[Federal Register Volume 80, Number 171 (Thursday, September 3, 2015)]
[Notices]
[Pages 53293-53308]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-21904]


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DEPARTMENT OF ENERGY

Western Area Power Administration


Salt Lake City Area Integrated Projects and Colorado River 
Storage Project--Rate Order No. WAPA-169

AGENCY: Western Area Power Administration, DOE.

ACTION: Notice of final firm power rate and transmission and ancillary 
services formula rates.

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SUMMARY: The Deputy Secretary of Energy confirmed and approved Rate 
Order No. WAPA-169 and Rate Schedule SLIP-F10. Through this notice, the 
Western Area Power Administration (Western) places firm power rates for 
Western's Salt Lake City Area Integrated Projects (SLCA/IP) into effect 
on an interim basis. The Deputy Secretary also confirmed Rate Schedules 
SP-PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-RS4, SP-EI4, SP-FR4, SP-SSR4, and 
SP-UU1. Through this notice, Western places firm and non-firm 
transmission and ancillary services formula rates on the Colorado River 
Storage Project (CRSP) transmission system into effect on an interim 
basis. The provisional rates will be in effect until the Federal Energy 
Regulatory Commission (FERC) confirms, approves, and places these into 
effect on a final basis or until these are replaced by other rates. The 
provisional rates will provide sufficient revenue to pay all annual 
costs, including interest expense, and repay required investments and 
irrigation aid within the allowable periods.

DATES: Rate Schedules SLIP-F10, SP-PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-
RS4, SP-EI4, SP-FR4, SP-SSR4, and SP-UU1 will be placed into effect on 
an interim basis on the first day of the first full-billing period 
beginning on October 1, 2015, and will be in effect until FERC 
confirms, approves, and places the rate schedules in effect on a final 
basis through September 30, 2020, or until the rate schedules are 
superseded.

FOR FURTHER INFORMATION CONTACT: Ms. Lynn C. Jeka, CRSP Manager, 
Colorado River Storage Project Management Center, Western Area Power 
Administration, 150 East Social Hall Avenue, Suite 300, Salt Lake City, 
UT 84111-1580, (801) 524-6372, email [email protected], or Mr. Rodney G. 
Bailey, Power Marketing Manager, Colorado River Storage Project 
Management Center, Western Area Power Administration, 150 East Social 
Hall Avenue, Suite 300, Salt Lake City, UT 84111-1580, (801) 524-4007, 
email [email protected].

SUPPLEMENTARY INFORMATION: Western proposed the rates for the SLCA/IP 
firm power and CRSP transmission and ancillary services rates on 
December 9, 2014 (79 FR 73067). On January 15, 2015, Western held a 
public information forum in Salt Lake City, Utah. On February 5, 2015, 
Western held a public comment forum in Salt Lake City, Utah. After 
considering the comments received, Western announced the rates for the 
SLCA/IP firm power and CRSP transmission and ancillary services.
    The existing Rate Schedule SLIP-F9 for SLCA/IP firm power and Rate 
Schedules SP-PTP7, SP-NW3, SP-NFT6, SP-SD3, SP-RS3, SP-EI3, SP-FR3, and 
SP-SSR3 for CRSP Transmission and Ancillary Services were approved 
under Rate Order No. WAPA-137 \1\ for a 5-year period beginning October 
1, 2008, and ending September 30, 2013. The Deputy Secretary of Energy 
approved Rate Order No. WAPA-161 \2\ on September 6, 2013, extending 
the rates through September 30, 2015.
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    \1\ FERC confirmed and approved Rate Order No. WAPA-137 on June 
19, 2009, in Docket EF08-5171. See United States Department of 
Energy, Western Area Power Administration, Salt Lake City Area 
Integrated Projects, 127 FERC ] 62,220 (June 19, 2009).
    \2\ Rate Order No. WAPA-161, approved by the Deputy Secretary of 
Energy on September 6, 2013 (78 FR 56692, September 13, 2013), and 
filed with FERC for informational purposes only.
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    The existing firm power Rate Schedule SLIP-F9 is being superseded 
by Rate Schedule SLIP-F10. The current capacity rate and energy rate 
under WAPA-137 remain sufficient to cover Operations Maintenance & 
Replacements and required repayment. Western will continue to use the 
existing energy charge of 12.19 mills/kWh and capacity charge of $5.18/
kWmonth. However, the composite rate, which is used for comparison 
purposes only and is not part of the billing component, will decrease 
from 29.62 to 29.42 mills/kWh. The composite rate is calculated by 
dividing the average revenue requirement for the rate-setting period by 
the average energy sales. The change in the composite rate is driven in 
large part by changes in the average energy sales due to changes in 
Project Use energy requirements. Rate Schedules SLIP-F10, SP-PTP8, SP-
NW4, SP-NFT7, SP-SD4, SP-RS4, SP-EI4, SP-FR4, SP-SSR4, and SP-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, 2015, and will be 
in effect until FERC confirms, approves, and places the rate schedules 
in effect on a final basis through September 30, 2020, or until the 
rate schedules are superseded.
    Under this rate action, Western makes the following changes to the 
existing rates as originally proposed:
    1. The firm power rate will continue to include a cost recovery 
mechanism to adequately maintain a sufficient cash balance in the Upper 
Colorado River Basin Fund (Basin Fund) when, among other things, the 
balance is at risk due to low hydropower generation, high prices for 
firming power, and funding for capitalized investments. The Cost 
Recovery Charge (CRC) is not a component of the firm power rate because 
the rate is set to collect sufficient revenue for repayment in the 
Power Repayment Study (PRS) and is not tied to the cash balance of the 
Basin Fund. Western is modifying the CRC by adopting a tiered 
implementation approach to afford Western discretion in implementing a 
potential CRC. Under the current criteria, if the CRC is triggered, 
Western must initiate the CRC regardless of the balance in the Basin 
Fund. This may potentially cause a CRC to be initiated when it is not 
necessary due to the projected ending balance of the fund being higher 
than the minimum amount Western's management has determined as an 
acceptable ending balance. Allowing Western to have discretion will 
ensure a CRC is only initiated when the projected ending balance of the 
Basin Fund is below $40 million.
    2. Western is adopting forward-looking methodology used to 
calculate the Annual Transmission Revenue Requirement (ATRR). This 
methodology allows Western to recover costs in line with the FY 
following when the cost occurred. In addition to annual audited 
financial data, Western will use projections from the 10-Year Plan and 
current year-to-date financial data for the annual rate calculation. 
This is a change in the manner in which the inputs for the rate are 
developed, rather than a change to the formula rate itself. Western 
will use a ``true-up'' procedure to ensure that no more and no less 
than the actual transmission costs are recovered for the year.
    3. Western proposes to use a formula-based rate for the Regulation 
and Frequency Response Ancillary Service that will more accurately 
reflect the incurred costs rather than using the SLCA/IP firm power 
capacity rate. This

[[Page 53294]]

proposed change will be more in line with other Western Federal 
transmission providers.
    4. Add a rate schedule for Unreserved Use, SP-UU1. The rate will be 
set at 200 percent of the Colorado River Storage Project Management 
Center's (CRSP MC) current transmission rate. Currently, the CRSP MC is 
using an ``Unauthorized Use'' charge that is at 150 percent of the 
current transmission rate. Increasing the charge to 200 percent brings 
the CRSP MC in line with other Western Federal transmission providers 
in the Balancing Authority (BA).
    5. Update all CRSP rate schedules that use the BA rates to 
reference the appropriate BA rate schedule.
    After reviewing customer comments, Western is not finalizing the 
following proposals in the Rate Order:
    1. Western will not use the proposed composite rate of 29.93 mills/
kWh, but will continue to charge the energy and capacity rates from the 
SLIP-F9 Rate Schedule. Western agrees with the customers' assessment 
that the current rate remains sufficient to recover costs and repayment 
(see item 2. below).
    2. The CRSP MC forecasts 5 years of firming purchased power in the 
PRS using the April, 24-month hydrology study from the Bureau of 
Reclamation. This reflects the firming purchase power requirements 
between projected generation and contract obligations. For the 
remaining out-years, a forecast of $4 million a year is projected to 
cover operational costs for the Energy Management and Marketing Office 
in Montrose, Colorado. Western proposed to add the projected $4 million 
to the first 5 years based on anticipated annual operational needs 
beyond firming purchases. Western will not include the addition of the 
$4 million per year increase at this time. Consistent with the 
procedures at 10 CFR part 903, Western will consider whether to refine 
the purchase power cost estimates.
    By Delegation Order No. 00-037.00A, effective October 25, 2013, the 
Secretary of Energy delegated: (1) The authority to develop power and 
transmission rates to Western's Administrator, (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 part 903) 
were published on September 18, 1985.
    Under Delegation Order Nos. 00-037.00A and 00-001.00F, and in 
compliance with 10 CFR part 903 and 18 CFR part 300, I hereby confirm, 
approve, and place Rate Order No. WAPA-169, the provisional SLCA/IP 
firm power rate, CRSP firm and non-firm transmission rates, and 
ancillary services rates into effect on an interim basis. The new Rate 
Schedules SLIP-F10, SP-PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-RS4, SP-EI4, 
SP-FR4, SP-SSR4, and SP-UU1 will be promptly submitted to FERC for 
confirmation and approval on a final basis.

    Dated: August 28, 2015.
Elizabeth Sherwood-Randall,
Deputy Secretary of Energy.

DEPARTMENT OF ENERGY

DEPUTY SECRETARY

    In the matter of: Western Area Power Administration Rate Adjustment 
for the Salt Lake City Area Integrated Projects and Colorado River 
Storage Project; Rate Order No. WAPA-169

ORDER CONFIRMING, APPROVING, AND PLACING THE SALT LAKE CITY AREA 
INTEGRATED PROJECTS FIRM POWER, COLORADO RIVER STORAGE PROJECT 
TRANSMISSION AND ANCILLARY SERVICES RATES INTO EFFECT ON AN INTERIM 
BASIS

    These rates were established in accordance with 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 Department 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 Project 
Act of 1939 (43 U.S.C. 485h(c)), and other acts that specifically apply 
to the project involved.
    By Delegation Order No. 00-037.00A, effective October 25, 2013, the 
Secretary of Energy delegated: (1) the authority to develop power and 
transmission rates to Western Area Power Administration's (Western) 
Administrator, (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 and Definitions

    As used in this Rate Order, the following acronyms and definitions 
apply:

AHP: Available Hydropower.
ATRR: Annual Transmission Revenue Requirement.
Balancing Authority: The responsible entity that integrates resource 
plans ahead of time, maintains load-interchange-generation balance 
within a designated area, and supports interconnection frequency in 
real-time.
Basin Fund: Upper Colorado River Basin Fund.
BFBB: Basin Fund Beginning Balance as used in the CRC formula.
BFTB: Basin Fund Target Balance as used in the CRC formula.
Capacity: The electric capability of a generator, transformer, 
transmission circuit, or other equipment. It is expressed in kW.
Capacity Rate: The rate which sets forth the charges for capacity. It 
is expressed in $/kWmonth and applied to each kW of the Contract Rate 
of Delivery (CROD).
CDP: Customer Displacement Power.
Composite Rate: The rate for firm power which is the total annual 
revenue requirement for capacity and energy divided by the total annual 
energy sales. It is expressed in mills/kWh and used for comparison 
purposes.
CRC: Cost Recovery Charge. A mechanism to assist in recovery of 
purchased power costs during financial hardship.
CRCE: CRC Energy (GWh) as used in the CRC and PYA formulas.
CRCEP: CRC Energy Percentage of full SHP as used in the CRC and PYA 
formulas.
CROD: Contract Rate of Delivery. The maximum amount of capacity made 
available to a preference customer for a period specified under a 
contract.
CRSP: Colorado River Storage Project.
CRSP Act: An act to authorize the Secretary of the Interior to 
construct, operate, and maintain the Colorado River Storage Project and 
Participating Projects, and for other purposes. (Act of April 11, 1956, 
ch. 203, 70 Stat. 105.)
CRSP MC: The CRSP Management Center of Western Area Power 
Administration.
Customer: An entity with a contract that is receiving firm electric 
service and transmission from Western's CRSP MC.
DOE Order RA 6120.2: A DOE order outlining power marketing 
administration financial reporting and ratemaking procedures.

[[Page 53295]]

DSW: The Desert Southwest Region of Western Area Power Administration.
EA: SHP Energy Allocation (GWh) as used in the CRC formula.
EAC: Sum of customers' energy allocations subject to the PYA formula.
Energy: Power produced or delivered over a period of time. It is 
expressed in kilowatthours.
Energy Rate: The rate which sets forth the charges for energy. It is 
expressed in mills/kWh and applied to each kWh delivered to each 
customer.
FA: Funds Available as used in the CRC formula.
FA1: Basin Fund Balance Factor as used in the CRC formula.
FA2: Revenue Factor as used in the CRC formula.
FARR: Additional revenue to be recovered as used in the CRC formula.
FE: Forecasted purchased energy as used in the CRC formula.
FFC: Forecasted average energy price per MWh as used in the CRC and PYA 
formulas.
Firm: A type of product and/or service always available at the time 
requested by the customer.
FRN: Federal Register notice.
FX: Forecasted energy purchased expense as used in the CRC formula.
FY: Fiscal year is the period from October 1 to September 30.
GWh: Gigawatthour. The electrical unit of energy that equals 1 billion 
watt-hours or 1 million kWh.
HE: Forecasted hydro energy as used in the CRC formula.
Integrated Projects: The resources and revenue requirements of the 
Collbran, Dolores, Rio Grande, and Seedskadee projects blended together 
with the CRSP to create the SLCA/IP resources and rate.
kW: Kilowatt. The electrical unit of capacity that equals 1,000 watts.
kWh: Kilowatthour. The electrical unit of energy that equals 1,000 
watts produced or delivered in 1 hour.
kWmonth: Kilowattmonth. The electrical unit of a monthly amount of 
capacity.
kWyear: Kilowattyear. The electrical unit of a yearly amount of 
capacity.
Load: The amount of electric power or energy delivered or required at 
any specified point(s) on a system.
Load-Ratio Share: Network customer's hourly load (including its 
designated network load not physically interconnected with Western) 
coincident with Western's monthly CRSP transmission system peak.
MAF: Million Acre-Feet. The amount of water required to cover 1 million 
acres, 1 foot in depth.
Mill: A monetary denomination of the United States that equals one-
tenth of a cent or one-thousandth of a dollar.
Mills/kWh: Mills per kilowatthour. A unit of charge for energy.
MW: Megawatt. The electrical unit of capacity that equals 1 million 
watts or 1,000 kilowatts.
MWh: One million watt-hours of electric energy. A unit of electrical 
energy which equals 1 megawatt of power used for 1 hour.
NATRR: Net Annual Transmission Revenue Requirement.
NB: Net Balance as used in the CRC formula.
NEPA: National Environmental Policy Act of 1969 (42 U.S.C. 4321, et 
seq.).
Non-firm: A type of product and/or service not always available for use 
when requested by the customer.
NR: The net revenue remaining after paying all annual expenses as used 
in the CRC formula.
OASIS: Open Access Same-Time Information System.
O&M: Operation and Maintenance.
OM&R: Operation, Maintenance, and Replacements.
PAE: Projected Annual Expenses as used in the CRC formula.
PAR: Projected Annual Revenue without the CRC as used in the CRC 
formula.
Participating Projects: The projects participating with CRSP according 
to the CRSP Act of 1956 (43 U.S.C. 620).
PFE: Prior year actual firming energy as used in the PYA formula.
PFX: Prior year actual firming expenses as used in the PYA formula.
Pinch Point: The nearest future year in the PRS where cumulative 
expenses and required payments equal cumulative revenues.
Power: Capacity and energy.
Preference: The provisions of Reclamation Law which require Western to 
first make Federal power available to certain entities. For example, 
section 9(c) of the Reclamation Project Act of 1939 (43 U.S.C. 485h(c)) 
states that preference in the sale of Federal power shall be given to 
municipalities and other public corporations or agencies and also to 
cooperatives and other nonprofit organizations financed in whole or in 
part by loans made under the Rural Electrification Act of 1936.
Price: Average price per MWh for purchased power as used in the CRC 
formula.
Project Use: Power used to operate the CRSP Participating Projects 
facilities under Reclamation Law.
Proposed Rate: A rate that has been recommended by Western to the 
Deputy Secretary of Energy for approval.
Provisional Rate: A rate which has been confirmed, approved, and placed 
into effect on an interim basis by the Deputy Secretary of Energy.
PRS: Power Repayment Study.
PYA: Prior Year Adjustment as used in the CRC formula.
RA: Revenue Adjustment as used in the PYA formula.
Rate Brochure: A document explaining the rationale and background for 
the rate proposal contained in this Rate Order dated January 2015.
Ratesetting PRS: The PRS used for the rate adjustment proposal.
Reclamation Law: A series of Federal laws, viewed as a whole, that 
create the originating framework under which Western markets power.
Revenue Requirement: The revenue required to recover annual expenses, 
such as O&M, purchased power, transmission service expenses, interest, 
deferred expenses, repayment of Federal investments, and other assigned 
costs.
RMR: Rocky Mountain Region of Western Area Power Administration.
SHP: Sustainable Hydropower as defined in the firm power contracts for 
SLCA/IP.
SLCA/IP: Salt Lake City Area Integrated Projects. The resources and 
revenue requirements of the Collbran, Dolores, Rio Grande, and 
Seedskadee projects blended together with the CRSP to create the SLCA/
IP rate.
Supporting Documentation: A compilation of data and documents that 
support the Rate Brochure and the Proposed Rate.
TRC: Transmission Revenue Credits.
True-up: True-up to actuals. Western will reconcile actual transmission 
costs against projections and adjust the transmission revenue 
requirements in a subsequent fiscal year. This ensures Western will 
recover no more and no less than the actual costs for that year.
TSTL: CRSP Transmission System Total Load.
WACM: Western Area Colorado Missouri.
WL: Waiver Level as used in the CRC formula.
WLP: Waiver Level Percentage of full SHP as used in the CRC formula.
WPR: Work Program Review. The work plan is a draft estimate of costs 
that are expected to be included in the Congressional Budget for 
Western and Reclamation and the basis for budget estimates to be used 
in the PRS.
WRP: Western Replacement Power as defined in the firm electric service 
contracts for SLCA/IP.

[[Page 53296]]

Effective Date

    Rate Schedules SLIP-F10, SP-PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-RS4, 
SP-EI4, SP-FR4, SP-SSR4, and SP-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, 2015, and will be in effect until FERC 
confirms, approves, and places the rate schedules in effect on a final 
basis through September 30, 2020, or until the rate schedules are 
superseded.

Public Notice and Comment

    Western followed the Procedures for Public Participation in Power 
and Transmission Rate Adjustments and Extensions, 10 CFR part 903, in 
developing these rates. The steps Western took to involve interested 
parties in the rate process were:
    1. Western publicly announced the rate action on June 24, 2014, 
during the formal customer meeting, to all SLCA/IP customers and 
interested parties.
    2. Western published an FRN on December 9, 2014 (79 FR 73067), 
announcing the proposed rates for the SLCA/IP firm power and CRSP 
transmission and ancillary services rates, initiating a public 
consultation and comment period and setting forth the dates and 
locations of public information and public comment forums.
    3. On December 12, 2014, Western's CRSP MC mailed an announcement 
of the January 15, 2015, public information forum to all SLCA/IP 
Preference customers, CRSP transmission customers, and interested 
parties, along with the Rate Brochure, which contains a copy of the 
published FRN proposal. This information was also posted to the CRSP MC 
Web page, http://www.wapa.gov/crsp/ratescrsp.
    4. On January 15, 2015, Western held a public information forum in 
Salt Lake City, Utah. Western provided detailed explanations about the 
proposed SLCA/IP firm power rate and the CRSP transmission and 
ancillary services rates. Western provided the Rate Brochure, 
supporting documentation, and informational handouts at this meeting.
    5. On February 5, 2015, Western held a public comment forum in Salt 
Lake City, Utah, to provide the public an opportunity to comment for 
the record. Western reiterated that the comment and consultation period 
ended March 13, 2015.
    6. Western received eight comment letters during the consultation 
and comment period. All comments have been considered in preparing this 
Rate Order.

Comments

    Written comments were received from the following organizations:

Arizona's Generation and Transmission Cooperatives, Arizona
Arizona Tribal Energy Association, Arizona
Colorado River Commission of Nevada, Nevada
Colorado River Energy Distributors Association, Arizona
Deseret Power Electric Cooperative, Utah
Irrigation and Electric Districts of Arizona, Arizona
Tri-State Generation and Transmission Association, Colorado
Utah Associated Municipal Power Systems, Utah

    Representatives of the following organizations made oral comments:

Colorado River Energy Distributors Association, Arizona
Deseret Power Electric Cooperative, Utah

Project Description

    The SLCA/IP consists of the CRSP, Collbran, and Rio Grande 
projects, which were integrated for marketing and ratemaking purposes 
on October 1, 1987, and two participating projects of the CRSP that 
have power facilities, the Dolores and the Seedskadee. The goals of 
integration were to increase marketable resources, simplify contract 
and rate development and project administration by creating one power 
rate and ensure repayment of the projects' costs. The Integrated 
Projects maintain their individual identities for financial accounting 
and repayment purposes, but their revenue requirements are integrated 
into the SLCA/IP PRS for ratemaking. The present CRSP point-to-point, 
network, and non-firm transmission rates, outlined in Rate Schedules 
SP-PTP7, SP-NW3, and SP-NFT6 became effective on October 1, 2008. On 
September 6, 2013, the Deputy Secretary of Energy extended the SLCA/IP 
firm power and CRSP transmission and ancillary services rates through 
September 30, 2015.

Power Repayment Study--Firm Power Rate

    Western prepares a PRS each year to determine if revenues will be 
sufficient to repay, within the required time, all costs assigned to 
the SLCA/IP. Repayment criteria are based on applicable laws and 
policies, including DOE Order RA 6120.2. To meet Cost Recovery Criteria 
outlined in DOE Order RA 6120.2, revised studies and rate adjustments 
have been developed to demonstrate that sufficient revenues will be 
collected under provisional Rates to meet future obligations.
    The current capacity rate and energy rate under Rate Schedule SLIP-
F9 remain sufficient to cover OM&R and required repayment. Western will 
continue to use the existing energy charge of 12.19 mills/kWh and 
capacity charge of $5.18/kWmonth. However, the composite rate, which is 
used for comparison purposes only and is not part of the billing 
component, will decrease from 29.62 to 29.42 mills/kWh. The composite 
rate is calculated by dividing the average revenue requirement for the 
ratesetting period by the average energy sales. The change in the 
composite rate is driven in large part by changes in the average energy 
sales due to changes in Project Use energy requirements.

                               Comparison of Current and Proposed Firm Power Rates
----------------------------------------------------------------------------------------------------------------
                                            Current Rate October 1,    Proposed Rate October 1,    Total Percent
                                          2008- September 30, 2015 *             2015                Increase
----------------------------------------------------------------------------------------------------------------
Rate Schedule...........................  SLIP-F9...................  SLIP-F10..................  ..............
Energy (mills/kWh)......................  12.19.....................  12.19.....................               0
Capacity ($/kWmonth)....................  5.18......................  5.18......................               0
Composite Rate (mills/kWh)..............  29.62.....................  29.42.....................              -1
----------------------------------------------------------------------------------------------------------------
*Approved under Rate Order No. WAPA-137 for a 5-year period beginning October 1, 2008, and ending September 30,
  2013. The Deputy Secretary of Energy approved Rate Order No. WAPA-161 on September 6, 2013, extending the
  rates through September 30, 2015.


[[Page 53297]]

Cost Recovery Charge

    Western will continue the CRC calculation and assessment in the 
provisional rate schedule as it has historically been established and 
will implement an additional triggering mechanism as shown in the below 
table. The CRC will use ``tiers,'' as outlined in the table, to 
quantify the need for a CRC based on the balance of the Basin Fund and 
Western's ability to meet contractual requirements. Western will 
implement the CRC per the criteria in the tiers.

----------------------------------------------------------------------------------------------------------------
                                          CRC Based on the Tiers Below
-----------------------------------------------------------------------------------------------------------------
             Tier                 Criteria, if the BFBB is:                          Review
----------------------------------------------------------------------------------------------------------------
i.............................  Greater than $150 million,     Annually.
                                 with an expected decrease to
                                 below $75 million
ii............................  Less than $150 million but
                                 greater than $120 million,
                                 with an expected 50-percent
                                 decrease in the next FY
iii...........................  Less than $120 million but
                                 greater than $90 million,
                                 with an expected 40-percent
                                 decrease in the next FY
iv............................  Less than $90 million but      Semi-annual (May/November).
                                 greater than $60 million,
                                 with an expected 25-percent
                                 decrease in the next FY
v.............................  Less than $60 million but      Monthly.
                                 greater than $40 million
                                 with an expected decrease to
                                 below $40 million in the
                                 next FY
----------------------------------------------------------------------------------------------------------------

    The CRC is based on a Basin Fund cash analysis only and is 
independent of the PRS calculations. In the event that expenses 
significantly exceed estimates and in order to adequately recover and 
maintain a sufficient balance in the Basin Fund, Western will calculate 
and assess a CRC. The CRC is designed to maintain a Basin Fund Target 
Balance (BFTB) for the following FY. The minimum Basin Fund targeted 
carryover balance is $40 million. The methodology for calculating the 
CRC is addressed in the Schedule of Rates for Firm Power Service, SLIP-
F10. Western will continue to include a mechanism that allows for the 
recalculation of the CRC if annual water releases from Glen Canyon Dam 
fall below 8.23 million acre-feet, regardless of the Basin Fund 
balance.

CRSP Transmission Service Rates

    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 
CRSP Transmission System. The transmission rates include the cost of 
Scheduling, System Control, and Dispatch Service. Western will continue 
to bundle CRSP transmission service in the SLCA/IP Power rate.
    A penalty for unauthorized use of transmission will now be assessed 
under a new rate schedule, SP-UU1. Unreserved Use Penalties will 
include the basic rate for the transmission service used and not 
reserved plus a penalty equal to 200 percent of the basic rate.
    Transmission losses, as posted on the RMR OASIS, are assessed for 
all real-time and prescheduled transactions on transmission facilities 
inside the Western Area Colorado Missouri (WACM) balancing authority.
    According to DOE Order RA 6120.2, Western is required to recover 
revenues for investments in the first year following the FY in which 
the investment goes into commercial service. Adopting the forward-
looking methodology to calculate the Annual Transmission Revenue 
Requirement (ATRR) will allow Western to better recover costs in the FY 
following occurrence. In addition to annual audited financial data, 
Western will use projections from the 10-Year Plan, the Budget Year 
Workplan, and current year-to-date financial data for the annual rate 
calculation. The 10-Year Plan and the Budget Year Workplan used in the 
forward-looking calculations are provided to customers at annual 
customer meetings. This is a change in the manner in which the inputs 
for the rate are developed, rather than a change to the formula rate 
itself.
    Western will use a true-up procedure to ensure that the actual 
transmission costs are recovered for that year. When the annual audited 
financial data is available, Western will calculate the actual ATRR for 
that year. Western will compare the actual ATRR to the projected ATRR 
and apply the difference as an adjustment to the ATRR in a subsequent 
year.

Firm Point-to-Point

    The firm point-to-point transmission rate will be based upon annual 
audited financial data and projections to the end of the current FY, 
using the annual forward-looking methodology described in the preceding 
paragraphs. The ATRR, as also described above, will be offset by 
appropriate revenue credits. The resultant NATRR will be divided by the 
capacity reserved for firm power and transmission commitments, 
including the total network integration loads at system peak, to derive 
a cost/kWyear. Rate Schedules SLIP-F10, SP-PTP8, SP-NW4, SP-NFT7, SP-
SD4, SP-RS4, SP-EI4, SP-FR4, SP-SSR4, and SP-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, 2015, and will be in effect 
until FERC confirms, approves, and places the rate schedules in effect 
on a final basis through September 30, 2020, or until the rate 
schedules are superseded. The cost/kWyear is calculated using the 
following formula:


------------------------------------------------------------------------
 
-------------------------------------------------------------------------
(1) ATRR-TRC=NATRR
(2) NATRR
 ------------
 TSTL
------------------------------------------------------------------------


Where:

ATRR = Annual Transmission Revenue Requirement: The costs associated 
with facilities that support the transfer capability of the CRSP 
transmission system, excluding generation facilities. These costs 
include investment costs, interest expenses, depreciation expense, 
administrative and general expenses, and operation and maintenance 
expense, including transmission purchases. Transmission purchases 
reflect those costs associated with CRSP contractual rights.
TRC = Transmission Revenue Credits: The revenues generated by the 
CRSP transmission system not related to the revenues from the sale 
of long-term firm transmission.
NATRR = Net Annual Transmission Revenue Requirement: The Annual 
Revenue Requirement minus Transmission Revenue Credits.
TSTL = CRSP Transmission System Total Load: The sum of the total 
CRSP transmission capacity under long-term reservation including the 
total network integration loads at system peak.

Non-Firm, Point-to-Point Transmission

    The provisional rate for non-firm, point-to-point, CRSP 
transmission service is a mills/kWh rate, which is

[[Page 53298]]

based upon the firm point-to-point rate and may be discounted. This 
rate will be concurrent with the firm, point-to-point rate and will 
also be reviewed annually. Transmission availability will be posted on 
Western's OASIS.

Network Transmission

    The provisional rate for network transmission service is a formula 
calculation based on the annual transmission revenue requirement. There 
will be no changes from the existing network integration transmission 
service formula under Rate Schedule SP-NW3 to the provisional network 
integration transmission service formula under Rate Schedule SP-NW4.

Ancillary Services Discussion

    Western will offer six ancillary services pursuant to its Tariff: 
(1) Scheduling, system control, and dispatch service; (2) reactive 
supply, and voltage control from generation or other sources service; 
(3) regulation and frequency response service; (4) energy imbalance 
service; (5) spinning reserve service; and (6) supplemental reserve 
service. The ancillary services formula rates are designed to recover 
only the costs associated with providing the service(s). These services 
will be offered either by CRSP or the WACM balancing authority. Sales 
of regulation and frequency response, energy imbalance, spinning 
reserve, and supplemental reserve services from SLCA/IP power resources 
are limited since Western has allocated the SLCA/IP power resources to 
preference entities under long-term commitments. Western will continue 
to use market-based rates to determine its rate for spinning and 
supplemental reserves under the Rate Schedule SSP-SSR4. The 
availability of ancillary service will be determined based on excess 
resources available at the time the services are requested, except for 
scheduling, system control, and dispatch service; and reactive supply, 
and voltage control from generation or other sources, which are 
required to be provided in conjunction with the sale of CRSP 
transmission services.

Certification of Rates

    Western's Administrator certified that the provisional rates for 
SLCA/IP firm power and CRSP transmission and ancillary services under 
Rate Schedules SLIP-F10, SP-PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-RS4, SP-
EI4, SP-FR4, SP-SSR4, and SP-UU1 are the lowest possible rates 
consistent with sound business principles. The provisional rates were 
developed following administrative policies and applicable laws.

SLCA/IP Firm Power Rate Discussion

    Pursuant to Reclamation Law, Western must establish power rates 
sufficient to recover O&M expenses, purchased power expenses, interest 
expenses, and repayment of power investment and irrigation aid.
    The CRSP MC forecasts 5 years of firming purchased power in the PRS 
using the April, 24-month hydrology study from Reclamation. This 5-year 
forecast reflects the firming purchase power requirements between 
projected generation and contract obligations. For the remaining out-
years, a forecast of $4 million a year is projected to cover 
operational costs for the Energy Management and Marketing Office in 
Montrose, Colorado. Western proposed to add the projected $4 million to 
the first 5 years based on anticipated annual operational needs beyond 
firming purchases. Western will not include the addition of the $4 
million per year increase at this time and will, consistent with the 
procedures at 10 CFR part 903, consider whether to refine the purchase 
power cost estimates.
    The current capacity rate and energy rate under Rate Schedule SLIP-
F9 remains sufficient to cover OM&R and required repayment. Western 
will continue to use the existing energy charge of 12.19 mills/kWh and 
capacity charge of $5.18/kWmonth. However, the composite rate, which is 
used for comparison purposes only and is not part of the billing 
component, will decrease from 29.62 to 29.42 mills/kWh. The composite 
rate is calculated by dividing the average revenue requirement for the 
ratesetting period by the average energy sales. The change in the 
composite rate is driven in large part by changes in the average energy 
sales due to changes in Project Use energy requirements.

Statement of Revenue and Related Expenses

        SLCA/IP Firm Power Comparison of 5-Year Rate Period (FY 2016-FY 2020) Total Revenues and Expenses
                                                     [$000]
----------------------------------------------------------------------------------------------------------------
                                                           Existing Rate     Provisional 2017
                          Item                             2010 Workplan         Workplan        Change Amount
----------------------------------------------------------------------------------------------------------------
Ratesetting Period:                                      .................  .................  .................
    Beginning year.....................................               2010               2016  .................
    Pinchpoint year....................................               2025               2025  .................
    Number of ratesetting years........................                 16                 10  .................
Annual Revenue Requirements:                             .................  .................  .................
                        Expenses                         .................  .................  .................
    Operation and Maintenance:.........................  .................  .................  .................
        Western........................................            $40,514            $52,631            $12,117
        Reclamation....................................             30,092             34,535              4,443
                                                        --------------------------------------------------------
            Total O&M..................................             70,606             87,166             16,560
Purchased Power........................................              5,163             10,279              5,116
Transmission...........................................             10,525             10,421              (104)
Integrated Projects requirements.......................              7,286              8,611              1,325
Interest...............................................              3,693              6,177              2,484
Other..................................................              2,984             14,587             11,603
                                                        --------------------------------------------------------
        Total Expenses.................................            100,257            137,240             36,983
                   Principal payments
Deficits...............................................                  0                  0                  0
Replacements...........................................             28,652             32,084              3,432
Original Project and Additions.........................             17,936              2,232           (15,704)
Irrigation.............................................             38,744             12,317           (26,427)
                                                        --------------------------------------------------------

[[Page 53299]]

 
    Total principal payments...........................             85,332             46,633           (38,699)
                                                        --------------------------------------------------------
    Total Annual Revenue Requirements:.................            185,589            183,873            (1,716)
           (Less Offsetting Annual Revenue:)
Transmission (firm and non-firm).......................             18,045             19,640              1,595
Merchant Function......................................              8,309              9,918              1,609
Other..................................................              7,687              5,118            (2,569)
                                                        --------------------------------------------------------
    Total Offsetting Annual Revenue....................             34,041             34,676                635
                                                        --------------------------------------------------------
    Net Annual Revenue Requirements:...................            151,548            149,197            (2,351)
Energy Sales...........................................          5,116,346          5,071,804           (44,542)
Capacity Sales.........................................          1,434,946          1,407,920           (27,026)
Composite Rate (mills/kWh).............................              29.62              29.42               -.20
----------------------------------------------------------------------------------------------------------------

Basis for Rate Development

    The provisional rates will provide sufficient revenue to pay all 
annual costs, including interest expense, and repayment of power 
investment and irrigation aid within the allowable periods. Rate 
Schedules SLIP-F10, SP-PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-RS4, SP-EI4, 
SP-FR4, SP-SSR4, and SP-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, 2015, and will be in effect until FERC confirms, 
approves, and places the rate schedules in effect on a final basis 
through September 30, 2020, or until the rate schedules are superseded. 
Provisions for transformer losses adjustment, power factor adjustment, 
WRP administrative charge, and CDP administrative charge adjustments 
are part of the provisional rates for SLCA/IP firm power. Western will 
not modify the provisions and methodologies for these adjustments, 
which will remain as specified in Rate Schedule SLIP-F10.

CRSP Transmission Service Discussion

    The firm and non-firm transmission formula rates apply to all 
transmission-only sales. The provisional formula rates include 
transmission rates as described in Rate Schedules SP-PTP8, SP-NW4, and 
SP-NFPT-7. The transmission rates include the cost for scheduling, 
system control, and dispatch service. The cost of transmission service 
for Western's SLCA/IP long-term firm electric service will continue to 
be included in the SLCA/IP firm power rate. Transmission services are 
outlined in Western's Tariff.

Change to Forward-Looking Transmission Rates

    Western changed the inputs used 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 current, year-to-
date costs as the basis for projecting the full current year's 
transmission costs for the upcoming year in the annual rate 
calculation, rather than using only historical information.
    When the actual annual audited financial data are 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 that year.

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 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 be assessed due to 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 the CRSP 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 1 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 1 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 will be included as a credit in 
the calculation of the ATRR in a subsequent year.

[[Page 53300]]

Comments

    The comments and responses regarding the firm power, transmission, 
and ancillary services rates, paraphrased for brevity when not 
affecting the meaning of the statement(s), are discussed below. Direct 
quotes from comment letters are used for clarity where necessary. The 
rate process issues discussed are (1) Purchased Power Component, (2) 
Transmission and Ancillary Services, (3) Unreserved Use Charge, (4) 
Firm Electric Service Rate Adjustment, (5) Cost Recovery Charge, and 
(6) Miscellaneous.

1. Purchased Power Component

    Comment: Many customers commented that Western should, in 
consultation with customers, refine the purchased-power, cost-
estimating tools, rather than adopting the proposed methodology.
    Response: Western will not add $4 million to the first 5 years of 
purchased power projections to meet the operational contingencies of 
the Energy Management and Marketing Office in Montrose, Colorado. 
Consistent with the procedures at 10 CFR part 903, Western will 
consider whether to refine the purchase power cost estimation.

2. Transmission and Ancillary Services

    Comment: Several commenters expressed concerns about Western 
changing to a forward-looking transmission rate methodology, stating 
Western has no data to show the historical method of using actual data 
from 2 years prior is insufficient in collecting adequate revenues.
    Response: Western appreciates the customers' concerns. The change 
allows Western to more accurately match cost recovery with cost 
incurrence. Western will use current, year-to-date costs in addition to 
a review of the Construction Work in Progress financial report and the 
10-Year Capital Plan by the CRSP MC as the basis for projecting the 
full, current year's transmission costs for the upcoming year in the 
annual rate calculation, rather than using only 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.
    Comment: A commenter raised concern about how the forecast and 
true-up information would interface and be consistent with the work 
program review and asset management processes.
    Response: The data sources, which will be used for the transmission 
cost projections, are reviewed annually at the 10-Year Capital Plan 
customer meeting prior to the annual rate calculation. In addition to 
these current year financial data, coupled with a mid-year review by 
the CRSP MC of which investments should be completed by the end of the 
current FY, will ensure that the most accurate projections will be used 
in the annual transmission rate recalculation. The true-up process is 
independent of the work program review and asset management process.
    Comment: Some commenters stated that the additional labor for 
Western associated with the forward-looking methodology would also 
likely create additional burden on the customers.
    Response: Western's staff appreciates and understands the 
customers' concern, but does not foresee any burden to the customer in 
this process. Western's staff prepared a parallel transmission rate 
recalculation for the FY 2014 rate using the forward-looking 
methodology, and this required only 8 hours of additional labor to 
process the true-up to actuals from the previous FY projections. 
Western believes the impact on the workload will be negligible.
    Comment: A commenter expressed concern that the forward-looking 
methodology may result in an over-collection of funds from the SLIP 
customers.
    Response: Western will true-up the estimates with actual costs and 
loads at the end of each FY. Revenue collected in excess of Western's 
actual net revenue requirement will be returned through a credit 
adjustment to the ATRR in a subsequent year. Actual revenues that are 
less than the net revenue requirement will be recovered through an 
adjustment to the ATRR in a subsequent year. The true-up procedure will 
ensure that Western will recover no more and no less than the actual 
costs for the year from the SLIP customers.

3. Unreserved Use Charge

    Comment: A commenter stated ``There is insufficient due process 
afforded a customer if Western adopts a change to terms and conditions 
for transmission service in the context of a rate proposal.''
    Response: The public process followed in implementing this new rate 
schedule for an Unreserved Use Charge affords transmission customers 
adequate opportunity to comment on the proposed penalty.

4. Firm Electric Service Rate Adjustment

    Comment: Many comments were received expressing a concern that the 
SLIP-F9 rate is sufficient to pay all required costs and should not be 
adjusted at this time.
    Response: Based on Western's decision to postpone implementation of 
the $4 million operational contingency in the first 5 years for 
purchase power, Western agrees with the customer's assessment that the 
current rate remains sufficient to recover costs and repayment. Both 
the energy rate of 12.19 mills per kilowatthour (mills/kWh), and the 
capacity rate of $5.18 per kWmonth will remain the same. However, the 
composite rate, which is used for comparison purposes only and is not 
part of the billing component, will decrease from 29.62 to 29.42 mills/
kWh. The composite rate is calculated by dividing the average revenue 
requirement for the ratesetting period by the average energy sales. The 
change in the composite rate is driven in large part by changes in the 
average energy sales due to changes in Project Use energy requirements.

5. Cost Recovery Charge (CRC)

    Comment: Customers commented in support of the proposed revision to 
the CRC as outlined in the rate brochure, specifically tables 8-11, and 
believe that the discussions between the Colorado River Energy 
Distributors Association (CREDA) and Western pursuant to the 1992 
Agreement \3\ regarding the Basin Fund, cash management, and returns to 
Treasury are important elements of the CRC consultation and decision-
making process.
---------------------------------------------------------------------------

    \3\ Letter Agreement No. 92-SLC-0208 and Agreement No. 96-SLC-
0315.
---------------------------------------------------------------------------

    Response: Western appreciates the customers' support. Western will 
implement the proposed CRC revision and will continue with the 
customer-consultation process.

6. Miscellaneous

    Comment: Many customers expressed appreciation for the level of 
detail and description contained in the December 2014 Rate Brochure and 
Western's timely written response to questions posed at the Information 
Forum in advance of the Comment Forum.
    Response: Western appreciates the customers' support.

Availability of Information

    Information about this rate adjustment, including PRSs, comments, 
letters, memorandums, and other supporting material made or kept by 
Western and used to develop the provisional rates, is available for 
public review at the Colorado River Storage Project Management Center, 
Western Area Power Administration, 150 East Social Hall Avenue, Suite 
300, Salt Lake City, Utah, or at Western's Web page:

[[Page 53301]]

https://www.wapa.gov/regions/CRSP/rates/Pages/rate-order-169.aspx.

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. A copy of the categorical exclusion determination is 
posted at the CRSP MC Web page, https://www.wapa.gov/regions/CRSP/rates/Pages/rate-order-169.aspx.

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 interim rates herein confirmed, approved, and placed into 
effect, 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 Rate Schedules SLIP-F10, SP-
PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-RS4, SP-EI4, SP-FR4, SP-SSR4, and SP-
UU1 to become effective on the first day of the first full-billing 
period beginning on or after October 1, 2015, and will remain in effect 
until FERC confirms, approves, and places the rate schedules in effect 
on a final basis through September 30, 2020, or until the rate 
schedules are superseded.

Dated: August 28, 2015.

Elizabeth Sherwood-Randall,

Deputy Secretary of Energy.

Rate Schedule SLIP-F10
(Supersedes Schedule SLIP-F9)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

SALT LAKE CITY AREA INTEGRATED PROJECTS

SCHEDULE OF RATES FOR FIRM POWER SERVICE

(Approved Under Rate Order No. WAPA-169)

    Effective:
    Rate Schedule SLIP-F10 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, 2015, and will remain in effect until FERC confirms, 
approves, and places the rate schedules in effect on a final basis 
through September 30, 2020, or until the rate schedules are superseded.
    Available:
    In the area served by the Salt Lake City Area Integrated Projects.
    Applicable:
    To the wholesale power customer for firm power service supplied 
through one meter at one point of delivery or as otherwise established 
by contract.
    Character:
    Alternating current, 60 hertz, three-phase, delivered and metered 
at the voltages and points established by contract.
    Monthly Rate:
    DEMAND CHARGE: $5.18 per kilowatt of billing demand.
    ENERGY CHARGE: 12.19 mills per kilowatthour of use.
    COST RECOVERY CHARGE:
    To adequately recover and maintain a sufficient balance in the 
Basin Fund, Western uses a cost recovery mechanism, called a Cost 
Recovery Charge (CRC). The CRC is a charge on all SHP energy.
    This charge will be recalculated before May 1 of each year, and 
Western will provide notification to the customers. The charge, if 
needed, will be placed into effect on the first day of the first full-
billing period beginning on or after October 1, 2015, through September 
30, 2020. If a Shortage Criteria is necessary, the CRC will be re-
calculated at that time. (See Shortage Criteria Trigger explanation 
below.) The CRC will be calculated as follows:

WESTERN HAS THE DISCRETION TO IMPLEMENT A CRC BASED ON THE TIERS BELOW.

                            Table--CRC Tiers
------------------------------------------------------------------------
                                 Criteria, If the BFBB
             Tier                         is:                Review
------------------------------------------------------------------------
i.............................  Greater than $150
                                 million, with an
                                 expected decrease to
                                 below $75 million.
ii............................  Less than $150 million  Annually.
                                 but greater than $120
                                 million, with an
                                 expected 50-percent
                                 decrease in the next
                                 FY.
iii...........................  Less than $120 million
                                 but greater than $90
                                 million, with an
                                 expected 40-percent
                                 decrease in the next
                                 FY.
iv............................  Less than $90 million   Semi-Annual (May/
                                 but greater than $60    November).
                                 million, with an
                                 expected 25-percent
                                 decrease in the next
                                 FY.
v.............................  Less than $60 million   Monthly.
                                 but greater than $40
                                 million with an
                                 expected decrease to
                                 below $40 million in
                                 the next FY.
------------------------------------------------------------------------


                                          Table--Sample CRC Calculation
----------------------------------------------------------------------------------------------------------------
                                                            Description          Example           Formula
----------------------------------------------------------------------------------------------------------------
STEP ONE                                       Determine the Net Balance available in the Basin Fund.
----------------------------------------------------------------------------------------------------------------
                                   BFBB...............  Basin Fund              $85,860,265  Financial forecast.
                                                         Beginning Balance
                                                         ($).
                                   BFTB...............  Basin Fund Target       $64,395,199  BFBB - (Tier % *
                                                         Balance ($).                         BFBB), or BFTB for
                                                                                              Tier i and Tier v
                                                                                              \1\.
                                   PAR................  Projected Annual       $232,780,000  Financial forecast.
                                                         Revenue ($) w/o
                                                         CRC.
                                   PAE................  Projected Annual       $226,649,066  Financial forecast.
                                                         Expenses ($).

[[Page 53302]]

 
                                   NR.................  Net Revenue ($)....      $6,130,934  PAR - PAE.
                                   NB.................  Net Balance ($)....     $91,991,199  BFBB + NR.
----------------------------------------------------------------------------------------------------------------
STEP TWO                                         Determine the Forecasted Energy Purchase Expenses.
----------------------------------------------------------------------------------------------------------------
                                   EA.................  SHP Energy                    4,952  Customer contracts.
                                                         Allocation (GWh).
                                   HE.................  Forecasted Hydro              4,924  Hydrologic &
                                                         Energy (GWh).                        generation
                                                                                              forecast.
                                   FE.................  Forecasted Energy               504  EA - HE or
                                                         Purchase (GWh).                      anticipated.
                                   FFC................  Forecasted Average           $34.23  From commercially
                                                         Energy Price per                     available price
                                                         MWh ($).                             indices.
                                   FX.................  Forecasted Energy       $17,262,512  FE * FFC *1000.
                                                         Purchase Expense
                                                         ($).
----------------------------------------------------------------------------------------------------------------
STEP THREE                           Determine the amount of Funds Available for firming energy purchases, and
                                        then determine additional revenue to be recovered. The following two
                                     formulas will be used to determine FA; the lesser of the two will be used.
----------------------------------------------------------------------------------------------------------------
                                   FA1................  Basin Fund Balance      $17,262,512  If (NB > BFBB, FX,
                                                         Factor ($).                          FX - (BFTB - NB)).
                                   FA2................  Revenue Factor ($).     $17,262,512  If (NR > - (BFBB -
                                                                                              BFTB), FX, FX + NR
                                                                                              + (BFBB - BFTB)).
                                   FA.................  Funds Available ($)     $17,262,512  Lesser of FA1 or
                                                                                              FA2 (not less than
                                                                                              $0).
                                   FARR...............  Additional Revenue               $0  FX - FA.
                                                         to be Recovered
                                                         ($).
----------------------------------------------------------------------------------------------------------------
STEP FOUR                            Once the FA for purchases have been determined, the CRC can be calculated,
                                                            and the WL can be determined.
----------------------------------------------------------------------------------------------------------------
                                   WL.................  Waiver Level (GWh).            5428  If (EA < HE, EA, HE
                                                                                              + (FE * (FA/FX))),
                                                                                              but not less than
                                                                                              HE.
                                   WLP................  Waiver Level                   110%  WL/EA * 100.
                                                         Percentage of Full
                                                         SHP.
                                   CRCE...............  CRC Energy (GWh)...               0  EA - WL.
                                   CRCEP..............  CRC Energy                       0%  CRCE/EA * 100.
                                                         Percentage of Full
                                                         SHP.
                                   CRC................  Cost Recovery                     0  FARR/(EA * 1,000).
                                                         Charge (mills/kWh).
----------------------------------------------------------------------------------------------------------------
Notes: 1--Use CRC Tiers Table to calculate applicable value.

Narrative CRC Example

    STEP ONE: Determine the net balance available in the Basin Fund.
    BFBB--Western will forecast the Basin Fund Beginning Balance for 
the next FY.

BFBB = $85,860,265

    BFTB--The Basin Fund Target Balance is based on the applicable 
tiered percentage, or minimum value, of the Basin Fund Beginning 
Balance derived from the CRC Tiers table with a minimum BFTB set at $40 
million.

BFTB = BFBB less 25 percent, see Tier iv (BFBB < 90 million, BFBB > 60 
million) = $85,860,265 - $21,464,066 = $64,395,199

    PAR--Projected Annual Revenue is Western's estimate of revenue for 
the next FY.

PAR = $232,780,000

    PAE--Projected Annual Expenses is Western's estimate of expenses 
for the next FY. The PAE includes all expenses plus non-reimbursable 
expenses, which are capped at $27 million per year plus an inflation 
factor. This limitation is for CRC formula calculation purposes only, 
and is not a cap on actual non-reimbursable expenses.

PAE = $226,649,066

    NR--Net Revenue equals revenues minus expenses.

    NR = PAR - PAE = $232,780,000 - $226,649,066 = $6,130,934

    NB--Net Balance is the Basin Fund Beginning Balance plus net 
revenue.

NB = BFBB + NR = $85,860,265 + $6,130,934 = $91,991,199

    STEP TWO: Determine the forecasted energy purchases expenses.
    EA--The Sustainable Hydro Power Energy Allocation (from Customer 
contracts). This does not include Project Use customers.

EA = 4,952 (GWh)

    HE--Western's forecast of Hydro Energy available during the next FY 
developed from Reclamation's April, 24-month study.

HE = 4,924 (GWh)

    FE--Forecasted Energy purchases are the difference between the 
Sustainable Hydro Power allocation and the forecasted hydro energy 
available for the next FY or the anticipated firming purchases for the 
next year.

FE = EA - HE or anticipated purchases = 504.33 (GWh, anticipated)

    FFC--The forecasted energy price for the next FY per MWh.

FFC = $34.23 per MWh


[[Page 53303]]


    FX--Forecasted energy purchase power expenses based on the current 
year's, April, 24-month study, representing an estimate of the total 
costs of firming purchases for the coming FY.

FX = FE * FFC * 1000 = 504.33 * $34.23 * 1000 = $17,263,215.90
    STEP THREE: Determine the amount of Funds Available (FA) to expend 
on firming energy purchases and then determine additional revenue to be 
recovered (FARR). The following two formulas will be used to determine 
FA; the lesser of the two will be used. Funds available shall not be 
less than zero.
A. Basin Fund Balance Factor (FA1)
    If the Net Balance is greater than the Basin Fund Target Balance, 
use the value for forecasted energy purchase power expenses (FX). If 
the net balance is less than the Basin Fund Target Balance, reduce the 
value of the Forecasted Energy Purchase Power Expenses by the 
difference between the Basin Fund Target Balance and the Net Balance.

FA1 = If (NB > BFTB, FX, FX - (BFTB - NB))
= $91,991,199 (NB) is greater than $64,395,199 (BFTB) then:
= $17,263,215.90 (FX)

    If the Net Balance is greater than the Basin Fund Target Balance, 
then FA1 = FX.
    If the Net Balance is less than the Basin Fund Target Balance, then 
FA1 = FX - (BFTB - NB).
B. Basin Fund Revenue Factor (FA2)
    The second factor ensures that Western collects sufficient funds to 
meet the Basin Fund Target Balance so long as the amount needed does 
not exceed the forecasted purchase expense (FX):
    In the situation when there is no projected revenue:

FA2 = If (NR > - (BFBB - BFTB), FX, FX + NR + (BFBB - BFTB))
= $6,130,934(NR) is greater than ($21,464,066) then:
= $17,263,215.90 (FX)

    If the Net Revenue (loss) value does not result in a loss that 
exceeds the allowable decrease value of the Basin Fund Beginning 
Balance ( - (BFBB - BFTB)), then FA2 = FX.
    If the Net Revenue (loss) results in a loss that exceeds the 
allowable decrease value of the Basin Fund Beginning Balance ( - (BFBB 
- BFTB)), then FX + NR + (BFBB - BFTB).
    FA--Determine the funds available for purchasing firming energy by 
using the lesser of FA1 and FA2.
    FA1 and FA2 are equal, so:

FA = $17,263,215.90 (FX)

    FARR--Calculate the additional revenue to be recovered by 
subtracting the Funds Available from the forecasted energy purchase 
power expenses.

FARR = FX - FA = $17,263,215.90 (FX) - $17,263,215.90 (FA) = $ 0.00

    STEP FOUR: Once the funds available for purchases have been 
determined, the CRC can be calculated and the Waiver Level (WL) can be 
determined.
    A. Cost Recovery Charge: The CRC will be a charge to recover the 
additional revenue required as calculated in Step 3. The CRC will apply 
to all customers who choose not to request a waiver of the CRC, as 
discussed below. The CRC equals the additional revenue to be recovered 
divided by the total energy allocation to all customers for the FY.

CRC = FARR/(EA * 1,000) = $0.00 charge

    B. Waiver Level (WL): Western will establish an energy WL that 
provides Western the ability to reduce purchase power expenses by 
scheduling less energy than what is contractually required. Therefore, 
for those customers who voluntarily schedule no more energy than their 
proportionate share of the WL, Western will waive the CRC for that 
year.
    After the Funds Available has been determined, the WL will be set 
at the sum of the energy that can be provided through hydro generation 
and purchased with Funds Available. The WL will not be less than the 
forecasted Hydro Energy.

WL = If (EA < HE, EA, HE + (FE * (FA/FX))
= 4,952 (EA) is not less than 4,924 (HE) then:
= 4,924 (HE) + (504.33 (FE) * ($17,263,215.90 (FA)/$17,263,215.90 (FX)) 
= 5,428 (GWh) is the Waiver Level

    If SHP Energy Allocation is less than forecasted Hydro Energy 
available, then WL = EA
    If SHP Energy Allocation is greater than the forecasted Hydro 
Energy available, then

WL = HE + (FE * (FA/FX))

    PRIOR YEAR ADJUSTMENT:
    The CRC PYA for subsequent years will be determined by comparing 
the prior year's estimated firming-energy cost to the prior year's 
actual firming-energy cost for the energy provided above the WL. The 
PYA will result in an increase or decrease to a customer's firm energy 
costs over the course of the following year. The table below is the 
calculation of a PYA.

                                                 PYA CALCULATION
----------------------------------------------------------------------------------------------------------------
                                                                     Description                  Formula
----------------------------------------------------------------------------------------------------------------
STEP ONE                              Determine actual expenses and purchases for previous year's firming. This
                                        data will be obtained from Western's financial statements at the end of
                                                                        the FY.
----------------------------------------------------------------------------------------------------------------
                                     PFX...................  Prior Year Actual Firming    Financial Statements.
                                                              Expenses ($).
                                     PFE...................  Prior Year Actual Firming    Financial Statements.
                                                              Energy (GWh).
----------------------------------------------------------------------------------------------------------------
STEP TWO                                        Determine the actual firming cost for the CRC portion.
----------------------------------------------------------------------------------------------------------------
                                     EAC...................  Sum of the energy            ......................
                                                              allocations of customers
                                                              subject to the PYA (GWh).
                                     FFC...................  Forecasted Firming Energy    From CRC Calculation.
                                                              Cost--($/MWh).
                                     AFC...................  Actual Firming Energy Cost-- PFX/PFE.
                                                              ($/MWh).
                                     CRCEP.................  CRC Energy Percentage......  From CRC Calculation.
                                     CRCE..................  Purchased Energy for the     EAC * CRCEP.
                                                              CRC (GWh).
----------------------------------------------------------------------------------------------------------------
STEP THREE                                            Determine Revenue Adjustment (RA) and PYA.
----------------------------------------------------------------------------------------------------------------
                                     RA....................  Revenue Adjustment ($).....  (AFC-FFC) * CRCE *
                                                                                           1,000.

[[Page 53304]]

 
                                     PYA...................  Prior Year Adjustment        (RA/EAC)/1,000.
                                                              (mills/kWh).
----------------------------------------------------------------------------------------------------------------

Narrative PYA Calculation

    STEP ONE: Determine actual expenses and purchases for previous 
year's firming. This data will be obtained from Western's financial 
statements at end of FY.

PFX--Prior year actual firming expense
PFE--Prior year actual firming energy

    STEP TWO: Determine the actual firming cost for the CRC portion.

EAC--Sum of the energy allocations of customers subject to the PYA
CRCE--The amount of CRC Energy needed
AFC--The Actual Firming Energy Cost are the PFX divided by the PFE
AFC = (PFX/PFE)/1,000

    STEP THREE: Determine Revenue Adjustment (RA) and Prior Year 
Adjustment (PYA).

RA--The Revenue Adjustment is AFC less FFC times CRCE
RA = (AFC - FFC) * CRCE) * 1,000

    PYA = The PYA is the RA divided by the EAC for the CRC customers 
only.

PYA = (RA/EAC)/1,000

    The customer's PYA will be based on its prior year's energy 
multiplied by the resulting mills/kWh to determine the dollar amount 
that will be assessed. The customers will be charged or credited for 
this dollar amount equally in the remaining months of the next year's 
billing cycle. Western will attempt to complete this calculation by 
December of each year. Therefore, if the PYA is calculated in December, 
the charge/credit will be spread over the remaining 9 months of the FY 
(January through September).
    Shortage Criteria Trigger:
    In the event that Reclamation's 24-month study projects that Glen 
Canyon Dam water releases will drop below 8.23 MAF in a water year 
(October through September), Western will recalculate the CRC to 
include those lower estimates of hydropower generation and the 
estimated costs for the additional purchase power necessary. Western, 
as in the yearly projection for the CRC, will give the customers a 45-
day notice to request a waiver of the CRC, if they do not want to have 
the CRC charge added to their energy bill. This recalculation will 
remain in effect for the remainder of the current FY.
    In the event that hydropower generation returns to an 8.23 MAF or 
higher during the trigger implementation, a new CRC will be calculated 
for the next month, and the customers will be notified.

CRC Schedule for customers

    Consistent with the procedures at 10 CFR 903, Western will provide 
its customers with information concerning the anticipated CRC for the 
upcoming FY in May. The established CRC will be in effect for the 
entire FY. The table below displays the time frame for determining the 
amount of purchases needed, developing customers' load schedules, and 
making purchases.

                                                  CRC Schedule
----------------------------------------------------------------------------------------------------------------
                                                       Respective dates under Table CRC tiers \1\
                 Task                 --------------------------------------------------------------------------
                                            i, ii, and iii               iv \2\                   v \3\
----------------------------------------------------------------------------------------------------------------
24-Month Study (Forecast to Model      April 1................  April 1................  Monthly Study.
 Projections).                                                  October 1..............
CRC Notice to Customers..............  May 1..................  May 1..................  Monthly.
                                                                November 1.............
Waiver Request Submitted by Customers  June 15................  Within 45 days.........  Within 30 days.
CRC Effective........................  October 1..............  August 1...............  Updated Monthly.
                                                                February 1.............
----------------------------------------------------------------------------------------------------------------
Notes:
\1\ This schedule does not apply if the CRC is triggered by the Glen Canyon Dam annual releases dropping below
  8.23 MAF.
\2\ If it is determined during the additional reviews, under tier iv, that a CRC is necessary, customers will be
  notified that a CRC will be implemented in 90 days. Western will provide its customers with information
  concerning the anticipated CRC and give them 45 days to request a waiver or accept the CRC. The established
  CRC will be in effect for 12 months from the date implemented unless superseded by another CRC.
\3\ If it is determined during the additional reviews, under tier v, that a CRC is necessary, customers will be
  notified that a CRC will be implemented in 60 days. Western will provide its customers with information
  concerning the anticipated CRC and give them 30 days to request a waiver or accept the CRC. The established
  CRC will be in effect for 12 months from the date implemented unless superseded by another CRC.

    Billing Demand:
    The billing demand will be the greater of:
    1. The highest 30-minute integrated demand measured during the 
month up to, but not more than, the delivery obligation under the power 
sales contract, or
    2. The Contract Rate of Delivery.
    Billing Energy:
    The billing energy will be the energy measured during the month up 
to, but not more than, the delivery obligation under the power sales 
contract.
    Adjustment for Waiver:
    Customers can choose not to take the full SHP energy supplied as 
determined in the attached formulas for CRC and will be billed the 
Energy and Capacity rates listed above, but not the CRC.
    Adjustment for Transformer Losses:
    If delivery is made at transmission voltage but metered on the low-
voltage side of the substation, the meter readings will be increased to 
compensate for transformer losses as provided in the contract.
    Adjustment for Power Factor:
    The customer will be required to maintain a power factor at all 
points of measurement between 95 percent lagging and 95 percent 
leading.
    Adjustment for Western Replacement Power:
    Pursuant to the contractor's Firm Electric Service Contract, as 
amended,

[[Page 53305]]

Western will bill the contractor for its proportionate share of the 
costs of Western Replacement Power (WRP) within a given time period. 
Western will include in the contractor's monthly power bill the cost of 
the WRP and the incremental administrative costs associated with WRP.
    Adjustment for Customer Displacement Power Administrative Charges:
    Western will include in the contractor's regular monthly power bill 
the incremental administrative costs associated with Customer 
Displacement Power.

Rate Schedule SP-NW4
ATTACHMENT H to Tariff
(Supersedes Schedule SP-NW3)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

NETWORK INTEGRATION TRANSMISSION SERVICE

(Approved Under Rate Order No. WAPA-169)

    Effective:
    Rate Schedule SP-NW4 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, 2015, and will remain in effect until FERC confirms, 
approves, and places the rate schedules in effect on a final basis 
through September 30, 2020, or until the rate schedules are superseded.
    Applicable:
    The transmission customer will compensate the Colorado River 
Storage Project Management Center each month for Network Integration 
Transmission Service under the applicable Network Integration 
Transmission Service Agreement and the formula rate described herein.
[GRAPHIC] [TIFF OMITTED] TN03SE15.000

    A recalculated Annual Transmission Revenue Requirement for Network 
Integration Transmission Service will go into effect every October 1 
based on the above formula and updated financial and operational data. 
Western will notify the transmission customer annually of the 
recalculated annual revenue requirement on or before September 1.
    Billing:
    Billing determinants for the formula rate above will be as 
specified in the service agreement. Billing will occur monthly under 
the formula rate.
    Adjustment for Losses:
    Losses incurred for service under this rate schedule will be 
accounted as agreed to by the parties in accordance with the service 
agreement. If losses are not fully provided by a transmission customer, 
charges for financial compensation may apply.

Rate Schedule SP-SD4
SCHEDULE 1 to Tariff
(Supersedes Schedule SP-SD3)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

SCHEDULING, SYSTEM CONTROL, AND DISPATCH SERVICE

(Approved Under Rate Order No. WAPA-169)

    Effective:
    Rate Schedule SP-SD4 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, 2015, and will remain in effect until FERC confirms, 
approves, and places the rate schedules in effect on a final basis 
through September 30, 2020, or until the rate schedules are superseded.
    Applicable:
    Scheduling, System Control, and Dispatch service is required to 
schedule the movement of power through, out of, within, or into a 
control area. The transmission customer must purchase this service from 
the transmission provider. The charges for this service will be 
included in the CRSP transmission service rates.
    Formula Rate:
    Provided through the Western Area Colorado Missouri (WACM) 
Balancing Authority under Rate Schedule L-AS1, or as superseded.

Rate Schedule SP-RS4
SCHEDULE 2 to Tariff
(Supersedes Schedule SP-RS3)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

REACTIVE SUPPLY AND VOLTAGE CONTROL FROM GENERATION AND OTHER SOURCES 
SERVICE

(Approved Under Rate Order No. WAPA-169)

    Effective:
    Rate Schedule SP-RS4 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, 2015, and will remain in effect until FERC confirms, 
approves, and places the rate schedules in effect on a final basis 
through September 30, 2020, or until the rate schedules are superseded.
    Applicable:
    To all CRSP transmission customers receiving this service.
    Formula Rate:
    Provided through the Western Area Colorado Missouri (WACM) 
Balancing Authority under Rate Schedule L-AS2, or as superseded.

Rate Schedule SP-FR4
SCHEDULE 3 to Tariff
(Supersedes Schedule SP-FR3)

[[Page 53306]]

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

REGULATION AND FREQUENCY RESPONSE SERVICE

(Approved Under Rate Order No. WAPA-169)

    Effective:
    Rate Schedule SP-FR4 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, 2015, and will remain in effect until FERC confirms, 
approves, and places the rate schedules in effect on a final basis 
through September 30, 2020, or until the rate schedules are superseded.
    Applicable:
    To all CRSP customers receiving this service.
    Formula Rate:
    Provided through the Western Area Colorado Missouri (WACM) 
Balancing Authority under Rate Schedule L-AS3 or as superseded. If the 
CRSP MC has regulation available for sale from Salt Lake City Area 
Integrated Projects resources, the rate will be calculated using the 
formula below.
[GRAPHIC] [TIFF OMITTED] TN03SE15.001

Rate Schedule SP-EI4
SCHEDULE 4 to Tariff
(Supersedes Schedule SP-EI3)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

ENERGY IMBALANCE SERVICE

(Approved Under Rate Order No. WAPA-169)

    Effective:
    Rate Schedule SP-EI4 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, 2015, and will remain in effect until FERC confirms, 
approves, and places the rate schedules in effect on a final basis 
through September 30, 2020, or until the rate schedules are superseded.
    Applicable:
    To all CRSP transmission customers receiving this service.
    Formula Rates:
    Provided through the Western Area Colorado Missouri (WACM) 
Balancing Authority under Rate Schedule L-AS4, or as superseded.

Rate Schedule SP-SSR4
SCHEDULES 5 & 6 TO TARIFF
(Supersedes Schedule SP-SSR3)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

OPERATING RESERVES--SPINNING AND SUPPLEMENTAL RESERVE SERVICES

(Approved Under Rate Order No. WAPA-169)

    Effective:
    Rate Schedule SP-SSR4 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, 2015, and will remain in effect until FERC confirms, 
approves, and places the rate schedules in effect on a final basis 
through September 30, 2020, or until the rate schedules are superseded.
    Applicable:
    To all CRSP transmission customers receiving this service.
    Character of Service:
    Spinning Reserve is defined in Schedule 5 of Western Area Power 
Administration's Open Access Transmission Tariff.
    Supplemental Reserve is defined in Schedule 6 of Western Area Power 
Administration's Open Access Transmission Tariff.
    Formula Rate:
    The transmission customer serving loads within the transmission 
provider's balancing authority must acquire Spinning and Supplemental 
Reserve services from CRSP, from a third party, or by self-supply.
Rate Schedule SP-PTP8
SCHEDULE 7 to Tariff
(Supersedes Schedule SP-PTP7)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

FIRM POINT-TO-POINT TRANSMISSION SERVICE

(Approved Under Rate Order No. WAPA-169)

    Effective:
    Rate Schedule SP-PTP8 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, 2015, and will remain in effect until FERC confirms, 
approves, and places the rate schedules in effect on a final basis 
through September 30, 2020, or until the rate schedules are superseded.
    Applicable:
    The transmission customer will compensate the Colorado River 
Storage Project each month for Reserved Capacity under the applicable 
Firm Point-To-Point Transmission Service Agreement and the formula rate 
described herein.

[[Page 53307]]

[GRAPHIC] [TIFF OMITTED] TN03SE15.002

    A recalculated rate will go into effect every October 1 based on 
the above formula and updated financial and operational data. Western 
will notify the transmission customer annually of the recalculated rate 
on or before September 1. Discounts may be offered from time-to-time in 
accordance with Western's Open Access Transmission Tariff.
    Billing:
    The formula rate above applies to the maximum amount of capacity 
reserved for periods ranging from 1 hour to 1 month, payable whether 
used or not. Billing will occur monthly.
    Adjustment for Losses:
    Losses incurred for service under this rate schedule will be 
accounted for as agreed to by the parties in accordance with the 
service agreement. If losses are not fully provided by a transmission 
customer, charges for financial compensation may apply.

Rate Schedule SP-NFT7
SCHEDULE 8 to Tariff
(Supersedes Schedule SP-NFT6)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE

(Approved Under Rate Order No. WAPA-169)

    Effective:
    Rate Schedule SP-NFT7 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, 2015, and will remain in effect until FERC confirms, 
approves, and places the rate schedules in effect on a final basis 
through September 30, 2020, or until the rate schedules are superseded.
    Applicable:
    The transmission customer will compensate the Colorado River 
Storage Project each month for Non-Firm, Point-to-Point Transmission 
Service under the applicable Non-Firm, Point-to-Point Transmission 
Service Agreement and the formula rate described herein.
    Formula Rate:

Maximum Non-Firm Point-To-Point Transmission Rate = Firm Point-To-Point 
Transmission Rate

    A recalculated rate will go into effect every October 1 based on 
the above formula and updated financial and load data. Western will 
notify the transmission customer annually of the recalculated rate on 
or before September 1. Discounts may be offered from time-to-time in 
accordance with Western's Open Access Transmission Tariff.
    Billing:
    The formula rate above applies to the maximum amount of capacity 
reserved for periods ranging from 1 hour to 1 month, payable whether 
used or not. Billing will occur monthly.
    Adjustment for Losses:
    Power and energy losses incurred in connection with the 
transmission and delivery of power and energy under this rate schedule 
shall be supplied by the customer in accordance with the service 
contract. If losses are not fully provided by a transmission customer, 
charges for financial compensation may apply.

Rate Schedule SP-UU1
SCHEDULE 10 to Tariff

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

UNRESERVED USE PENALTIES

(Approved Under Rate Order No. WAPA-169)

    Effective:
    Rate Schedule SP-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, 2015, and will remain in effect until FERC confirms, 
approves, and places the rate schedules in effect on a final basis 
through September 30, 2020, or until the rate schedules are superseded.
    Applicable:
    The transmission customer shall compensate the Colorado River 
Storage Project (CRSP) 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 CRSP's approved transmission service 
rate for point-to-point (PTP) transmission service assessed as follows:
    (i) The Unreserved Use Penalty for a single hour of Unreserved Use 
is based upon the rate for daily firm PTP service.
    (ii) 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).
    (iii) The Unreserved Use Penalty for multiple instances of 
Unreserved Use (e.g., more than 1 hour) within a day is based on the 
rate for daily firm PTP service. The Unreserved Use Penalty charge for 
multiple instances of Unreserved Use isolated to 1 calendar week would 
result in a penalty based on the rate for weekly firm PTP service. The 
Unreserved Use Penalty charge for multiple instances of Unreserved Use 
during more than 1 week in a calendar month will be based on the rate 
for monthly firm PTP 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 
identified in Western's Open Access Transmission Tariff that were 
provided by the CRSP 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.
    Rate:
    The rate for Unreserved Use Penalties is 200 percent of Western'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 and policies

[[Page 53308]]

and made part of the applicable service agreement.

[FR Doc. 2015-21904 Filed 9-2-15; 8:45 am]
 BILLING CODE 6450-01-P