replace energy ordinarily generated by a facility's own generation equipment during an unscheduled outage of the facility.

340.01.11  "Interruptible power" means electric energy or capacity supplied by an electric utility subject to interruption by the electric utility under specified conditions.

340.01.12  "Maintenance power" means electric energy or capacity supplied by an electric utility to a qualifying facility during scheduled outages of the qualifying facility.

340.01.13  "Supplementary firing" means an energy input to the co-generation facility used only in the thermal process of a topping-cycle co-generation facility, or only in the electric generating process of a bottoming-cycle cogeneration facility.

340.01.14  "Useful power output" of a co-generation facility means the electric or mechanical energy made available for use, exclusive of any such energy used in the power production process.

340.01.15  "Useful thermal energy output” of a topping-cycle co-generation facility means the thermal energy made available for use in any industrial or commercial process, or used in any heating or cooling application.

340.01.16  "Total energy output" of a topping-cycle co-generation facility is the sum of the useful power output and useful thermal energy output.

340.01.17  “Total energy input” means the total energy of all forms supplied from external sources other than supplementary firing to the facility.

340.01.18  "Natural gas" means either natural gas unmixed, or any mixture of natural gas and artificial gas.

340.01.19  "Oil" means crude oil, residual fuel oil, natural gas liquids, or any refined petroleum products; and

340.01.20  Energy input in the case of energy in the form of natural gas or oil is to be measured by the lower heating value of the natural gas or oil.

340.01.21  "Utility geothermal small power production facility" means a small power production facility which uses geothermal energy as the primary energy resource and of which more than 50% is owned either:

A.  By an electric utility, electric utility holding company, or any combination thereof; or

B.  By any company 50% or more of the outstanding voting securities of which are directly or indirectly owned, controlled, or held with power to vote by an electric utility, electric utility holding company, or any combination thereof.

340.01.22  "Co-generation facility" means equipment used to produce electric energy and forms of useful thermal energy (such as heat or steam), used for industrial, commercial, heating or cooling purposes, through the sequential use of energy.

340.01.23 "Topping-cycle co-generation facility" means a co-generation facility in which the energy input to the facility is first used to produce useful power output, and the reject heat from the power production is then used to provide useful thermal energy.

340.01.24  "Bottoming-cycle co-generation facility” means a co-generation facility in which the energy input to the system is first applied to a useful thermal energy process, and the reject heat emerging from the process is then used for power production.

340.01.25  "Small power production facility" means equipment used to produce electrical energy and meets the requirements and criteria contained in these rules for small power production Facilities.

A "qualifying facility" (QF) is any small power production facility or co-generation Facility which is a qualifying facility under Subpart B of 18 CFR 292, Sections 201, 203, 204, 205, and 206 FERC Rules, and Section 201 of the Public Utility Regulatory Policies Act of 1978 (PURPA).

340.02.1    Small Power Production Facilities

A.      Maximum Size Criteria

A facility where the power production capacity of the facility for which qualification is sought, together with the capacity of all other Facilities which use the same energy resource, are owned by the same person, and are located at the same site, may not exceed 80 megawatts.

For purposes herein, Facilities are considered to be located at the same site as the facility for which qualification is sought if they are located within one mile of the facility for which qualification is sought and, for hydroelectric Facilities, if they use water from the same impoundment for power generation. The distance between Facilities shall be measured from the electrical generating equipment of each facility.

If any qualifying facility obtains a waiver of the criteria of this paragraph 342.01.A from the FERC, a copy of such written waiver shall be filed with the Cooperative within 20 days of receipt of such by the qualifying facility.

B.      Fuel Use Criteria

The primary energy source of the facility must be biomass, waste, renewable resources, geothermal resources, or any combination thereof, and 75% or more of the total energy input must be from these sources. The use of oil, natural gas, and coal by a facility may not in the aggregate, exceed 25% of its total energy input during any calendar year.

Any primary energy source which, on the basis of its energy content, is 50% or more biomass shall be considered biomass.

C.      Ownership Criteria

A qualifying small power production facility may not be owned by a person primarily engaged in the generation or sale of electric power (other than electric power solely from co-generation or small power production Facilities).

A qualifying small power production facility shall be considered to be owned by a person primarily engaged in the generation or sale of electric power, if more than 50% of the equity interest in the facility is held by an electric utility or utilities, or by a public utility holding company, or companies, or any combination thereof. If a wholly or partially owned subsidiary of an electric utility or public utility holding company has an ownership interest in a facility, the subsidiary's ownership interest shall be considered as ownership by an electric utility or public utility holding company.

D.      Exceptions

For purposes herein, a company shall not be considered to be an "electric utility" company if it:

1.      Is a subsidiary of an electric utility holding company which is exempt by rule or order adopted or issued pursuant to Section 3 (a) (3) or 3(a)(5) of the Public Utility Holding Company Act of 1935, 15 U.S.C. 79c(a)(3), 79c(a)(5); or

2.      Is declared not to be an electric utility company by rule or order of The Securities and Exchange Commission pursuant to Section 2(a)(3)(A) of the Public Utility Holding Company Act of 1935, 15 U.S.C. subsection 79 b (a)(3)(A).

 340.02.2      Co-generation Facilities

"Co-generation facility" means equipment which is used to produce electric energy and forms of useful thermal energy (such as heat or steam), used for industrial, commercial, heating, or cooling purposes, through the sequential use of energy. Both topping-cycle and bottoming-cycle co-generation Facilities may qualify.

A.      Operating and Efficiency Standards For Topping and Bottoming-Cycle Facilities

Any co-generation facility must, in order to qualify, meet the following operating and efficiency standards:

1.      Topping-Cycle Co-generation Facilities Operating Standard

For any topping-cycle cogeneration facility, the useful thermal energy output of the facility must, during any calendar year, be no less than 5% of the total energy output.

Efficiency Standard

For any topping-cycle co-generation facility for which any of the energy input is natural gas or oil, and the installation of which began on or after March 13, 1980, the useful power output of the facility plus 1/2 the useful thermal energy output, during any calendar year period, must, subject to the remaining requirements of this paragraph, be no less than 42.5% of the total energy input of natural gas and oil to the facility; or if the useful thermal energy output is less than 15% of the total energy output of the facility, be no less than 45% of the total energy input of natural gas and oil to the facility. For any topping-cycle co-generation facility not subject to the above provisions of this paragraph, there is no efficiency standard.

2.  Bottoming-Cycle Co-generation Facilities

Efficiency Standard For Bottoming-Cycle Facilities

For any bottoming-cycle co-generation facility for which any of the energy input as supplementary firing is natural gas or oil, and the installation of which began on or after March 13, 1980, the useful power output of the facility must, during any calendar year period, be no less than 45% of the energy input of the natural gas and oil for supplementary firing. For any bottoming-cycle co-generation facility not covered by the above provisions, there is no efficiency standard.

3,  Waiver

The qualifying facility may apply to the Colorado Public Utilities Commission for a waiver of the operations or efficiency standards upon a showing that the facility will produce sufficient energy savings. If such waiver is obtained, a copy shall be delivered to the Cooperative within 20 days of its receipt.

B.      Ownership Criteria

A co-generation facility may not be owned by a person primarily, engaged in the generation or sale of electric power (other than electric power solely from co-generation or small power production Facilities).

A co-generation facility shall be considered to be owned by a person primarily engaged in the generation or sale of electric power, if more than 50% of the equity interest in the facility is held by an electric utility or utilities, or by a public utility holding company, or companies, or any combination thereof. If a wholly or partially owned subsidiary of an electric utility or public utility holding company has an ownership interest of a facility, the subsidiary's ownership interest shall be considered as ownership by an electric utility or public utility holding company.

C.      Exceptions

For purposes of these Rules and Regulations, a company shall not be considered to be an "electric utility" company if it:

1.  Is a subsidiary of an electric utility holding company which is exempt by rule or order adopted or issued pursuant to Section 3(a)(3) or 3(a)(5) of the Public Utility Holding Company Act of 1935, 15 U.S.C. 79c(a)(3), 79c(a)(5); or

2.  Is declared not to be an electric utility company by rule or order of the Securities and Exchange Commission pursuant to Section 2(a)(3)(A) of the Public Utility Holding Company Act of 1935, 15 U.S.C. subsection 79b(a)(3)(A). Copies of such declarations shall be delivered to the Cooperative.

A small power production or co-generation facility which meets the requirements and criteria for qualification set forth above and in Exhibit A of the Colorado Public Utilities Commission Decision Number C82-1438, and Section 292.203 FERC and Section 2.0 of these rules is a qualifying facility.

340.03.1  Information To Be Filed

The owner of any facility qualifying under these rules shall file the following information with the Colorado Public Utilities Commission and the Cooperative:

• The name and address of all owners and operators, and location of the facility;

• A brief description of the facility, including a statement indicating whether the facility is a small power production or cogeneration facility. If a cogeneration facility, whether it is a topping-cycle or bottoming-cycle facility.

• The primary energy source used or proposed to be used by the facility, and the energy source mix of the facility;

• The power production capacity of the facility; and

• The percentage of ownership of the facility by any electric utility or by any public utility holding company or by any person, corporation or entity owned by either.

A.  Additional Information Required from Small Power Production Facilities

In addition to the information required in 340.03.1 above, small power production Facilities shall file the following information with the Colorado Public Utilities Commission and the Cooperative:

• The location of the facility in relation to any other small power production Facilities located within one mile of the facility, owned by the facility which use the same energy source; and

• Information identifying any planned usage of natural gas, oil, or coal.

B.   Additional Information Required from Co-generation Facilities

In addition to the information required in paragraph 340.03.1 above, co-generation Facilities shall file the following additional information with the Colorado Public Utilities Commission and the Cooperative:

• A description of the co-generation system, including whether the facility is a topping or bottoming-cycle and sufficient information to determine that any applicable operating and efficiency rules and criteria set forth in A, Operating And Efficiency Standards for Topping and Bottoming Cycle Facilities and in Section 292.205, FERC regulations, will be met; and

• The date installation of the facility began or will begin.

C.  Notification Requirements for Qualifying Facilities of 500 kW or Larger Design Capacity

The Cooperative is not required to purchase electric power, energy, or both from a facility with a design capacity of 500 kW or more until 90 days after the facility notifies the Cooperative that it is a qualifying facility, or until 90 days after the facility has applied to the Federal Energy Regulatory Commission for certification that the facility is a qualifying facility pursuant to Section 292.207(d), FERC rules. The Cooperative and the qualifying facility may alter the above time periods by mutual agreement.

D.  Revocation of Qualifying Status

In the event that any QF has its qualifying status revoked by the Federal Energy Regulatory Commission, in accordance with Section 292.207(d) of the FERC rules, the QF owner shall notify the Cooperative within 30 days of receipt of such notification from the FERC.

E.  Substantial Alteration or Modification of the Qualifying Facility

Any small power production or co-generation facility which applies to the FERC, pursuant to Section 292.207(d)(2) FERC rules, for a determination that any proposed alteration or modification will not result in a revocation of qualifying status, shall file the FERC determination of the application with the Cooperative within 30 days after receipt thereof. Any qualifying facility owner who incorporates changes in the QF design shall provide the Cooperative with a revised informational filing (defined in Section 3.1) within twenty-five (25) days after such changes are incorporated.

Any alteration or modification of a small power production or co-generation facility may result in revocation of qualifying status, as a consequence of a formal complaint or show cause proceeding before the Colorado Public Utilities Commission or if it is established that the facility, from the alteration of modification, is not operating in compliance with these Rules and Regulations, other applicable laws, or in accordance with the required Contract for service.

F. Transmission of Qualifying Facility Power Energy, or Both to Other Electric Utilities

If the QF owner agrees, the Cooperative, which is otherwise obligated to purchase power, energy, or both from the qualifying facility, may transmit such power, energy, or both to any other electric utility. However, the rate for purchase of QF output by the electric utility to which such power, energy, or both, is transmitted shall be adjusted up or down to reflect line losses. Such adjustments shall be determined on a case-by-case basis by computation and shall reflect whether the energy and capacity displaces other energy and capacity. Charges, if any, for such transmission services, shall be subject to agreement between the transmitting utility and the qualifying facility owner and incorporated by reference into the associated Contract for service required herein. Any adjustments determined necessary for line losses over the Cooperative's system shall be billed or credited to the qualifying facility owner by the Cooperative.

G.  Resale of Power, Energy, or Both Provided by the Cooperative to the Qualifying Facility

The qualifying facility owner shall not resell any power, energy, or both provided by the Cooperative to the qualifying facility back to the Cooperative. The Cooperative may inspect the qualifying facility in accordance with these Rules and Regulations at any time to determine if any such power, energy, or both resales are occurring or have occurred.

H.  No Purchases Required When Excessive Costs Would Result

The Cooperative, giving notice in accordance with the paragraphs below, shall not be required to purchase electric power, energy, or both during any period which, due to operational circumstances, purchases from the qualifying facility will result in costs greater than those which the Cooperative would incur if it did not make such purchases, but instead generated itself or purchased at wholesale an equivalent amount of energy or capacity.

I.  Notice

The Cooperative, upon affecting a cessation of purchase due to operational circumstances causing increased costs, will use its best efforts to notify the interconnected qualifying facility owner in sufficient time for the qualifying facility owner to cease the delivery of power, energy, or both to the Cooperative. Such notification will be by telephone and in written form to all known qualifying Facilities affected. The Cooperative will use its best efforts to make a telephone notification in advance of the proposed stoppage of purchases. Written notification will also be provided by the Cooperative after the cessation of purchases and will specify the operational circumstances causing the situation. Such written notification shall be within one business day after the cessation of purchases.

Each qualifying facility owner shall be obligated to pay the costs of interconnecting with the Cooperative necessary to effectuate purchases of any power, energy, or both made available by the qualifying facility. The Cooperative will establish, prior to the interconnection, to the extent possible, the total costs of interconnection necessary to effectuate such purchases from the qualifying facility and will advise the qualifying facility owner in writing of such costs. Where total interconnection costs cannot be determined in advance of interconnection, the Cooperative will advise the qualifying facility owner promptly of such costs on a case-by-case basis. Unless otherwise set forth in the associated Contract required by these Rules and Regulations, the qualifying facility owner shall make payment of such interconnection costs within 30 days of the invoice date.  Interconnection costs shall include the Capacity Charge defined in the Cooperative's Tariff Section 308.

340.04.1  Payment of Schedule of Interconnection Costs

Interconnection costs necessary by the Cooperative prior to the agreed interconnection date shall be paid to the Cooperative in full prior to interconnection equipment installation and receipt of service under this schedule unless agreed otherwise in the associated Contract required in Section 340.05.22. Payment for interconnection costs incurred after the date of interconnection shall be paid within 30 days of the qualifying facility owner's receipt of invoice for same unless agreed otherwise in the associated Contract.

340.04.2  Typical Interconnection Costs

Interconnection costs are generally defined as any costs which, but for the interconnection of the qualifying facility, would not have been incurred by the Cooperative to accommodate the interconnection. Interconnection costs will typically include, but not be limited to the following:

• On-site inspections prior to construction to verify safe setback and physical clearance distances

• Pre-engineering costs accrued prior to interconnection to evaluate circuit protection equipment

• Specific evaluations of qualifying facility interactions with the Cooperative's installed regulation and circuit protection equipment

• Replacement and re-coordination costs associated with the Cooperative’s equipment

• The cost of performing any requested measurements to establish baseline quality of service or for subsequent measurements

• Modifications to electrical grounding necessary to correct any operational or safety problems on the Cooperative's system caused by the qualifying facility

• Modifications of grounding to reduce electromagnetic interferences, improve radio and television reception, or operation or other electrical devices affected by the qualifying facility

• The cost for interconnection at any secondary voltage other than presently established levels

• Corrections of abnormal power factor caused by the qualifying facility. Such corrections shall be made by the Cooperative on its system at the expense of the qualifying facility. Deleterious effects on power factor shall be corrected by the qualifying facility on its own system at the qualifying facility's expense

• Required disconnection equipment installed by the qualifying facility

• Fused protection of switched interconnections between major components of equipment in the qualifying facility

• The cost of protective relaying to confine the effects of faults, lightning strikes, or other abnormalities shall be installed by the QF at its expense

• The cost of any equipment to correct phase voltage or load imbalances caused by the qualifying facility is an interconnection cost

• Cost of monitoring and communication equipment, RTU’s, radios, point wiring and modeling within the Cooperative’s SCADA

• Cost of meters to measure total qualifying facility generation required for billing purposes

• Liability insurance coverage for the qualifying facility in the amount the Cooperative determines to be adequate and reasonable

Qualifying Facilities interconnecting with the Cooperative’s system shall comply with the following minimum standards, except for Facilities of less than 10 kW design capacity which shall, as a minimum, comply with items 340.05.4, 340.05.5, 340.05.11, 340.05.13, 340.05.15, 340.05.20, 340.05.21, and 340.05.23.

340.05.1 Filing of Design Information

Any person seeking to establish interconnected operations of the qualifying facility shall first file detailed design information of the proposed facility with the Cooperative to which it proposes to interconnect at least 150 days prior to the interconnection. In addition, the qualifying facility owner shall file one copy each of all available manufacturers’ literature, equipment operating instructions, and recommendations for installation. If the information filed is not adequate for the Cooperative to assess the impact of the proposed interconnection on its operations and/or system expansion, the Cooperative will notify the qualifying facility owner (in writing) within 25 days of any additional information required. The qualifying facility owner shall submit any such additional information requested by the Cooperative within 25 days after receiving the request.

340.05.2 Conference

At the earliest possible time after the prospective qualifying facility owner's filing of the required design information, a conference shall be held at the Cooperative's facility at which time the Cooperative will inform the proposed qualifying facility in its opinion of those governmental agencies and departments having requirements for interconnection of the qualifying facility. Also, at the time of the conference, the Cooperative will inform the proposed QF owner in its opinion of the interconnection requirements needed to assure a safe interconnection and operation. After the conference and review of the design information, the Cooperative may agree to an interconnection sooner than 150 days after the conference. If such is the case, the Cooperative will notify the qualifying facility owner of such finding in writing.

340.05.3 No Interconnection Until Compliance

The proposed qualifying facility shall not be inter-connected with the Cooperative's system until it has established, to the satisfaction of the Cooperative, that it complies with and has met all applicable rules set forth herein. In the event of a disagreement regarding the applicability of certain standards, the qualifying facility may file pleading using appropriate procedures with the Colorado Public Utilities Commission.

340.05.4 Code Certification

Each prospective qualifying facility owner shall obtain, at no cost to the Cooperative, all appropriate certifications and present them to the Cooperative to establish that the QF has met all applicable codes and construction standards. If, in the Cooperative’s opinion, additional inspections or certifications must be obtained for the qualifying facility, the Cooperative will notify the qualifying facility owner in writing within 25 days of such needed additional certifications. In expressing its opinion regarding such certification, the Cooperative makes no warranty, either express or implied, as to the adequacy of such codes or certifications and accepts no liability for any deficiencies on the part of the qualifying facility owner, his or her agents, representatives, or assigns.

340.05.5 Inspection and Access

The Cooperative may perform on-site inspections(s) on the site of the proposed qualifying facility prior to its construction to determine that minimum setback distances and physical clearances have been established. (Cost of these inspections shall be included as a qualifying facility interconnection cost.)

The Cooperative's personnel shall have rights of access to the qualifying facility owner's premises to repair, maintain, or retrieve any of the Cooperative's equipment which may be affected by the failure of either the Cooperative's or the qualifying facility's equipment, or to make inspections at any time.

340.05.6 Coordination of Circuit Protection Equipment

Prior to the interconnection and at the time of filing complete design information, each qualifying facility owner shall submit to the Cooperative a detailed electrical and mechanical plan so that the Cooperative may determine the safety and adequacy of the Cooperative's installed service drops and installed circuit protection equipment. Additional interconnection protective equipment needed shall be communicated in writing by the Cooperative to the qualifying facility within 25 days.

340.05.7 Potential Effects of Operations of the Cooperative's Equipment on the Qualifying Facility's Equipment

The Cooperative shall not be liable for the operational effects of the Cooperative's equipment on equipment and/or systems of the qualifying facility. The Cooperative will advise each potential qualifying facility owner within 25 days after receiving the qualifying facility's proposed design information of the necessity to install appropriate protection equipment to accommodate typical known operations of the Cooperative's equipment.

340.05.8 Quality of Services

The Cooperative, at the request of the qualifying facility owner, may measure the quality of service available to the premises of the proposed qualifying facility prior to interconnection. Cost of such measurements shall be included as interconnection costs. The Cooperative will provide a quality of service after the interconnection equivalent to that existing prior to the inter-connection. However, the costs for any changes requested by the qualifying facility owner to improve the quality of service shall be paid to the Cooperative as interconnection costs in accordance with the Contract for service.

340.05.9 Grounding of Qualifying Equipment

The Cooperative requires that the qualifying facility owner show that certificates establishing compliance with all appropriate grounding codes (subject to the Cooperative's approval) have been obtained prior to the interconnection. Upon request, the Cooperative will provide the qualifying facility owner with information and guidelines regarding grounding requirements, such to be made within 25 days of the qualifying facility's request for same. In the event that improper grounding of any of the qualifying facility equipment contributes to interferences or safety hazards of any kind, it shall be the responsibility of the qualifying facility owner to incorporate the necessary modifications at no expense to the Cooperative.

340.05.10 Standards for Harmonics and Frequency

The Cooperative will notify the qualifying facility owner in writing regarding limitations on any harmonic content of the voltage and current waveforms produced by the qualifying facility. Such notification will be in writing within 25 days after the Cooperative receives the required design information specified in 342.01.

No interconnected qualifying facility shall generate power at frequencies other than 60 Hz plus or minus .1 Hz.

The Cooperative shall not be responsible or liable for the effects of any on-site interference caused by harmonics produced by the qualifying facility. The costs for any off-site system equipment needed to neutralize the effects of on-site harmonic production by the qualifying facility shall be paid by the qualifying facility owner to the Cooperative as interconnection costs.

340.05.11 Interconnected Voltage Levels

The qualifying facility shall be interconnected only at presently available secondary voltage levels on the Cooperative's system unless all costs for modified interconnections are paid as a cost of interconnection.

340.05.12 Types of Generators and Inverting Equipment

The Cooperative encourages the use of induction generators, line-commutated inverters, or other equipment which provide for a power factor of at least 0.90 leading or lagging.

Any deleterious effects caused by the qualifying facility on the Cooperative's system due to QF equipment power factor being less than 0.90 (lead or lag) will be corrected by the Cooperative on its system at the expense of the qualifying facility. Deleterious effects on the qualifying facility's system caused by abnormal power factor of the qualifying facility's equipment shall be corrected by the qualifying facility owner at no expense to the Cooperative.

340.05.13 Disconnection Equipment

Prior to interconnection, each qualifying facility owner shall install suitable disconnection equipment which will automatically and reliably disconnect the generating equipment of the qualifying facility from the Cooperative's lines in the event of a line outage or failure of the generating equipment of the qualifying facility. As a minimum this equipment shall include a lockable disconnect switch with visibly open contacts, which can be locked open by the Cooperative. The Cooperative may require alternate or additional protection devices which will be determined on a case-by-case basis.

The disconnection devices shall be accessible to both the Cooperative and the qualifying facility owner. Either the Cooperative or the qualifying facility owner shall have the right to operate the disconnection devices whenever, in the judgment of either party, that it is necessary to maintain the safe operating conditions and whenever the operations of the qualifying facility or Cooperative adversely affects the equipment of either party. These isolating devices shall be lockable only by the Cooperative in the open position for isolation of the qualifying facility's generation and the device which isolates the Cooperative's supply shall be lockable only by the qualifying facility owner in the open position. Such devices shall be installed so that visual verification of the locking of the device in the open position can be accomplished by the Cooperative and the qualifying facility owner.

340.05.14 Fused Protection and Relaying Equipment

The qualifying facility owner shall install fused protection devices between major components of the equipment of the qualifying facility. Each qualifying facility owner shall install sufficient protective relaying equipment to confine the effects of faults, lightning strikes, or other abnormalities within the equipment of the qualifying facility and to protect the equipment of both the qualifying facility and the Cooperative.

340.05.15 Phasing

The interconnections of the qualifying facility shall be at the present phasing available at the interconnection point unless the qualifying facility owner pays for the cost of any equipment to correct or modify circuit phasing at the point of interconnection. In the event that phase voltage unbalances greater than 3% (phase-phase), or phase power unbalances exceeding 15% from phase to phase are caused by the qualifying facility, the qualifying facility will modify its equipment to maintain phase loadings within 15% of each other at all times.

340.05.16 Meters

The Cooperative will specify, supply, install, and maintain meters (at cost) suitable for the service rate schedule determined for the qualifying facility. The cost of such meters and their installation is an interconnection cost to be paid prior to interconnection. Costs for maintenance and calibration of the meters shall be paid by the qualifying facility owner as they are incurred and billed by the Cooperative. Meter seals will be affixed by the Cooperative and can be removed or reaffixed only by the Cooperative. Service under this service schedule will be provided only while proper meter seals are installed and intact. The costs for specialized meter reading or data processing needed to provide service under the appropriate schedule shall be paid to the Cooperative as they are incurred. Standard metering plans are shown in Exhibit 1.

340.05.17 Maintenance Schedule

Prior to the interconnection of the qualifying facility, its owner shall file a planned maintenance schedule with the Cooperative specifying the dates, times, means, and procedures planned. No interconnection will be allowed until the Cooperative approves the proposed maintenance schedule.

The Cooperative may inspect the qualifying facility from time to time at the Cooperative's convenience to insure compliance by the qualifying facility owner with the approved maintenance schedule and to verify proper operation of all protective equipment, including relays, circuit breakers at the inter-connection, and tripping breakers at the protective relays.

If, from inspection, the Cooperative finds that the qualifying facility owner has not complied with its maintenance schedule, has been reselling Cooperative energy or capacity to the Cooperative, or protective equipment is not operating properly, the Cooperative may immediately disconnect the qualifying facility, or may give the qualifying facility a thirty (30) day notice of disconnection.

All QF inspections, other than for safety reasons or to check for resale of Cooperative power, energy, or both, shall be witnessed by the Cooperative's and the qualifying facility's personnel at mutually agreeable times. However, Cooperative inspections to determine whether the qualifying facility has been reselling Cooperative energy or capacity to the Cooperative, or for safety, may be accomplished without prior notice and without the presence of the QF owner. At an inspection to determine safety, or if the qualifying facility owner is reselling energy or capacity, the Cooperative will invite the qualifying facility owner to witness the inspection, but such inspections may also be conducted without the presence of the qualifying facility owner should he or she decline to participate.

The qualifying facility owner shall maintain complete maintenance records, and the Cooperative shall maintain complete inspection records. The qualifying facility owner and the Cooperative shall provide copies of such records to the other party.

Any disconnection notice which the Cooperative may issue shall specify the required maintenance to be performed, operational practices to be modified or terminated, and all repairs to be made to the protective equipment, prior to the impending disconnection. The qualifying facility owner shall perform the specified maintenance, modify or stop the stated dangerous operational practices, or repair the specified protective equipment, prior to the date of the proposed disconnection. Upon completion of all such maintenance, proof of modified or terminated operational practices, or protective equipment repairs, the qualifying facility owner shall notify the Cooperative which shall reinspect the facility. If the Cooperative finds compliance with the specified requirements, scheduled disconnection shall be cancelled. If the Cooperative finds noncompliance with the specified requirements, the qualifying facility shall be disconnected as provided in the initial disconnection notice.

The Cooperative and the qualifying facility owner may agree to a reasonable continuance of disconnection, or re-connection if the qualifying facility has been disconnected pursuant to these Rules and Regulations or if the Cooperative determines that the qualifying facility is making bona fide efforts to perform the specified maintenance, modify or stop the specified operational practices, or repair the protective equipment. Where the qualifying facility owner has been served with notice of disconnection, or has been disconnected for reselling power, energy, or both to the Cooperative, the agreement for reasonable continuance of disconnection or re-connection can be conditioned on the agreement of the qualifying facility owner to repay the Cooperative for such resales.

340.05.18  Qualifying Facility Generation Schedules

For all qualifying Facilities other than those depending on intermittent sources of energy the QF owner shall file a planned generation schedule with the Cooperative for its use in coordinating normal maintenance of the distribution Facilities and for coordination with the Cooperative's power supplier. This schedule shall be received by the Cooperative prior to the qualifying facility's first interconnected operations.

340.05.19 Siting of Qualifying Facility Equipment

All QF equipment (including interconnection devices) shall be located such that the failure of any component will not cause abnormal or unsafe electrical contact with any of the Cooperative's transmission, distribution, transformation, service drop, meters, or other utility equipment. The Cooperative may inspect the qualifying facility equipment at any time to verify compliance with this requirement.

340.05.20 Insurance

The QF owner agrees, at no cost to the Cooperative, to secure and maintain in effect during the life of this Agreement the following insurance to protect the QF owner and the Cooperative during the performance of the qualifying facility operation hereunder:

Comprehensive General Liability insurance including Contractual Liability coverage for liability assumed by the QF owner in the amount of not less than $1 million Combined Single Limit for Bodily Injury and Property Damage. Such liability insurance shall name the Cooperative as additional insured and shall contain severability of interest or cross-liability clauses.

Property loss insurance in the amount of $250,000 or greater.

Certificates of Insurance evidencing such coverage’s and provisions required above shall be furnished to the Cooperative by the QF owner prior to the execution of this Agreement and shall provide that written notice be given to the Cooperative at least thirty (30) days prior to cancellation or reduction of any coverage. The QF owner agrees to provide the Cooperative with copies of renewals of the insurance coverage required hereunder. The Cooperative shall have the right, but not the obligation, to inspect the original policies of such insurance.

340.05.21  Indemnification

The QF owner shall indemnify and hold harmless the Cooperative and its directors, officers, and employees or authorized agents from any and all liability, damages, costs, losses, claims, demand, action and causes of action, including attorney's fees and expenses for damage to the property of any person or entity, and liability arising from the death of or injury to any person or entity which is attributable in whole or in part, to the negligence or willful action of the QF owner in which directly or indirectly results from or arises out of or in connection with the operation of the qualifying facility operating in parallel with the Cooperative’s electrical systems.

340.05.22 Contract

The owner of the qualifying facility shall execute the standard. Electric Service Agreement Contract prepared by the Cooperative and applicable for electric service to qualifying Facilities prior to interconnecting and receiving service under this schedule, and receiving payments for power, energy or both provided to the Cooperative.

340.05.23 System Emergencies

A.      Qualifying Facility Energy or Capacity During an Emergency

The qualifying facility is required to provide power, energy, or both to the Cooperative during a system emergency only to the extent:

• Provided by agreement between the qualifying facility and the Cooperative; or

• Ordered under Section 202(c) of the Federal Power Act.

A system emergency means a condition on the Cooperative’s system which is likely to result in imminent significant disruption of service to customers or is imminently likely to endanger life or property.

B.      Emergency Disconnections

During any system emergency, as defined above, the Cooperative may discontinue:

• Purchases from a qualifying facility if such purchases would contribute to the emergency

• Sales to the qualifying facility, if such sales would contribute to the emergency and provided that the discontinuance is on a nondiscriminatory basis

C.      Notification During Emergency Discontinuances

Should a discontinuance of purchases or sales to the qualifying facility be necessary due to an emergency, the Cooperative will use its best and reasonable efforts to notify the qualifying facility owner prior to the discontinuance. The qualifying facility owner shall be entitled to telephone notification under this rule only if a current telephone number is provided to the Cooperative. The Cooperative will also provide written notice of the emergency discontinuance no later than three (3) business days subsequent to the termination of the emergency causing the discontinuance. The written notice shall describe the emergency, and its duration, and the reasons for the discontinuance. If the Cooperative is unable to give telephone notice to the qualifying facility owner prior to the emergency discontinuance, the Cooperative will notify the qualifying facility owner by telephone by no later than the end of the next business day subsequent to the termination of the emergency, if the emergency occurs during after normal business hours. If the emergency is terminated during normal business hours, the Cooperative will use its best efforts to notify the qualifying facility owner by telephone no later than 2 hours subsequent to the termination of the emergency.

Any qualifying facility owner discontinuing sales or purchases to the Cooperative shall make reasonable efforts to notify the Cooperative by telephone prior to such discontinuance. The written notification by the qualifying facility owner shall also be provided to the Cooperative no later than three (3) business days subsequent to the termination of the emergency causing the discontinuance.

The written notice provided by the qualifying facility owner to the Cooperative shall describe the emergency, its duration, and the reasons for discontinuance of operation. If the qualifying facility owner was unable to give prior telephone notice to the Cooperative of such discontinuance, the qualifying facility owner shall notify the utility by telephone no later than 2 hours subsequent to the termination of the emergency during normal business hours, and by the end of and no later than one (1) business day after the termination of the emergency, if the emergency occurs during outside of normal business hours.

D.      Other Discontinuances

Prior to any other temporary discontinuance of purchases or sales, the Cooperative or the qualifying facility owner shall notify the other party in the manner set forth in the paragraphs above. Such notification shall not be required if the discontinuance has been previously agreed upon by the parties, or is less than 15 minutes in duration. When discontinuances are 15 minutes or less, the Cooperative or qualifying facility owner shall provide the information required above in this rule to the other party only upon written request.

In the process of restoring service during an unforeseen emergency due to, for example, acts of nature, vehicular accidents, or equipment failure, the Cooperative may exercise its right to open the disconnect switch to the qualifying facility. If so, the Cooperative will, to the best of its ability, notify the qualifying facility owner within 2 hours after the termination of the service discontinuance by telephone that the causes for the emergency have been remedied, and the Cooperative will return its portion of the disconnect switch to the closed position.

In the event that the Cooperative plans a service discontinuance of greater than 15 minutes in duration associated with scheduled maintenance, line improvements, construction, or other common utility operations, the Cooperative will use its best efforts to advise all known qualifying facility owners in writing prior to the discontinuance. Such notice shall include the expected duration of the discontinuance, the reasons therefore, and telephone number where a representative of the Cooperative may be reached regarding status of the extended discontinuance. After service has been restored due to a foreseen or planned discontinuance of service, the Cooperative will use its best efforts to advise all known qualifying Facilities of service restoration within 2 hours of same, if the restoration occurs during normal business hours, or by the close of the subsequent business day if the service restoration occurs outside of normal business hours. For such scheduled discontinuances, the Cooperative shall not be required to notify the known qualifying facility owners in writing of the restoration of service.

To request Standard Metering Requirement for QF of 250 kW or less providing energy or  energy and power generating capacity, call MPEI at (970) 887-3378.

The purpose of this document is to set forth the requirements of Mountain Parks Electric, Inc. (MPEI) regarding interconnection with, purchases from, sales to, and wheeling for distributed generation (DG) facilities.

MPEI is one of several distribution cooperatives (Members) of Tri-State Generation and Transmission Association, Inc. (Tri-State). MPEI provides retail service to over 19,000 consumers in Grand, Jackson, Summit, Routt, and Larimer counties of Colorado.

MPEI purchases all of its power and energy requirements from Tri-State under a long-term contract. Therefore, the rates which will be paid to the owners of the DG are based on Tri-State’s costs. Power and energy from DGs with nameplate ratings of 25 kW or less will be purchased under MPEI’s Net Metering Tariff. Purchases from DGs with a nameplate rating over 25 kW will be through contractual agreements between Tri-State and the owner of the DG, even though DGs will, in most cases, be directly interconnected with MPEI rather than Tri-State.

MPEI will assist DG owners with the interconnection of the DG to MPEI’s power system. DG owners should initially contact MPEI for basic information regarding interconnection. Detailed interconnection studies and contractual development for DGs over 25 kW will generally involve both Tri-State and MPEI.

If the DG wishes to sell to another utility, MPEI and Tri-State will assist by wheeling to the other utility. The term wheeling is used to denote the transmission of power by one utility for the account of another or, in this case, the transmission of DG power over one utility system for delivery to a different utility.

Under the regulations implementing PURPA, the directly interconnected utility has both the obligation and the right to purchase power and energy from a DG. However, if the directly interconnected utility agrees, a DG may wheel energy to another utility. The other utility must purchase such energy at its avoided costs, less transmission losses, if any. All electric utilities subject to the jurisdiction of the Public Utilities Commission of the State of Colorado (PUC) have been required to file certain information regarding avoided costs with the PUC. Non-regulated utilities, and utilities in other states, are required to provide similar information. In order to assist DGs in obtaining the best price for their power and energy, MPEI and Tri-State will wheel DG power and energy over its system to other utilities at cost, at the option of the DG owner.

MPEI will permit interconnection and parallel operation with a DG in accordance with the terms and conditions set forth in this document and the rules and regulations of the PUC.

Some of the information contained in this policy statement and attachments is technical in nature. DG owners should contact MPEI if assistance is needed to understand any such information. Inquiries concerning interconnection of DG may be directed to:

Contact

Mountain Parks Electric, Inc.
Attention: Engineering Department
PO Box 170
321 W Agate Ave.
Granby CO  80446
970-887-3378

For systems of 25 kW or less, the DG owner, at its own expense, shall secure and maintain in effect while interconnected liability insurance with a combined single limit for bodily injury and property damage of not less than $300,000 for each occurrence. For systems above 25 kW and up to 3 MW, the DG owner, at its own expense, shall secure and maintain in effect during the term of the Agreement liability insurance with a combined single limit for bodily injury and property damage of not less than $5,000,000 for each occurrence.

Except for DGs installed on a residential premise which have a design capacity of 5 kW or less, MPEI shall be named as an additional insured by endorsement to the insurance policy and the policy shall provide that written notice be given to MPEI at least thirty (30) days prior to any cancellation or reduction of any coverage. Such liability insurance shall provide, by endorsement to the policy, that MPEI shall not by reason of its inclusion as an additional insured incur liability to the insurance carrier for the payment of premium of such insurance. For all DGs, the liability insurance shall not exclude coverage for any incident related to the subject generator or its operation.

Certificates of Insurance evidencing the requisite coverage and provision(s) shall be furnished to MPEI prior to the Date of Interconnection of the DG system. MPEI shall be permitted to periodically obtain proof of current insurance coverage from the generating customer in order to verify proper liability insurance coverage. The DG will not be allowed to commence or continue interconnected operations unless evidence is provided that satisfactory insurance coverage is in effect at all times.

The cost of the required insurance may be a factor in a DG’s decision to become a power producer and, if so, whether to sell its power to MPEI or produce solely for its own use. MPEI recommends that the DG consult its insurance agent at an early stage in its planning so that this cost may be properly incorporated into that planning.

Any inspections, reviews of plans, specifications and/or sites and any approvals, written or oral, are conducted or provided solely for the use and purposes of MPEI; MPEI makes no warranty, direct or indirect, and provides no assurances, direct or indirect, as to the adequacy or safety of any plans, specifications, sites, installations or other characteristics of the DG. The owners of DG are solely responsible for determining and ensuring the adequacy and safety of all plans, specifications, sites, installations and other characteristics of the DG.

341.03.1 Introduction

These standards have been established to assist DG owners in planning and designing an electrical interconnection with the system of MPEI and Tri-State. DG and MPEI personnel may be guided by this document when planning, installing and operating customer-owned generating equipment. The following requirements are general in nature and may not cover all details of a specific installation. Potential DG owners should discuss project plans with MPEI before purchasing or installing equipment.

MPEI will assist any DG owner in its efforts to generate electric power and energy. MPEI encourages the development of DG projects which can supplement MPEI’s existing generating resources whenever this can be done without adverse effects on the general public or to MPEI’s equipment or personnel. To help achieve the maximum reliability and use of DG projects, MPEI will provide the potential DG with information, technical assistance, and other aid the DG might require in the evaluation of the technical and economic feasibility of the project.

341.03.2 General Requirements for Interconnection

Certain protective equipment (relays, circuit breakers, etc.) specified by MPEI must be installed at locations where the customer wishes to operate generating facilities in parallel with MPEI’s system. The purpose of this equipment is to ensure safe and reliable power system operation and to allow prompt disconnection of the DG in the event of short circuit or other malfunction. Other changes, such as revisions to the electrical system configuration and/or modifications to protective equipment at other locations, may also be required in order to accommodate parallel operation. MPEI will assist DG owners in determining interconnection requirements. This document gives general information about parallel operation; however, MPEI may impose additional restrictions or require additional equipment when the particular installation so warrants. Each DG must be reviewed individually, since interconnection requirements vary with the type of generation equipment and the proposed location on MPEI’s system. All costs associated with interconnection, necessary system additions, and modifications to accommodate the DG will be borne by the DG owner.

MPEI requires that the customer design, construct and operate their equipment in a manner which will not degrade the quality of service to other MPEI customers. This requires that the DG equipment be designed, specified and installed in a manner appropriate to its intended service and in accordance with all applicable standards regulating design, construction and operation of such equipment. MPEI reserves the right to specify the quality and determine the adequacy of customer equipment, installation and operation in any respect which affects safety, reliability or quality of service.

MPEI will not assume responsibility for protection of the generator(s) or any other portion of the DG’s electrical equipment. The DG is fully responsible for properly protecting its equipment. Equipment which is not properly protected may be damaged as the result of normal system operation or disturbances on MPEI’s system. MPEI will, however, aid the DG in determining conditions to which its equipment is likely to be subjected as a result of probable system operation, malfunctions or disturbances, insofar as it is possible to determine these conditions in advance.

A permanent, weather proof sign indicating the location of the DG Generation Disconnect shall be clearly displayed at the point of service connection (generally at the customer meter). For DGs greater than 25 kW of capacity, a one-line electrical diagram and the names and current telephone numbers of at least two persons that are authorized to provide access to the DG and who have authority to make decisions regarding the DG interconnection and operation shall be included with or attached to the sign. This telephone listing shall be updated as needed to maintain its usefulness.

For interconnection of a DG to a radial distribution circuit, the aggregated generation, including the proposed DG, on the circuit shall not exceed 15% of the line section annual peak load as most recently measured at the substation or calculated for the line section without MPEI evaluating the capability of the distribution facility. A line section is that portion of MPEI’s electric system connected to a customer bounded by automatic sectionalizing devices or the end of the distribution line.

The DG, in aggregation with other generation on the distribution circuit, shall not contribute more than 10% to the distribution circuit’s maximum fault current at the point on the distribution feeder voltage (primary) level nearest the proposed point of change of ownership without MPEI’s evaluation and approval.

The DG, in aggregation with other generation on the distribution circuit, shall not cause any distribution protective devices and equipment (including, but not limited to, substation breakers, fuse cutouts, and line reclosers), or DG equipment on the system to exceed 87.5 % of the short circuit interrupting capability; nor shall the interconnection be proposed for a circuit that already exceeds 87.5 % of the short circuit interrupting capability.

341.03.3 Codes, Standards And Regulatory Agencies

The DG must ensure that the facility and all equipment connected therewith comply with the National Electrical Code, the National Electrical Safety Code, and/or any applicable local, state, and federal government requirements, whichever are stricter. For DG’s with a design capacity greater than 25 kW, the DG must submit a statement from a registered Professional Electrical Engineer currently licensed in the state of Colorado certifying that the design of the DG and its interconnection equipment complies with MPEI requirements and with reasonable interconnection safety and design standards and prudent electrical practices. The DG owner agrees to hold MPEI harmless for any damage to person or loss to property arising out of the DG’s failure to comply with such codes or legal requirements. The DG’s installation must be inspected and certified by a Colorado State Electrical Inspector before the generation equipment may be energized or interconnected. Inspection and startup procedures will conform to Colorado Public Utilities Commission rules. Grounding shall be in accordance with applicable sections of the National Electrical Code and the National Electrical Safety Code and shall conform to IEEE Standard 142, “IEEE Recommended Practice for Grounding of Industrial and Commercial Power Systems” and RUS Bulletin 1724E-300, “Design Guide for Rural Substations,” where applicable. For a summary of applicable codes and standards, see 341.07.

341.03.4 Synchronous Generators

Synchronous generators have several features which make them desirable from a utility system standpoint, but the excitation and synchronization equipment required often make these generators economically unfeasible, except in the larger sizes. The synchronous generator with associated excitation equipment is able to supply its own reactive power and hence may operate at unity or lagging power factor. DGs are required to supply sufficient generator reactive power capability to withstand normal voltage variations on MPEI’s system and to maintain essentially unity power factor. This operation enhances generator stability and alleviates the need for supplemental power factor correction equipment.

Synchronous generators require automatic synchronization equipment and supervisory relays to prevent closure into MPEI’s network when the DG generator is improperly synchronized. Reclosing an isolated synchronous generator onto the system may cause damage to that generator or associated equipment if the generator and system are not properly synchronized. Automatic reclosing of circuit breakers or circuit reclosers is commonly used on distribution and subtransmission lines in order to increase the system reliability. Changes to existing MPEI equipment may be required to prohibit reclosing into a synchronous generator. Other protective relaying may be required to account for over speed, excitation overvoltage, loss of excitation, loss of synchronism, frequency deviation, field ground, neutral overvoltage and reclosure control. Suggested minimum protective equipment requirements for synchronous generator installations are given in Section 3 by class of DG.

341.03.5 Induction Generators

Induction generator installations are in many respects simpler than synchronous generator systems but they pose additional problems. The induction generator may be started as a motor if current inrush, voltage regulation and lamp flicker are not serious problems. If the quality of service to other MPEI customers is degraded due to induction generator starting, reduced voltage starting or other special procedures may be necessary to relieve the situation.

The induction generator cannot maintain constant voltage and frequency operation without an outside source of reactive power. MPEI must supply this power under all operating conditions. The size and type of induction generator which may be interconnected at a given point on an existing MPEI circuit is limited by the ability of that circuit to regulate voltage and maintain adequate quality of service to other MPEI customers. MPEI reserves the right to limit the application of induction generators on existing circuits and to specify modifications, if any, to the existing system to accommodate the DG. All such modifications will be made at the expense of the DG owner.

Capacitors installed at the generator may be required to limit the adverse effects of excess VAR flow on MPEI’s system. Installation of capacitors at or near an induction generator increases the risk that the machine may become self-excited if it is completely isolated from or isolated with a relatively small portion of MPEI’s system. A self-excited induction generator can produce power of abnormal voltage and frequency. This unregulated power may damage equipment of other customers who are electrically connected to the isolated generator.

To minimize the risk of self-excited operation, the compensation installed at or near an induction generator should be limited to that value necessary to correct the no-load power factor to 95 percent. Over and under-frequency relays and voltage regulation relays will also be required on all induction generators to protect against self-excited operation. Other protective equipment such as voltage restrained over current relays may be required to reduce the possibility of damage to MPEI equipment or the equipment of other customers. Where self-excitation problems appear likely, it may be necessary to rearrange the distribution network to avoid isolating the induction generator with a small attached load. Costs of power factor correction equipment, protective equipment and any MPEI system changes must be borne by the DG owner.

Re-closing a distribution line after a utility system disturbance may cause damage to the customer’s induction generator if adequate protective equipment is not installed to mitigate the adverse effects.

341.03.6 Inverter Systems

Inverter systems are used to transform direct current to alternating current. The resulting waveform may be rich in harmonics. These nonstandard waveforms may cause radio and television interference on other customers’ equipment, objectionable audible noise, and malfunction of electrical equipment. Excessive harmonic content may also cause overheating in electrical equipment.

The inverter system should be designed and operated in accordance with UL 1741. This standard (“Inverters, Converters, and Controllers for Use in Independent Power Systems”) addresses the electrical interconnection design of various forms of generating equipment. Many manufacturers submit their equipment to a Nationally Recognized Testing Laboratory (NRTL) that verifies compliance with UL 1741. This “listing” is then marked on the equipment and supporting documentation.

Owners of 3-phase inverter systems are responsible to limit harmonics to values allowed by IEEE Standard 519, “IEEE Guide for Harmonic control and Reactive Compensation of Static Power Converters.” DG owners will be responsible for costs of any corrective actions necessary for problems resulting from excessive harmonics.   

Inverter systems require a significant reactive power flow to ensure proper operation. MPEI requires the customer to provide equipment to correct the power factor. However, care must be taken to ensure that an inverter system which is electrically close to capacitors cannot drive an isolated load. Self-commutated inverters as well as line-commutated inverters connected to rotating machines may operate in a self-excited mode. In order to protect MPEI’s equipment and other customers’ equipment, the DG shall install protective relays to prevent isolated operation. For the purpose of preventing service to isolated loads, inverter systems shall conform to standards outlined in IEEE Standard 929.

341.03.7 Protection of the Utility System

In order to be assured of continuing safe, reliable service to MPEI customers, MPEI must be concerned with the manner in which DG are connected to the existing MPEI system. MPEI’s concerns are fourfold:

1. The DG must promptly disconnect from MPEI in the event of a utility system disturbance;
2. The DG must disconnect in the event of a malfunction or disturbance on the DG equipment;
3. The DG must not back feed a de-energized MPEI line; and
4. The DG must not significantly degrade the quality of service to other MPEI customers.

A.  Utility System Disturbances

In the event of a utility line fault or other system disturbance, protective equipment will promptly act to de-energize the affected line section. A DG connected to this portion of line represents an additional source of power to energize the line. Thus, the DG’s equipment must also automatically act to disconnect the generator(s) to avoid contributing to the severity of the fault, to avoid isolated operation and to protect the DG equipment.

Isolated operation (islanding) occurs when a portion of the MPEI load becomes separated from the MPEI source but is still connected to the parallel generation. If the isolated load is sufficiently large with respect to the rated output of the DG, the voltage will collapse and protective relays will take the machines off line. When the generator rating is greater than or comparable to the size of the isolated load, sustained independent operation becomes possible. This situation is intolerable, since the voltage and frequency on the isolated network are likely to be poorly regulated and damage to MPEI equipment, or that of other customers, is likely to result. Restoration of normal service to this island is also hampered by the presence of an isolated energy source.

In instances where MPEI’s system arrangement is such that it is possible that the generators will not always be isolated with a sufficiently large load to prevent independent operation, MPEI requires the installation of voltage and frequency relays, even on the smallest DGs. For installations with rated capacity of greater than 25 kW, specific devices are required to detect faults on MPEI’s system as well as voltage and frequency relays to detect isolated operation. Equipment may also be required on MPEI’s system to provide additional assurance that islanded operation does not continue. The need for such equipment will be determined on a case-by-case basis.  In some situations where islanding is considered possible, the DG system may be required to be interconnected with a direct transfer trip protection system. 

B.  DG Disturbances

To prevent loss of service to other MPEI customers, the DG must provide protective equipment to promptly disconnect their generators in the event of a fault or other disturbance on the DG’s installation. The protective equipment must be coordinated with MPEI’s equipment to ensure proper operation in the event of a fault. MPEI will assist the DG to properly coordinate the protective equipment.

C.  Back feed To Utility System

The distributed generators provide an additional source of power for MPEI’s network. The DG must provide protective equipment sufficient to give positive assurance that the generators cannot be connected to an otherwise de-energized MPEI line. This prevents a potential hazard to MPEI personnel who may be in contact with the line for maintenance purposes. In addition to an automatic fail-safe device, MPEI will require an accessible disconnect device that is visibly marked “Generation Disconnect” and has the capability of isolating the energy generated by each DG. This device must be lockable in the open position and may be operated by either party at any time in order to maintain safe operating conditions. At a minimum, this protection can be provided by an isolation switch which can be locked in the open position by MPEI to visibly indicate isolation of the DG. Other equipment such as under voltage, synchronizing, voltage phase sequence or reclosing relays may also be required.

 If it is discovered that any equipment connected to the MPEI system is in MPEI’s judgment problematic or is considered to be unsafe it will be disconnected immediately from the MPEI system.

D.  Power Quality

The DG will not be allowed to degrade the quality of power delivered to other MPEI customers. The DG will be expected to operate within the limits on voltage, frequency and harmonic content as outlined.

The DG synchronous generation is expected to operate at as nearly unity power factor as is practical to prevent voltage flicker upon switching. The generator and associated equipment are expected to be engineered to allow stable unity power factor operation without exceeding the voltage regulation limits outlined in RUS Bulletin 169-4, “Voltage Levels.” Power factor limits on DG induction generators are discussed in Section 341.03.6. Should voltage regulation or lamp flicker become a problem, then operational restrictions may be imposed until the situation can be corrected.

Excess harmonic content or unnecessary service interruptions will not be allowed. If degradation in quality of service to other MPEI customers or interference with the operation of MPEI equipment occurs, MPEI will disconnect the DG generators until such time as the problem is resolved.

E.  Protective Equipment

The type and quality of protective equipment required will depend on the size and type of the AF generation equipment as well as the electrical characteristics of MPEI’s interconnection. At a minimum, this equipment will consist of a circuit breaker with associated relaying, a disconnect switch, and voltage and frequency regulation relays. Additional equipment may be necessary for a given installation. The equipment specified above may be part of a vendor-supplied control package, providing the desired level of protection is ensured. Any such protective equipment must be approved by MPEI for each application. MPEI shall be the only judge of adequacy and suitability of protective equipment for DG installations.

341.03.8  Protection of DG Facilities

The DG is solely responsible for protection of its equipment. To facilitate its design, MPEI herein lists potential hazards to the DG equipment which might occur as a result of interconnection with MPEI’s system. The probable hazards are of three types: those that occur as a direct result of a faulted transmission or distribution line, synchronism problems, and voltage surges.

Transmission and distribution lines are susceptible to both short circuits and ground faults. Both of these line faults may produce excessive phase currents, single-phased supply and excessive negative sequence currents. Typical equipment to sense and protect against these hazards are listed in Section 341.04.

The DG unit can be damaged by interconnection with MPEI’s system if the voltage, phase sequence or phase angle of the machine does not match that of the system. For synchronous generators the customer must provide either automatic synchronizing equipment or a synchronizing relay to supervise manual closure. Unsupervised manual synchronizing is not permitted. Induction starting will be allowed if the inrush current is not excessive. Should voltage dip or lamp flicker problems result from induction starting, other steps must be taken to eliminate these problems.

 Damage may result to a DG unit as a result of automatic re-closing unless proper protection is provided. MPEI’s transmission and distribution lines are usually equipped with circuit re-closers or power circuit breakers with automatic re-closing relays, which, after a time delay, attempt to restore a circuit which has been tripped due to a fault. If the fault was temporary, the re-close is successful and the circuit is restored to service; if not, the circuit is locked out until manual re-closing is attempted. The re-closer may attempt to restore the circuit several times before lockout occurs. If the DG unit was not taken off-line when MPEI’s circuit was opened, the generator and MPEI’s system may not re-close in synchronism. Voltage surges and damaging torque may occur upon re-closing. Protective devices should be installed to trip the generator before re-closing is attempted and to prohibit re-closing into MPEI’s system if MPEI’s voltage is of abnormal magnitude or phase sequence. Modifications to MPEI’s re-closer or addition of other equipment may be required to protect the DG unit. The cost of such modifications will be charged to the DG.

Transient voltage surges may occur on MPEI lines due to switching operations or lightning strikes. The DG should have protective devices to mitigate the effects of these surges as well as direct lightning strikes. Inverter systems and other solid state components are particularly susceptible to damage by voltage surge.

Details of typical protective equipment to sense and mitigate the potential hazards described above are given in Section 341.04.

341.03.9 Inspection and Maintenance

The DG shall not commence interconnected operation, until:

1)  The DG has supplied MPEI with a completed Application for Interconnection on a form supplied by MPEI for review and acceptance, and executed MPEI's interconnection agreement.

2)   The DG has obtained a certificate of code compliance from a Colorado State Electrical Inspector;

3)   MPEI has made any necessary modifications to its system to accommodate the DG;

4)   MPEI has inspected and observed testing of the DG and certified, in writing, that the DG has complied with all requirements for interconnection; and

5)    The DG has submitted proof of adequate insurance.

The completed installation will be subject to a final inspection and test by MPEI for compliance before parallel operation is permitted. MPEI will determine satisfactory performance.

The DG must notify MPEI prior to any modifications made to the DG system or to the interconnection between the DG and MPEI. The DG must receive approval from MPEI prior to proceeding with such modifications. The DG must permit MPEI, at any time, to install or modify any equipment, facility, or apparatus to protect the safety of its employees and insure the accuracy of its metering equipment. These costs will be borne by the DG owner.

The DG must permit MPEI employees to enter its property at any time for the purpose of inspecting and/or testing the interconnection facilities to ensure their continued safe operation and the accuracy of MPEI’s metering equipment, but such inspection does not relieve the DG owner of the obligation to maintain the facilities in satisfactory operating condition.

The DG shall discontinue parallel operations when requested by MPEI:

1)   To facilitate maintenance, test or repair of utility facilities;

2)   During system emergencies;

3)   When the DG equipment is interfering with other customers on the system;

4)   When an inspection of the DG reveals a condition likely to be hazardous to MPEI’s system; and

5)   When an inspection of the DG facility reveals that the generating equipment is operating outside allowable limits on voltage, frequency, power factor or harmonic content.

The DG shall operate and maintain the interconnection equipment at its cost unless previous arrangements have been made with MPEI to maintain the interconnection. In this case, MPEI will operate and maintain the interconnection and bill the DG for these services.

In all other respects, inspection and maintenance of the DG shall conform to applicable Colorado Public Utilities Commission regulations.

341.03.10 Important Considerations for Interconnection

The DG owner should allow adequate time in the design and construction schedule for design interface meetings with MPEI and for material procurement by MPEI. This time will vary depending on the DG’s location, size, design, specific operating and system requirements, and the availability of materials needed to accomplish the interconnection.

If it is discovered that any equipment connected to the MPEI system is in MPEI’s judgment problematic or is considered to be unsafe it will be disconnected from the MPEI system.

DG’s that generate electrical energy for on-site use only and are interlocked or otherwise prevented from feeding energy into the MPEI system are special cases and may not be required to meet all of the requirements of this document. However, they are required to show by design and by operation that they cannot feed energy into the MPEI system.

MPEI has established guidelines for the protection and interconnection of parallel generators by size classes. These guidelines represent the minimum requirements for interconnection and recommended practice for DG equipment protection. The DG owner shall be the sole judge of what equipment is necessary to protect the DG units and associated electrical equipment. MPEI shall be the sole judge of what equipment is necessary to ensure a safe, reliable interconnection with MPEI’s system.

The size classes for parallel distributed generation are:

1)   25 kW and below;

2)   Greater than 25 kW;

341.04.1 Distributed Generation Less Than 25 kW

DG with less than 25 kW in capacity is covered by MPEI Net Metering regulations.

341.04.2 Distributed Generation Greater than 25 kW

DG with greater than 25 kW in capacity will be studied on a case-by-case basis by MPEI and Tri-State to determine specific requirements. Typical protective devices are listed below and shown in DG.

341.04.3 Typical Protective Device Descriptions

Device Numbers for Protective Equipment

13 – Speed Switch
15 – Tachometer Relay
25 – Synchronizing Relay
27 – Under voltage Relay
32 – Directional Power Relay
38 – Bearing Temperature
40 – Generator Field Failure Relay
46 – Phase-Balance (Reverse-Phase) Current Relay
47 – Phase-Sequence Voltage Relay
49 – Thermal Relay
        A) 49T – Transformer Thermal Relay
        B) 49G – Generator Thermal Relay
51 – Time-Over current Relay
        A) 51GB - Ground Bank Time-Over current
        B) 51T - Transformer Time-Over current
        C)  51V - Voltage-Restrained Time-Over current or Voltage-Controlled Time-Over current
52 - Circuit Breaker (52G - Generator Circuit Breaker)
59 - Overvoltage
64G - Ground Detector Relay
67 - Directional Over current
81 - Frequency Relay (over frequency & under frequency)
87 - Differential Relay
        A) 87G - Generator Differential
        B) 87T - Transformer Differential
90 - Field Voltage Regulator
S.A./L.A. - Surge Arrestor

341.04.4 Overview of Technical Requirements of Interconnection and Operation of DG Resources

• The DG installation must meet all applicable national, state, and local construction and safety codes as well as all requirements of MPEI and Tri-State.
   
• The DG installation must be equipped with protective hardware and software designed to prevent the generator from being connected to a de-energized circuit owned by MPEI. The DG installation shall not energize the point of common coupling when the MPEI system has been de-energized.
   
• The DG installation must be equipped with protective hardware and software designed to prevent the connection or parallel operation of the DG installation with the MPEI system unless the MPEI system service voltage and frequency is of nominal value.
   
• The DG installation shall not degrade the voltage provided to other MPEI members to service voltages outside the limits of ANSI C84.1, Range A.
   
• The MPEI distribution system is a four wire multi-grounded neutral system. All grounding must ensure that fault conditions are not worsened by the interconnection of the DG installation. For example in the MPEI system, the voltages of the unfaulted phases during a single line to ground fault with no DG installation will be the limit of the voltages of the same unfaulted phases during a single line to ground fault with the DG installation.
   
• The DG installation shall follow the MPEI system frequency with the range of 59.3 Hz to 60.5 Hz (on a 60 Hz nominal value). The DG installation shall disconnect from the MPEI system within 0.16 seconds if the frequency goes outside of the range specified.
   
• The DG installation shall synchronize with the MPEI system without causing a voltage fluctuation at the point of common coupling greater than +/-5% of the operating voltage. Synchronism shall be automatically performed by hardware and software
  .
• The DG installation shall be equipped with a disconnect that allows the DG installation and all protective devices and control apparatus to be disconnected entirely from the circuits supplied by the DG installation.
   
• Interconnection system response to abnormal voltages shall include disconnecting from the MPEI system within the following limits.

• The DG installation shall disconnect from the MPEI system in the case of a fault condition on the line to which it is connected.  The DG shall wait a minimum of five (5) minutes until after the Cooperative's system is restored to normal voltage levels before attempting to synchronize to the system.
   
• The DG installation shall individually be coordinated with the MPEI protection schemes that are utilized on the line to which it is connected.
   
• The DG installation shall not inject DC current greater than 0.5% of the full rated output current at the point of interconnection.
   
• The DG installation shall not create voltage flicker outside of industry accepted voltage flicker curves and in no case shall the flicker exceed 5% unless agreed to by MPEI.
   
• The DG installation shall not inject harmonic currents into the MPEI system outside the limits as stated in IEEE 519-1992. In no cases shall the THD of the current be above 5%.
   
• The DG installation shall in no way create electromagnetic interference that causes misoperation of MPEI system components.
   
• The DG installation shall have the capability to withstand voltage and current surges in accordance with the environments defined in IEEE/ANSI C62.41 or IEEE C37.90 as appropriate.
   
• Islanding is not acceptable with the DG installation. Islanding is when a DG installation keeps a portion of the MPEI system energized when power has been disconnected for some reason.
   
• The DG installation shall produce power at a minimum 95% power factor whether leading or lagging. The DG installation shall strive to produce power at unity power factor.

For net metered Distributed Generation installations where most of the energy generated by a renewable resource (solar, wind, hydro, biomass, waste) is used by the customer at the net metered service, the following rates apply to the energy delivered to the Cooperative:

a.     Monthly energy generated by the DG, but not delivered to Cooperative:  All energy generated by the customer, but not delivered to the Cooperative, may be used to offset energy that the customer would have otherwise purchased from the Cooperative.  This energy will not otherwise be credited or paid for by Cooperative.

b.     Monthly energy delivered to the Cooperative: Any monthly energy delivered to the Cooperative by the customer will be credited to the customer's monthly bill at the Cooperative's average wholesale cost of power (demand and energy charges) during that month.

c.     The customer retains all rights to environmental attributes (renewable energy credits).

1)            Customer with potential DG Facility contacts MPEI and obtains Application for Interconnection (Application).

2)            The DG submits the Application to MPEI. If DG’s nameplate capacity is greater than 25 kW, the Qualifying Facility Design Data Requirements shown in Section 341.08 are also required.

3)            MPEI evaluates the Application for Interconnection for completeness and notifies the DG owner within ten business days of receipt that the Application is or is not complete and, if not, advises what material is missing.

4)            Within 15 business days, MPEI conducts preliminary engineering studies, if warranted, to determine the effect the DG might have on existing MPEI customers and equipment.

5)            Provided all the criteria in the Interconnection Standards for Distributed Generation are met, unless MPEI determines and demonstrates that the DG cannot be interconnected safely and reliably, MPEI approves and executes the Application and returns it to the Customer.   If MPEI determines that a system impact study and facility study is necessary to evaluate the proposed DG interconnect, MPEI will estimate the cost to complete the necessary studies, including consulting engineer costs, and will notify the DG owner of additional engineering deposit payment required prior to authorizing any further studies.

6)            MPEI designs and constructs the interconnection and provides a line extension contract with estimated costs to the DG owner.  After receipt of the executed line extension contract and receipt of the full estimated costs, MPEI modifies the existing MPEI network as necessary to accept the DG.   MPEI also provides the DG owner with interconnection agreement, and if applicable the power purchase contract.  The DG owner signs and returns those agreements to MPEI.

7)            The DG owner provides notice of insurance coverage. The DG owner should investigate liability insurance coverage early in the planning stage.

8)            After installation, the Customer returns the Certificate of Completion to MPEI. Prior to parallel operation, MPEI will inspect the DG facility for compliance with standards within ten business days of the receipt of the Certificate of Completion. MPEI will inspect the DG for compliance with standards, and may schedule appropriate metering replacement, if necessary.

9)            MPEI notifies the Customer in writing or by fax or e-mail that interconnection of the DG is authorized within five business days. If the witness test is not satisfactory, MPEI has the right to disconnect the DG. The customer has no right to operate in parallel until a witness test has been performed.

10) Interconnection and startup.

General

− NFPA 70 (2008), National Electrical Code (NEC)
− IEEE Std 929-2000 IEEE Recommended Practice for Utility Interface of Photovoltaic (PV) Systems
− UL 1741 Inverters, Converters, and Controllers for Use in Independent Power Systems
− IEEE1547 Standard for Interconnecting Distributed Resources with Electric Power Systems (including use of IEEE 1547.1 testing protocols to establish conformity)
− National Electrical Safety Code (NESC 2007)
− Local Building Codes
− NEMA MG 1-1998, Motors and Small Resources, Revision 3
− NEMA MG 1-2003 (Rev 2004), Motors and Generators, Revision 1
− ANSI C84.1-1995 Electric Power Systems and Equipment – Voltage Ratings (60 Hertz)
− IEEE Std 100-2000, IEEE Standard Dictionary of Electrical and Electronic Terms
− NEPA 70E (2009), Standard for Electrical Safety in the Workplace

Grounding

− REA Bulletin 65-1, “Design Guide for Rural Substations”
− IEEE Standard 142, “Recommended Practice for Grounding of Industrial and Commercial Power Systems”

Voltage Drop

− REA Bulletin 169-27, “Voltage Regulator Application on Rural Distribution Systems”

− REA Bulletin 169-4, “Voltage Levels on Rural Distribution Systems”

Phase Balance

− <3% (three phase difference)

Frequency

− +0.1 (for Qualifying Facility of rated capacity greater than 5 kW)

Harmonics

− IEEE Standard 519, “IEEE Guide for Harmonic control and Reactive Compensation of Static Power Converters”

Flicker

− REA Bulletin 160-3, “Engineering and Operations Manual - Service to Induction Motors”

Surge Control

− IEEE Std C62.41 .2-2002, “IEEE Recommended Practice on Characterization of Surges in Low Voltage (1000V and Less) AC Power Circuits”

− IEEE Std C37.90.1-1989 (R1 994), “IEEE Standard Surge Withstand Capability (SWC) Tests for Protective Relays and Relay Systems”

− IEEE Std C62.45-1992 (R2002), IEEE Recommended Practice on Surge Testing for Equipment Connected to Low-Voltage (1000V and Less) AC Power Circuits

Interference

− IEEE Std C37.90.2 (1995), IEEE Standard Withstand Capability of Relay Systems to Radiated

Service Reliability

− Qualifying Facility shall not cause loss of service to other customers.

Other (May Be Required)

− City/County Zoning or Building Permit

− Section 404 Clean Water Act Permit

− Colorado Department of Health

− Emission Permit/Fugitive Dust Permit

− Special Use Permit/Conditional Use Permit from County - FAA Approval for tower

Mountain Parks Electric, Inc. (MPEI) reviews all proposals for interconnection of a DG facility for compliance with MPEI guidelines and Colorado Public Utilities Commission Rules. MPEI attempts, insofar as is reasonable, to determine whether a design will create problems on MPEI’s system but cannot comment or make assurances on the technical prudence or economic feasibility of a proposed project.  MPEI cannot review your facility design until a complete design package is submitted. Typically, a complete design package would include:

1.            A complete site plan, detailing physical locations of all equipment to be installed from MPEI’s supply line to the powerhouse. This plan should show sufficient detail to determine physical clearances between pieces of equipment and between any piece of equipment and an adjacent permanent structure. The site plan should show the location of proposed metering, disconnecting and circuit protective devices. Particular detail should be given to physical location of equipment in the powerhouse, and provisions for grounding of powerhouse equipment.

2.            A system one-line diagram which states wire sizes and types, as well as ratings and types of circuit protective devices. This diagram should include all equipment which has been installed or which will be installed up to MPEI’s connection.

3.            A relay control diagram which clearly indicates relay contact arrangements and which indicates functionally the operation of all relays, protective devices and interlocks.

4.            Device types, sizes, model numbers, settings and manufacturer’s data on all circuit protective devices and relays.

5.            The location, ratings, impedances, time constants and manufacturer’s data for the generator and all associated control equipment, including but not limited to exciters, governors, voltage regulators and synchronizers, where applicable.

6.            The location, ratings and switching arrangement for power factor correction capacitors, if any.

7.            Proposed operating procedures for startup, shutdown and restart functions. The procedures should include all operational parameters and appropriate limits of operation.

8.            Anticipated peak power production and monthly energy production figures.

MPEI recommends not purchasing equipment or beginning construction of facilities until a design review is completed and MPEI gives final written design approval.

The Cooperative may discontinue service to a Customer under any of the following circumstances:

A.        Nonpayment of a Bill

If the Customer fails or refuses to pay a delinquent account for electric service (whether or not based upon estimated billing); or

B.        Deferred Payment Plan

If the Customer fails to perform any obligation under the terms of a deferred payment agreement; or

C.        Interference with Service

If Customer violates any rule pertaining to the use of electric service in a manner which interferes with or is likely to cause interference with electric service to other Customers or operates nonstandard equipment, provided that the Cooperative has made a reasonable effort to notify the Customer and provided there has been a reasonable opportunity to remedy the situation; or

D.        Failure to Make Application for Service

If Customer fails or refuses to make application for electric service in accordance with these rules; or

E.         Refusal of Access

If Customer fails or refuses to provide the Cooperative reasonable access to its facilities located on Customer’s premises; or

F.         Default on Guaranty Agreement.

If a Customer, whose account is in good standing, has signed a written Guaranty Agreement for another Customer or applicant and fails or refuses to pay the amount due on the guaranteed account when requested to do so by the Cooperative; or

G.        Comply with Law

If Customer fails or refuses to comply with any applicable Federal, State, Municipal, or other law, ordinance, rule or regulation; or

H.        Back-billing

If Customer fails or refuses to timely pay any billing authorized by these rules resulting from previous under-billing (whether caused by meter inaccuracy, misapplication of rates or otherwise). Correction of billings for meter inaccuracy shall be made for the period of six (6) months immediately preceding removal of the inaccurate meter from service for testing or from the time the meter was in service since last tested, but not exceeding six (6) months. If a meter is found not to register for any period, unless bypassed or tampered with, the Cooperative shall make a charge for units used, but not metered, for a period not to exceed six (6) months, based on amounts used under similar conditions during the period preceding or subsequent thereto, or during corresponding periods in previous years; or

I.          Hazardous Condition

When a hazardous condition exists in Customer’s installation or equipment;                        or

J.          Meter Tampering

If Cooperative’s meter which serves Customer has been tampered with or bypassed, the Cooperative may discontinue service. For purposes of this section, meter tampering, bypass, or diversion shall be defined as tampering with an electric meter or equipment, bypassing the same, or other instance of diversion, such as physically disorienting the meter, objects attached to the meter to divert service or to bypass, insertion of objects into the meter, and other electrical and mechanical means of tampering with bypassing, or diverting electrical service or there has been a theft of electric service; or

K.        Insufficient Fund Checks

Payments made for electric service by personal checks that are returned to the Cooperative as being insufficient, account closed, or other reasons will be considered as a non-receipt of payment and be subject to discontinuance of electric service for non-payment of account. Notification will be rendered to the Customer as set forth in the Cooperative’s rules on discontinuance of electric service.

The Cooperative may also require payment in the form of cash or cash equivalent after two (2) or more checks are returned to the Cooperative.

L.         Unauthorized interconnection of parallel source (Generator)            

The unauthorized interconnection of a parallel source (generator, net metering system, or co-generation system) shall be reason for discontinuance of service as a safety hazard.

Discontinuance of service shall not occur until the Cooperative has made a reasonable effort to give notice of the proposed discontinuance to the Customer, or a responsible member of Customer’s household, or to any designated third party of the Customer.

A.        Notification Procedure

The following notification of delinquency and discontinuance of service shall be implemented by the Cooperative;

1.         The due date for payment of the billing for electric service shall be upon receipt of and noted on the invoice, clearly and conspicuously.
2.         The account will be considered delinquent normally thirty (30) days after the account is billed.
3.         If payment is not received by the delinquent date, the Cooperative will assess a late payment fee of 1.5%. Also, a notice of delinquency shall be mailed to the Customer stating payment is due within ten (10) days, the date payment is due, and the amount of payment required to avoid service being discontinued for non-payment of account.
4.         If payment is not received by the final due date, a reasonable effort shall be made to contact by telephone at least 48 hours prior to the proposed disconnect date, and at least 24 hours prior to the proposed disconnect date a representative of the Cooperative will attempt to make contact with the Customer, or failing to do so, shall leave a written notice at the premise.

Discontinuance of service shall not occur between 12 noon on Friday and 8:00 AM the following Monday or between 12 noon on the day prior to and 8:00 AM on the day following any closure of the Cooperative business office.

On or before the expiration date of a notice of discontinuance, the Customer may pay at least one-third of the amount shown on the notice of discontinuance and enter a deferred payment plan as described in this Tariff.

Any employee dispatched to discontinue service will be authorized to receive full payment.

B.        Disconnection Without Notice.

Electric service may be disconnected without any notice to the Customer if;

1.         Discontinuance of service to the premises is imperative for reasons of safety. Such reasons might include a condition or installation of any part of the Customer’s or the Cooperative’s lines, apparatus or appliance which is found to be dangerous to life, health or safety of any person.

2.         Discontinuance is ordered by any properly constituted governmental authority to protect the health or welfare of any person or property or due to alleged violations by the Customer of the ordinances,statutes or regulations applicable to the service. The Cooperative shall not be responsible for ascertaining such conditions.

3.         Service having been discontinued in accordance with this tariff is discovered restored by someone other than the utility and the original cause for discontinuance has not been cured.

C.        Disconnection After Reasonable Notice.

1.         Electric service will be disconnected for violation of service rules pertaining to the use of service in a manner that interferes with the service of others or the operation of nonstandard equipment [Section 351.1(C)], if a reasonable attempt has been made to notify the customer and the customer is provided with a reasonable opportunity to remedy the situation.

2.         Electric service will be disconnected for failure to make application for service [Section 351.1 (D)]; refusal of access [Section 351.1 (E)]; failure to pay a bill to correct previous under-billing [Section 351.1 (H)]; default on guarantee agreement [Section 351.1 (F)]; if reasonable notice is given. Reasonable notice shall consist of a separate mailing or hand delivery at least ten (10) days prior to a stated date of disconnection with the words “termination notice” or similar language prominently displayed on the notice, a reasonable effort shall be made to contact by telephone at least 48 hours prior to the proposed disconnect date, and at least 24 hours prior to the proposed disconnect date a representative of the Cooperative will attempt to make contact with the Customer, or failing to do so, shall leave a written notice at the premise. The information included in the notice shall be provided in English and Spanish as necessary to adequately inform the customer. If mailed, the cut-off day may not fall on a holiday or weekend but shall fall on the next working day after the tenth day.

If discontinuance of service involves individual permanent residents of multi-unit dwellings where service for the entire multi-unit dwelling is supplied through one meter, or in the case of multiple meters, if any one meter would have an adverse effect upon other occupants, and the Cooperative is aware of such condition,discontinuance of service shall occur only after the Cooperative has given thirty (30) days notice of intent to terminate to the party responsible for payment of utility bills for the dwelling and to individual occupants of each unit within the dwelling. Notice to such individual occupants shall be delivered to each dwelling unit or mailed to the addressee or occupant if known of each unit. In addition, a copy of said notice shall be posted, to the extent possible, in at least one of the common areas of the multi-unit dwelling. Occupants of a multi-unit dwelling may avoid termination by agreeing to pay each new bill within thirty (30) days of issuance. Occupants so agreeing shall not be entitled to installment payments or any other payment plan and may be discontinued without further notice or attempt a personal contact for failure to pay each new bill within thirty (30) days of issuance.

The Cooperative will not discontinue electric services, or if already discontinued will restore, during any period when discontinuance of electric service will be especially dangerous to the health or safety of a residential customer or a permanent resident of the customer’s household.

Discontinuance of electric service that would be especially dangerous to the health or safety of the residential household means that discontinuance of electric service would aggravate an existing medical condition or create a medical emergency for the customer or a permanent resident of the customer’s household. Such shall be deemed to be the case when a physician licensed by the State of Colorado, or a health practitioner licensed by the State of Colorado and acting under a physician’s authority, makes a certification there of and said certification is received by the Cooperative in writing or by phone. A utility may require written confirmation of a certification received by phone within ten (10) days of the call. Such certification shall be incontestable by the utility as to medical judgment, although the utility may use reasonable means to verify the authenticity of such certification.

In the event a medical certification is delivered to or received by the Cooperative, the non-discontinuance of electric service shall be effective for sixty (60) days from the date of said medical certification. One thirty (30) day extension of the non-discontinuance of electric service may be effected by the delivery to or receipt by the Cooperative of a second medical certification, as aforesaid, prior to the expiration of the initial sixty (60) day period.

A residential customer may invoke the provisions of this clause no more than once during any period of twelve (12) consecutive months, said period to commence on the first date said medical certification is presented.

A Customer who invokes this clause may request an installment payment plan arrangement on or before the last day covered by a medical certification or extension thereof. A Customer who already has entered an installment payment plan arrangement and who has not broken arrangements prior to invoking this clause may renegotiate the installment payment plan arrangement on or before the last day covered by a medical certification or extension thereof. A Customer who already has entered an installment payment plan arrangement but has broken arrangements prior to invoking this clause must pay, on or before the last day covered by the medical certification or extension thereof, all amounts that would have been paid up to that date had arrangements not been broken, and resume the installment payment plan arrangement, in order to avoid discontinuance of electric service.

Disconnection by the Cooperative is prohibited for the following reasons:

A.  Delinquency in payment for utility service by a previous occupant on the premises;
B.  Failure to pay for merchandise, or charges for non-utility service provided by the Cooperative;
C.  Failure to pay for a different type or class of utility service unless fee for such service is included on the same bill;
D.  Failure to pay the account of another customer as guarantor thereof, unless the Cooperative has in writing the guarantee as a condition precedent to service;
E.  Failure to pay charges arising from an under-billing occurring due to any misapplication of rates more than six months prior to the current billing;
F.  Failure to pay charges arising from under-billing due to any faulty metering, unless the meter has been tampered with or unless such under-billing charges are due;
G.  Failure to pay an estimated bill other than a bill rendered pursuant to an approved meter-reading plan, unless the Cooperative is unable to read the meter due to circumstances beyond its control;
H.  For non-payment of any sum due which has not appeared on a regular monthly bill. The due date must be specifically indicated on the bill;
I.    For non-payment of any sum due which is less than (30) days past due; nor shall any notice of intent to discontinue service be sent with respect to any amount which is not thirty days past due;

A.        Customer’s Obligations

Discontinuance of service shall not relieve Customer from any obligation to the Cooperative or lessen or change any obligation in any manner.

B.        Cooperative’s Rights

Discontinuance of service shall not reduce, diminish, or eliminate any legal right or remedy accruing to the Cooperative on or before the date of discontinuance, nor shall discontinuance operate as a waiver of any legal right or remedy.

Failure of Cooperative to discontinue electric service at any time after default or breach of these Service Regulations, the rate under which Customer is receiving electric service, or the Electric Service Agreement, or to resort to any legal remedy or its exercise of any one or more of such remedies does not affect the Cooperative’s right to resort thereafter to any one or more of such remedies for the same or any default or breach by Customer.

Service which has been terminated due to failure to pay or make arrangements for payment of bills for service rendered will be restored if Customer pays all applicable collection and/or re-connection charges. If service is terminated after breach of arrangements, service will be reinstated only after Customer has made payment in full of all amounts owed, including any collection and/or re-connection charges and after posting any deposit required for service.

Service also will be restored upon receipt of a valid medical certificate and will not be discontinued again until said medical certificate, or any valid extension thereof, has expired.

Where service has been discontinued as set forth in these rules, the Cooperative shall restore such service within twelve (12) hours after elimination by Customer of the cause for discontinuance, unless extenuating circumstances prevent restoration. Extenuating circumstance includes the restoration of service outages or the requirement that the Customer or someone designated by the Customer to be present at the premises at the time of restoration.

The Cooperative may, upon discontinuance of electric service to Customer, retire and remove all lines, equipment, apparatus, or other facilities which the Cooperative may have installed to provide electric service to Customer. The Cooperative may, however, abandon in place, in whole or in part its underground lines and equipment in lieu of removing such facilities.

The Cooperative shall not be liable for any damages of any kind or character resulting from discontinuance or disconnection made pursuant to these rules.

After disconnection of service, if service is not reconnected, the Cooperative shall refund the Customer’s deposit, plus accrued interest on the balance, if any, in excess of unpaid bills for service furnished.

A person requesting electric service from the Cooperative in the manner prescribed in the Cooperative’s service rules and regulations.

The Public Utilities Commission of Colorado.

Mountain Parks Electric, Inc.

The Cooperative’s primary and secondary voltage conductors, transformers, switchgear, connection enclosures, pedestals, services, and other associated equipment used to provide electric service.

Electric power and energy produced, or transmitted, or distributed, or provided, or made available by the Cooperative at the point of delivery together with all services and functions performed by the Cooperative.

The capacity for doing work. The unit for measuring electrical energy is the watt hour, or kilowatt hour which is 1,000 watt hours (kWh).

All the plant and equipment of the Cooperative including all tangible personal property without limitation, in any manner owned, operated, leased, licensed, used, controlled, furnished, or supplied for, by or in connection with the business of the Cooperative.

Any person (customer) receiving electric service from the Cooperative.

All conductors, equipment, buildings, structures, or apparatus of any kind on the Customer’s side of point of deliver, excluding only Cooperative’s meter equipment.

A device, or devices, together with auxiliary equipment, for measuring electric energy usage and/or demand and/or other data.

Any incorporated city, town, or village.

Any installation other than a permanent installation.

The Cooperative and an applicant or Customer.

Any installation that is constructed on or permanently affixed to a foundation, and which is, or will be, used or occupied on a permanent full-time basis. A manufactured home or prefabricated structure shall qualify as a permanent installation only if it is installed on a foundation system according to regulations of the Colorado Department of Labor and Standards or is otherwise impractical to     move and has the wheels, axles, and hitch or towing device removed, and if it is connected to a permanent water and sewer system.

Any individual, partnership, association, joint venture, corporation, or governmental entity.

The point where the Cooperative’s conductors are connected to the Member’s conductors.

A tract of land or real estate, including buildings or other appurtenances thereon.

Any schedule of rates approved by the Board of Directors and contained in Section II of these tariffs.

The Public Utilities Commission of Colorado, Rural Utilities Services, or the governing body of any municipality with which service is provided.

Any service rule or regulation of the Cooperative approved by the Board of Directors and contained in Section III of these tariffs.

The area or territory in which the Cooperative provides electric utility service.

Conductors provided by the Member extending from Member’s electrical  equipment to the point of delivery where connection is made to the Cooperative’s conductors.

In computing a period of days, the first day is excluded and the last day is included.  If the last day of any period is a Saturday, Sunday or State of Colorado legal holiday, the period shall be extended to include the next day which is not a Saturday, Sunday or State of Colorado legal holiday.

As used in these Regulations, the following words shall have the meanings indicated unless the context otherwise requires:

1. The words "this Corporation" shall mean Mountain Parks Electric, Inc.
    
2. The word "Board" shall mean the Board of Directors of this Corporation.
    
3. The word "consumer" shall mean any person who is not a member but who has contracted for and directly receives electric service from this Corporation.
    
4. The words "immediately shuts off service" or "immediate shut off policy" shall mean any situation in which the Corporation voluntarily disconnects service to a member or consumer without prior notice.
    
5. The phrases "increase in rates" or "general increase" or similar terms, shall mean and include any increase in a rate or any change in a rule or regulation which has the effect of increasing any rate of this Corporation to an existing member or consumer.

6. The words "local newspaper" shall mean the newspapers having a circulation in the areas of the state wherein are located the members and consumers of this Corporation affected by the matter of which notice is given.
    
7. The word "member" shall mean any person who has executed an application for membership with this Corporation, whose application has been accepted, and who directly receives electric service from this Corporation.
    
8. The word "person" shall mean any natural person, firm, partnership, corporation, company, association, joint venture or any other legal entity.
    
9. The words "presiding officer" shall mean the President of this Corporation or such other person (s) as may be designated by the Board to conduct a hearing under these Regulations.  The presiding officer need not be a Director, member or consumer of the Corporation.
    
10. The words "pro se" shall mean any individual appearing on his own behalf in a proceeding under these Regulations.
     
11. The word "rate" shall mean and include any rate, fare, toll, rental or charge.
     
12. The word "tariff" shall mean and include any rate, classification, rule, regulation, policy, or contract relating to or affecting any rate, classification, or service, or any privilege or facility.

An informal complaint is one that may be resolved without formal order.  Members and consumers must use the informal complaint procedure before filing a formal complaint, unless an emergency exists which precludes the use of the informal complaint procedure, or unless a proposed increase in rates is involved.  An informal complaint may be in writing or may be made orally to an office employee of the Corporation authorized to receive complaints at any local office, but in any event shall contain such facts and other information, including supporting data and documents, to adequately state the circumstances by which any act or thing done or omitted to be done by this Corporation, including any rule, regulation or charge heretofore established or fixed or proposed to be established or fixed, is in violation, or claimed to be in violation, of any provision of law or of any order or rule of this Corporation.  No anonymous informal complaint shall be considered.  An informal complaint shall be referred to the General Manager of this Corporation or his designee, and said General Manager or designee shall attempt to resolve such complaint, within the law, orders, rules and regulations of this Corporation, as soon as reasonably practicable, and if the said informal complaint is not resolved within 30 days after filing, the same shall be deemed denied.  Where an informal complaint is not resolved to the satisfaction of the complainant, he may file a Formal Complaint.  The informal complaint, Form No. 2 attached to these regulations may be used if the complainant so desires.

Informal complaints shall be made no later than six (6) months following the act or omission complained of or within six (6) months of the date the complainant knew or reasonably should have known of the act or omission complained of.

The General Manager or his/her designee, may, in their discretion, submit an informal complaint to the   Board of Directors of the Corporation for review and/or determination.

Prior to filing a Formal Complaint, a complainant must comply with the informal complaint procedures set forth in Tariff 410 (A) above.

A Formal Complaint shall be in writing, and generally shall conform to Form No. 3 attached to these Regulations.  Said complaint shall set forth sufficient facts and other information to adequately state the circumstances by which any law or order or rule or tariff provision of this Corporation has been violated.  Said complaint may be amended up to ten days before the hearing, if any.

A Formal Complaint may be filed with this Corporation by any member or consumer of this Corporation concerning (1) the rates charged by this Corporation, (2) the manner in which electric service is provided by this Corporation, and (3) proposed changes in the rates or regulations of this Corporation.  A Formal Complaint filed under this Rule shall not be entertained unless said complaint is signed as herein required.  If a Formal Complaint does not substantially comply with these Regulations, it can be rejected or dismissed for that reason alone.

Form No. 1

NOTICE TO CHANGE TARIFFS

AS DEFINED IN Tariff 408

NOTICE

Date of Notice: ______, ______

NOTICE OF A CHANGE IN THE TARIFFS OF

MOUNTAIN PARKS ELECTRIC ASSOCIATION, INC.

321 WEST AGATE
P.O. BOX 170
GRANBY, COLORADO 80446

You are hereby notified that the above name Corporation proposes to make the following changes in its tariffs, to become effective _________________ (Date)                 

(NOTE:  State fully the changes to be put into effect and the present tariff provision(s) to be changed; or if too lengthy, call attention to the effect of the changes and state that the proposed and present tariff provisions are available for examination and explanation at each business office of such association, stating the address of each such office.  In the event changes in rates are involved, the notice also shall state the dollar changes (or ranges thereof) or percentage increases (or ranges thereof) for each class or type of service).

Anyone who desires to complain about the proposed change shall file a written complaint with the Corporation at 321 West Agate, P.O. Box 170, Granby, Colorado 80446, at least 10 days before the proposed effective date.  In any such complaint a request for a hearing on the complaint should be made if you wish such a hearing.

The Corporation may hold a hearing to determine what changes will be authorized.  The changes ultimately authorized may or may not be the same as those proposed and may include changes different than those tariffs proposed or currently in effect.  Anyone who desires to receive notice of hearing, if any, shall make a written request therefore to the Corporation, at the above address, at least 10 days before the proposed effective date.

MOUNTAIN PARKS ELECTRIC, INC.

BY _____________________________________

             Board President

STATE OF COLORADO         )

                                                )

COUNTY OF GRAND             )

A F F I D A V I T

___________________________________, of lawful age, being first duly sworn upon his oath, states:
 

1.  That he is ________________________ of Mountain Parks Electric, Inc. (Mountain Parks)    

                                        Title

2.  That on __________________________, ______, he mailed true copies of the attached Notice to all

Mountain Park's customers, (first class), postage prepaid, at the addresses as shown on Mountain Park's records.

                                                                                                     OR

3.  That he caused the attached Notice to be published in newspapers of general circulation in Mountain Park's

service territory as follows:

                                Name of Paper                                         Date Published

DATED:  _______________________, _______                                                                               

The foregoing Affidavit was acknowledged before me this _____ day of _____________, ______, by ___________________________.

WITNESS my hand and official seal.

My Commission Expires:                        ______________________________________

                                                                ______________________________________

                                                                NOTARY PUBLIC

                                                                 ______________________________________      

                                                                 ______________________________________

(NOTARY SEAL)                                      ______________________________________

                                                                                Notary's Street Address

Form No. 2

FORM OF INFORMAL COMPLAINT

INFORMAL COMPLAINT

NAME:                    _______________________________________________

ADDRESS:              _______________________________________________

                                _______________________________________________

                                _______________________________________________

PHONE:                   (    )_______________(Home)

                                (    )_______________(Work)

COMPLAINT

(Please state the specific act or thing complained of, together with such facts as are necessary to give a full understanding of the situation.  Please use additional sheets if necessary.)

_______________________________________________________________________________________________

_______________________________________________________________________________________________

_______________________________________________________________________________________________

_______________________________________________________________________________________________

 ________________________________________             ____________________________

                   Signature of Complainant                                                         Date

*************************************************************************************************

FOR OFFICE USE ONLY:

Date Received:         ___________________________, _________

Disposition_______________________________________________________________________________________________________________________________________________________________________________________________________________

________________________________________________________________________________________________________________________________________________________________________________________________________________________

_________________________________________________________________________________________________________________________________________________________________     

(Name of Each Complainant)                                                 )

                                                                                                )              

Complainant(s),                                                                       )                               CASE NO. _________

vs.                                                                                            )

MOUNTAIN PARKS ELECTRIC , INC.                                    )                                                              

                                Respondent                                              )

Mountain Parks Electric, Inc.

Form No. 3

FORMAL COMPLAINT

The Complainant(s) state:

1.  The name and address and telephone number of each person making this Complaint are as follows:

                                                    _____________________________________

                                                    _____________________________________

                                                                                 (Names)

                                                     _____________________________________

                                                     _____________________________________

                                                                                 (Address)

                                                    _____________________________________

                                                                                  (Telephone)

2.  The Complainant(s) will appear at the hearing on this Complaint.

3.  The specific act or thing complained of, together with such facts as are necessary to give a full understanding of the situation complained of are as    follows: (Use additional sheets if necessary)

________________________________________________________________________________________________________________________________________________________________________________________________________________________

________________________________________________________________________________________________________________________________________________________________________________________________________________________

______________________________________________________________________________________________________________________________________________________

Wherefore, Complainant(s) request the Board of Directors of Mountain Parks Electric, Inc. to grant the Complainant(s) the following relief:

________________________________________________________________________________________________________________________________________________________________________________________________________________________

_____________________________________________________________________________________________________________________________________________________________________     

(State what you want the Board to do.  Use additional sheets if necessary.)

DATED:  __________________, ________

SIGNATURES:

_____________________________________                                                                                              

_____________________________________

           (Each Complainant Must Sign)

Mountain Parks Electric, Inc.

VERIFICATION

STATE OF COLORADO         )

                                                                ) ss.

COUNTY OF                           )              

The undersigned, being first duly sworn upon oath, deposes and says that he/she has read the above and foregoing complaint and any attachments thereto and believes the facts stated herein to be true.

                                                            _______________________________________

                                                            _______________________________________

                                                                          (Signature of each Complainant)

Acknowledged and sworn to before me this ___ day of _________________, _______, by

WITNESS my hand and official seal.

My Commission Expires:        __________________________________

                                                __________________________________

                                                                    NOTARY PUBLIC

(NOTARY SEAL)