[Federal Register Volume 85, Number 164 (Monday, August 24, 2020)]
[Notices]
[Pages 52115-52130]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-18533]


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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-190

AGENCY: Western Area Power Administration, Energy (DOE).

ACTION: Notice of rate order concerning firm power rate, transmission 
and ancillary services formula rates, and sale of surplus products 
formula rate.

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SUMMARY: The fixed rate for the Salt Lake City Area Integrated Projects 
(SLCA/IP) firm power rate, the formula rates for the Colorado River 
Storage Project (CRSP) transmission and ancillary services, and the new 
formula rate for CRSP sales of surplus products (collectively, 
Provisional Rates) have been confirmed, approved, and placed into 
effect on an interim basis. These Provisional Rates replace the 
existing firm power, transmission, and ancillary services rates under 
Rate Order No. WAPA-169 that expire on September 30, 2020.

DATES: The Provisional Rates under Rate Schedules SLIP-F11, SP-NW5, SP-
PTP9, SP-NFT8, SP-UU2, SP-EI5, SP-SSR5, and SP-SS1 are effective on the 
first day of the first full billing period beginning on or after 
October 1, 2020, and will remain in effect through September 30, 2025, 
pending confirmation and approval by the Federal Energy Regulatory 
Commission (FERC) on a final basis or until superseded.

FOR FURTHER INFORMATION CONTACT: Mr. Tim Vigil, CRSP Manager, Colorado 
River Storage Project Management Center, Western Area Power 
Administration, 299 South Main Street, Suite 200, Salt Lake City, UT 
84111, telephone: (970) 252-3005, or email: [email protected]; or Mr. 
Thomas Hackett, Rates Manager, Colorado River Storage Project 
Management Center, Western Area Power Administration, telephone: (801) 
524-5503, or email: [email protected].

SUPPLEMENTARY INFORMATION: On December 29, 2016, FERC confirmed and 
approved, under Rate Order No. WAPA-169,\1\ on a final basis effective 
through September 30, 2020, the following Rate Schedules: SLIP-F10 for 
SLCA/IP Firm Power, SP-NW4 for Network Integration Transmission 
Service, SP-PTP8 for Firm Point-To-Point Transmission Service, SP-NFT7 
for Non-Firm Point-To-Point Transmission Service, SP-UU1 for Unreserved 
Use Penalties, SP-SD4 for Scheduling, System Control, and Dispatch 
Service, SP-RS4 for Reactive Supply and Voltage Control from Generation 
and Other Sources Service, SP-EI4 for Energy Imbalance Service, SP-FR4 
for Regulation and Frequency Response Service, and SP-SSR4 for 
Operating Reserves--Spinning and Supplemental Reserve Services. On 
March 9, 2017, FERC confirmed and approved, under Rate Order No. WAPA-
174,\2\ on a final basis effective through September 30, 2021, the 
following Rate Schedules: L-AS1 for Scheduling, System Control, and 
Dispatch Service, L-AS2 for Reactive Supply and Voltage Control from 
Generation or Other Sources Service, and L-AS3 for Regulation and 
Frequency Response Service; which superseded Rate Schedules SP-SD4, SP-
RS4, and SP-FR4, respectively.
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    \1\ Order Confirming and Approving Rate Schedules on a Final 
Basis, FERC Docket No. EF15-10-000, 155 FERC ] 61,042 (2016).
    \2\ Order Confirming and Approving Rate Schedules on a Final 
Basis, FERC Docket No. EF16-5-000, 158 FERC ] 62,181 (2017).
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    On January 21, 2020, WAPA published a Federal Register notice 
(Proposal FRN) \3\ proposing new 5-year rates for firm power, 
transmission, and ancillary services, and a new rate for the sale of 
surplus products. The Proposal FRN also initiated a public consultation 
and comment period and set forth the date and location of the public 
information and the public comment forums. The new firm power rate is a 
fixed rate. The transmission and ancillary service rates continue to 
use formula-based rate methodologies that include an annual update to 
the data in the rate formulas. The new sale of surplus products rate is 
also formula-based. The charges under the applicable formula rate 
schedules will be updated annually on the first of October.
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    \3\ 85 FR 3367 (January 21, 2020)
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    On June 26, 2020, WAPA published a Federal Register notice, ``Re-
Opening of Comment Period for Proposed Salt Lake City Area Integrated 
Projects Firm Power Rate and Colorado River Storage Project 
Transmission and Ancillary Services Rates--Rate Order No. WAPA-190'' 
(Re-opening of comment period FRN),\4\ to extend the public comment 
period from June 26, 2020, through July 10, 2020. This extension 
provided interested parties additional time to review and provide 
comments related to information about the rate proposals made available 
by WAPA during and after the original comment period.
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    \4\ 85 FR 38369 (June 26, 2020).
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Legal Authority

    By Delegation Order No. 00-037.00B, effective November 19, 2016, 
the Secretary of Energy delegated: (1) The authority to develop power 
and transmission rates to the Western Area Power Administration's 
(WAPA) 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 on a final basis, 
remand, or disapprove such rates to FERC. By Delegation Order No. 00-
002.00S, effective January 15, 2020, the Secretary of Energy also 
delegated the authority to confirm, approve, and place such rates into 
effect on an interim basis to the Under Secretary of Energy. By 
Redelegation Order No. 00-002.10E, effective February 14, 2020, the 
Under Secretary of Energy further delegated the authority to confirm, 
approve, and place such rates into effect on an interim basis to the 
Assistant Secretary for Electricity. By Redelegation Order No. 00-
002.10-05, effective July 8, 2020, the Assistant Secretary for 
Electricity further delegated the authority to confirm, approve, and 
place such rates into effect on an interim basis to WAPA's 
Administrator. This rate action is issued under the Redelegation Order 
No. 00-002.10-05 and Department of Energy procedures for public 
participation in rate adjustments set forth at 10 CFR part 903.\5\
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    \5\ 50 FR 37835 (September 18, 1985) and 84 FR 5347 (February 
21, 2019).
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    Following DOE's review of WAPA's proposal, I hereby confirm, 
approve, and place Rate Order No. WAPA-190, which provides the rates 
for firm power, transmission, ancillary services, and sale of surplus 
products into effect on an interim basis. WAPA will submit Rate Order 
No. WAPA-190 to FERC for

[[Page 52116]]

confirmation and approval on a final basis.

Signing Authority

    This document of the Department of Energy was signed on August 17, 
2020, by Mark A. Gabriel, Administrator, Western Area Power 
Administration, pursuant to delegated authority from the Secretary of 
Energy. That document, with the original signature and date, is 
maintained by DOE. For administrative purposes only, and in compliance 
with requirements of the Office of the Federal Register, the 
undersigned DOE Federal Register Liaison Officer has been authorized to 
sign and submit the document in electronic format for publication, as 
an official document of the Department of Energy. This administrative 
process in no way alters the legal effect of this document upon 
publication in the Federal Register.

    Signed in Washington, DC, on August 19, 2020.
Treena V. Garrett,
Federal Register Liaison Officer, U.S. Department of Energy.

Department of Energy

Administrator, Western Area Power Administration

    In the matter of:
Western Area Power Administration Rate Adjustment for the Salt Lake 
City Area Integrated Projects Firm Power Rate and the Colorado River 
Storage Project Transmission and Ancillary Services Formula Rates
Rate Order No. WAPA-190
Order Confirming, Approving, and Placing the Fixed Firm Power Rate and 
the Sale of Surplus Products Formula Rate for the Salt Lake City Area 
Integrated Projects and the Transmission and Ancillary Services Formula 
Rates for the Colorado River Storage Project Into Effect on an Interim 
Basis
    The rates in Rate Order No. WAPA-190 are established following 
section 302 of the Department of Energy (DOE) Organization Act (42 
U.S.C. 7152).\6\
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    \6\ 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 projects 
involved.
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    By Delegation Order No. 00-037.00B, effective November 19, 2016, 
the Secretary of Energy delegated: (1) The authority to develop power 
and transmission rates to the Western Area Power Administration's 
(WAPA) Administrator; (2) the authority to confirm, approve, and place 
into effect such rates on an interim basis to the Deputy Secretary of 
Energy; and (3) the authority to confirm, approve on a final basis, 
remand, or disapprove such rates to the Federal Energy Regulatory 
Commission (FERC). By Delegation Order No. 00-002.00S, effective 
January 15, 2020, the Secretary of Energy also delegated the authority 
to confirm, approve, and place such rates into effect on an interim 
basis to the Under Secretary of Energy. By Redelegation Order No. 00-
002.10E, effective February 14, 2020, the Under Secretary of Energy 
further delegated the authority to confirm, approve, and place such 
rates into effect on an interim basis to the Assistant Secretary for 
Electricity. By Redelegation Order No. 00-002.10-05, effective July 8, 
2020, the Assistant Secretary for Electricity further delegated the 
authority to confirm, approve, and place such rates into effect on an 
interim basis to WAPA's Administrator. This rate action is issued under 
Redelegation Order No. 00-002.10-05 and Department of Energy procedures 
for public participation in rate adjustments set forth at 10 CFR part 
903.\7\
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    \7\ 50 FR 37835 (September 18, 1985) and 84 FR 5347 (February 
21, 2019).
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Acronyms, Terms, and Definitions

    As used in this Rate Order, the following acronyms, terms, and 
definitions apply:
    $/MWmonth: Monthly charge for capacity (i.e., $ per megawatt (MW) 
per month).
    '92 Agreement: A 1992 agreement among WAPA, Reclamation, and the 
Colorado River Energy Distributors Association (CREDA) that allows 
CREDA to review Work Plans prior to inclusion in the SLCA/IP rate.
    AFC: Actual Firming Energy Cost.
    ATRR: Annual Transmission Revenue Requirement--the net revenue 
requirement for the Transmission Services calculated in accordance with 
the Formula Rate.
    BA: Balancing Authority--The responsible entity that integrates 
resource plans, maintains load-interchange-generation balance within a 
designated area, and supports interconnection frequency in real-time. 
Formerly known as a Control Area.
    Basin Fund: Upper Colorado River Basin Fund.
    BFBB: Basin Fund Beginning Balance.
    BFTB: Basin Fund Target Balance.
    Capacity: The electric capability of a generator, transformer, 
transmission circuit, or other equipment. It is expressed in kilowatts 
(kW) or megawatts (MW).
    CDP: Customer Displacement Power.
    CRC: Cost Recovery Charge.
    CROD: Contract Rate of Delivery. The maximum amount of capacity 
made available to a preference Customer for a period specified under a 
contract.
    CRCE: CRC Energy in Gigawatthours (GWh).
    CRCEP: CRC Energy Percentage of full Sustainable Hydro Power (SHP).
    CRSP: Colorado River Storage Project.
    CRSP MC: Colorado River Storage Project Management Center.
    Customer: Firm electric service customer(s) contractually receiving 
SLCA/IP power and energy.
    EA: SHP Energy Allocation + Project Use (GWh).
    EMMO: Energy Management and Marketing Office.
    Energy: Power produced or delivered over a period of time. Measured 
in terms of the work capacity over a period of time. Electric energy 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.
    Energy Imbalance Service: A service that provides energy correction 
for any hourly mismatch between energy supply and the demand served.
    FA: Funds Available.
    FA1: Basin Fund Balance Factor.
    FA2: Revenue Factor.
    FARR: Additional Revenue to be recovered.
    FE: Forecasted Purchase Energy.
    FFC: Forecasted Firming Energy Cost.
    Firm: A type of product and/or service available at the time 
requested by the Customer.
    FX: Forecasted Energy Purchase Expense.
    FY: Fiscal Year, October 1 to September 30.
    Generator Imbalance Service: A service that provides energy 
correction for any hourly mismatch between generator output and a 
delivery schedule from that generator to another Balancing Authority 
Area or to a load within the same Balancing Authority Area.
    GWh: Gigawatthour--the electrical unit of energy that equals 1 
billion watthours, 1 million kWh, or 1,000 MWh.
    HE: Forecasted Hydro Energy.
    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.

[[Page 52117]]

    kWh: Kilowatthour--the electrical unit of energy that equals 1,000 
watts in 1 hour.
    kWmonth: Kilowattmonth--the electrical unit of the monthly amount 
of capacity.
    Load: The amount of electric power or energy delivered or required 
at any specified point(s) on a system.
    Load Factor: The actual amount of kWh delivered on a system in a 
designated time period, as opposed to the total possible kWh that could 
be delivered on a system in a designated time period.
    Load-Ratio Share: Network Customer's hourly load (including its 
designated network load not physically interconnected with WAPA) 
coincident with CRSP's monthly transmission system peak.
    MAF: Million Acre-Feet. The number of gallons of water required to 
cover 1 million acres, 1 foot in depth.
    mills/kWh: Mills per kilowatthour--the unit of charge for energy 
(equal to one tenth of a cent or one thousandth of a dollar).
    MW: Megawatt--the electrical unit of capacity that equals 1 million 
watts or 1,000 kilowatts.
    MWh: One million watthours 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. Total of Basin Fund Beginning Balance and Net 
Annual Revenues in the CRC formula.
    NR: Net Revenue. Revenue remaining after paying all annual 
expenses.
    NRate: Net Rate. The difference between the Market rate WAPA 
purchases power at and the Firm Energy rate that WAPA sells power.
    OASIS: Open Access Same-Time Information System--An electronic 
posting system that a service provider maintains for transmission 
access data that allows all customers to view information 
simultaneously.
    O&M: Operation & Maintenance.
    PAR: Projected Annual Revenue ($) without CRC.
    Participating Projects: The Dolores and Seedskadee projects 
participating with CRSP according to the CRSP Act 1956.
    PFE: Prior year actual Firming Energy.
    PFX: Prior year actual Firming expenses.
    Pinch Point Year: The year in the PRS that requires the greatest 
amount of revenue.
    Power: Capacity and energy.
    PRS: Power Repayment Study.
    Price: Average price per MWh for purchased power.
    Project Use: Power used to operate SLCA/IP and CRSP facilities 
under Reclamation Law as well as authorized irrigation projects under 
the CRSP Act.
    Provisional Rate: A rate confirmed, approved, and placed into 
effect on an interim basis by the WAPA Administrator
    PYA: Prior Year Adjustment.
    RA: Revenue Adjustment.
    Rate Brochure: A document prepared for public distribution 
explaining the rationale and background for the information contained 
in this rate order.
    Reclamation Law: A series of Federal laws, viewed as a whole, that 
create the originating framework under which WAPA markets power.
    Regulation and Frequency A service that provides for following the 
moment-
    Response Service: to-moment variations in the demand or supply in a 
Balancing Authority Area and maintaining scheduled interconnection 
frequency.
    Reserve Services: Spinning Reserve Service and Supplemental Reserve 
Service.
    Revenue Requirement: The revenue required to recover annual 
expenses (such as operation and maintenance, purchase power, 
transmission service expenses, interest expense, and deferred expenses) 
and repay Federal investments and other assigned costs.
    RISC: Reduction in SHP Capacity for those customers taking the CRC 
waiver to maintain each Customer's existing monthly Load Factor 
percentage at the same level provided by the full SHP capacity and 
energy allocation.
    Schedule: An agreed-upon transaction size (megawatts) for (a) 
beginning and ending ramp times and rate, and (b) service required for 
delivery and receipt of power between the contracting parties and the 
Balancing Authority(ies) involved in the transaction.
    Scheduling, System Control and Dispatch Service: A service that 
provides for (a) scheduling, (b) confirming and implementing an 
interchange schedule with other balancing authorities, including 
intermediary balancing authorities providing transmission service, and 
(c) ensuring operational security during the interchange transaction.
    SHP: Sustainable Hydro Power (long-term SLCA/IP hydro capacity with 
energy). The minimum quantity of firm energy, expressed in kWh, that 
each Salt Lake City Area Integrated Projects firm electric service 
customer/contractor is entitled to receive each Winter Season and each 
Summer Season as set forth in their respective firm electric service 
contracts.
    SLCA/IP: Salt Lake City Area Integrated Projects.
    SLIP: The CRSP PRS that also includes the Collbran, Dolores, Rio 
Grande, and Seedskadee revenue requirements.
    Spinning Reserve Service: Generation capacity needed to serve load 
immediately in the event of a system contingency. Spinning Reserve 
Service may be provided by generating units that are on-line and loaded 
at less than maximum output.
    Supplemental Reserve Service: Generation capacity needed to serve 
load in the event of a system contingency; however, it is not available 
immediately to serve load but rather within a short period of time. 
Supplemental Reserve Service may be provided by generation units that 
are on-line but unloaded, by quick start generation or by interruptible 
load.
    Transmission Provider: Any utility that owns, operates, or controls 
facilities used to transmit electric energy in interstate commerce.
    Transmission System: The facilities owned, controlled, or operated 
by the transmission owner or Transmission Provider that are used by the 
Transmission Provider to provide transmission service.
    Website: Location online where supporting documents are posted: 
https://www.wapa.gov/regions/CRSP/rates/Pages/rate-order-190.aspx.
    WL: Waiver Level.
    WLP: Waiver Level Percentage of full SHP.
    Work Plan: An estimate of costs expected to become the 
Congressional Budget for WAPA and Reclamation. Also known as a Work 
Program.
    WRP: Western Replacement Power.

Effective Date

    The Provisional Rate Schedules SLIP-F11, SP-NW5, SP-PTP9, SP-NFT8, 
SP-UU2, SP-EI5, SP-SSR5, and SP-SS1 will take effect on the first day 
of the first full billing period beginning on or after October 1, 2020, 
and will remain in effect through September 30, 2025, pending approval 
by FERC on a final basis or until superseded.

Public Notice and Comment

    WAPA followed the Procedures for Public Participation in Power and 
Transmission Rate Adjustments and Extensions, 10 CFR part 903, in 
developing these rates. Following are the steps WAPA took to involve 
interested parties in the rate process:
    1. On January 21, 2020, a Federal Register notice (85 FR 3367) 
(Proposal FRN) announced the proposed rates and launched the 90-day 
public consultation and comment period.

[[Page 52118]]

    2. On January 21, 2020, WAPA notified all CRSP MC Customers and 
interested parties of the proposed rates and provided a copy of the 
Proposal FRN.
    3. On March 12, 2020, WAPA held a Public Information Forum (PIF) in 
Salt Lake City, Utah. WAPA's representatives explained the proposed 
rates, answered questions, and gave notice that more information was 
available in the customer Rate Brochure.
    4. On March 12, 2020, WAPA held a public comment forum in Salt Lake 
City, Utah. This provided customers and other interested parties an 
opportunity to provide official comments for the record.
    5. WAPA provided a website containing all dates, customer letters, 
presentations, FRNs, customer Rate Brochure, and other information 
about this rate process.
    6. During the 90-day consultation and comment period, which ended 
on April 20, 2020, WAPA received one oral comment (at the March 12, 
2020, public comment forum) and eight written sets of comments. WAPA 
also received a redlined version of the March 2020 Rate Brochure with 
questions and comments. WAPA posted the brochure comments and responses 
to the website on April 16, 2020. The other comments and WAPA's 
responses are addressed below.
    7. On June 3, 2020, WAPA held a webinar on purchased power data 
sources and calculations.
    8. On June 4, 2020, WAPA held a webinar on calculating the CRC and 
treatment of prior year adjustment.
    9. On June 26, 2020, WAPA published Federal Register notice (Re-
opening of Comment Period) \8\ that launched an additional 14-day 
public consultation and comment period. The additional comments 
received during the extended comment period and WAPA's responses are 
addressed below. WAPA posted the comments and an updated brochure to 
the website on August 12, 2020. All comments have been considered in 
the preparation of this Rate Order.
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    \8\ 85 FR 38369 (June 26, 2020).
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    Oral comments were received from the following organization:

    Colorado River Energy Distributors Association (CREDA)

    Written comments were received from the following organizations 
during the original comment period:

Arizona Tribal Energy Association (ATEA)
City of St. George Energy Services Department (SGESD)
Colorado River Commission of Nevada (Commission)
Colorado River Energy Distributors Association (CREDA)
Irrigation and Electrical Districts' Association of Arizona (IEDA)
Municipal Energy Agency of Nebraska (MEAN)
Tri-State Generation and Transmission Association, Inc. (Tri-State)
Utah Associated Municipal Power Systems (UAMPS)

    Written comments were received from the following organizations 
during the extended comment period:

Arizona Tribal Energy Association (ATEA)
Colorado River Energy Distributors Association (CREDA)

Power Repayment Study--Firm Power Service Rate Discussion

    WAPA prepares PRSs each fiscal 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 WAPA's applicable laws and 
legislation as well as policies including DOE Order RA 6120.2. To meet 
the Cost Recovery Criteria outlined in DOE Order RA 6120.2, a revised 
PRS and a rate adjustment have been developed to demonstrate sufficient 
revenues will be collected under the Provisional Rate to meet future 
obligations. The Revenue Requirement and composite rate for SLCA/IP 
firm power service are being reduced as indicated in Table 1:

                         Table 1--Comparison of Revenue Requirements and Composite Rates
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                                                                     Existing       Provisional
                                                                   requirements    requirements
                       Firm power service                           (October 1,     (October 1,   Percent change
                                                                       2015)           2020)
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Revenue Requirement (million $).................................        $183.873        $173.511            -5.6
Composite Rate (mills/kWh)......................................           29.42           27.45            -6.7
----------------------------------------------------------------------------------------------------------------

    Under the existing rate methodology, rates for firm power service 
are designed to recover an annual Revenue Requirement that includes 
power investment repayment, aid to irrigation repayment, interest, 
purchase power, O&M, and other expenses within the allowable period.

Firm Power Service--Existing and Provisional Rates

    WAPA is lowering the overall charges due to Participating Projects 
being repaid through FY 2025, which moved the Pinch Point Year out to 
FY 2038. Additionally, the downward rate pressure associated with 
reductions in future costs for Participating Projects and most expense 
categories outweighed the upward pressure created by an increase in O&M 
and loss of offsetting revenues.
    A comparison of the existing and Provisional Rates for firm 
electric service is listed in Table 2:

                              Table 2--Comparison of Existing and Provisional Rates
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                                                                  Existing rates    Provisional
                                                                    under rate      rates under
                                                                  schedule SLIP-   rate schedule
                       Firm power service                            F10 as of    SLIP-F11 as of  Percent change
                                                                    October 1,      October 1,
                                                                       2015            2020
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Firm Energy Rate (mills/kWh)....................................           12.19           11.43            -5.5
Firm Capacity Rate ($/kWmonth)..................................            5.18            4.85            -6.4
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[[Page 52119]]

Statement of Revenue and Related Expenses

    Table 3 provides a summary of projected revenue and expense data 
for the firm electric service Revenue Requirement through the 5-year 
provisional rate approval period:

         Table 3--Comparison of 5-Year Rate Period (FY 2016-2021) Total Revenues and Expenses Unit 1,000
----------------------------------------------------------------------------------------------------------------
                                                                                    Provisional
                                                                   Existing rate  rate 2021 work   Change amount
                                                                  2017 work plan       plan
----------------------------------------------------------------------------------------------------------------
Ratesetting Period:
    Beginning Year..............................................            2016            2021
    Pinch Point Year............................................            2025            2038
    Number of Ratesetting Years.................................              10              18
Annual Revenue Requirement:
Expenses:
    Operations & Maintenance WAPA...............................         $52,630         $61,509          $8,878
    Reclamation.................................................          34,535          35,843           1,308
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        Total O&M...............................................          87,165          97,352          10,187
    Purchase Power..............................................          10,280           1,119         (9,161)
    Transmission................................................          10,421           8,998         (1,423)
    Integrated Projects.........................................           8,610           6,485         (2,125)
    Interest....................................................           4,706           6,066           1,360
    Other Expenses..............................................          14,587          17,909           3,322
----------------------------------------------------------------------------------------------------------------
        Total Expenses..........................................         135,769         137,928           2,159
Principal Payments:
    Deficits....................................................               0               0               0
    Replacements................................................          30,037          26,918         (3,119)
    Original Project and Additions..............................           3,937           2,484         (1,453)
    Irrigation..................................................          14,130           6,181         (7,949)
----------------------------------------------------------------------------------------------------------------
        Total Principal Payments................................          48,104          35,583        (12,521)
Total Annual Revenue Requirement................................         183,873         173,511        (10,362)
(Less Offsetting Annual Revenue)
    Transmission................................................          19,640          15,257         (4,383)
    Merchant Function...........................................           9,918           9,375           (543)
    Other Revenues..............................................           5,118           4,855           (263)
----------------------------------------------------------------------------------------------------------------
        Total Offsetting Annual Revenue.........................          34,676          29,487         (5,189)
Net Annual Revenue Requirements.................................         149,197         144,024         (5,173)
Energy Sales (MWH)..............................................       5,071,804       5,245,909         174,105
Capacity Sales (kW).............................................       1,407,920       1,428,306          20,386
Composite Rate (mills/kWh)......................................           29.42           27.45          (1.97)
----------------------------------------------------------------------------------------------------------------

    Provisions for transformer losses, power factor, WRP administrative 
charge, and CDP administrative charge adjustments are part of the 
Provisional Rates for SLCA/IP firm power. WAPA did not modify the 
provisions and methodologies for these adjustments. These remain as 
they were specified in Rate Schedule SLIP-F10.

Purchased Power Discussion

    WAPA currently forecasts 5 years of firming purchased power 
requirements in the PRS using average water releases reported in 
Reclamation's April 24-month Study in combination with Reclamation's 
August Colorado River Simulation System (CRSS) model traces. Although 
WAPA will continue to use the April 24-month Study and the CRSS model 
traces, it will begin forecasting firming purchased power differently. 
Going forward, WAPA will use the most-probable water releases reported 
in the April 24-month Study to determine the first year of firming-
energy-purchase projections. For subsequent years, WAPA will continue 
to use the August CRSS model traces to estimate energy purchase 
projections while using a rolling average value to minimize 
fluctuations. Additionally, WAPA will extend the number of years for 
projecting the required firming-energy purchases to a period that 
overlaps the years in which a subsequent rate would become effective in 
order to avoid gaps in the forecasts. Finally, WAPA will remove the $4 
million per year it previously included to account for the required 
purchase power within the current rate schedule. This value was 
previously used to estimate operational energy purchases for the EMMO 
in Montrose, Colorado. Fortunately, this is no longer needed because 
improved modeling tools incorporating outages and scheduled maintenance 
can produce more accurate estimates of purchase power expenses.

Cost Recovery Charge

    The methodology for calculating the CRC continues to be addressed 
in the Schedule of Rates for Firm Power Service and has been modified 
as described here. The CRC is based on a Basin Fund cash analysis only 
and is independent of the PRS calculations. In the event expenses 
significantly exceed revenues and in order to adequately recover and 
maintain a sufficient balance in the Basin Fund,\9\ WAPA will calculate 
and assess a CRC. The CRC is implemented at WAPA's discretion based on 
the balance of the Basin Fund and WAPA's ability to meet contractual

[[Page 52120]]

requirements.\10\ The minimum Basin Fund targeted carryover balance is 
$40 million. WAPA collects the CRC as an additional surcharge on all 
SHP energy deliveries. WAPA may implement the CRC for reasons 
including: (1) Low cash balance in the Basin Fund due to low hydropower 
generation; (2) high prices for firming power; and/or (3) funding for 
capitalized investments. The volatility of hydropower generation and 
power prices continues to be a concern for cost-recovery issues for the 
SLCA/IP. WAPA will base the CRC on a calendar year (CY) timeline, will 
use Reclamation's August 24-month Study to calculate projected purchase 
power expenses, and will change the annual CRC notification date from 
May 1 to October 1. Using Reclamation's August 24-month Study aligns 
the purchase power projections for the CRC with water year releases.
---------------------------------------------------------------------------

    \9\ The Basin Fund was established through the CRSP Act of 1956 
to receive revenues collected in connection with the projects to be 
made available for defraying the project's costs of operation, 
maintenance, and emergency expenditures.
    \10\ See Table 4.
---------------------------------------------------------------------------

    WAPA will provide information to its customers concerning the 
anticipated CRC by October 1 and will allow customers 45 days to 
request a waiver or accept the CRC. The established CRC would be in 
effect for 12 months from the date implemented. If circumstances should 
dictate the need to reassess an enacted CRC, the updated CRC would 
supersede the previous CRC and remain in effect for 12 months.

                                        Table 4--CRC Implementation Tiers
----------------------------------------------------------------------------------------------------------------
                                         Criteria, if the Basin Fund beginning balance
                 Tier                                         is:                                 Review
----------------------------------------------------------------------------------------------------------------
i....................................  Greater than $150 million with an expected        Annually.
                                        decrease to below $75 million.
ii...................................  Less than $150 million but greater than $120      Annually.
                                        million with an expected 50 percent decrease in
                                        the next CY.
iii..................................  Less than $120 million but greater than $90       Annually.
                                        million with an expected 40 percent decrease in
                                        the next CY.
iv...................................  Less than $90 million but greater than $60        Semi-Annual (February/
                                        million with an expected 25 percent decrease in   August).
                                        the next CY.
v....................................  Less than $60 million but greater than $40        Monthly.
                                        million with an expected decrease to below $40
                                        million in the next CY.
----------------------------------------------------------------------------------------------------------------

    WAPA will continue to include a mechanism that allows 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. WAPA will establish an energy Waiver Level (WL) that provides 
WAPA the ability to reduce purchase power expenses by scheduling less 
energy than what is contractually required. Customers can accept either 
the CRC or WL, not a combination of the two. For those customers who 
agree to schedule no more energy than their proportionate share of the 
WL, WAPA will waive the CRC for that year. WAPA modified the 
calculations in SLIP-F11 to account for lost projected revenue 
associated with the decreased energy deliveries that occur when a 
customer requests the WL. WAPA will also decrease a customer's monthly 
SHP capacity allocation proportionally under the WL to match the 
monthly energy reduction.

CRSP Transmission Service

    In accordance with WAPA's Open Access Transmission Tariff (Tariff), 
CRSP offers Network Integration Transmission Service and Firm and Non-
Firm Point-to-Point Transmission Services. These services include the 
transmission of energy to points of delivery on the CRSP interconnected 
high-voltage system, which is comprised of transmission lines, 
substations, and related facilities. The transmission rates include the 
cost for Scheduling, System Control, and Dispatch Service. The 
Provisional Rates are as described in Rate Schedules SP-NW5, SP-PTP9, 
and SP-NFPT-8 and apply to transmission-only sales. The cost of 
transmission service for WAPA's SLCA/IP long-term, firm electric 
service will continue to be included in the SLCA/IP firm power rate.

Change to Forward-Looking Transmission Rates

    WAPA changed the formula rate inputs used to calculate the ATRR to 
recover transmission expenses and investments on a current basis rather 
than on a historical basis as described in Rate Order WAPA-169.\11\ The 
change allows WAPA to more accurately match cost recovery with cost 
incurrence. WAPA will use the same methodology going forward for 
expenses. WAPA 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 annual audited financial data is available, WAPA 
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 
WAPA recovers no more and no less than the actual transmission costs 
for that year.
---------------------------------------------------------------------------

    \11\ Order Confirming and Approving Rate Schedules on a Final 
Basis, FERC Docket No. EF15-10-000, 155 FERC ] 61,042 (2016).
---------------------------------------------------------------------------

CRSP Ancillary Services

    In accordance with WAPA's Tariff, ancillary services are needed 
with transmission service to maintain reliability inside and among the 
Control Areas affected by the transmission service. CRSP continues to 
offer seven ancillary services pursuant to WAPA's 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; (6) Supplemental Reserve 
Service; and (7) Generator Imbalance Service. The ancillary services 
formula rates are designed to recover the costs associated with 
providing the services. These services will continue to be offered by 
CRSP or the Western Area Colorado Missouri (WACM) BA.
    CRSP's rate schedules for energy and generator imbalance services 
and reserve services are included in this Rate Order. The rate 
schedules applicable to CRSP scheduling, voltage support, and 
regulation services are implemented by WAPA's Rocky Mountain Region 
(RMR) under separate rate orders. Information pertaining to those rate 
schedules can be found at https://www.wapa.gov/regions/RM/

[[Page 52121]]

rates/Pages/rates.aspx. FERC approved and confirmed, under Rate Order 
No. WAPA-174,\12\ on a final basis through September 30, 2021, Rate 
Schedules L-AS1 for Scheduling, System Control, and Dispatch Service, 
L-AS2 for Reactive Supply and Voltage Control from Generation or Other 
Sources Service, and L-AS3 for Regulation and Frequency Response 
Service, which superseded Rate Schedules SP-SD4, SP-RS4, and SP-FR4 in 
Rate Order No. WAPA-169, respectively.
---------------------------------------------------------------------------

    \12\ Order Confirming and Approving Rate Schedules on a Final 
Basis, FERC Docket No. EF16-5-000, 158 FERC ] 62,181 (2017).
---------------------------------------------------------------------------

Generator Imbalance Services

    WAPA added Generator Imbalance Service, Schedule 9 to WAPA's 
Tariff. CRSP's Energy Imbalance Service Rate Schedule, Rate Schedule 
SP-EI5, indicates both Energy and Generator Imbalance Services are 
provided to CRSP, as a Transmission Service Provider, by the WACM BA 
under Rate Schedules L-AS4 and L-AS9, respectively.

Sale of Surplus Products

    WAPA is implementing a new rate schedule, SP-SS1, applicable to the 
sale of the following CRSP surplus energy and capacity products: 
Energy, frequency response, regulation, and reserves. If CRSP surplus 
products are available, the charge will be determined based on market 
rates plus administrative costs. The customer will be responsible for 
acquiring transmission service necessary to deliver the product(s). 
This rate schedule is not applicable to transmission service and, 
therefore, is not provided through WAPA's Tariff.

Comments

    WAPA received oral comments from one commenter and eight comment 
letters during the initial public consultation and comment period. Two 
comment letters were received during the extended comment period. The 
comments expressed have been paraphrased, where appropriate, without 
compromising the meaning of the comments. The comments have been 
grouped as follows: (1) Purchased Power Component, (2) Transmission and 
Ancillary Services, (3) Supporting Data, (4) Firm Power Service Rate 
Adjustment, (5) Cost Recovery Charge, (6) Miscellaneous, and (7) 
Extended Comment Period.

1. Purchased Power Component

    Comment: Commenter expressed support for WAPA's methodology and 
revisions regarding purchase power, as described in the March 11, 2020, 
Rate Brochure. They believe the updated forecasting and modeling and 
adjustment to the $4 million in out years are appropriate.
    Response: WAPA acknowledges the Commenter's feedback.
    Comment: Commenter requests that in the future WAPA provide 
additional detail regarding the assumptions used to calculate purchased 
power.
    Response: WAPA held a webinar on purchased power data sources and 
calculations on June 3, 2020, to address this and other purchased power 
concerns listed below. The presentation was posted to the website.
    Comment: Commenter questioned why WAPA is changing to average 
rather than median hydrology when forecasting firming purchased power.
    Response: As a statistical method, the median is chosen when 
outliers may create a disproportionate effect and skew the 
distribution. Fortunately, current water management tools reduce the 
likelihood of outliers having such an effect and, therefore, WAPA finds 
the use of average hydrology more accurate.
    Comment: Commenter questions why WAPA is extending the number of 
years for purchased power calculations.
    Response: WAPA purchases power annually. Extending the window for 
purchased power projections ensures forecasts are in place through the 
lifecycle of the rate action.
    Comment: Commenter requests supporting documentation showing the 
details of which hydrologic traces were used in Reclamation's CRSS 
model.
    Response: WAPA posted the list of the 112 traces provided by 
Reclamation to the website on April 16, 2020.
    Comment: Commenter asked about the nature of the product(s) priced 
by Argus.
    Response: Argus provides WAPA with forecasted average monthly peak 
and off-peak energy prices. WAPA used forecasted prices at the Palo 
Verde hub in this rate action.
    Comment: When will Reclamation issue the April 24-month Study and 
will WAPA update and make available the updated rate brochure values 
prior to the April 20, 2020, comment deadline?
    Response: Reclamation issued its April 24-month Study on April 15, 
2020. Using this study, WAPA provided the updated purchased power 
calculation, which showed an increase from $10,510,987 to $12,332,900 
for FY 2020, to customers and interested parties via email on April 16, 
2020. WAPA updated the purchased power values in the Rate Brochure.

2. Transmission and Ancillary Services

    Comment: Commenter is concerned the forward-looking methodology 
will result in additional labor expenses and questions whether it 
matches up with asset management and/or Work Plan review data. 
Commenter approves of the use of a forward-looking methodology for O&M, 
as long as the data has been screened and reviewed in accordance with 
the '92 Agreement process.
    Response: WAPA does not anticipate additional labor expenses tied 
to changing methodologies. The data used for the forward-looking 
methodology is based on a combination of prior year Work Plans that 
have been reviewed pursuant to the '92 Agreement process and current-
year actual data extrapolated through the end of the fiscal year.
    Comment: Commenters noted WAPA plans to eliminate $5 million from 
the PRS due to a 250-MW bidirectional contract, which utilizes a 
portion of the CRSP transmission system, terminating in February 2021. 
The projected impact of removing the capacity load and offsetting 
transmission revenues results in a $0.10/kW-month increase to the CRSP 
transmission rate. Commenters believe this capacity will be sold to a 
new customer and that WAPA should, therefore, not remove it from the 
transmission rate.
    Response: WAPA posted the availability of the transmission capacity 
in OASIS on January 25, 2018. WAPA did not include the capacity in the 
FY 2021 transmission rate design because the transmission capacity was 
not contracted before this rate package was finalized and submitted to 
the Administrator. WAPA reviews capacity-under-contract to be included 
in the rate design on an annual basis.
    Comment: Commenter wants to confirm Southwest Power Pool Western 
Energy Imbalance Service (WEIS) market replaces Rate Schedule SP-E15 as 
of the start date of the WEIS market.
    Response: Potential changes related to CRSP's participation in the 
WEIS EIS Market are not within the scope of this rate action. That 
said, Rate Schedule SP-EI5 is not expected to change as a result of the 
potential start of the WEIS Market.

3. Supporting Data

    Comment: Commenters understand that approximately $3 million 
(representing revenue from a Reclamation water supply contract) was 
removed from the PRS with the closure of the Navajo Generating Station. 
Commenters believe it would be incorrect to assume this water would

[[Page 52122]]

not be sold in the future and that WAPA should not remove the revenue 
associated with this water contract until Reclamation determines that 
this water will not be remarketed.
    Response: WAPA removed the associated revenue from the PRS because 
additional water contract commitments were not identified before this 
rate package was finalized and submitted to the Administrator. Revenue 
will continue to be added/removed in subsequent annual PRS updates as 
changes to water contract commitments are identified.
    Comment: Commenter suggests delaying this rate action due to 
potential cost savings on Participating Projects in the summer of 2020.
    Response: WAPA's current rate expires September 30, 2020. Delaying 
the rate action would prevent having an effective rate in place by 
October 1, 2020. WAPA included cost savings on Participating Projects 
in the final PRS and posted the information to the website on June 30, 
2020.
    Comment: Commenters expressed concerns about the use of the FY 2022 
Work Plans and whether timely review of the FY 2022 Work Plans can be 
accomplished in accordance with the '92 Agreement.
    Response: Because the FY 2022 Work Plan review was not completed 
before this rate package was finalized and submitted to the 
Administrator, WAPA is using the FY 2021 Work Plans for this 
ratesetting action. WAPA notified customers of this decision via email 
and posted notice to the website on June 19, 2020.
    Comment: Commenter understood that security guard service was going 
to be discontinued at the Flaming Gorge Dam; however, this service was 
still in Reclamation's FY 2022 Work Plan.
    Response: WAPA did not use the FY 2022 Work Plan.
    Comment: Commenter asked if project-use power is usually used for 
fish and wildlife mitigation as noted in the footnote for the Provo 
River Delta Restoration Project (Provo Project). The Commenter further 
suggests not including such an increase in project use power until the 
project is complete.
    Response: The Provo River Restoration Project is an authorized 
project in the Central Utah Project Completion Act of 1992 (CUPCA). 
Because electric power needs for CUPCA are categorized as project-use 
power, WAPA will include the projected project-use increase in the PRS. 
Notably, including project-use energy allocations in the PRS leads to 
downward pressure on the rate when the Revenue Requirements are divided 
by energy sales.
    Comment: Commenter questioned why there were increases to project-
use power in FY 2024 and FY 2028.
    Response: FY 2024 is the current official date for operational 
buildout of the Navajo Gallup Water Supply Project. FY 2028 is the 
anticipated beginning of CUPCA mandated water recycling. Both will 
require project-use power in those respective years.

4. Firm Power Service Rate

    Comment: Commenter supported the rate in the Proposal FRN published 
January 21, 2020. The Commenter does not, however, support the higher 
rate WAPA proposed at the March 12, 2020, PIF. The Commenter requests 
WAPA republish a new Proposal FRN with the rates presented at the PIF 
and provide at least 2 months of additional review.
    Response: In the Proposal FRN, WAPA alerted customers and 
interested parties of a possible change to the proposal by stating, 
``The Revenue Requirement for the proposed rate is based upon the most 
current data available, but WAPA plans to use the FY 2019 historical 
financial data and FY 2022 Work Plans, if available, in the final rate 
setting [PRS] and rate order submission'' (85 FR 3368). WAPA's rate 
presented at the PIF was based on the FY 2019 historical data and the 
FY 2022 Work Plans. Commenters had over 30 days to submit comments 
after the PIF was held. Additionally, WAPA provided a 14-day extended 
comment period from June 26, 2020, through July 10, 2020. Due to the 
'92 Agreement review of the FY 2022 Work Plan not being completed, WAPA 
will use the FY 2021 Work Plans, which was what was proposed in the 
Proposal FRN.
    Comment: Commenter expressed significant concern with the fact that 
WAPA can make adjustments to rates after the close of the comment 
period and final rates may therefore not be available until after the 
comment period ends.
    Response: WAPA's commitment to certifying that rates are the lowest 
possible consistent with sound business principles necessitates 
additional tasks beyond the closeout of the comment period, including: 
Reviewing customer comments, allotting time to ensure compliance with 
the '92 Agreement, gathering forward-looking data for the transmission 
rate, and tracking whether water contracts and transmission contracts 
will be acquired by new customers. Customers were aware from the 
Proposal FRN, as noted in response to a previous comment, that the 
rates could be updated from the proposed rates based on additional 
data.
    Comment: Commenter is concerned that there was no opportunity to 
weigh in on the changing rate between April and June and questions how 
and when WAPA will finalize a proposed rate. Similarly, another 
commenter requested more detail regarding why the rate changed from the 
Proposal FRN to the presentation at the PIF.
    Response: WAPA understands the concerns with the rate changes. WAPA 
continued to post updates to the website as data became available. 
Although the initial comment period ended on April 20, 2020, WAPA 
continued to post answers to questions on the website so that all 
interested parties were aware of any ongoing communications before the 
final rule, in accordance with DOE's ex parte communication rules 
(available at https://www.energy.gov/gc/downloads/guidance-ex-parte-communications). WAPA also re-opened the customer comment period from 
June 26, 2020, through July 10, 2020, and posted the final rates to the 
website June 30, 2020, to ensure customers had an opportunity to submit 
additional comments.
    Comment: Commenter believes CREDA is unable to independently model 
rate scenarios with the customer portal element of the WAPA-wide PRS, 
which has not performed as anticipated, has affected collaborative 
efforts toward achieving the lowest possible rate.
    Response: WAPA understands the frustrations related to the use of 
the customer PRS portal and continues to troubleshoot the hardware and 
software. To that end, WAPA meets with and processes rate scenarios 
requested by CREDA and provides corresponding system-generated reports. 
WAPA will continue these efforts to strengthen customer collaboration.

5. Cost Recovery Charge

    Comment: Commenters continue to have questions regarding the 
proposed changes to the CRC. Although the Proposal FRN had a 
significant amount of discussion, the commenters would like WAPA to 
provide additional information and specific examples.
    Response: WAPA held a webinar to describe how it calculates the CRC 
and treatment of the subsequent prior year adjustment on June 4, 2020, 
and addressed this and the additional CRC questions below. The 
presentation was posted on the website on June 5, 2020.
    Comment: Customer does not support the proposed revised CRC lost 
revenue calculation, which calculates the difference between the 
projected purchased power cost and the energy

[[Page 52123]]

rate. Commenter encourages additional discussion on this issue.
    Response: Prior versions of the CRC did not account for the revenue 
lost when customers elect the WL and reduce their allocated energy (in 
lieu of the CRC). WAPA addressed this issue during the public webinar 
held on June 4, 2020 and a presentation detailing the CRC process was 
posted to the website on June 5, 2020.
    Comment: Commenter does not support the revised CRC process that 
will reduce SHP capacity for those customers opting for the WL to 
maintain each customer's existing monthly Load Factor percentage at the 
same level while maintaining minimums.
    Response: WAPA was concerned that maintaining existing SHP capacity 
levels would be inconsistent with reduced allocations resulting from 
WLs. Customers requesting a WL will have their energy allocation 
reduced, which will result in a corresponding reduction to their 
capacity allocation. To be consistent with marketing plan requirements, 
WAPA has elected to maintain a customer's Load Factor at consistent 
levels to provide for a reduction in capacity proportionate to any 
energy reduction under a WL.
    Comment: Commenter stated it would be very helpful to explain the 
proposed CRC changes by providing sample invoices for a Customer who 
does not waive the CRC and a Customer who waives the CRC, and showing 
proposed changes to the CRC calculation.
    Response: WAPA posted sample bills, sample CRC and WL calculations 
by Customer, and worksheets showing the difference between the SLIP-F10 
and SLIP-F11 versions of the CRC on the website on April 16, 2020. 
Additionally, WAPA walked the Customers through the CRC calculations 
during the June 4, 2020, webinar. WAPA posted its presentation from the 
webinar to the website on June 5, 2020.
    Comment: Commenter asks that the 8.23 MAF trigger be reconsidered 
in favor of a Lake Powell reservoir level trigger. Customer feels the 
advances made in hydropower modeling by WAPA, Drought Contingency Plan 
establishment and implementation, and uncertainty associated with 
Interim Guidelines renegotiation make a lake-level trigger preferable.
    Response: The water release trigger does not trigger a CRC; rather, 
it permits WAPA to recalculate the CRC if water releases drop below 
8.23 MAF. Shifting from FY to CY calculations will enable WAPA to 
review more accurate forecasts of annual water release data prior to 
calculating the annual CRC. WAPA will reevaluate the need for this 
trigger as well as other options (including lake levels) in the future.
    Comment: Commenter asked whether the CROD billing capacity will get 
reduced, similar to SHP billing energy, if a customer elects to waive 
the CRC.
    Response: CROD billing capacity will not be reduced.
    Comment: Commenter supports converting CRC from an FY to a CY 
cycle.
    Response: WAPA acknowledges the comment.
    Comment: Commenter proposed that WAPA rename ``trigger for shortage 
criteria'' in the CRC due to confusion with other processes containing 
the term ``shortage criteria.''
    Response: WAPA agrees and has renamed it ``trigger for water 
release criteria.''
    Comment: Commenter asked if WAPA is proposing any changes related 
to the CRC that would impact the Customer's ability to firm up their 
resource with WRP or CDP.
    Response: No changes are planned.

6. Miscellaneous

    Comment: Commenter recognized WAPA's willingness to entertain 
suggestions and collaborate to develop alternatives capable of 
mitigating significant rate increases and stated it indicates a true 
desire to implement the lowest possible rate, consistent with sound 
business principles, on a regional basis and with a project-specific 
focus.
    Response: WAPA acknowledges the comment.
    Comment: Multiple commenters encouraged WAPA to support CREDA's 
comments on proposed adjustments.
    Response: WAPA acknowledges the input and has responded to CREDA's 
comments in this final rule.
    Comment: Commenter thanked WAPA for its diligent work preparing the 
Rate Brochure, the information from the PIF, and the willingness to 
work with Customers to ensure the lowest possible rate.
    Response: WAPA acknowledges the comment.

7. Extended Comment Period Comments

    Comment: Commenter appreciates the opportunity to work with WAPA 
throughout the rate process, particularly WAPA's online posting of rate 
information, supporting documentation, and responses to questions and 
comments.
    Response: WAPA recognizes the benefits of customer engagement and 
the need for transparency in the rate process.
    Comment: Commenter appreciates WAPA's June webinars, which provided 
additional information and responses to customer questions and comments 
on the CRC. As issues such as hydrology, environmental program funding, 
and purchased power all have potential impacts to the triggering and 
implementation of a CRC, the commenter encourages ongoing discussion on 
the various elements of the CRC, including triggering criteria, as well 
as changes proposed to the CRC in this rate proceeding.
    Response: WAPA welcomes additional discussion on the methods to 
ensure cost recovery is achieved and on the various elements of the CRC 
and WL.
    Comment: Commenter appreciates WAPA's decision to incorporate the 
FY 2021 Work Plan materials into this rate proceeding.
    Response: WAPA acknowledges the comment.
    Comment: Commenter supports the adoption of the rate as made 
available for customer review on June 30, 2020, and the revision of the 
rate proposed on January 21, 2020, as structured to reduce the relevant 
apportionment and extend the ``pinch point'' to 2038. Commenter agrees 
that this rate formulary best ensures that WAPA imposes only the 
minimum cost to CRSP customers, consistent with WAPA's obligations.
    Response: WAPA acknowledges the comment.

Certification of Rates

    I have certified that the Provisional Rates for SLCA/IP firm power 
and sales of surplus products and the CRSP transmission and ancillary 
services under Rate Schedules SLIP-F11, SP-NW5, SP-PTP9, SP-NFT8, SP-
UU2, SP-E15, SP-SSR5, and SP-SS1 are the lowest possible rates, 
consistent with sound business principles. The Provisional Rates were 
developed following administrative policies and applicable laws.

Availability of Information

    Information about this rate adjustment, including the customer Rate 
Brochure, PRSs, comments, letters, memoranda, and other supporting 
materials that were used to develop the Provisional Rates, is available 
for inspection and copying by appointment at the Colorado River Storage 
Project Management Center, located at 299 South Main Street, Suite 200, 
Salt Lake City, Utah. Many of these documents are also available on 
WAPA's website at https://www.wapa.gov/regions/CRSP/rates/Pages/rates.aspx.

[[Page 52124]]

Ratemaking Procedure Requirements

Environmental Compliance

    WAPA has determined that this action is categorically excluded from 
the preparation of an environmental assessment or an environmental 
impact statement.\13\ A copy of the categorical exclusion determination 
is available on WAPA's website at https://www.wapa.gov/regions/CRSP/rates/Pages/rates.aspx.
---------------------------------------------------------------------------

    \13\ The determination was made in compliance with the National 
Environmental Policy Act (NEPA) of 1969, as amended, 42 U.S.C. 4321-
4347; the Council on Environmental Quality Regulations for 
implementing NEPA (40 CFR parts 1500-1508); and DOE NEPA 
Implementing Procedures and Guidelines (10 CFR part 1021).
---------------------------------------------------------------------------

Determination Under Executive Order 12866

    WAPA 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 Provisional Rates herein confirmed, approved, and placed into 
effect on an interim basis, together with supporting documents, will be 
submitted to FERC for confirmation and final approval.

Order

    In view of the above and under the authority delegated to me, I 
hereby confirm, approve, and place into effect, on an interim basis, 
Rate Order No. WAPA-190. The rates will remain in effect on an interim 
basis until: (1) FERC confirms and approves them on a final basis; (2) 
subsequent rates are confirmed and approved; or (3) such rates are 
superseded.
    Signed in Lakewood, CO, on August 17, 2020.

Mark A Gabriel,
Administrator.

Rate Schedule SLIP-F11
(Supersedes Rate Schedule SLIP-F10)

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-190)

    Effective:
    Rate Schedule SLIP-F11 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, 2020, and will remain in effect until FERC confirms, 
approves, and places the rate schedules into effect on a final basis 
through September 30, 2025, 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: $4.85 per kilowatt of billing demand.
    Energy Charge: $11.43 mills per kilowatthour of use.
    Cost Recovery Charge:
    To adequately recover and maintain a sufficient balance in the 
Basin Fund, WAPA 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 October 1 of each year, and 
WAPA 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 January 1, 2021. Under a Water Release 
Trigger, the CRC will be re-calculated at that time. (See Trigger for 
Water Release Criteria explanation below.) The CRC will be calculated 
as follows:

WAPA has the Discretion To Implement a CRC Based on the Tiers Below

                                               Table 1--CRC Tiers
----------------------------------------------------------------------------------------------------------------
                 Tier                              Criteria, If the BFBB is:                      Review
----------------------------------------------------------------------------------------------------------------
    i................................  Greater than $150 million, with an expected       Annually.
                                        decrease to below $75 million.
    ii...............................  Less than $150 million but greater than $120
                                        million, with an expected 50 percent decrease
                                        in the next CY.
    iii..............................  Less than $120 million but greater than $90
                                        million, with an expected 40 percent decrease
                                        in the next CY.
    iv...............................  Less than $90 million but greater than $60        Semi-Annual (August/
                                        million, with an expected 25 percent decrease     February).
                                        in the next CY.
    v................................  Less than $60 million but greater than $40        Monthly.
                                        million with an expected decrease to below $40
                                        million in the next CY.
----------------------------------------------------------------------------------------------------------------


                                         Table 2--Sample CRC Calculation
----------------------------------------------------------------------------------------------------------------
                                        Description                 Example                  Formula
----------------------------------------------------------------------------------------------------------------
                        Step one: Determine the Net Balance available in the Basin Fund.
----------------------------------------------------------------------------------------------------------------
    BFBB...................  Basin Fund Beginning Balance ($).    $117,508,000  Financial forecast.
    BFTB...................  Basin Fund Target Balance ($)....     $70,504,800  BFBB--(Tier % *BFBB), or BFTB
                                                                                 for Tier i and Tier v.\1\
    PAR....................  Projected Annual Revenue ($) w/o     $190,628,000  Financial forecast.
                              CRC.
    PAE....................  Projected Annual Expenses ($)....    $249,187,000  Financial forecast.
    NR.....................  Net Revenue ($)..................    $-58,559,000  PAR--PAE.
    NB.....................  Net Balance ($)..................     $58,949,000  BFBB + NR.
----------------------------------------------------------------------------------------------------------------
                          Step two: Determine the Forecasted Energy Purchase Expenses.
----------------------------------------------------------------------------------------------------------------
    EA.....................  SHP Energy Allocation (GWh)......           5,135  Customer contracts.
    HE.....................  Forecasted Hydro Energy (GWh)....           4,459  Hydrologic & generation
                                                                                 forecast.

[[Page 52125]]

 
    FE.....................  Forecasted Energy Purchase (GWh).             676  EA--HE or anticipated.
    FFC....................  Forecasted Average Energy Price            $30.57  From commercially available
                              per MWh ($).                                       price indices.
    FX.....................  Forecasted Energy Purchase            $20,665,320  FE * FFC *1000.
                              Expense ($).
----------------------------------------------------------------------------------------------------------------
 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 Factor ($)....      $9,109,520  If (NB>BFBB,FX,FX-(BFTB-NB)).
    FA2....................  Revenue Factor ($)...............      $9,109,520  If (NR>-(BFBB-BFTB), FX, FX+NR
                                                                                 +(BFBB-BFTB)).
    FA.....................  Funds Available ($)..............      $9,109,520  Lesser of FA1 or FA2 (not less
                                                                                 than $0).
    FARR...................  Additional Revenue to be              $11,555,800  FX--FA.
                              Recovered ($).
----------------------------------------------------------------------------------------------------------------
            Step four: Determine the difference between the market price and the SLCA/IP Energy Rate.
----------------------------------------------------------------------------------------------------------------
    SLIP...................  SLCA/IP Energy Rate..............          $11.43  From Rate Schedule SLIP-F10.
    NRATE..................  Net Rate: Difference between               $19.14  FFC--SLIP.
                              Market Price and SLCA/IP Energy
                              Rate.
----------------------------------------------------------------------------------------------------------------
Step five: Once the FA for purchases and the NRATE for cost have been determined, the CRC can be calculated, and
                                            the WL can be determined.
----------------------------------------------------------------------------------------------------------------
    CRC....................  Cost Recovery Charge (mills/kWh).            2.25  FARR/(EA*1,000).
    WL.....................  Waiver Level (GWh)...............           4,531  EA-((FARR/NRATE)/1000).
    WLP....................  Waiver Level Percentage of Full            88.24%  WL/EA*100.
                              SHP.
    CRCE...................  CRC Energy (GWh).................             604  EA--WL.
    CRCEP..................  CRC Energy Percentage of Full SHP          11.76%  CRCE/EA*100.
    RISC...................  Reduction in SHP Capacity........          11.76%  Same as CRCEP percentage.
----------------------------------------------------------------------------------------------------------------
Notes:
1. Use Table 1 to calculate applicable value.

Narrative CRC Example

    Step One: Determine the net balance available in the Basin Fund.
    BFBB--WAPA will forecast the Basin Fund Beginning Balance for the 
next CY.

BFBB = $117,508,000

    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 40 percent, see Tier iii (BFBB < 120 million, BFBB > 
90 million)
= $117,508,000-$47,003,200
= $70,504,800

    PAR--Projected Annual Revenue is WAPA's estimate of revenue for the 
next CY.

PAR = $190,628,000

    PAE--Projected Annual Expenses is WAPA's estimate of expenses for 
the next CY. The PAE includes all cash outflows from the Basin Fund 
including capital expenses, O&M, revenue transfers to Reclamation, and 
returns to Treasury.

PAE = $249,187,000

    NR--Net Revenue equals revenues minus expenses.

NR = PAR-PAE
    = $190,628,000-249,187,000
    = $-58,559,000

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

NB = BFBB + NR
= $117,508,000 + (-58,559,000)
= $58,949,000

    Step Two: Determine the forecasted energy purchases expenses.
    EA--The Sustainable Hydro Power Energy (from Customer contracts) 
and Project Use allocations.

EA = 5,135 (GWh)

    HE--WAPA's forecast of Hydro Energy available during the next FY 
developed from Reclamation's August 24-month Study.

HE = 4,459 (GWh)

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

FE = EA-HE or anticipated purchases
= 676 (GWh, anticipated)

    FFC--The forecasted energy price for the next CY per MWh. WAPA 
currently uses Argus to estimate market prices for purchase power.

FFC = $30.57 per MWh

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

FX = FE*FFC*1000
= 676 * $30.57*1000
= $20,665,320

    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 (FA1, FA2) 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, 
then the value for forecasted energy purchased power expenses (FX) is 
used. If the net balance is less than the Basin Fund Target Balance, 
then the Forecasted Energy Purchased Power Expenses, subtracted by the 
difference between the Basin Fund Target Balance and the Net Balance, 
is used.

FA1 = If (NB >BFTB, FX, FX--(BFTB--NB))

    If the Net Balance is greater than the Basin Fund Target Balance, 
then FA1 = FX.

= $58,949,000 (NB) is greater than $70,504,800 (BFTB) then:
= $20,665,320 (FX)

    If the Net Balance is less than the Basin Fund Target Balance (as 
it is in this example), then this equation would be used to determine 
FA1:


[[Page 52126]]


    FA1 = FX - (BFTB-NB)
= $20,665,320 (FX)-($70,504,800 (BFTB)-$58,949,000 (NB))
= $9,109,520
B. Basin Fund Revenue Factor (FA2)
    The second factor ensures WAPA collects sufficient funds to meet 
the Basin Fund Target Balance as long as the amount needed does not 
exceed the forecasted purchase expense (FX):
    In the situation, there is no projected positive net revenue:

FA2 = If (NR>-(BFBB-BFTB), FX, FX + NR + (BFBB-BFTB))

    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:

= -$58,559,000(NR) is greater than-($117,508,000-$70,504,800) then:
= $20,665,320 (FX) else:

    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):

= $20,665,320 (FX) + (-58,559,000) (NR) + ($117,598,000-$70,504,800)
= $9,109,520

    FA--Determine funds available for purchasing firming energy by 
using the lesser of FA1 and FA2.
    FA1 and FA2 are equal, so:

FA = $9,109,520 (FX)

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

FARR = FX-FA
= $20,665,320 (FX)-$9,109,520 (FA)
= $11,555,800

    Step four: Determine the difference between the Market Price and 
the SLCA/IP energy rate.

SLIP--SLCA/IP energy rate from Rate Schedule SLIP F11
SLIP = $11.43 per MWh
NRATE--Difference between the Market Price and the SLCA/IP energy rate
NRATE = FFC - SLIP
= $30.57 (FFC) - $11.43 (SLIP)
= $19.14 per MWh

    Step five: 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 (FARR) 
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 CY.

CRC = FARR/(EA*1,000)
= $11,555,800 (FARR)/(5,135 (EA) * 1,000)
= $ 2.25 mills/kWh

B. Waiver Level (WL)
    WAPA will establish a WL that provides WAPA the ability to reduce 
purchased 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, WAPA 
will waive the CRC for that year. After the Funds Available have 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.
    If SHP Energy Allocation (EA) is less than forecasted Hydro Energy 
(HE) available, then WL = EA. If SHP Energy Allocation (EA) is greater 
than the forecasted Hydro Energy (HE) available, then WL = (EA - 
((FARR/NRATE)/1000))

WL = If (EA < HE), EA, (EA - ((FARR/NRATE)/1000)
= If 5,135 (EA) is less than 4,459 (HE), then:
= 5,135 (EA), else:
= 5,135 (EA) - (($11,555,800 (FARR)/$19.14 (NRATE))/1,000)
= 4,531 (GWh) is the Waiver Level
C. Waiver Level Percentage of Full SHP WLP
WLP = WL/EA
= 4,531/5,135
= 88.24%
D. CRC Energy GWh (CRCE)
CRCE = EA - WL
= 5,135--4,531
= 604 GWh
E. CRC Level Percentage of Full SHP (CRCEP)
CRCEP = CRCE/EA
= 604/5,135
= 11.76%
F. Reduction in Capacity (RISC):
    SHP capacity reductions will be made, for those customers taking 
the CRC waiver, to maintain each customer's existing monthly Load 
Factor percentage at the same level provided by the full SHP capacity 
and energy allocation.

RISC = CRCEP
= 11.76%

Trigger for Water Release Criteria

    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), WAPA will recalculate the CRC to include 
those lower estimates of hydropower generation and the estimated costs 
for the additional purchase power necessary. WAPA, 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 bills. This recalculation will remain in effect 
for the remainder of the current CY.
    If the annual water release volumes from Glen Canyon Dam return to 
8.23 MAF or higher during the trigger implementation, a new CRC will be 
calculated for the next month, and the Customer will be notified.

Narrative PYA Discussion

    Since the annual determination of the CRC is based upon estimates, 
an annual, prior-year adjustment (PYA) will be calculated. The CRC PYA 
for the next subsequent year 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. See Table 3 below for an example of the 
PYA.

[[Page 52127]]



                                            Table 3--PYA Calculation
----------------------------------------------------------------------------------------------------------------
                                                 PYA CALCULATION
-----------------------------------------------------------------------------------------------------------------
                                         Description                Example              Formula/Source
----------------------------------------------------------------------------------------------------------------
 Step one: Determine actual expenses and purchases for previous year's firming. This data will be obtained from
                                WAPA's financial statements at the end of the CY.
----------------------------------------------------------------------------------------------------------------
PFX                           Prior Year Actual Firming            $11,020,808  Monthly Income Statements.
                               Expenses ($).
PFE                           Prior Year Actual Firming Energy             490  Financial Settlements Data.
                               (GWh).
----------------------------------------------------------------------------------------------------------------
                        Step two: Determine the actual firming cost for the CRC portion.
----------------------------------------------------------------------------------------------------------------
EAC                           Sum of the energy allocations of           3,266
                               customers subject to the PYA
                               (GWh).
FFC                           Forecasted Firming Energy Cost--          $30.57  From CRC Calculation.
                               ($/MWh).
AFC                           Actual Firming Energy Cost--($/           $22.49  PFX/PFE.
                               MWh).
CRCEP                         CRC Energy Percentage...........          11.76%  From CRC Calculation.
CRCE                          Purchased Energy for the CRC                 384  EAC*CRCEP.
                               (GWh).
----------------------------------------------------------------------------------------------------------------
                             Step three: Determine Revenue Adjustment (RA) and PYA.
----------------------------------------------------------------------------------------------------------------
RA                            Revenue Adjustment ($)..........    ($3,102,720)  (AFC-FFC)*CRCE*1,000.
PYA                           Prior Year Adjustment (mills/       (.95 mills)/  (RA/EAC)/1,000.
                               kWh).                                       kWh
----------------------------------------------------------------------------------------------------------------

Narrative PYA Example

    Narrative PYA Example Only (assumes that a CRC was needed for the 
previous year).
    Step one: Determine actual expenses and purchases for previous 
year's firming. This data will be obtained from WAPA's financial 
statements at end of the FY.
    PFX--Prior year actual firming expense.

PFX = $11,020,808

    PFE--Prior year actual firming energy.

PFE = 490 GWh

    Step two: Determine the actual firming cost for the CRC portion.
    EAC--Sum of the energy allocations of customers who were assessed 
the CRC for the prior year.

EAC = 3,266 GWh

    CRCE--The amount of CRC Energy needed.

CRCE = EAC * CRCEP
= 3,266 * .1176
= 384 GWh

    AFC--The Actual Firming Energy Cost is the PFX divided by the PFE.

AFC = (PFX/PFE)/1,000
= ($11,020,808/490)/1,000
= $22.49/MWh

    Step three: Determine Revenue Adjustment and PYA.
    RA--The Revenue Adjustment is Actual Firming Energy Cost less 
Forecasted Firming Energy Cost times Purchased Energy for the CRC.

RA = (AFC - FFC) * CRCE * 1,000
= ($22.49 - $30.57) * 384 * 1,000
= ($3,102,720)

    PYA--The PYA is the Revenue Adjustment divided by the SHP Energy 
Allocation for the CRC Customers in the prior year only and will be 
applied to those same customers.

PYA = (RA/EAC)/1,000
= (-$3,102,720/3,266)/1,000
=-.95 mills/kWh

    The Customers' PYA will be based on their prior CY's energy 
multiplied by the PYA mills/kWh to determine the dollar value that will 
be assessed. The Customer will be charged or credited for this dollar 
amount equally in the remaining months of the next year's billing 
cycle. WAPA will complete this calculation by March 1 of each year. 
Therefore, if the PYA is calculated in March, the charge/credit will be 
spread over the remaining 9 months of the CY (April through December).
    CRC Schedule for Customers:
    Consistent with the procedures at 10 CFR 903, WAPA will provide its 
customers with information concerning the anticipated CRC for the 
upcoming CY by October 1. The established CRC will be in effect for the 
entire CY. The table below displays the time frame for determining the 
amount of purchases needed, developing customers' load schedules, and 
making purchases.

                                              Table 4--CRC Schedule
----------------------------------------------------------------------------------------------------------------
                                                         Respective dates under table CRC tiers
                 Task                 --------------------------------------------------------------------------
                                            i, ii, and iii               iv \1\                   v \2\
----------------------------------------------------------------------------------------------------------------
24-month Study (Forecast used to       August 1...............  August 1...............  Monthly Study.
 Model Projections).                                            February 1.............
CRC Notice to Customers..............  October 1..............  October 1..............  Monthly.
                                                                April 1................
Waiver Request Submitted by Customers  November 15............  Within 45 days.........  Within 30 days.
CRC Effective........................  January 1..............  January 1..............  Updated Monthly.
                                                                July 1.................
----------------------------------------------------------------------------------------------------------------
Notes:
\1\ Under a Water Release Criteria Trigger, this schedule will change. Customers will be notified that a CRC
  will be implemented in 90 days. WAPA 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.

[[Page 52128]]

 
\2\ 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. WAPA 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 Customer's Firm Electric Service Contract, as 
amended, WAPA will bill the Customer for its proportionate share of the 
costs of Western Replacement Power (WRP) within a given time period. 
WAPA will include in the monthly power bill the cost of the WRP and the 
incremental administrative costs associated with WRP.
    Adjustment for Customer Displacement Power Administrative Charges:
    WAPA will include in the Customer's regular monthly power bill the 
incremental administrative costs associated with Customer Displacement 
Power.
Rate Schedule SP-NW5

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

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-190)

    Effective:
    Rate Schedule SP-NW5 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, 2020, and will remain in effect until FERC confirms, 
approves, and places the rate schedules into effect on a final basis 
through September 30, 2025, or until the rate schedules are superseded.
    Applicable:
    The Transmission Customer will compensate the Colorado River 
Storage Project each month for Network Integration Transmission Service 
under the applicable Network Integration Transmission Service Agreement 
and the formula rate described herein.
    Formula Rate:
    [GRAPHIC] [TIFF OMITTED] TN24AU20.012
    
    A calculated 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. 
WAPA 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-PTP9

SCHEDULE 7 to Tariff
(Supersedes Schedule SP-PTP8)

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-190)

    Effective:
    Rate Schedule SP-PTP9 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, 2020, and will remain in effect until FERC confirms, 
approves, and places the rate schedules into effect on a final basis 
through September 30, 2025, 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.
    Formula Rate:
    [GRAPHIC] [TIFF OMITTED] TN24AU20.013
    

[[Page 52129]]


    A recalculated rate will go into effect every October 1 based on 
the above formula and updated financial and operational data. WAPA 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 WAPA'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-NFT8

SCHEDULE 8 to Tariff
(Supersedes Schedule SP-NFT7)

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-190)

    Effective:
    Rate Schedule SP-NFT8 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, 2020, and will remain in effect until FERC confirms, 
approves, and places the rate schedules into effect on a final basis 
through September 30, 2025, 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. WAPA 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 WAPA'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-UU2

SCHEDULE 10 to Tariff
(Supersedes Schedule SP-UU1)

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-190)

    Effective:
    Rate Schedule SP-UU2 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, 2020, and will remain in effect until FERC confirms, 
approves, and places the rate schedules into effect on a final basis 
through September 30, 2025, 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 (SP-PTP9) 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 WAPA's Open Access Transmission Tariff that were provided 
by the CRSP and associated with the Unreserved Use. The Transmission 
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 WAPA'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 and made part of the applicable 
service agreement.
Rate Schedule SP-EI5

SCHEDULES 4 & 9 to Tariff
(Supersedes Rate Schedule SP-EI4)

United States Department of Energy Western Area Power Administration

Colorado River Storage Project Management Center Colorado River Storage 
Project

Energy and Generator Imbalance Services (Approved Under Rate Order No. 
WAPA-190)

    Effective:
    Rate Schedule SP-EI5 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, 2020, and will remain in effect until FERC confirms, 
approves, and places the rate schedules into effect on a final basis 
through September 30, 2025, 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 Schedules L-AS4 and L-AS9, or as 
superseded.

Rate Schedule SP-SSR5


[[Page 52130]]


SCHEDULES 5 & 6 to Tariff
(Supersedes Rate Schedule SP-SSR4)

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-190)

    Effective:
    Rate Schedule SP-SSR5 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, 2020, and will remain in effect until FERC confirms, 
approves, and places the rate schedules into effect on a final basis 
through September 30, 2025, or until the rate schedules are superseded.
    Applicable:
    To all CRSP Transmission Customers receiving this service.
    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-SS1

United States Department of Energy Western Area Power Administration

Colorado River Storage Project Management Center Colorado River Storage 
Project

Sale of Surplus Products (Approved Under Rate Order No. WAPA-190)

    Effective:
    The first day of the first full billing period beginning on or 
after October 1, 2020, and extending through September 30, 2025, or 
until superseded by another rate schedule, whichever occurs earlier.
    Applicable:
    This Rate Schedule applies to the sale of the following Salt Lake 
City Area Integrated Projects (SLCA/IP) surplus energy and capacity 
products: energy, frequency response, regulation, and reserves. If any 
of the above SLCA/IP surplus products are available, SLCA/IP can make 
the product(s) available for sale, providing entities enter into 
separate agreement(s) with CRSP Marketing which will specify the terms 
of the sale(s).
    Formula Rate:
    The charge for each product will be determined at the time of the 
sale based on market rates, plus administrative costs. The customer 
will be responsible for acquiring transmission service necessary to 
deliver the product(s), for which a separate charge may be incurred.

[FR Doc. 2020-18533 Filed 8-21-20; 8:45 am]
BILLING CODE 6450-01-P