Loveland Area Projects-Western Area Colorado Missouri Balancing Authority-Rate Order No. WAPA-155

Western Area Power Administration

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Loveland Area Projects--Western Area Colorado Missouri Balancing

Authority--Rate Order No. WAPA-155; Notice; Republication

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

Notices

[[Page 61184]]

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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.

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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rate schedules are superseded.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 [email protected].

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.

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\1\ WAPA-106 was approved by FERC on a final basis on January

31, 2005, in Docket No. EF2-04-5182-000 (110 FERC ] 62,084).

\2\ WAPA-141, Extension of Rate Order No. WAPA-106 through

February 28, 2011. 73 FR 48382, August 19, 2008.

\3\ WAPA-118 was approved by FERC on a final basis on November

17, 2006, in Docket No. EF-06-5182-000 (117 FERC ] 62,163).

\4\ WAPA-154, Extension of Rate Order Nos. WAPA-106 and WAPA-118

through February 28, 2013. 76 FR 1429, January 10, 2011.

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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.

[[Page 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:

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Acronym/Term Definition

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$/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 The highest priority transmission

Service: 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 Firm Point-to-Point Transmission

Transmission Service: Service reservation for a duration

of at least 12 consecutive months.

[[Page 61186]]

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 Firm transmission service for the

Service: delivery of capacity and energy

from designated network resources

to designated network loads not

using one specific path.

Non-Firm Point-to-Point Point-to-point transmission service

Transmission Service: reserved on an as-available basis

for periods ranging from 1 hour to

1 year.

Open Access Same Time Information An electronic posting system that

System (OASIS): the Transmission Provider

maintains for transmission access

data that allows all transmission

customers to view the data

simultaneously.

Operating Reserve--Spinning Reserve Generation capacity needed to serve

Service: 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 Generation capacity needed to serve

Reserve Service: 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 on-line

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 The ancillary service under which a

from Generation or Other Sources Balancing Authority operates

Service: 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 The ancillary service under which a

Service: Balancing Authority maintains

moment-by-moment load-interchange-

generation balance with the

Balancing Authority area and

supports interconnection

frequency.

Scheduling, System Control, and The ancillary service under which a

Dispatch Service: 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 Firm Point-to-Point Transmission

Transmission Service: 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.

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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

[[Page 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 Pumped-

Storage 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-To-Point 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

[[Page 61188]]

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

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Provisional Formula Rates Effective Existing Formula Rates Effective October

Class of Service October 1, 2011 (FY 2012) 1, 2010 (FY 2011)

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Network Integration L-NT1 L-NT1

Transmission Service Load ratio share of 1/12 of the revenue Load ratio share of 1/12 of the revenue

requirement of $56,775,913. requirement of $48,000,660.

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Firm Point-to-Point L-FPT1 L-FPT1

Transmission Service $3.48/kW-month $3.18/kW-month

Unauthorized Use Penalty of 150% of

demand charge, with a maximum of

monthly service.

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Non-Firm Point-to-Point L-NFPT1 L-NFPT1

Transmission Service Maximum of 4.77 mills/kWh Maximum of 4.17 mills/kWh

Unauthorized Use Penalty of 150% of

demand charge, with a maximum of

monthly service.

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Unreserved Use Penalties L-UU1 Provided Under Rate Schedules L-FPT1 and

Penalized 200% of demand charge, with a L-NFPT1 as Unauthorized Use.

maximum of monthly service.

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Transmission Losses Service L-AS7 L-AS7

Transmission losses may be settled Transmission losses may be settled

either financially or with energy. either financially or with energy.

Insufficient losses supplied will be Insufficient losses supplied will be

settled financially by default. settled financially by default.

All customers will have the option to All customers will have the option to

return the loss obligation for both return the loss obligation for both

prescheduled and real-time transactions prescheduled and real-time transactions

7 days later, same profile. 7 days later, same profile.

Pricing used is WACM weighted average Pricing used is LAP weighted average

hourly purchase price. hourly real-time purchase price.

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

Scheduling, System Control, L-AS1 L-AS1

and Dispatch Service $24.22 per schedule per day for non- $38.30 per tag per day for non-

Federal transmission customers. Not Federal transmission customers.

applicable to schedules for delivery of Applicable to all tags.

Losses to WACM.

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Reactive Supply and Voltage L-AS2 L-AS2

Control from Generation or $0.305/kW-month $0.180/kW-month

Other Sources Service

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Regulation and Frequency L-AS3 L-AS3

Response $0.331/kW-month $0.339/kW-month

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Energy Imbalance Service L-AS4 L-AS4

--Imbalances less than or equal to 1.5% --Imbalances less than or equal to 5%

(minimum 4 MW) of metered load settled (minimum 4 MW) of metered load settled

using WACM hourly pricing with no using WACM hourly pricing with no

penalty. penalty.

--Imbalances between 1.5% and 7.5% --Imbalances greater than 5% of metered

(minimum 4 MW to 10 MW) of metered load load settled using WACM hourly pricing

settled using WACM hourly pricing with with a 10% penalty.

a 10% penalty.

--Imbalances greater than 7.5% (minimum --WACM aggregate imbalance dictates

10 MW) of metered load settled using pricing in no-penalty band. Customer

WACM hourly pricing with a 25% penalty. imbalance dictates pricing in penalty

--WACM aggregate imbalance determines band (surpluses indicate sale pricing,

pricing in all bands--aggregate surplus deficits indicate purchase pricing).

dictates sale pricing, aggregate --Intermittent resources not subject to

deficit dictates purchase pricing. penalties.

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Operating Reserve Service-- L-AS5, L-AS6 L-AS5, L-AS6

Spinning and Supplemental Long-term Reserves are not available Long-term Reserves are not available

from WACM. Reserves may be acquired and from WACM. Reserves may be acquired and

provided at pass-through cost, plus an provided at pass-through cost, plus an

amount for administration. amount for administration.

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[[Page 61189]]

Generator Imbalance Service L-AS9 Provided under Rate Schedule L-AS4.

--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.

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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:

[GRAPHIC] [TIFF OMITTED] TN03OC11.000

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-to-Point Transmission Service is as

follows:

[GRAPHIC] [TIFF OMITTED] TN03OC11.001

The rates for FY 2012 are as follows:

[GRAPHIC] [TIFF OMITTED] TN03OC11.002

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-to-Point 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

[[Page 61190]]

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:

[GRAPHIC] [TIFF OMITTED] TN03OC11.003

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:

[GRAPHIC] [TIFF OMITTED] TN03OC11.004

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, sub-transmission, 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 ``sub-transmission'' 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 generation-related

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 true-up, see discussion below on ``Change

to Forward-Looking Transmission Rates.''

[[Page 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 under-collection of

the revenue requirement will be included as a charge in the ATRR in a

subsequent year. This true-up 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

over-collected 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-to-Point Transmission Service. This load

calculation is prepared once annually and is used to calculate the

point-to-point 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-to-Point 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:

[[Page 61192]]

[GRAPHIC] [TIFF OMITTED] TN03OC11.005

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:

[GRAPHIC] [TIFF OMITTED] TN03OC11.006

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

[GRAPHIC] [TIFF OMITTED] TN03OC11.007

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:

[[Page 61193]]

[GRAPHIC] [TIFF OMITTED] TN03OC11.008

Applying this percentage to the amount of net generation plant

investment results in the TARRG:

TARRG = $334,166,538 x 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 x 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-to-point 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:

[GRAPHIC] [TIFF OMITTED] TN03OC11.009

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:

[GRAPHIC] [TIFF OMITTED] TN03OC11.010

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% x $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:

[[Page 61194]]

[GRAPHIC] [TIFF OMITTED] TN03OC11.011

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 x 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- 1,320,110

peak hours.............................................

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.

[GRAPHIC] [TIFF OMITTED] TN03OC11.012

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 Sub-Balancing 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 self-provision. 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

[[Page 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 off-peak).

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-the-fact 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 ``must-run'' 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 non-intermittent 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

[[Page 61196]]

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 Load-Serving 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

[[Page 61197]]

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

[GRAPHIC] [TIFF OMITTED] TN03OC11.013

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

[GRAPHIC] [TIFF OMITTED] TN03OC11.014

[[Page 61198]]

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-by-moment 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 Sub-Balancing 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 Self-provision on a regular basis.

If Western determines that the entity has not been attempting to self-

regulate, WACM will, upon notification, employ the Load-based

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

[[Page 61199]]

[GRAPHIC] [TIFF OMITTED] TN03OC11.015

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 off-peak).

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 off-peak).

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 over-deliveries.

The cost to Western of any penalty assessed by a regulatory authority

due to a violation of operating standards resulting from under- or

over-delivery 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.

[[Page 61200]]

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

under-provided) 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-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 the 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.

[[Page 61201]]

Effective

The first day of the first full billing period beginning on or

after October 1, 2011, through September 30, 2016.

Formula Rate

[GRAPHIC] [TIFF OMITTED] TN03OC11.016

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

[GRAPHIC] [TIFF OMITTED] TN03OC11.017

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.

[[Page 61202]]

Effective

The first day of the first full billing period beginning on or

after October 1, 2011, through September 30, 2016.

Formula Rate

[GRAPHIC] [TIFF OMITTED] TN03OC11.018

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 non-intermittent 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 off-peak).

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 off-peak).

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 over-deliveries.

The cost to Western of any penalty assessed by a regulatory authority

due to a violation of operating standards resulting from under- or

over-delivery 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.

[[Page 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-to-point 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