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Notice

Salt Lake City Area Integrated Projects and Colorado River Storage Project-Rate Order No. WAPA-190

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Start Preamble

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.

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2025, pending confirmation and approval by the Federal Energy Regulatory Commission (FERC) on a final basis or until superseded.

Start Further Info

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: tvigil@wapa.gov; or Mr. Thomas Hackett, Rates Manager, Colorado River Storage Project Management Center, Western Area Power Administration, telephone: (801) 524-5503, or email: hackett@wapa.gov.

End Further Info End Preamble Start Supplemental Information

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.

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.

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.

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]

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 Start Printed Page 52116confirmation 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.

Start Signature

Signed in Washington, DC, on August 19, 2020.

Treena V. Garrett,

Federal Register Liaison Officer, U.S. Department of Energy.

End Signature

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]

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]

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.Start Printed 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.Start Printed 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.

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

Firm power serviceExisting requirements (October 1, 2015)Provisional requirements (October 1, 2020)Percent change
Revenue Requirement (million $)$183.873$173.511−5.6
Composite Rate (mills/kWh)29.4227.45−6.7

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

Firm power serviceExisting rates under rate schedule SLIP-F10 as of October 1, 2015Provisional rates under rate schedule SLIP-F11 as of October 1, 2020Percent change
Firm Energy Rate (mills/kWh)12.1911.43−5.5
Firm Capacity Rate ($/kWmonth)5.184.85−6.4
Start Printed 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

Existing rate 2017 work planProvisional rate 2021 work planChange amount
Ratesetting Period:
Beginning Year20162021
Pinch Point Year20252038
Number of Ratesetting Years1018
Annual Revenue Requirement:
Expenses:
Operations & Maintenance WAPA$52,630$61,509$8,878
Reclamation34,53535,8431,308
Total O&M87,16597,35210,187
Purchase Power10,2801,119(9,161)
Transmission10,4218,998(1,423)
Integrated Projects8,6106,485(2,125)
Interest4,7066,0661,360
Other Expenses14,58717,9093,322
Total Expenses135,769137,9282,159
Principal Payments:
Deficits000
Replacements30,03726,918(3,119)
Original Project and Additions3,9372,484(1,453)
Irrigation14,1306,181(7,949)
Total Principal Payments48,10435,583(12,521)
Total Annual Revenue Requirement183,873173,511(10,362)
(Less Offsetting Annual Revenue)
Transmission19,64015,257(4,383)
Merchant Function9,9189,375(543)
Other Revenues5,1184,855(263)
Total Offsetting Annual Revenue34,67629,487(5,189)
Net Annual Revenue Requirements149,197144,024(5,173)
Energy Sales (MWH)5,071,8045,245,909174,105
Capacity Sales (kW)1,407,9201,428,30620,386
Composite Rate (mills/kWh)29.4227.45(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 Start Printed Page 52120requirements.[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.

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

TierCriteria, if the Basin Fund beginning balance is:Review
iGreater than $150 million with an expected decrease to below $75 millionAnnually.
iiLess than $150 million but greater than $120 million with an expected 50 percent decrease in the next CYAnnually.
iiiLess than $120 million but greater than $90 million with an expected 40 percent decrease in the next CYAnnually.
ivLess than $90 million but greater than $60 million with an expected 25 percent decrease in the next CYSemi-Annual (February/August).
vLess than $60 million but greater than $40 million with an expected decrease to below $40 million in the next CYMonthly.

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.

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/​Start Printed Page 52121rates/​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.

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 Start Printed Page 52122not 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 Start Printed Page 52123rate. 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. Start Printed 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.

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

TierCriteria, If the BFBB is:Review
iGreater than $150 million, with an expected decrease to below $75 millionAnnually.
iiLess than $150 million but greater than $120 million, with an expected 50 percent decrease in the next CY
iiiLess than $120 million but greater than $90 million, with an expected 40 percent decrease in the next CY
ivLess than $90 million but greater than $60 million, with an expected 25 percent decrease in the next CYSemi-Annual (August/February).
vLess than $60 million but greater than $40 million with an expected decrease to below $40 million in the next CYMonthly.

Table 2—Sample CRC Calculation

DescriptionExampleFormula
Step one: Determine the Net Balance available in the Basin Fund.
BFBBBasin Fund Beginning Balance ($)$117,508,000Financial forecast.
BFTBBasin Fund Target Balance ($)$70,504,800BFBB—(Tier % *BFBB), or BFTB for Tier i and Tier v.1
PARProjected Annual Revenue ($) w/o CRC$190,628,000Financial forecast.
PAEProjected Annual Expenses ($)$249,187,000Financial forecast.
NRNet Revenue ($)$−58,559,000PAR—PAE.
NBNet Balance ($)$58,949,000BFBB + NR.
Step two: Determine the Forecasted Energy Purchase Expenses.
EASHP Energy Allocation (GWh)5,135Customer contracts.
HEForecasted Hydro Energy (GWh)4,459Hydrologic & generation forecast.
Start Printed Page 52125
FEForecasted Energy Purchase (GWh)676EA—HE or anticipated.
FFCForecasted Average Energy Price per MWh ($)$30.57From commercially available price indices.
FXForecasted Energy Purchase Expense ($)$20,665,320FE * FFC *1000.
Step three: Determine the amount of Funds Available for firming energy purchases, and then determine additional revenue to be recovered. The following two formulas will be used to determine FA; the lesser of the two will be used.
FA1Basin Fund Balance Factor ($)$9,109,520If (NB>BFBB,FX,FX−(BFTB−NB)).
FA2Revenue Factor ($)$9,109,520If (NR>−(BFBB-BFTB), FX, FX+NR +(BFBB-BFTB)).
FAFunds Available ($)$9,109,520Lesser of FA1 or FA2 (not less than $0).
FARRAdditional Revenue to be Recovered ($)$11,555,800FX—FA.
Step four: Determine the difference between the market price and the SLCA/IP Energy Rate.
SLIPSLCA/IP Energy Rate$11.43From Rate Schedule SLIP-F10.
NRATENet Rate: Difference between Market Price and SLCA/IP Energy Rate$19.14FFC—SLIP.
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.
CRCCost Recovery Charge (mills/kWh)2.25FARR/(EA*1,000).
WLWaiver Level (GWh)4,531EA−((FARR/NRATE)/1000).
WLPWaiver Level Percentage of Full SHP88.24%WL/EA*100.
CRCECRC Energy (GWh)604EA—WL.
CRCEPCRC Energy Percentage of Full SHP11.76%CRCE/EA*100.
RISCReduction in SHP Capacity11.76%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:

Start Printed 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.Start Printed Page 52127

Table 3—PYA Calculation

PYA CALCULATION
DescriptionExampleFormula/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.
PFXPrior Year Actual Firming Expenses ($)$11,020,808Monthly Income Statements.
PFEPrior Year Actual Firming Energy (GWh)490Financial Settlements Data.
Step two: Determine the actual firming cost for the CRC portion.
EACSum of the energy allocations of customers subject to the PYA (GWh)3,266
FFCForecasted Firming Energy Cost—($/MWh)$30.57From CRC Calculation.
AFCActual Firming Energy Cost—($/MWh)$22.49PFX/PFE.
CRCEPCRC Energy Percentage11.76%From CRC Calculation.
CRCEPurchased Energy for the CRC (GWh)384EAC*CRCEP.
Step three: Determine Revenue Adjustment (RA) and PYA.
RARevenue Adjustment ($)($3,102,720)(AFC-FFC)*CRCE*1,000.
PYAPrior Year Adjustment (mills/kWh)(.95 mills)/kWh(RA/EAC)/1,000.

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

TaskRespective dates under table CRC tiers
i, ii, and iiiiv 1v 2
24-month Study (Forecast used to Model Projections)August 1August 1 February 1Monthly Study.
CRC Notice to CustomersOctober 1October 1 April 1Monthly.
Waiver Request Submitted by CustomersNovember 15Within 45 daysWithin 30 days.
CRC EffectiveJanuary 1January 1 July 1Updated Monthly.
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.Start Printed 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:

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:

Start Printed 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

Start Printed 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.

End Supplemental Information

Footnotes

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

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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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3.  85 FR 3367 (January 21, 2020)

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4.  85 FR 38369 (June 26, 2020).

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5.  50 FR 37835 (September 18, 1985) and 84 FR 5347 (February 21, 2019).

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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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7.  50 FR 37835 (September 18, 1985) and 84 FR 5347 (February 21, 2019).

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8.  85 FR 38369 (June 26, 2020).

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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.

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10.  See Table 4.

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

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12.  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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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).

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[FR Doc. 2020-18533 Filed 8-21-20; 8:45 am]

BILLING CODE 6450-01-P