61184 Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 

1WAPA–106 was approved by FERC on a final 

basis on January 31, 2005, in Docket No. EF2–04– 

5182–000 (110 FERC ¶ 62,084). 2WAPA–141, Extension of Rate Order No. 

WAPA–106 through February 28, 2011. 73 FR 

48382, August 19, 2008. 3WAPA–118 was approved by FERC on a final 

basis on November 17, 2006, in Docket No. EF–06– 

5182–000 (117 FERC ¶ 62,163). 4WAPA–154, Extension of Rate Order Nos. 

WAPA–106 and WAPA–118 through February 28, 

2013. 76 FR 1429, January 10, 2011. 

DEPARTMENT OF ENERGY 

Western Area Power Administration 

Loveland Area Projects—Western Area 

Colorado Missouri Balancing 

Authority—Rate Order No. WAPA–155 

Republication 

Editorial Note: FR Doc. 2011–23391 was 

originally published on pages 56433–56452 

in the issue of Tuesday, September 13, 2011. 

In that publication an incorrect version of 

this document was published. The corrected 

document is republished below in its 

entirety. 

AGENCY: Western Area Power 

Administration, DOE. 

ACTION: Notice of order concerning 

transmission and ancillary services 

formula rates. 

SUMMARY: The Deputy Secretary of 

Energy has confirmed and approved 

Rate Order No. WAPA–155 and Rate 

Schedules L–NT1, L–FPT1, L–NFPT1, 

L–AS1, L–AS2, L–AS3, L–AS4, L–AS5, 

L–AS6, L–AS7, L–AS9, and L–UU1, 

placing Loveland Area Projects (LAP) 

transmission and Western Area 

Colorado Missouri (WACM) Balancing 

Authority ancillary services formula 

rates into effect on an interim basis. The 

provisional formula rates will be in 

effect until the Federal Energy 

Regulatory Commission (FERC) 

confirms, approves, and places them 

into effect on a final basis or until they 

are replaced by other formula rates. The 

provisional formula rates will provide 

sufficient revenue to pay all annual 

costs, including interest expense, and to 

repay power investment within the 

allowable periods. 

DATES: Rate Schedules L–NT1, L–FPT1, 

L–NFPT1, L–AS1, L–AS2, L–AS3, L– 

AS4, L–AS5, L–AS6, L–AS7, L–AS9, 

and L–UU1 will be placed into effect on 

an interim basis on the first day of the 

first full billing period beginning on or 

after October 1, 2011, and will remain 

in effect until FERC confirms, approves, 

and places the rate schedules into effect 

on a final basis for a 5-year period 

ending September 30, 2016, or until the 

rate schedules are superseded. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Bradley S. Warren, Regional Manager, 

Rocky Mountain Customer Service 

Region, Western Area Power 

Administration, 5555 East Crossroads 

Boulevard, Loveland, CO 80538–8986, 

telephone (970) 461–7201, or Mrs. 

Sheila D. Cook, Rates Manager, Rocky 

Mountain Customer Service Region, 

Western Area Power Administration, 

5555 East Crossroads Boulevard, 

Loveland, CO 80538–8986, telephone 

(970) 461–7211, e-mail 

scook@wapa.gov. 

SUPPLEMENTARY INFORMATION: The 

Deputy Secretary of Energy approved 

current Rate Schedules L–NT1, L–FPT1, 

L–NFPT1, L–AS1, L–AS2, L–AS3, L– 

AS4, L–AS5, L–AS6, and L–AS7 on 

December 30, 2003 (Rate Order No. 

WAPA–106, 69 FR 1723, January 12, 

2004).1 These rates became effective on 

March 1, 2004, with an expiration date 

of February 28, 2009. The rate 

schedules, with the exception of Rate 

Schedule L–AS3, Regulation and 

Frequency Response, were extended 

through February 28, 2011, under Rate 

Order No. WAPA–141.2 Rate Schedule 

L–AS3 was revised and approved under 

Rate Order No. WAPA–118,3 which 

became effective on June 1, 2006, with 

an expiration date of May 31, 2011. 

Under Rate Order No. WAPA–154,4 all 

LAP transmission and WACM ancillary 

services rate schedules, including L– 

AS3, were extended through February 

28, 2013. 

LAP Transmission Service 

Rate Schedules L–NT1, L–FPT1, and 

L–NFPT1 for LAP transmission services 

are based on a revenue requirement that 

recovers the LAP transmission system 

costs for facilities associated with 

providing all transmission services as 

well as the non-transmission facility 

costs allocated to transmission services. 

These firm and non-firm LAP 

transmission service rates include the 

costs for scheduling, system control, 

and dispatch service needed to provide 

the transmission service. 

Rate Schedule L–UU1, Unreserved 

Use Penalties, is a new rate schedule 

established in accordance with 

Western’s Open Access Transmission 

Tariff (Tariff). This rate will recover 

costs for transmission service that has 

not been reserved or has been used in 

excess of the amount reserved. Rate 

Schedule L–UU1 also provides for a 

penalty in addition to the base charge 

for the transmission service used. 

Previously, a penalty for unauthorized 

use of transmission was included in the 

Point-to-Point Transmission Service, 

Rate Schedules L–FPT1 and L–NFPT1. 

Rate Schedule L–AS7, Transmission 

Losses Service, is designed to recover 

losses on all real-time and prescheduled 

transactions on transmission facilities 

inside WACM. 

Ancillary Services 

Western will provide seven ancillary 

services pursuant to its Tariff. These are: 

(1) Scheduling, System Control, and 

Dispatch Service (L–AS1); (2) Reactive 

Supply and Voltage Control from 

Generation or Other Sources Service (L– 

AS2); (3) Regulation and Frequency 

Response Service (L–AS3); (4) Energy 

Imbalance Service (L–AS4); (5) 

Spinning Reserve Service (L–AS5); (6) 

Supplemental Reserve Service (L–AS6); 

and (7) Generator Imbalance Service (L– 

AS9). Generator Imbalance Service is 

also a new rate schedule established 

under the Tariff. Currently, Generator 

Imbalance Service is provided under 

Rate Schedule L–AS4, Energy Imbalance 

Service. 

Rates for LAP transmission and 

ancillary services will be recalculated 

each year to incorporate the most recent 

financial, load, and schedule 

information and will be applicable to all 

transmission and ancillary services 

customers. 

By Delegation Order No. 00–037.00, 

effective December 6, 2001, the 

Secretary of Energy delegated (1) the 

authority to develop power and 

transmission rates to the Administrator 

of Western; (2) the authority to confirm, 

approve, and place such rates into effect 

on an interim basis to the Deputy 

Secretary of Energy; and (3) the 

authority to confirm, approve, and place 

into effect on a final basis, to remand, 

or to disapprove such rates to FERC. 

Existing Department of Energy 

procedures for public participation in 

power rate adjustments (10 CFR 903) 

were published on September 18, 1985 

(50 FR 37835). 

Under Delegation Order Nos. 00– 

037.00 and 00–001.00C, 10 CFR part 

903, and 18 CFR part 300, I hereby 

confirm, approve, and place Rate Order 

No. WAPA–155, the proposed LAP 

transmission and WACM ancillary 

services formula rates, into effect on an 

interim basis. By this order, I am placing 

the rates into effect in less than 30 days 

to meet contract deadlines, to avoid 

financial difficulties, and to provide 

rates for new services. The revised Rate 

Schedules L–NT1, L–FPT1, L–NFPT1, 

L–AS1, L–AS2, L–AS3, L–AS4, L–AS5, 

L–AS6, L–AS7, L–AS9, and L–UU1 will 

be submitted promptly to FERC for 

confirmation and approval on a final 

basis. 


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Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 61185 

Dated: September 2, 2011. 

Daniel B. Poneman, 

Deputy Secretary. 

Order Confirming, Approving, and 

Placing the Loveland Area Projects 

Transmission and Western Area 

Colorado Missouri Balancing Authority 

Ancillary Services Formula Rates Into 

Effect on an Interim Basis 

These transmission and ancillary 

services formula rates are established 

pursuant to section 302 of the 

Department of Energy (DOE) 

Organization Act (42 U.S.C. 7152). This 

act transferred to and vested in the 

Secretary of Energy the power marketing 

functions of the Secretary of the Interior 

and the Bureau of Reclamation 

(Reclamation) under the Reclamation 

Act of 1902 (ch. 1093, 32 Stat. 388), as 

amended and supplemented by 

subsequent laws, particularly section 

9(c) of the Reclamation Act of 1939 (43 

U.S.C. 485h(c)) and section 5 of the 

Flood Control Act of 1944 (16 U.S.C. 

825s), and other acts that specifically 

apply to the projects involved. 

By Delegation Order No. 00–037.00, 

effective December 6, 2001, the 

Secretary of Energy delegated: (1) The 

authority to develop power and 

transmission rates to the Administrator 

of Western; (2) the authority to confirm, 

approve, and place such rates into effect 

on an interim basis to the Deputy 

Secretary of Energy; and (3) the 

authority to confirm, approve, and place 

into effect on a final basis, to remand, 

or to disapprove such rates to the 

Federal Energy Regulatory Commission 

(FERC). Existing DOE procedures for 

public participation in power rate 

adjustments (10 CFR part 903) were 

published on September 18, 1985. 

Acronyms/Terms and Definitions 

As used in this Rate Order, the 

following acronyms/terms and 

definitions apply: 

Acronym/Term Definition 

$/kW-month: Dollars per kilowatt per month. 

12-cp: Rolling 12-month average of customers’ loads in excess of Federal Entitlement, coincident with the Loveland Area Projects (LAP) transmission system peak. 

Administrator: The Administrator of the Western Area Power Administration. 

Area Control Error (ACE): The instantaneous difference between a Balancing Authority’s net actual and scheduled 

interchange, taking into account the effects of frequency bias and correction for meter 

error. 

Ancillary Services: Those services that are necessary to support the transmission of capacity and energy 

from resources to loads while maintaining reliable operation of the Transmission Provider’s transmission system in accordance with good utility practice. 

ATRR: Annual transmission revenue requirement. 

Automatic Generation Control: Equipment that automatically adjusts generation in a Balancing Authority area from a 

central location to maintain the Balancing Authority’s interchange schedule plus frequency bias. 

Balancing Authority: The responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance within a Balancing Authority area, and supports interconnection frequency in real time. 

Control Area: The term used for a Balancing Authority area in Western’s Open Access Transmission 

Tariff. 

CRSP: Colorado River Storage Project. 

DOE: Department of Energy. 

Energy Imbalance Service: The ancillary service in which the Balancing Authority corrects hourly for the difference 

between a customer’s energy supply and energy usage. 

Federal Customers: LAP customers taking delivery of long-term firm service under firm electric service contracts, project use, and special use contracts. 

Firm Electric Service Contracts: Contracts for the sale of long-term firm LAP Federal energy and capacity, pursuant to 

the Post-1989 General Power Marketing and Allocation Criteria (Marketing Plan). 

Firm Point-to-Point Transmission Service: The highest priority transmission service offered to customers on a specified path that 

anticipates no planned interruption. 

Federal Entitlements: The energy and capacity delivered to Federal Customers under Firm Electric Service 

Contracts. 

FERC: Federal Energy Regulatory Commission. 

Fry-Ark: Fryingpan-Arkansas Project. 

FY: Fiscal Year, October 1 through September 30. 

Generator Imbalance Service: The ancillary service in which the Balancing Authority corrects hourly for the difference 

between a customer’s actual generation and scheduled generation. 

kW: Kilowatt. The electrical unit of capacity equal to 1,000 watts. 

kWh: Kilowatt-hour. The electrical unit of energy equal to 1 kW produced or delivered for 1 

hour. 

kW-month: Kilowatt-month. The electrical unit of energy equal to 1 kW produced or delivered for 1 

month. 

LAP: Loveland Area Projects. 

LAP Transmission System or Service: Transmission system operated by, or service provided by, the Loveland Area Projects. 

LAP Transmission System Total Load: Sum of 12-cp averages for all customer loads for Network Integration Transmission 

Service, plus 12-month rolling average of monthly entitlements of Federal Customers, 

plus reserved capacity for all Long-Term Firm Point-to-Point Transmission Service. 

Load ratio share: Network Transmission Customer’s 12-cp load coincident with LAP’s monthly transmission system peak, expressed as a ratio. 

Load Serving Entity (LSE): An entity within the Balancing Authority that secures energy and transmission service 

(and related interconnected operations services) to serve the electrical demand and 

energy requirements of its end-use customers. 

Long-Term Firm Point-to-Point Transmission Service: Firm Point-to-Point Transmission Service reservation for a duration of at least 12 consecutive months. 


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61186 Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 

Acronym/Term Definition 

Losses: The reduction of power being delivered as it moves across transmission lines or other 

equipment, due to resistance in the conducting material. 

M&I: Municipal and Industrial. 

Mill: Unit of monetary value equal to .001 of a U.S. dollar; i.e., 1⁄10 of a cent. 

Mills/kWh: Mills per kilowatt-hour. 

Monthly Entitlements: Maximum capacity to be delivered each month under Firm Electric Service Contracts. 

Each monthly entitlement is a percentage of the seasonal contract-rate-of-delivery. 

MW: Megawatt. The unit of electrical capacity that equals 1,000 kW or 1,000,000 watts. 

NERC: North American Electric Reliability Corporation. 

Network Integration Transmission Service: Firm transmission service for the delivery of capacity and energy from designated network resources to designated network loads not using one specific path. 

Non-Firm Point-to-Point Transmission Service: Point-to-point transmission service reserved on an as-available basis for periods ranging 

from 1 hour to 1 year. 

Open Access Same Time Information System 

(OASIS): 

An electronic posting system that the Transmission Provider maintains for transmission 

access data that allows all transmission customers to view the data simultaneously. 

Operating Reserve—Spinning Reserve Service: Generation capacity needed to serve load immediately in the event of a system contingency. Spinning Reserve Service may be provided by generating units that are on-line 

and loaded at less than maximum output. 

Operating Reserve—Supplemental Reserve Service: Generation capacity needed to serve load in the event of a system contingency, which 

capacity is not available immediately to serve load but rather within a short period of 

time. Supplemental Reserve Service may be provided by generation units that are online but unloaded, by quick start generation, or by interruptible load. 

Provisional Formula Rate: A formula rate that has been confirmed, approved, and placed into effect on an interim 

basis by the Deputy Secretary. 

P–SMBP: Pick-Sloan Missouri Basin Program. 

P–SMBP—WD: Pick-Sloan Missouri Basin Program—Western Division. 

RMR: Rocky Mountain Customer Service Region. 

Reactive Supply and Voltage Control from Generation or Other Sources Service: The ancillary service under which a Balancing Authority operates generation facilities 

under its control to produce or absorb reactive power to maintain voltages on all transmission facilities within acceptable limits. 

Reclamation: The United States Bureau of Reclamation. 

Regulation and Frequency Response Service: The ancillary service under which a Balancing Authority maintains moment-by-moment 

load-interchange-generation balance with the Balancing Authority area and supports 

interconnection frequency. 

Scheduling, System Control, and Dispatch Service: The ancillary service under which a Balancing Authority sets up an arrangement for an 

energy interchange transaction for delivery and receipt of energy between the two entities involved in the transaction. 

Service Agreement: The initial agreement and any amendments or supplements entered into by a Transmission Customer and Western for service under the Tariff. 

Short-Term Firm Point-to-Point Transmission Service: Firm Point-to-Point Transmission Service for a duration of less than 12 consecutive 

months. 

Sub-Balancing Authority: An area within a Balancing Authority area which has its own boundary metering scheme 

and for which an ACE can be measured. 

Tariff: Western’s revised Open Access Transmission Service Tariff, effective December 1, 2009 

(Docket NJ10–1–000). 

Transmission Customer: The RMR customer taking Network Integration Transmission Service or Point-to-Point 

Transmission Service. 

Transmission Losses Service: The service provided by the Balancing Authority to supply electrical losses on pre-scheduled and real-time transmission transactions. 

Transmission Provider: An entity that administers a transmission tariff and provides transmission service to 

transmission customers under applicable transmission service agreements. 

Unreserved Use Penalties: The use of transmission capacity that was not reserved, or the use of transmission in excess of reserved capacity. 

WACM: Western Area Colorado Missouri Balancing Authority. 

WECC: Western Electricity Coordinating Council. 

Western: Western Area Power Administration. 

Effective Date 

The Provisional Formula Rates will 

take effect on the first day of the first 

full billing period beginning on or after 

October 1, 2011, and will remain in 

effect through September 30, 2016, 

pending approval by FERC on a final 

basis. 

Public Notice and Comment 

Western has followed the Procedures 

for Public Participation in Power and 

Transmission Rate Adjustments and 

Extensions, 10 CFR Part 903, in the 

development of these formula rates and 

schedules. The steps Western took to 

involve interested parties in the rate 

process were: 

1. On September 29, 2010, Western 

held an informal meeting with 

customers and interested parties to 

discuss the proposed formula rates for 

LAP Transmission and WACM 

Ancillary Services. Western posted all 

information presented at the informal 

meeting, as well as responses to 

questions asked at the meeting, on its 

Web site at http://www.wapa.gov/rm/ 

ratesRM/2012/default.htm. 

2. Western published a Federal 

Register notice on January 28, 2011 (76 

FR 5148), officially announcing the 

proposed LAP Transmission and 

WACM Ancillary Services formula rates 

adjustment, initiating the public 

consultation and comment period, 

announcing the date and location of the 

public information and public comment 


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Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 61187 

forums, and outlining procedures for 

public participation. 

3. On February 2, 2011, Western sent 

a letter to all interested parties 

providing them with a copy of the 

Federal Register notice published on 

January 28, 2011 (76 FR 5148). 

4. On March 9, 2011, Western held its 

public information forum in Loveland, 

Colorado, where Western 

representatives explained the need for 

the formula rates adjustment in detail 

and answered questions. 

5. On March 9, 2011, following the 

public information forum, Western held 

a public comment forum in Loveland, 

Colorado, to provide an opportunity for 

customers and other interested parties 

to comment for the record. At this 

forum, one individual expressed general 

support of Western’s efforts to 

communicate with its customers well in 

advance of implementation of the 

proposed rates. 

6. Western received one written 

comment during the 90-day 

consultation and comment period, 

which ended on April 28, 2011. This 

comment is addressed below following 

the ancillary services discussion. 

All comments received have been 

considered in the preparation of this 

Rate Order. 

Project Descriptions 

The Post-1989 General Power 

Marketing and Allocation Criteria, 

published in the Federal Register on 

January 31, 1986 (51 FR 4012), 

integrated the resources of the P– 

SMBP—WD and Fry-Ark. This 

operational and contractual integration, 

known as LAP, allowed an increase in 

marketable resources, simplified 

contract administration, and established 

a blended rate for LAP power sales. 

WACM offers Ancillary Services from a 

combination of all LAP generation 

resources and some CRSP generation 

resources. 

P–SMBP—WD 

The P–SMBP was authorized by 

Congress in section 9 of the Flood 

Control Act of December 22, 1944 (Pub. 

L. 534, 58 Stat. 877, 891). This 

multipurpose program provides flood 

control, M&I water supply, irrigation, 

navigation, recreation, preservation and 

enhancement of fish and wildlife, and 

hydroelectric power. Multipurpose 

projects have been developed on the 

Missouri River and its tributaries in 

Colorado, Montana, Nebraska, North 

Dakota, South Dakota, and Wyoming. 

In addition to the multipurpose water 

projects authorized by section 9 of the 

Flood Control Act of 1944, certain other 

existing projects have been integrated 

with the P–SMBP for power marketing, 

operation, and repayment purposes. The 

Colorado-Big Thompson, Kendrick, 

Riverton, and Shoshone Projects were 

combined with P–SMBP in 1954, 

followed by the North Platte Project in 

1959. These projects are known as the 

‘‘Integrated Projects’’ of the P–SMBP. 

The Riverton Project was reauthorized 

as a unit of the P–SMBP in 1970. 

Together, the P–SMBP—WD and the 

Integrated Projects have 19 power 

plants. 

There are six power plants in P– 

SMBP—WD: Glendo, Kortes, and 

Fremont Canyon power plants on the 

North Platte River; Boysen and Pilot 

Butte power plants on the Wind River; 

and Yellowtail power plant on the Big 

Horn River. The Colorado-Big 

Thompson Project has six power plants: 

Green Mountain power plant on the 

Blue River is on the West Slope of the 

Continental Divide; and Mary’s Lake, 

Estes, Pole Hill, Flatiron, and Big 

Thompson power plants along the Big 

Thompson River are on the East Slope 

of the Continental Divide. The Kendrick 

Project has two power plants: Alcova 

and Seminoe power plants on the North 

Platte River. Power plants in the 

Shoshone Project are the Shoshone, 

Buffalo Bill, Heart Mountain, and Spirit 

Mountain plants on the Shoshone River. 

The only power plant in the North 

Platte Project is the Guernsey power 

plant, also on the North Platte River. 

Fry-Ark 

Fry-Ark is a trans-mountain diversion 

development in southeastern Colorado 

authorized by the Act of Congress on 

August 16, 1962 (Pub. L. 87–590, 76 

Stat. 389, as amended by Title XI of the 

Act of Congress on October 27, 1974 

(Pub. L. 93–493, 88 Stat. 1486, 1497)). 

The Fry-Ark diverts water from the 

Fryingpan River and other tributaries of 

the Roaring Fork River in the Colorado 

River Basin on the West Slope of the 

Rocky Mountains to the Arkansas River 

on the East Slope. The water diverted 

from the West Slope, together with 

regulated Arkansas River water, 

provides supplemental irrigation and 

M&I water supplies and produces 

hydroelectric power. Flood control, fish 

and wildlife enhancement, and 

recreation are other important purposes 

of Fry-Ark. The only generating facility 

in Fry-Ark is the Mt. Elbert PumpedStorage power plant on the East Slope. 

CRSP 

CRSP was authorized by the Colorado 

River Storage Project Act, ch. 203, 70 

Stat. 105, on April 11, 1956. The project 

provides water-use developments for 

states in the Upper Basin (Colorado, 

New Mexico, Utah, and Wyoming) 

while still maintaining water deliveries 

to the states of the Lower Basin 

(Arizona, California, and Nevada) as 

required by the Colorado River Compact 

of 1922. CRSP hydroelectric facilities 

providing ancillary services for WACM 

are the Aspinall power plant (formerly 

Curecanti) on the Gunnison River, the 

Flaming Gorge power plant on the 

Green River, the Towaoc Power Plant on 

the Towaoc Canal in southwestern 

Colorado, and the Glen Canyon power 

plant on the Colorado River. 

LAP Transmission Service 

Transmission formula rates, including 

those for Firm and Non-Firm Point-ToPoint Transmission Service and 

Network Integration Transmission 

Service, are designed to recover the 

annual costs of the LAP Transmission 

System. The transmission rates include 

the cost of Scheduling, System Control, 

and Dispatch Service. Western will 

continue to bundle transmission service 

for delivery of LAP long-term firm 

Federal power to Federal Customers in 

the firm electric service rate under 

existing Firm Electric Service Contracts 

that expire in 2024. 

The penalty for unauthorized use of 

transmission, currently assessed under 

the Point-to-Point Transmission rate 

schedules, will now be assessed as a 

penalty for unreserved use under a 

separate rate schedule, L–UU1. 

Unreserved Use Penalties will include 

the basic rate for the transmission 

service used and not reserved, plus a 

penalty equal to the basic rate. 

Transmission losses are assessed for 

all real-time and prescheduled 

transactions on transmission facilities 

inside WACM. The current loss factor, 

as posted on the RMR OASIS, is 4.5 

percent. 

WACM Ancillary Services 

Western will offer seven Ancillary 

Services pursuant to its Tariff. The 

seven Ancillary Services are: (1) 

Scheduling, System Control, and 

Dispatch Service (SSCD Service); (2) 

Reactive Supply and Voltage Control 

from Generation or Other Sources 

Service (VAR Support Service); (3) 

Regulation and Frequency Response 

Service (Regulation Service); (4) Energy 

Imbalance Service; (5) Spinning Reserve 

Service; (6) Supplemental Reserve 

Service; and (7) Generator Imbalance 

Service. Generator Imbalance Service, 

currently provided as part of Rate 

Schedule L–AS4 for Energy Imbalance 

Service, is a new service under the 

Tariff. The Ancillary Services formula 

rates are designed to recover only the 


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61188 Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 

costs incurred for providing the 

service(s). 

Comparison of Existing and Provisional 

Formula Rates for Transmission and 

Ancillary Services 

The following table displays a 

comparison of existing formula rates 

and the Provisional Formula Rates for 

FY 2012. These rates will be 

recalculated annually based on updated 

financial, schedule, and load data. 

FORMULA RATE COMPARISON TABLE

Class of Service Provisional Formula Rates 

Effective October 1, 2011 (FY 2012) 

Existing Formula Rates 

Effective October 1, 2010 (FY 2011) 

Network Integration Transmission 

Service 

L–NT1 

Load ratio share of 1/12 of the revenue requirement 

of $56,775,913. 

L–NT1 

Load ratio share of 1/12 of the revenue requirement 

of $48,000,660. 

Firm Point-to-Point Transmission 

Service 

L–FPT1 

$3.48/kW-month 

L–FPT1 

$3.18/kW-month 

Unauthorized Use Penalty of 150% of demand 

charge, with a maximum of monthly service. 

Non-Firm Point-to-Point Transmission Service L–NFPT1 

Maximum of 4.77 mills/kWh 

L–NFPT1 

Maximum of 4.17 mills/kWh 

Unauthorized Use Penalty of 150% of demand 

charge, with a maximum of monthly service. 

Unreserved Use Penalties L–UU1 

Penalized 200% of demand charge, with a maximum 

of monthly service. 

Provided Under Rate Schedules L–FPT1 and L– 

NFPT1 as Unauthorized Use. 

Transmission Losses Service L–AS7 L–AS7 

Transmission losses may be settled either financially 

or with energy. Insufficient losses supplied will be 

settled financially by default. 

Transmission losses may be settled either financially 

or with energy. Insufficient losses supplied will be 

settled financially by default. 

All customers will have the option to return the loss 

obligation for both prescheduled and real-time 

transactions 7 days later, same profile. 

All customers will have the option to return the loss 

obligation for both prescheduled and real-time 

transactions 7 days later, same profile. 

Pricing used is WACM weighted average hourly purchase price. Pricing used is LAP weighted average hourly realtime purchase price. 

Current loss factor as posted is 4.5%. Current loss factor as posted is 4.5%. 

Scheduling, System Control, and 

Dispatch Service 

L–AS1 

$24.22 per schedule per day for non-Federal transmission customers. Not applicable to schedules for 

delivery of Losses to WACM. 

L–AS1 

$38.30 per tag per day for nonFederal transmission customers. Applicable to all 

tags. 

Reactive Supply and Voltage 

Control from Generation or 

Other Sources Service 

L–AS2 

$0.305/kW-month 

L–AS2 

$0.180/kW-month 

Regulation and Frequency Response L–AS3 

$0.331/kW-month 

L–AS3 

$0.339/kW-month 

Energy Imbalance Service L–AS4 L–AS4 

—Imbalances less than or equal to 1.5% (minimum 4 

MW) of metered load settled using WACM hourly 

pricing with no penalty. 

—Imbalances less than or equal to 5% (minimum 4 

MW) of metered load settled using WACM hourly 

pricing with no penalty. 

—Imbalances between 1.5% and 7.5% (minimum 4 

MW to 10 MW) of metered load settled using 

WACM hourly pricing with a 10% penalty. 

—Imbalances greater than 5% of metered load settled using WACM hourly pricing with a 10% penalty. 

—Imbalances greater than 7.5% (minimum 10 MW) 

of metered load settled using WACM hourly pricing 

with a 25% penalty. 

—WACM aggregate imbalance determines pricing in 

all bands—aggregate surplus dictates sale pricing, 

aggregate deficit dictates purchase pricing. 

—WACM aggregate imbalance dictates pricing in nopenalty band. Customer imbalance dictates pricing 

in penalty band (surpluses indicate sale pricing, 

deficits indicate purchase pricing). 

—Intermittent resources not subject to penalties. 

Operating Reserve Service— 

Spinning and Supplemental 

L–AS5, L–AS6 

Long-term Reserves are not available from WACM. 

Reserves may be acquired and provided at passthrough cost, plus an amount for administration. 

L–AS5, L–AS6 

Long-term Reserves are not available from WACM. 

Reserves may be acquired and provided at passthrough cost, plus an amount for administration. 


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FORMULA RATE COMPARISON TABLE—Continued 

Class of Service Provisional Formula Rates 

Effective October 1, 2011 (FY 2012) 

Existing Formula Rates 

Effective October 1, 2010 (FY 2011) 

Generator Imbalance Service L–AS9 

—Imbalances less than or equal to 1.5% (minimum 4 

MW) of metered generation settled using WACM 

hourly pricing with no penalty. 

—Imbalances between 1.5% and 7.5% (minimum 4 

MW to 10 MW) of metered generation settled using 

WACM hourly pricing with a 10% penalty. 

—Imbalances greater than 7.5% (minimum 10 MW) 

of metered generation settled using WACM hourly 

pricing with a 25% penalty. 

—Intermittent resources not subject to 25% penalties. 

—WACM aggregate imbalance determines pricing in 

all bands—aggregate surplus dictates sale pricing, 

aggregate deficit dictates purchase pricing. 

Provided under Rate Schedule L–AS4. 

Certification of Rates 

Western’s Administrator certified that 

the Provisional Formula Rates for LAP 

Transmission and WACM Ancillary 

Services under Rate Schedules L–NT1, 

L–FPT1, L–NFPT1, L–AS1, L–AS2, L– 

AS3, L–AS4, L–AS5, L–AS6, L–AS7, L– 

AS9, and L–UU1 are the lowest possible 

rates consistent with sound business 

principles. The Provisional Formula 

Rates were developed following 

administrative policies and applicable 

laws. 

LAP Transmission Service Discussion 

Network Integration Transmission 

Service 

The monthly charge for Network 

Integration Transmission Service for the 

Transmission Customer will be as 

follows: 

The customer’s load-ratio share is the 

ratio of its network load to the LAP 

Transmission System Total Load at the 

LAP system peak. This is calculated on 

a rolling 12-month average (12 

coincident peak average or 12-cp). 

Firm Point-to-Point Transmission 

Service 

The formula rate for Firm Point-toPoint Transmission Service is as 

follows: 

The rates for FY 2012 are as follows: 

Discussions of the ATRR and the LAP 

Transmission System Total Load are 

located below. 

Non-Firm Point-to-Point Transmission 

Service 

The maximum Non-Firm Point-toPoint Transmission Service formula rate 

is the same as the Firm Point-to-Point 

Transmission Service rate. Non-Firm 

Point-to-Point Transmission Service is 

available for periods ranging from 1 

hour to 1 year. 

Maximum Hourly Non-Firm Rate: 4.77 

mills/kW of reserved capacity per 

hour 


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61190 Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 

Annual Transmission Revenue 

Requirement 

The ATRR is applicable to both 

Network and Point-to-Point 

Transmission Service. The ATRR is the 

annual cost of the LAP Transmission 

System, adjusted for revenue credits, 

costs that increase the capacity available 

for transmission, other miscellaneous 

charges or credits, and the prior year 

true-up. The formula, with amounts 

calculated for the FY 2012 rate, is as 

follows: 

The annual cost of the LAP 

Transmission System is the ratio of 

gross investment cost for transmission 

facilities to gross investment cost for all 

facilities multiplied by the total annual 

costs for all facilities. Total annual costs 

include operations and maintenance, 

interest, and depreciation expenses. The 

calculation, with amounts for FY 2012, 

is as follows: 

The source for the annual costs is the 

formalized work plans for FY 2012 and 

the FY 2010 Results of Operations for P– 

SMBP—WD, with certain items adjusted 

for projected asset capitalization or 

historical trends. See discussion below 

on ‘‘Change to Forward-Looking 

Transmission Rates.’’ 

The gross investment cost for 

transmission facilities is determined by 

an analysis of the LAP Transmission 

System. Each LAP facility is classified 

by function: transmission, subtransmission, distribution, or 

generation-related. The facilities 

identified as performing the function of 

transmission include all transmission 

lines that are normally operated in a 

continuously-looped manner and the 

associated substations and switchyard 

facilities. In the LAP Transmission 

System, these are primarily the 115-kV 

and the 230-kV transmission lines. In 

addition, portions of the 

communication, maintenance, and 

administration facilities are included in 

the investment costs for transmission. 

Only the investment costs of the 

facilities identified as ‘‘transmission’’, 

including allocated costs for 

communication, maintenance, and 

administration facilities, are used in 

developing the annual cost of the 

transmission system. The investment 

costs of facilities identified as ‘‘subtransmission’’ and ‘‘distribution’’ are 

excluded from the ATRR, as the LAP 

sub-transmission and distribution 

systems are used primarily for delivery 

of Federal power to Federal Customers. 

If a Transmission Customer requires the 

use of the sub-transmission or 

distribution systems, an additional 

facility-use charge will be assessed. All 

Fry-Ark costs are considered generationrelated and, therefore, are excluded 

from the ATRR. 

System augmentation expense 

includes payments made to others for 

their systems’ augmentation of the LAP 

Transmission System. Miscellaneous 

charges and credits will include, but 

will not be limited to, Unreserved Use 

Penalties and facility use charges for 

transmission facility investments 

included in the revenue requirement. 

For a description of the prior year trueup, see discussion below on ‘‘Change to 

Forward-Looking Transmission Rates.’’ 


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Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 61191 

Change to Forward-Looking 

Transmission Rates 

Western has changed the method it 

uses to calculate the ATRR to recover 

transmission expenses and investments 

on a current basis rather than a 

historical basis. The change allows 

Western to more accurately match cost 

recovery with cost incurrence. Western 

will use projections to estimate 

transmission costs and load for the 

upcoming year in the annual rate 

calculation, rather than using historical 

information. The method is a change in 

the manner in which the inputs for the 

rate are developed, rather than a change 

to the formula rate itself. When actual 

cost information for a year becomes 

available, Western will calculate the 

actual revenue requirement for that 

year. Revenue collected in excess of the 

actual revenue requirement will be 

included as a credit in the ATRR in a 

subsequent year. Similarly, any undercollection of the revenue requirement 

will be included as a charge in the 

ATRR in a subsequent year. This trueup procedure will ensure that Western 

recovers no more and no less than the 

actual transmission costs for any year. 

For example, as FY 2012 actual 

financial data becomes available during 

FY 2013, the under- or over-collection 

of revenue during FY 2012 can be 

determined. When the rates are 

recalculated for FY 2014, the 

implemented rates will include an 

adjustment for revenue under- or overcollected in FY 2012. 

Transmission System Total Load for 

Point-to-Point Service 

The LAP Transmission System Total 

Load is a 12-month average of the sum 

of (1) all Network Integration 

Transmission Service customer loads in 

excess of deliveries of Federal 

Entitlements, measured at the monthly 

LAP Transmission System peak hour, 

plus (2) the monthly entitlements of 

Federal Customers, plus (3) the reserved 

capacity for Long-Term Firm Point-toPoint Transmission Service. This load 

calculation is prepared once annually 

and is used to calculate the point-topoint rates for the entire year. 

The LAP Transmission System Total 

Load is calculated as follows, based 

upon data projected for FY 2012: 

Federal Customers ............... 604,639 kW 

Network Transmission Customers ............................... 743,818 kW 

Subtotal ............................ 1,348,457 kW 

Point-to-Point Reserved Capacity ................................ 9,885 kW 

LAP Transmission System 

Total Load ........................ 1,358,342 kW 

Unreserved Use Penalties 

Unreserved use of the transmission 

system (Unreserved Use) occurs when a 

Transmission Customer uses 

transmission service that exceeds its 

reserved capacity or an eligible 

customer uses transmission service that 

it has not reserved. Western will assess 

Unreserved Use Penalties against a 

customer that has not secured reserved 

capacity or exceeds its reserved capacity 

at any point of receipt or any point of 

delivery. Unreserved Use may also 

include a Transmission Customer’s 

failure to curtail transmission when 

requested. 

A customer that engages in 

Unreserved Use will be assessed a 

penalty charge of 200 percent of LAP’s 

approved transmission service rate for 

Firm Point-to-Point Transmission 

Service as follows: 

(1) The Unreserved Use penalty for a 

single hour of Unreserved Use will be 

based upon the rate for daily Firm 

Point-to-Point Service. 

(2) The Unreserved Use penalty for 

more than one assessment for a given 

duration (e.g., daily) will increase to the 

next longest duration (e.g., weekly). 

(3) The Unreserved Use penalty 

charge for multiple instances of 

Unreserved Use (e.g., more than one 

hour) within a day will be based on the 

rate for daily Firm Point-to-Point 

Service. Multiple instances of 

Unreserved Use isolated to one calendar 

week will result in a penalty based on 

the charge for weekly Firm Point-toPoint Service. The penalty charge for 

multiple instances of Unreserved Use 

during more than one week during a 

calendar month will be based on the 

charge for monthly Firm Point-to-Point 

Service. 

A Transmission Customer that 

exceeds its firm reserved capacity at any 

point of receipt or point of delivery or 

an eligible customer that uses 

transmission service at a point of receipt 

or point of delivery that it has not 

reserved will be required to pay, in 

addition to the Unreserved Use 

Penalties, for all applicable Ancillary 

Services identified in Western’s Tariff 

based on the amount of transmission 

service it used and did not reserve. 

Unreserved Use Penalties collected 

over and above the base Point-to-Point 

Transmission Service rate will be 

included as a credit in the calculation 

of the ATRR in a subsequent year. 

Transmission Losses Service 

Transmission Losses are assessed for 

all real-time and prescheduled 

transactions on transmission facilities 

inside WACM. In the case of Network 

Integration Transmission Service 

Customers, transmission and 

transformer Losses applicable under 

customers’ respective contracts are 

calculated as part of the customers’ 

Energy Imbalance Service settlements. 

Other customers are allowed the option 

of financial settlement or energy 

repayment. Energy repayment is either 

concurrently or 7 days later, to be 

delivered using the same profile as the 

related transmission transaction. When 

a transmission loss energy obligation is 

not provided (or is under-provided) by 

a customer for a transmission 

transaction, the energy still owed for 

Losses is calculated and a charge is 

assessed to the customer, based on the 

WACM weighted average hourly 

purchase price. The loss factor, 

currently 4.5 percent, is updated 

periodically and posted on the RMR 

OASIS Web site. 

Transmission Service Comments 

RMR received no comments 

concerning transmission service, 

Unreserved Use Penalties, or 

Transmission Losses during the public 

consultation and comment period. 

Ancillary Services Discussion 

Pursuant to Western’s Tariff, WACM 

will offer seven Ancillary Services. Two 

of these services, SSCD Service and 

VAR Support Service, are services that, 

under Western’s Tariff, the 

Transmission Provider is required to 

provide (or offer to arrange with the 

Balancing Authority operator) and the 

Transmission Customer is required to 

purchase. 

The other five Ancillary Services, 

Regulation Service, Energy Imbalance 

Service, Generator Imbalance Service, 

Operating Reserve—Spinning Reserve 

Service, and Operating Reserve— 

Supplemental Reserve Service, are 

services that the Transmission Provider 

is required to offer to provide to the 

Transmission Customer. The 

Transmission Customer is required to 

acquire these Ancillary Services, either 

from the Transmission Provider or from 

a third party, or to self-supply them. 

Scheduling, System Control, and 

Dispatch Service 

The formula for SSCD Service, with 

amounts shown for FY 2012, is as 

follows: 


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61192 Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 

This rate recovers the annual 

expenses associated with transmission 

scheduling. The annual cost of 

scheduling personnel and related costs 

is comprised of annual expenses for 

personnel, facilities, equipment, and 

software, as well as credits representing 

fees for agent services and unscheduled 

flow mitigation services. This revenue 

requirement is divided by the number of 

schedules (excluding schedules for 

delivery of losses to WACM) per year to 

derive a rate per schedule per day. 

Per Schedule 1 of Western’s Tariff, 

‘‘this service can be provided only by 

the operator of the Control Area in 

which the transmission facilities used 

for transmission service are located.’’ In 

cases in which the Transmission 

Provider (LAP and/or CRSP) directly 

provides the service as the Control Area 

operator, the costs for this service are 

bundled in the respective Federal 

transmission rate. In cases in which the 

Transmission Providers on the 

schedules are not the operator, WACM 

indirectly performs this service for those 

Transmission Providers’ transmission 

systems. Western has historically 

invoiced the last Transmission Provider 

that is inside WACM on the schedule. 

Since all non-Federal Transmission 

Providers are indirectly taking this 

service from WACM, Western will 

allocate the cost of each schedule 

equally among all Transmission 

Providers (Federal and non-Federal) 

listed on the schedule that are inside 

WACM. The Federal transmission 

segments will be exempt from invoicing, 

as costs for these segments will continue 

to be included in the Federal (LAP and 

CRSP) transmission service rates. 

Western will not include schedules 

for delivery of transmission losses to 

WACM in the calculation of the rate and 

will not invoice for them, so that 

entities delivering losses may create 

individual loss schedules associated 

with specific transactions without 

charge. Western will accept any number 

of schedule changes over the course of 

a day, without additional charge, so that 

entities attempting to follow their loads 

closely may do so without penalty. 

Reactive Supply and Voltage Control 

from Generation or Other Sources 

Service 

The formula for VAR Support Service 

is the following: 

TARRG = Total Annual Revenue 

Requirement for Generation 

% of Resource = Percentage of Resource Used 

for VAR Support 

The numerator captures the percentage of 

annual generation plant costs that are 

used for this service. Most of the LAP 

generation plant facilities are owned and 

operated by Reclamation, but Western 

has some facilities that are considered 

generation-related. Net generation plant 

costs are multiplied by a fixed charge 

rate (FCR) for generation to determine 

the TARRG, where 

The FCR is a methodology used to 

assign a portion of total expenses to 

generation. Applying these formulas to 

FY 2010 data provides the following 

results: 


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Applying this percentage to the amount 

of net generation plant investment 

results in the TARRG: 

TARRG = $334,166,538 × 17.847% = 

$59,638,020 

The percentage of the TARRG that is 

included in the revenue requirement is 

based on the nameplate capability of the 

generating units with regard to reactive 

and real power production. The TARRG 

is multiplied by the complement of the 

weighted average power factor rating for 

generating units. The weighted average 

power factor rating for the LAP 

generating units is 94.77 percent, so the 

revenue requirement for this rate 

includes 5.23 percent of the TARRG. 

The portion of the revenue requirement 

contributed by LAP plant costs is as 

follows: 

LAP Plant Costs = $59,638,020 × 

5.2284% = $3,118,089 

Plant costs for CRSP plants providing 

VAR Support Service are calculated 

using identical methodology. The 

contribution to the revenue requirement 

from CRSP plants is $1,539,255. The 

total revenue requirement, after 

adjusting for a small amount of VAR 

Support Service revenue on point-topoint transmission transactions not in 

the rate design, is as follows: 

LAP Plant Costs ................... $3,118,089 

CRSP Plant Costs ................. $1,539,255 

PTP Revenue ........................ $(53,525) 

Revenue Requirement ......... $4,603,819 

The load taking this service totals 

1,258,524 kW, resulting in a proposed 

rate for FY 2012 of: 

The rate is applicable to all 

transmission transactions inside WACM 

in excess of any Federal Entitlements. 

For Federal Entitlements, the cost for 

this service will be included in the firm 

electric service rates. Customers with 

generators providing WACM with VAR 

Support Service may be excluded from 

the application of this rate. Any such 

exclusion must be documented in the 

customer’s Service Agreement. 

Regulation and Frequency Response 

Service 

The formula rate for Regulation 

Service has two different applications: 

1. Load-based Assessment. The 

formula for the Load-based Assessment 

is as follows: 

The rate applies to all entities’ auxiliary 

load (total metered load less Federal 

Entitlements) and also to the installed 

nameplate capacity of intermittent 

generators serving load inside WACM. 

The revenue requirement will include 

costs such as plant costs, purchases of 

a regulation product, purchases of 

power in support of the generating 

units’ ability to regulate, purchases of 

transmission for regulating units that are 

trapped geographically inside another 

balancing authority, purchases of 

transmission required to relocate energy 

due to regulation/load following issues, 

and lost sales opportunities resulting 

from the requirement to generate at 

night to permit units to have ‘‘down’’ 

regulating capability. 

The methodology for determining 

annual plant costs is as follows. First, 

the annual costs for plants used to 

regulate is calculated by multiplying the 

net plant costs by the FCR for 

generation. 

Annual Costs = 17.847% × $159,716,812 

Annual Costs = $28,504,334 

Then, the annual cost per unit of 

capacity for regulating plants is 

calculated by dividing the annual costs 

for regulating plants by the capacity of 

those plants: 


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61194 Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 

Next, the portion of the total annual 

plant costs to be recovered in the 

Regulation Service rate is calculated by 

multiplying the annual unit cost by the 

amount of capacity required for 

regulation. The capacity required for 

regulation is subject to re-evaluation 

every year. Current analyses indicate 

that 75 MW of capacity will be required 

for WACM Regulation Service for FY 

2012. Of this total, 55 MW will be 

supplied by LAP plants and 20 MW will 

be supplied by CRSP plants. 

Regulating Plant Costs (LAP) = $60.32 × 

55,000 kW 

Regulating Plant Costs (LAP) = 

$3,317,614 

CRSP regulating plant costs are 

calculated in a similar manner. Inserting 

this and other financial data for FY 2010 

into the formula results in the following 

Revenue Requirement: 

LAP Plant Costs .................................................................................................................................................................................. $3,317,614 

Purchase Power Costs in Support of Regulation .............................................................................................................................. 5,049,193 

Lost Sales Opportunities from having to generate in off-peak hours ............................................................................................. 1,320,110 

Transmission Costs for Trapped Regulating Units ........................................................................................................................... 1,042,800 

Purchases of Transmission ................................................................................................................................................................ 52,598 

CRSP Plant Costs ................................................................................................................................................................................ 590,429 

Annual Revenue Requirement ....................................................................................................................................................... 11,372,744 

The load inside WACM requiring 

Regulation Service and the installed 

nameplate capacity of intermittent 

resources serving load inside WACM are 

2,791,390 kW and 73,220 kW, 

respectively. 

2. Self-Provision Assessment. Western 

allows entities with AGC to self-provide 

for all or a portion of their loads. 

Entities with AGC are known as SubBalancing Authorities (SBA) and must 

meet all of the following criteria: 

a. Have a well-defined boundary, with 

WACM-approved revenue-quality 

metering, accurate as defined by NERC, 

to include MW flow data availability at 

6-second or smaller intervals; 

b. Have AGC capability; and 

c. Have demonstrated Regulation 

Service capability. 

Self-provision will be measured by 

use of the entity’s 1-minute average ACE 

to determine the amount of selfprovision. The ACE will be used to 

calculate Regulation Service charges 

every hour as follows: 

a. If the entity’s 1-minute average ACE 

for the hour is less than or equal to 0.5 

percent of its hourly average load, no 

Regulation Service charges will be 

assessed by WACM. 

b. If the entity’s 1-minute average ACE 

for the hour is greater than or equal to 

1.5 percent of its hourly average load, 

WACM will assess full Regulation 

Service charges using the Load-based 

Assessment applied to the entity’s 12-cp 

load for that month. 

c. If the entity’s 1-minute average ACE 

for the hour is greater than 0.5 percent 

of its hourly average load, but less than 

1.5 percent of its hourly average load, 

WACM will assess Regulation Service 

charges based on linear interpolation of 

zero charge and full charge, using the 

Load-based Assessment applied to the 

entity’s 12-cp load for that month. 

d. Western will monitor the entity’s 

self-provision on a regular basis. If 

Western determines that the entity has 

not been attempting to self-regulate, 

Western will, upon notification, employ 

the full Load-based Assessment 

described above. 

Alternative Arrangements 

1. Exporting Intermittent Resource 

Requirement: An entity that exports the 

output from an intermittent generator to 

another Balancing Authority will be 

required to dynamically meter or 

dynamically schedule that resource out 

of WACM to another Balancing 

Authority unless arrangements, 

satisfactory to Western, are made for 

that entity to acquire this service from 

a third party or self-supply (as outlined 

below). An intermittent generator is one 

that is volatile and variable due to 

factors beyond direct operational 

control and, therefore, is not 

dispatchable. 

2. Self- or Third-party supply: 

Western may allow an entity to supply 

some or all of its required regulation, or 

contract with a third party to do so, 

even without well-defined boundary 

metering. This entity must have revenue 

quality metering at every load and 

generation point, accurate as defined by 

NERC, to include MW flow data 

availability at 6-second or smaller 

intervals. WACM will evaluate the 

entity’s metering, telecommunications 

and regulating resource, as well as the 


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Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 61195 

required level of regulation, and 

determine whether the entity qualifies 

to self-supply under this provision. If 

approved, the entity will be required to 

enter into a separate agreement with 

Western, which will specify the terms of 

the self-supply application. 

Energy Imbalance Service 

WACM provides Energy Imbalance 

Service using a penalty and bandwidth 

structure with three deviation bands as 

follows. The term ‘‘metered load’’ is 

defined to be ‘‘metered load adjusted for 

losses.’’ 

1. An imbalance of less than or equal 

to 1.5 percent of metered load (or 4 MW, 

whichever is greater) for any hour will 

be settled financially at 100 percent of 

the WACM weighted average hourly 

price. Each hour will stand on its own— 

there will be no monthly netting. 

2. An imbalance between 1.5 percent 

and 7.5 percent of metered load (or 4 to 

10 MW, whichever is greater) for any 

hour will be settled financially at 90 

percent of WACM weighted average 

hourly price when net energy scheduled 

exceeds metered load or 110 percent of 

the WACM weighted average hourly 

price when net energy scheduled is less 

than metered load. 

3. An imbalance greater than 7.5 

percent of metered load (or 10 MW, 

whichever is greater) for any hour will 

be settled financially at 75 percent of 

the WACM weighted average hourly 

price when net energy scheduled 

exceeds metered load or 125 percent of 

the WACM weighted average hourly 

price when net energy scheduled is less 

than metered load. 

Aggregate Imbalance, Pricing, and 

Settlement 

All Energy Imbalance Service 

provided by WACM will be accounted 

for hourly and settled financially after 

the end of each month. The WACM 

aggregate imbalance will determine the 

pricing used in all settlements, 

including those subject to a penalty. For 

each hour, the gross energy imbalance 

for all entities inside WACM will be 

totaled/netted to determine an aggregate 

energy imbalance for WACM. The sign 

of the aggregate energy imbalance will 

determine whether WACM sale or 

purchase pricing will be used for 

settling imbalances in that hour. A 

calculated surplus will dictate the use of 

sale pricing; a calculated deficit will 

dictate the use of purchase pricing. 

When there are no real-time sales or 

purchases within an hour, pricing 

defaults will be applied in the following 

order: 

1. Weighted average sale or purchase 

pricing for the day (on- and off-peak). 

2. Weighted average sale or purchase 

pricing for the current month (on- and 

off-peak). 

3. Weighted average sale or purchase 

pricing for the prior month (on- and offpeak). 

4. Weighted average sale or purchase 

pricing for the month immediately prior 

to the prior month (and continuing in 

this manner until sale or purchase 

pricing is located) (on- and off-peak). 

Expansion of the Bandwidth 

Expansion of the bandwidth may be 

done to accommodate the following: (1) 

Response to physical resource loss; (2) 

transition of large thermal resources. 

Details are as follows: 

1. Western will expand the bandwidth 

during an event established by a 

Western-recognized reserve-sharing 

group, such as the Rocky Mountain 

Reserve Group. A response made by a 

member of the reserve group will be 

accounted for by an after-the-fact 

schedule. Normally, these events are 1– 

2 hours in duration. Since the after-thefact schedule replaces lost generation, 

no expansion will be necessary for the 

entity receiving the response. The 

expanded bandwidth will apply to the 

customer that increased generation in 

response to the event and will be based 

on the magnitude of that customer’s 

generation response. 

2. During transition of large base-load 

thermal resources (capacity greater than 

200 MW) between off-line and on-line 

following a reserve sharing group 

response, Western may expand the 

bandwidth to eliminate all penalties 

during hours in which the unit 

generates less than the predetermined 

minimum scheduling level. Western 

may not have access to information 

necessary to determine these hours for 

some generators and will not have 

access to information on events for 

reserve sharing groups outside RMR. 

Customers should request bandwidth 

expansion in hours in which they 

believe it to be warranted. Western may 

request additional information for its 

decision as to whether to grant the 

request. Bandwidth will not be 

expanded when ramping services have 

been acquired by another entity. 

Balancing Authority Operating 

Constraints 

Western reserves the right to offer no 

credit for Energy Imbalance Service 

over-deliveries during times of WACM 

operating constraints, such as ‘‘mustrun’’ hydrologic conditions, or times 

when WACM cannot dispose of surplus 

energy. Due to the unpredictable nature 

of hour-to-hour energy imbalances and 

the very short notice for disposition of 

over-deliveries, WACM may experience 

some hours of zero-value sales and may 

eliminate credits in these hours. 

If WACM is unable to dispose of the 

entire net over-delivery and operating 

criteria for the Balancing Authority are 

not met, there may be financial 

sanctions to Western from reliability 

oversight agencies, such as NERC or 

WECC. In these cases, credits to 

customers will be eliminated and 

customers over-delivering may share in 

the cost of the sanction. Also, there may 

be conditions under which customers 

who under-deliver may share in any 

sanctions imposed on Western by 

reliability oversight agencies. 

Generator Imbalance Service 

WACM will provide Generator 

Imbalance Service to the following 

customers: 

1. Jointly-owned generators whose 

output is shared by several entities. At 

the written request of all entities who 

jointly own the generator’s output, 

WACM will accept allocations of the 

generation among the participants. In 

this situation, a participant’s share of 

actual generation will be included in its 

separate Energy Imbalance calculation. 

2. Intermittent generators. At the 

written request of the customer, WACM 

will include the intermittent 

generator(s) in the customer’s Energy 

Imbalance calculation. The customer 

makes this choice with the 

understanding that the intermittent 

generator will be subject to 3rd band (25 

percent) penalties (see formula rate 

details below). 

3. Non-intermittent generators serving 

load only outside WACM. 

An entity’s solely-owned nonintermittent generator serving load 

inside WACM will be included in its 

Energy Imbalance Service calculation. 

WACM will provide Generator 

Imbalance Service using a penalty and 

bandwidth structure with three 

deviation bands as follows: 

1. An imbalance of less than or equal 

to 1.5 percent of metered generation (or 

4 MW, whichever is greater) for any 

hour is settled financially at 100 percent 

of the WACM weighted average hourly 

price. 

2. An imbalance between 1.5 percent 

and 7.5 percent of metered generation 

(or 4 to 10 MW, whichever is greater) for 

any hour is settled financially at 90 

percent of the WACM weighted average 

hourly price when actual generation 

exceeds scheduled generation or 110 

percent of the WACM weighted average 

hourly price when actual generation is 

less than scheduled generation. 

3. An imbalance greater than 7.5 

percent of metered generation (or 10 


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61196 Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 

MW, whichever is greater) for any hour 

is settled financially at 75 percent of the 

WACM weighted average hourly price 

when actual generation exceeds 

scheduled generation or 125 percent of 

the WACM weighted average hourly 

price when actual generation is less 

than scheduled generation. 

Intermittent generators will be exempt 

from the 25 percent penalty band. All 

imbalances greater than 1.5 percent of 

metered generation for an intermittent 

generator will be subject only to a 10 

percent penalty. 

The features of Energy Imbalance 

Service described above under 

Aggregate Imbalance, Pricing, and 

Settlement, Expansion of the 

Bandwidth, and Balancing Authority 

Operating Constraints, also apply to 

Generator Imbalance Service. 

Penalty Elimination 

In any hour, Western will charge a 

customer a penalty for either Generator 

Imbalance Service or Energy Imbalance 

Service, but not both, unless the 

imbalances aggravate rather than offset 

each other. In an hour in which 

penalties on offsetting imbalances 

would exist based on the separate 

imbalance calculations, Western will 

remove the penalty from the Generator 

Imbalance calculation. There will be no 

penalty elimination for jointly-owned 

generators whose participants have a 

separate Energy Imbalance calculation. 

Administrative Charge 

In the Notice of Proposed Rates (76 FR 

5148), Western proposed to assess an 

administrative charge on each monthly 

settlement under both Energy Imbalance 

and Generator Imbalance Services. After 

further analysis and customer input, 

Western has decided not to implement 

an administrative charge under either 

service. 

Operating Reserve—Spinning and 

Supplemental 

WACM has no long-term Reserves 

available for sale. At a customer’s 

request, WACM will purchase and pass 

through the cost of Reserves and any 

activation energy, plus a fee for 

administration. For all Reserves 

purchased, the customer will be 

responsible for providing the 

transmission to deliver the Reserves. 

Ancillary Services Comments 

Western received one written 

comment concerning the Ancillary 

Services during the public consultation 

and comment period. This comment has 

been paraphrased where appropriate, 

without compromising the meaning of 

the comment. 

Comment: The customer requested 

that, for Regulation Service, rather than 

requiring an intermittent generator that 

exports its output to dynamically meter 

or dynamically schedule the generation 

out of WACM, Western open 

communications to pursue other options 

to avoid this requirement. The customer 

expressed concern about the cost of 

implementing this requirement and the 

effects the unexpected costs will have 

on member municipalities and their 

customers. The customer also noted that 

these additional costs were not known 

at the inception of its existing projects 

when cost analyses were being 

performed. 

Response: Western thanks the 

customer for its comment. As noted 

above under Regulation and Frequency 

Response Service (Alternative 

Arrangements), Western has included as 

a part of the Regulation Service rate 

schedule, a condition under which an 

exporting intermittent generator will not 

have to be dynamically removed from 

WACM. Under this condition, the entity 

must make arrangements, satisfactory to 

Western, to acquire Regulation and 

Frequency Response Service from a 

third party or self-supply it. Western 

believes that this is a reasonable 

requirement that will not place an 

undue burden on existing or potential 

customers who will export intermittent 

generation from WACM, but will 

support the concept in Western’s Tariff 

that WACM is required to provide 

Ancillary Services only for LoadServing Entities. 

Availability of Information 

All brochures, studies, comments, 

letters, memorandums, or other 

documents that Western used to 

develop the Provisional Formula Rates 

are available for inspection and copying 

at the Rocky Mountain Regional Office, 

located at 5555 East Crossroads 

Boulevard, Loveland, Colorado. Many of 

these documents and supporting 

information are also available on 

Western’s Web site under the ‘‘2012 

Rate Adjustment—Transmission and 

Ancillary Services’’ section located at 

http://www.wapa.gov/rm/ratesRM/ 

2012/default.htm. 

Ratemaking Procedure Requirements 

Environmental Compliance 

In compliance with the National 

Environmental Policy Act (NEPA) of 

1969 (42 U.S.C. 4321 et seq.), Council 

on Environmental Quality Regulations 

(40 CFR parts 1500–1508), and DOE 

NEPA Regulations (10 CFR part 1021), 

Western has determined that this action 

is categorically excluded from preparing 

an environmental assessment or an 

environmental impact statement. 

Determination Under Executive Order 

12866 

Western has an exemption from 

centralized regulatory review under 

Executive Order 12866; accordingly, no 

clearance of this notice by the Office of 

Management and Budget is required. 

Submission to the Federal Energy 

Regulatory Commission 

The formula rates herein confirmed, 

approved, and placed into effect on an 

interim basis, together with supporting 

documents, will be submitted to FERC 

for confirmation and final approval. 

Order 

In view of the foregoing, and under 

the authority delegated to me, I confirm 

and approve on an interim basis, 

effective on the first full billing period 

on or after October 1, 2011, formula 

rates for Loveland Area Projects 

Transmission and Western Area 

Colorado Missouri Balancing Authority 

Ancillary Services under Rate 

Schedules L–NT1, L–FPT1, L–NFPT1, 

L–AS1, L–AS2, L–AS3, L–AS4, L–AS5, 

L–AS6, L–AS7, L–AS9, and L–UU1. By 

this order, I am placing the rates into 

effect in less than 30 days to meet 

contract deadlines, to avoid financial 

difficulties, and to provide rates for new 

services. These rate schedules shall 

remain in effect on an interim basis, 

pending FERC’s confirmation and 

approval of them or substitute formula 

rates on a final basis through September 

30, 2016. 

Dated: September 2, 2011. 

Daniel B. Poneman, 

Deputy Secretary. 

Rate Schedule L–AS1 

Schedule 1 to Tariff 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Western Area Colorado Missouri 

Balancing Authority 

Scheduling, System Control, and 

Dispatch Service 

Applicable 

Scheduling, System Control, and 

Dispatch Service is required to schedule 

the movement of power into, out of, 

inside, or through the Western Area 

Colorado Missouri Balancing Authority 

(WACM). This service must be 

purchased from the WACM operator. 

The rate will be applied to all 


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schedules, except those for the delivery 

of transmission losses to WACM. 

Unless other arrangements are made 

with Western, the rate will be divided 

equally among the transmission 

providers displayed in the schedule that 

are inside WACM. The charges 

applicable to non-Federal transmission 

will be assessed to those transmission 

providers. The charges applicable to 

Federal transmission will be included in 

the Federal transmission service rates. 

WACM will accept any number of 

scheduling changes over the course of 

the day without any additional charge. 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Formula Rate 

Rate 

The rate to be in effect October 1, 

2011, through September 30, 2012, is 

$24.22 per schedule per day. A revised 

rate will go into effect October 1 of each 

year of the effective rate period based on 

the formula above and updated financial 

and schedule data. Western will notify 

the Customer annually of the revised 

rate before October 1. 

Any change to the rate for Scheduling, 

System Control, and Dispatch Service 

will be listed in a revision to this rate 

schedule issued under applicable 

Federal laws, regulations, and policies 

and made part of the applicable service 

agreement. 

Rate Schedule L–AS2 

Schedule 2 to Tariff 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Western Area Colorado Missouri 

Balancing Authority 

Reactive Supply and Voltage Control 

from Generation or Other Sources 

Service 

Applicable 

To maintain transmission voltages on 

all transmission facilities within 

acceptable limits, generation facilities 

under the control of the Western Area 

Colorado Missouri Balancing Authority 

(WACM) are operated to produce or 

absorb reactive power. Thus, Reactive 

Supply and Voltage Control from 

Generation or Other Sources Service 

(VAR Support Service) is provided for 

each transaction on the transmission 

facilities. The amount of VAR Support 

Service supplied to the Customer’s 

(Federal Transmission Customers and 

customers on others’ transmission 

systems inside WACM) transactions will 

be based on the VAR Support Service 

necessary to maintain transmission 

voltages within limits that are generally 

accepted in the region and consistently 

adhered to by WACM. The Customer 

must purchase this service from the 

WACM operator. 

Customers with generators providing 

WACM with VAR Support Service may 

be excluded from the application of this 

rate. Any such exclusion must be 

documented in the Customer’s service 

agreement. 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Formula Rate 


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Rate 

The rate to be in effect October 1, 

2011, through September 30, 2012, is: 

Monthly $0.305/kW-month 

Weekly $0.070/kW-week 

Daily $0.010/kW-day 

Hourly $0.000418/kWh 

A revised rate will go into effect October 

1 of each year of the effective rate period 

based on the formula above and updated 

financial and load data. Western will 

notify the Customer annually of the 

revised rate before October 1. 

Any change to the rate for VAR 

Support Service will be listed in a 

revision to this rate schedule issued 

under applicable Federal laws, 

regulations, and policies and made part 

of the applicable service agreement. 

Rate Schedule L–AS3 

Schedule 3 to Tariff 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Western Area Colorado Missouri 

Balancing Authority 

Regulation and Frequency Response 

Service 

Applicable 

Regulation and Frequency Response 

Service (Regulation Service) is 

necessary to provide for the continuous 

balancing of resources with obligations, 

and for maintaining scheduled 

interconnection frequency at sixty 

cycles per second (60 Hz). Regulation 

Service is accomplished by committing 

on-line generation whose output is 

raised or lowered as necessary, 

predominantly through the use of 

automatic generation control (AGC) 

equipment, to follow the moment-bymoment changes in load. The obligation 

to maintain this balance between 

resources and load lies with the Western 

Area Colorado Missouri Balancing 

Authority (WACM) operator. Customers 

(Federal Transmission Customers and 

customers on others’ transmission 

systems inside WACM) must purchase 

this service from WACM or make 

alternative comparable arrangements to 

satisfy their Regulation Service 

obligations. 

Types 

There are two different applications of 

this Formula Rate: 

1. Load-based Assessment: The rate 

for the load-based assessment is 

reflected in the Formula Rate section 

and is applied to entities that take 

Regulation Service from WACM. This 

load-based rate is assessed on an entity’s 

auxiliary load (total metered load less 

Federal entitlements) and is also 

applied to the installed nameplate 

capacity of all intermittent generators 

serving load inside WACM. 

2. Self-provision Assessment: Western 

allows entities with AGC to self-provide 

for all or a portion of their loads. 

Entities with AGC are known as SubBalancing Authorities (SBA) and must 

meet all of the following criteria: 

a. Have a well-defined boundary, with 

WACM-approved revenue-quality 

metering, accurate as defined by the 

North American Electric Reliability 

Corporation (NERC), to include MW 

flow data availability at 6-second or 

smaller intervals; 

b. Have AGC capability; 

c. Demonstrate Regulation Service 

capability; and 

d. Execute a contract with WACM: 

i. Provide all requested data to 

WACM. 

ii. Meet SBA error criteria as 

described under section 2.1 below. 

2.1. Self-provision is measured by use of 

the entity’s 1-minute average Area 

Control Error (ACE) to determine the 

amount of self-provision. The ACE is 

used to calculate the Regulation Service 

charges every hour as follows: 

a. If the entity’s 1-minute average ACE 

for the hour is less than or equal to 0.5 

percent of its hourly average load, no 

Regulation Service charge is assessed by 

WACM for that hour. 

b. If the entity’s 1-minute average ACE 

for the hour is greater than or equal to 

1.5 percent of its hourly average load, 

WACM assesses Regulation Service 

charges to the entity’s entire auxiliary 

load, using the hourly Load-based 

Assessment applied to the entity’s 

auxiliary 12-cp load for that month. 

c. If the entity’s 1-minute average ACE 

for the hour is greater than 0.5 percent 

of its hourly average load, but less than 

1.5 percent of its hourly average load, 

WACM assesses Regulation Service 

charges based on linear interpolation of 

zero charge and full charge, using the 

hourly Load-based Assessment applied 

to the entity’s auxiliary 12-cp load for 

that month. 

d. Western monitors the entity’s Selfprovision on a regular basis. If Western 

determines that the entity has not been 

attempting to self-regulate, WACM will, 

upon notification, employ the Loadbased Assessment described in No. 1, 

above. 

Alternative Arrangements 

Exporting Intermittent Resource 

Requirement: An entity that exports the 

output from an intermittent generator to 

another balancing authority will be 

required to dynamically meter or 

dynamically schedule that resource out 

of WACM to another balancing 

authority unless arrangements, 

satisfactory to Western, are made for 

that entity to acquire this service from 

a third party or self-supply (as outlined 

below). An intermittent generator is one 

that is volatile and variable due to 

factors beyond direct operational 

control and, therefore, is not 

dispatchable. 

Self- or Third-party supply: Western 

may allow an entity to supply some or 

all of its required regulation, or contract 

with a third party to do so, even without 

well-defined boundary metering. This 

entity must have revenue quality 

metering at every load and generation 

point, accurate as defined by NERC, to 

include MW flow data availability at 6- 

second or smaller intervals. Western 

will evaluate the entity’s metering, 

telecommunications and regulating 

resource, as well as the required level of 

regulation, and determine whether the 

entity qualifies to self-supply under this 

provision. If approved, the entity is 

required to enter into a separate 

agreement with Western which will 

specify the terms of the self-supply 

application. 

Customer Accommodation 

For entities unwilling to take 

Regulation Service, self-provide it as 

described above, or acquire the service 

from a third party, Western will assist 

the entity in dynamically metering its 

loads/resources to another balancing 

authority. Until such time as that meter 

configuration is accomplished, the 

entity will be responsible for charges 

assessed by WACM under the rate in 

effect. 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Formula Rate 


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Rate 

The rate to be in effect October 1, 

2011, through September 30, 2012, for 

Nos. 1 and 2, as described above in the 

‘‘Types’’ section of this rate schedule, is: 

Monthly $0.331/kW-month 

Weekly $0.076/kW-week 

Daily $0.011/kW-day 

Hourly $0.000458/kWh 

A revised rate will go into effect October 

1 of each year of the effective rate period 

based on the formula above and updated 

financial and load data. Western will 

notify the Customer annually of the 

revised rate before October 1. 

Any change to the rate for Regulation 

Service will be listed in a revision to 

this rate schedule issued under 

applicable Federal laws, regulations, 

and policies and made part of the 

applicable service agreement. 

Rate Schedule L–AS4 

Schedule 4 to Tariff 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Western Area Colorado Missouri 

Balancing Authority 

Energy Imbalance Service 

Applicable 

The Western Area Colorado Missouri 

Balancing Authority (WACM) provides 

Energy Imbalance Service when there is 

a difference between a Customer’s 

(Federal Transmission Customers and 

customers on others’ transmission 

systems inside WACM) resources and 

obligations. Energy Imbalance is 

calculated as resources minus 

obligations (adjusted for transmission 

and transformer losses) for any 

combination of generation, scheduled 

transfers, transactions, or actual load 

integrated over each hour. Customers 

inside WACM must either obtain this 

service from WACM or make alternative 

comparable arrangements to satisfy their 

Energy Imbalance Service obligation. 

This rate applies to all customers with 

load inside WACM. 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Formula Rate 

Imbalances are calculated in three 

deviation bands as follows. The term 

‘‘metered load’’ is defined to be 

‘‘metered load adjusted for losses.’’ 

1. An imbalance of less than or equal 

to 1.5 percent of metered load (or 4 MW, 

whichever is greater) for any hour is 

settled financially at 100 percent of the 

WACM weighted average hourly price. 

2. An imbalance between 1.5 percent 

and 7.5 percent of metered load (or 4 to 

10 MW, whichever is greater) for any 

hour is settled financially at 90 percent 

of the WACM weighted average hourly 

price when net energy scheduled 

exceeds metered load or 110 percent of 

the WACM weighted average hourly 

price when net energy scheduled is less 

than metered load. 

3. An imbalance greater than 7.5 

percent of metered load (or 10 MW, 

whichever is greater) for any hour is 

settled financially at 75 percent of the 

WACM weighted average hourly price 

when net energy scheduled exceeds 

metered load or 125 percent of the 

WACM weighted average hourly price 

when net energy scheduled is less than 

metered load. 

All Energy Imbalance Service 

provided by WACM is accounted for 

hourly and settled financially. The 

WACM aggregate imbalance determines 

the pricing used in all deviation bands. 

A surplus dictates the use of sale 

pricing; a deficit dictates the use of 

purchase pricing. When no hourly data 

is available, the pricing defaults for 

sales and purchase pricing are applied 

in the following order: 

1. Weighted average sale or purchase 

pricing for the day (on- and off-peak). 

2. Weighted average sale or purchase 

pricing for the month (on- and off-peak). 

3. Weighted average sale or purchase 

pricing for the prior month (on- and offpeak). 

4. Weighted average sale or purchase 

pricing for the month prior to the prior 

month (and continuing until sale or 

purchase pricing is located) (on- and offpeak). 

Expansion of the bandwidth may be 

allowed during the following instances: 

• Response to the loss of a physical 

resource. 

• During transition of large base-load 

thermal resources (capacity greater than 

200 MW) between off-line and on-line 

following a reserve sharing group 

response, when the unit generates less 

than the predetermined minimum 

scheduling level. 

During periods of balancing authority 

operating constraints, Western reserves 

the right to eliminate credits for overdeliveries. The cost to Western of any 

penalty assessed by a regulatory 

authority due to a violation of operating 

standards resulting from under- or overdelivery of energy may be passed 

through to Energy Imbalance Service 

customers. 

Rate 

The bandwidths, penalties, and 

pricing described above are in effect 

October 1, 2011, through September 30, 

2012. 

Any change to the rate for Energy 

Imbalance Service will be listed in a 

revision to this rate schedule issued 

under applicable Federal laws, 

regulations, and policies and made part 

of the applicable service agreement. 

Rate Schedule L–AS5 

Schedule 5 to Tariff 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Western Area Colorado Missouri 

Balancing Authority 

Operating Reserve—Spinning Reserve 

Service 

Applicable 

Spinning Reserve Service (Reserves) 

is needed to serve load immediately in 

the event of a system contingency. 

Reserves may be provided by generating 

units that are on-line and loaded at less 

than maximum output. The Customers 

(Federal Transmission Customers and 

customers on others’ transmission 

system inside Western Area Colorado 

Missouri Balancing Authority (WACM)) 

must either purchase this service from 

WACM or make alternative comparable 

arrangements to satisfy their Reserves 

obligation. 


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Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Formula Rate 

WACM has no long-term Reserves 

available for sale. At a Customer’s 

request, WACM will purchase Reserves 

and pass through the cost of Reserves 

and any activation energy, plus a fee for 

administration. The Customer will be 

responsible for providing the 

transmission to deliver the Reserves. 

Rate Schedule L–AS6 

Schedule 6 to Tariff 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Western Area Colorado Missouri 

Balancing Authority 

Operating Reserve—Supplemental 

Reserve Service 

Applicable 

Supplemental Reserve Service 

(Reserves) is needed to serve load in the 

event of a system contingency; however, 

it is not available immediately to serve 

load but rather within a short period of 

time. Reserves may be provided by 

generating units that are on-line but 

unloaded, by quick-start generation, or 

by interruptible load. The Customers 

(Federal Transmission Customers and 

customers on others’ transmission 

system inside Western Area Colorado 

Missouri Balancing Authority (WACM)) 

must either purchase this service from 

WACM or make alternative comparable 

arrangements to satisfy their Reserves 

obligation. 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Formula Rate 

WACM has no long-term Reserves 

available for sale. At a Customer’s 

request, WACM will purchase Reserves 

and pass through the cost of Reserves 

and any activation energy, plus a fee for 

administration. The Customer will be 

responsible for providing the 

transmission to deliver the Reserves. 

Rate Schedule L–AS7 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Western Area Colorado Missouri 

Balancing Authority 

Transmission Losses Service 

Applicable 

The Western Area Colorado Missouri 

Balancing Authority (WACM) provides 

Transmission Losses Service to all 

Transmission Service Providers who 

market transmission inside WACM. The 

loss factor currently in effect is posted 

on the Rocky Mountain Region (RMR) 

Open Access Same-Time Information 

System (OASIS) Web site. 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Formula Rate 

Transmission Losses are assessed for 

all real-time and prescheduled 

transactions on transmission facilities 

inside WACM. The Customer is allowed 

the option of energy repayment or 

financial repayment. Energy repayment 

may be either concurrently or seven 

days later, to be delivered using the 

same profile as the related transmission 

transaction. Customers must declare 

annually their preferred methodology of 

energy payback. 

When a transmission loss energy 

obligation is not provided (or is underprovided) by a Customer for a 

transmission transaction, the energy still 

owed for Transmission Losses is 

calculated and a charge is assessed to 

the Customer, based on the WACM 

weighted average hourly purchase price. 

Pricing for loss energy due 7 days 

later, and not received by WACM, will 

be priced at the 7-day-later-price based 

on the WACM weighted average hourly 

purchase price. 

There will be no financial 

compensation or energy return to 

Customers for over-delivery of 

Transmission Losses, as there should be 

no condition beyond the control of the 

Customer that results in overpayment. 

Rate 

This loss factor, as posted on the RMR 

OASIS, is in effect October 1, 2011, 

through September 30, 2012. Customers 

may settle financially or with energy. 

The pricing for this service will be the 

WACM weighted average hourly 

purchase price. When no hourly data is 

available, pricing defaults will be 

applied in the following order: 

1. Weighted average purchase pricing 

for the day (on- and off-peak). 

2. Weighted average purchase pricing 

for the current month (on- and off-peak). 

3. Weighted average purchase pricing 

for the prior month (on- and off-peak). 

4. Weighted average purchase pricing 

for the month prior to the prior month 

(and continuing until or purchase 

pricing is located) (on- and off-peak). 

Any change to the rate for Transmission 

Losses Service will be listed in a 

revision to this rate schedule issued 

under applicable Federal laws, 

regulations, and policies and made part 

of the applicable service agreement. 

Rate Schedule L–FPT1 

Schedule 7 to Tariff 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Loveland Area Projects 

Long-Term Firm and Short-Term Firm 

Point-To-Point Transmission Service 

Applicable 

The Transmission Customer shall 

compensate the Loveland Area Projects 

(LAP) each month for Reserved Capacity 

under the applicable Firm Point-toPoint Transmission Service Agreement 

and the rate outlined herein. 

Discounts 

Three principal requirements apply to 

discounts for transmission service as 

follows: (1) Any offer of a discount 

made by LAP must be announced to all 

eligible customers solely by posting on 

the Rocky Mountain Region’s Open 

Access Same-Time Information System 

web site (OASIS); (2) any customerinitiated requests for discounts, 

including requests for use by the LAP 

merchant, must occur solely by posting 

on the OASIS; and (3) once a discount 

is negotiated, details must be 

immediately posted on the OASIS. For 

any discount agreed upon for service on 

a path, from Point(s) of Receipt to 

Point(s) of Delivery, LAP must offer the 

same discounted transmission service 

rate for the same time period to all 

eligible customers on all unconstrained 

transmission paths that go to the same 

point(s) of delivery on the transmission 

system. 


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Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Formula Rate 

Rate 

The rate to be in effect October 1, 

2011, through September 30, 2012, is: 

Maximum of 

Yearly $41.80/kW of reserved 

capacity per year 

Monthly $3.48/kW of reserved capacity per month 

Weekly $0.80/kW of reserved capacity per week 

Daily $0.11/kW of reserved capacity per day 

A revised rate will go into effect 

October 1 of each year of the effective 

rate period based on the formula above, 

updated financial and load projections, 

and the true-up of previous projections. 

Western will notify the Transmission 

Customer annually of the revised rate 

before October 1. 

Any change to the rate for Long-Term 

Firm and Short-Term Firm 

Transmission Service will be listed in a 

revision to this rate schedule issued 

under applicable Federal laws, 

regulations, and policies and made part 

of the applicable service agreement. 

Rate Schedule L–NFPT1 

Schedule 8 to Tariff 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Loveland Area Projects 

Non-Firm Point-To-Point Transmission 

Service 

Applicable 

The Transmission Customer will 

compensate Loveland Area Projects 

(LAP) for Non-Firm Point-to-Point 

Transmission Service under the 

applicable Non-Firm Point-to-Point 

Transmission Service Agreement and 

the rate outlined herein. 

Discounts 

Three principal requirements apply to 

discounts for transmission service as 

follows: (1) Any offer of a discount 

made by LAP must be announced to all 

eligible customers solely by posting on 

Rocky Mountain Region’s Open Access 

Same-Time Information System web site 

(OASIS); (2) any customer-initiated 

requests for discounts, including 

requests for use by the LAP merchant, 

must occur solely by posting on the 

OASIS; and (3) once a discount is 

negotiated, details must be immediately 

posted on the OASIS. For any discount 

agreed upon for service on a path, from 

Point(s) of Receipt to Point(s) of 

Delivery, LAP must offer the same 

discounted transmission service rate for 

the same time period to all eligible 

customers on all unconstrained 

transmission paths that go to the same 

point(s) of delivery on the transmission 

system. 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Formula Rate 

Rate 

The rate to be in effect October 1, 

2011, through September 30, 2012, is: 

Maximum of 

Yearly $41.80/kW of reserved 

capacity per year 

Monthly $3.48/kW of reserved capacity per month 

Weekly $0.80/kW of reserved capacity per week 

Daily $0.11/kW of reserved capacity per day 

Hourly 4.77 mills/kWh 

A revised rate will go into effect 

October 1 of each year of the effective 

rate period based on the formula above, 

updated financial and load projections, 

and the true-up of previous projections. 

Western will notify the Transmission 

Customer annually of the revised rate 

before October 1. 

Any change to the rate for Non-Firm 

Point-to-Point Transmission Service 

will be listed in a revision to this rate 

schedule issued under applicable 

Federal laws, regulations, and policies 

and made part of the applicable service 

agreement. 

Rate Schedule L–NT1 

Schedule H to Tariff 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Loveland Area Projects 

Annual Transmission Revenue 

Requirement for Network Integration 

Transmission Service 

Applicable 

Transmission Customers will 

compensate the Loveland Area Projects 

each month for Network Integration 

Transmission Service under the 

applicable Network Integration 

Transmission Service Agreement and 

the Annual Transmission Revenue 

Requirement described herein. 


srobinson on DSK4SPTVN1PROD with NOTICES3EN03OC11.016</GPH> EN03OC11.017</GPH>
61202 Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Formula Rate 

Rate 

The Annual Transmission Revenue 

Requirement in effect October 1, 2011, 

through September 30, 2012, is 

$56,775,913. 

A revised Annual Transmission 

Revenue Requirement will go into effect 

October 1 of each year of the effective 

rate period based on updated financial 

projections and the true-up of previous 

projections. Western will notify the 

Transmission Customer annually of the 

revised Annual Transmission Revenue 

Requirement before October 1. 

Any change to the rate for Network 

Integration Transmission Service will be 

listed in a revision to this rate schedule 

issued under applicable Federal laws, 

regulations, and policies and made part 

of the applicable service agreement. 

Rate Schedule L–AS9 

Schedule 9 to Tariff 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Western Area Colorado Missouri 

Balancing Authority 

Generator Imbalance Service 

Applicable 

The Western Area Colorado Missouri 

(WACM) Balancing Authority provides 

Generator Imbalance Service when there 

is a difference between a Customer’s 

(Federal Transmission Customers and 

customers on others’ transmission 

systems inside WACM) resources and 

obligations. Generator Imbalance is 

calculated as actual generation minus 

scheduled generation for each hour. 

Customers inside WACM must either 

obtain this service from WACM or make 

alternative comparable arrangements to 

satisfy their Generator Imbalance 

Service obligation. This rate applies to 

all jointly-owned generators (unless 

arrangements are made to allocate actual 

generation to each individual owner), 

intermittent generators (unless 

arrangements are made to assess the 

intermittent generator under Rate 

Schedule L–AS4), and any nonintermittent generators serving load 

only outside WACM. 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Formula Rate 

Imbalances are calculated in three 

deviation bands as follows: 

1. An imbalance of less than or equal 

to 1.5 percent of metered generation (or 

4 MW, whichever is greater) for any 

hour is settled financially at 100 percent 

of the WACM weighted average hourly 

price. 

2. An imbalance between 1.5 percent 

and 7.5 percent of metered generation 

(or 4 to 10 MW, whichever is greater) for 

any hour is settled financially at 90 

percent of the WACM weighted average 

hourly price when actual generation 

exceeds scheduled generation or 110 

percent of the WACM weighted average 

hourly price when actual generation is 

less than scheduled generation. 

3. An imbalance greater than 7.5 

percent of metered generation (or 10 

MW, whichever is greater) for any hour 

is settled financially at 75 percent of the 

WACM weighted average hourly price 

when actual generation exceeds 

scheduled generation or 125 percent of 

the WACM weighted average hourly 

price when actual generation is less 

than scheduled generation. 

Intermittent generators are exempt 

from 25 percent penalties. All 

imbalances greater than 1.5 percent of 

metered generation are subject only to a 

10 percent penalty. 

All Generator Imbalance Service 

provided by WACM is accounted for 

hourly and settled financially. The 

WACM aggregate imbalance determines 

the pricing used in all deviation bands. 

A surplus dictates the use of sale 

pricing; a deficit dictates the use of 

purchase pricing. When no hourly data 

is available, the pricing defaults for 

sales and purchase pricing are applied 

in the following order: 

1. Weighted average sale or purchase 

pricing for the day (on- and off-peak). 

2. Weighted average sale or purchase 

pricing for the current month (on- and 

off-peak). 

3. Weighted average sale or purchase 

pricing for the prior month (on- and offpeak). 

4. Weighted average sale or purchase 

pricing for the month prior to the prior 

month (and continuing until sale or 

purchase pricing is located) (on- and offpeak). 

Expansion of the bandwidth may be 

allowed during the following instances: 

• Response to the loss of a physical 

resource. 

• During transition of large base-load 

thermal resources (capacity greater than 

200 MW) between off-line and on-line 

following a reserve sharing group 

response, when the unit generates less 

than the predetermined minimum 

scheduling level. 

During periods of balancing authority 

operating constraints, Western reserves 

the right to eliminate credits for overdeliveries. The cost to Western of any 

penalty assessed by a regulatory 

authority due to a violation of operating 

standards resulting from under- or overdelivery of energy may be passed 

through to Generator Imbalance Service 

customers. 

Rate 

The bandwidths, penalties, and 

pricing described above are in effect 

October 1, 2011, through September 30, 

2012. 

Any change to the rate for Generator 

Imbalance Service will be listed in a 

revision to this rate schedule issued 

under applicable Federal laws, 

regulations, and policies and made part 

of the applicable service agreement. 


srobinson on DSK4SPTVN1PROD with NOTICES3EN03OC11.018</GPH>
Federal Register / Vol. 76, No. 191 / Monday, October 3, 2011 / Notices 61203 

Rate Schedule L–UU1 

Schedule 10 to Tariff 

October 1, 2011 

United States Department of Energy 

Western Area Power Administration 

Rocky Mountain Region 

Loveland Area Projects 

Unreserved Use Penalties 

Applicable 

The Transmission Customer shall 

compensate the Loveland Area Projects 

(LAP) each month for any unreserved 

use of the transmission system 

(Unreserved Use) under the applicable 

transmission service rates as outlined 

herein. Unreserved Use occurs when an 

eligible customer uses transmission 

service that it has not reserved or a 

Transmission Customer uses 

transmission service in excess of its 

reserved capacity. Unreserved Use may 

also include a Customer’s failure to 

curtail transmission when requested. 

Penalty Rate 

The penalty rate for a Transmission 

Customer that engages in Unreserved 

Use is 200 percent of LAP’s approved 

rate for firm point-to-point transmission 

service assessed as follows: the 

Unreserved Use Penalty for a single 

hour of Unreserved Use is based upon 

the rate for daily firm point-to-point 

service. The Unreserved Use Penalty for 

more than one assessment for a given 

duration (e.g., daily) increases to the 

next longest duration (e.g., weekly). The 

Unreserved Use Penalty for multiple 

instances of Unreserved Use (e.g., more 

than one hour) within a day is based on 

the rate for daily firm point-to-point 

service. The Unreserved Use Penalty for 

multiple instances of Unreserved Use 

isolated to one calendar week is based 

on the rate for weekly firm point-topoint service. The Unreserved Use 

Penalty for multiple instances of 

Unreserved Use during more than one 

week in a calendar month is based on 

the rate for monthly firm point-to-point 

service. 

A Transmission Customer that 

exceeds its firm reserved capacity at any 

point of receipt or point of delivery, or 

an eligible customer that uses 

transmission service at a point of receipt 

or point of delivery that it has not 

reserved, is required to pay for all 

ancillary services that were provided by 

the Western Area Colorado Missouri 

Balancing Authority and associated 

with the Unreserved Use. The Customer 

will pay for ancillary services based on 

the amount of transmission service it 

used and did not reserve. 

Effective 

The first day of the first full billing 

period beginning on or after October 1, 

2011, through September 30, 2016. 

Rate 

The rate for Unreserved Use Penalties 

is 200 percent of LAP’s approved rate 

for firm point-to-point transmission 

service assessed as described above. 

Any change to the rate for Unreserved 

Use Penalties will be listed in a revision 

to this rate schedule issued under 

applicable Federal laws, regulations, 

and policies and made part of the 

applicable service agreement. 

[FR Doc. 2011–23391 Filed 9–12–11; 8:45 

am] 

Editorial Note: FR Doc. 2011–23391 which 

was originally published on pages 56433– 

56452 in the issue of Tuesday, September 13, 

2011 is being republished in its entirety in 

the issue of Monday, October 3, 2011 because 

of editing errors. 

[FR Doc. R1–2011–23391 Filed 9–30–11; 8:45 am] 

BILLING CODE 6450–01–P 


srobinson on DSK4SPTVN1PROD with NOTICES3