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Notice

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

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AGENCY:

Western Area Power Administration, DOE.

ACTION:

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

SUMMARY:

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

DATES:

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and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

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FOR FURTHER INFORMATION CONTACT:

Ms. Lynn C. Jeka, CRSP Manager, Colorado River Storage Project Management Center, Western Area Power Administration, 150 East Social Hall Avenue, Suite 300, Salt Lake City, UT 84111-1580, (801) 524-6372, email jeka@wapa.gov, or Mr. Rodney G. Bailey, Power Marketing Manager, Colorado River Storage Project Management Center, Western Area Power Administration, 150 East Social Hall Avenue, Suite 300, Salt Lake City, UT 84111-1580, (801) 524-4007, email rbailey@wapa.gov.

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SUPPLEMENTARY INFORMATION:

Western proposed the rates for the SLCA/IP firm power and CRSP transmission and ancillary services rates on December 9, 2014 (79 FR 73067). On January 15, 2015, Western held a public information forum in Salt Lake City, Utah. On February 5, 2015, Western held a public comment forum in Salt Lake City, Utah. After considering the comments received, Western announced the rates for the SLCA/IP firm power and CRSP transmission and ancillary services.

The existing Rate Schedule SLIP-F9 for SLCA/IP firm power and Rate Schedules SP-PTP7, SP-NW3, SP-NFT6, SP-SD3, SP-RS3, SP-EI3, SP-FR3, and SP-SSR3 for CRSP Transmission and Ancillary Services were approved under Rate Order No. WAPA-137 [1] for a 5-year period beginning October 1, 2008, and ending September 30, 2013. The Deputy Secretary of Energy approved Rate Order No. WAPA-161 [2] on September 6, 2013, extending the rates through September 30, 2015.

The existing firm power Rate Schedule SLIP-F9 is being superseded by Rate Schedule SLIP-F10. The current capacity rate and energy rate under WAPA-137 remain sufficient to cover Operations Maintenance & Replacements and required repayment. Western will continue to use the existing energy charge of 12.19 mills/kWh and capacity charge of $5.18/kWmonth. However, the composite rate, which is used for comparison purposes only and is not part of the billing component, will decrease from 29.62 to 29.42 mills/kWh. The composite rate is calculated by dividing the average revenue requirement for the rate-setting period by the average energy sales. The change in the composite rate is driven in large part by changes in the average energy sales due to changes in Project Use energy requirements. Rate Schedules SLIP-F10, SP-PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-RS4, SP-EI4, SP-FR4, SP-SSR4, and SP-UU1 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will be in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Under this rate action, Western makes the following changes to the existing rates as originally proposed:

1. The firm power rate will continue to include a cost recovery mechanism to adequately maintain a sufficient cash balance in the Upper Colorado River Basin Fund (Basin Fund) when, among other things, the balance is at risk due to low hydropower generation, high prices for firming power, and funding for capitalized investments. The Cost Recovery Charge (CRC) is not a component of the firm power rate because the rate is set to collect sufficient revenue for repayment in the Power Repayment Study (PRS) and is not tied to the cash balance of the Basin Fund. Western is modifying the CRC by adopting a tiered implementation approach to afford Western discretion in implementing a potential CRC. Under the current criteria, if the CRC is triggered, Western must initiate the CRC regardless of the balance in the Basin Fund. This may potentially cause a CRC to be initiated when it is not necessary due to the projected ending balance of the fund being higher than the minimum amount Western's management has determined as an acceptable ending balance. Allowing Western to have discretion will ensure a CRC is only initiated when the projected ending balance of the Basin Fund is below $40 million.

2. Western is adopting forward-looking methodology used to calculate the Annual Transmission Revenue Requirement (ATRR). This methodology allows Western to recover costs in line with the FY following when the cost occurred. In addition to annual audited financial data, Western will use projections from the 10-Year Plan and current year-to-date financial data for the annual rate calculation. This is a change in the manner in which the inputs for the rate are developed, rather than a change to the formula rate itself. Western will use a “true-up” procedure to ensure that no more and no less than the actual transmission costs are recovered for the year.

3. Western proposes to use a formula-based rate for the Regulation and Frequency Response Ancillary Service that will more accurately reflect the incurred costs rather than using the SLCA/IP firm power capacity rate. This Start Printed Page 53294proposed change will be more in line with other Western Federal transmission providers.

4. Add a rate schedule for Unreserved Use, SP-UU1. The rate will be set at 200 percent of the Colorado River Storage Project Management Center's (CRSP MC) current transmission rate. Currently, the CRSP MC is using an “Unauthorized Use” charge that is at 150 percent of the current transmission rate. Increasing the charge to 200 percent brings the CRSP MC in line with other Western Federal transmission providers in the Balancing Authority (BA).

5. Update all CRSP rate schedules that use the BA rates to reference the appropriate BA rate schedule.

After reviewing customer comments, Western is not finalizing the following proposals in the Rate Order:

1. Western will not use the proposed composite rate of 29.93 mills/kWh, but will continue to charge the energy and capacity rates from the SLIP-F9 Rate Schedule. Western agrees with the customers' assessment that the current rate remains sufficient to recover costs and repayment (see item 2. below).

2. The CRSP MC forecasts 5 years of firming purchased power in the PRS using the April, 24-month hydrology study from the Bureau of Reclamation. This reflects the firming purchase power requirements between projected generation and contract obligations. For the remaining out-years, a forecast of $4 million a year is projected to cover operational costs for the Energy Management and Marketing Office in Montrose, Colorado. Western proposed to add the projected $4 million to the first 5 years based on anticipated annual operational needs beyond firming purchases. Western will not include the addition of the $4 million per year increase at this time. Consistent with the procedures at 10 CFR part 903, Western will consider whether to refine the purchase power cost estimates.

By Delegation Order No. 00-037.00A, effective October 25, 2013, the Secretary of Energy delegated: (1) The authority to develop power and transmission rates to Western's Administrator, (2) the authority to confirm, approve, and place such rates into effect on an interim basis to the Deputy Secretary of Energy, and (3) the authority to confirm, approve, and place into effect on a final basis, to remand or to disapprove such rates to FERC. Existing Department of Energy procedures for public participation in power rate adjustments (10 CFR part 903) were published on September 18, 1985.

Under Delegation Order Nos. 00-037.00A and 00-001.00F, and in compliance with 10 CFR part 903 and 18 CFR part 300, I hereby confirm, approve, and place Rate Order No. WAPA-169, the provisional SLCA/IP firm power rate, CRSP firm and non-firm transmission rates, and ancillary services rates into effect on an interim basis. The new Rate Schedules SLIP-F10, SP-PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-RS4, SP-EI4, SP-FR4, SP-SSR4, and SP-UU1 will be promptly submitted to FERC for confirmation and approval on a final basis.

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Dated: August 28, 2015.

Elizabeth Sherwood-Randall,

Deputy Secretary of Energy.

End Signature

DEPARTMENT OF ENERGY

DEPUTY SECRETARY

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

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

These rates were established in accordance with section 302 of the Department of Energy (DOE) Organization Act (42 U.S.C. 7152). This Act transferred to and vested in the Secretary of Energy the power marketing functions of the Secretary of the Department of the Interior and the Bureau of Reclamation (Reclamation) under the Reclamation Act of 1902 (ch. 1093, 32 Stat. 388), as amended and supplemented by subsequent laws, particularly section 9(c) of the Reclamation Project Act of 1939 (43 U.S.C. 485h(c)), and other acts that specifically apply to the project involved.

By Delegation Order No. 00-037.00A, effective October 25, 2013, the Secretary of Energy delegated: (1) the authority to develop power and transmission rates to Western Area Power Administration's (Western) Administrator, (2) the authority to confirm, approve, and place such rates into effect on an interim basis to the Deputy Secretary of Energy, and (3) the authority to confirm, approve, and place into effect on a final basis, to remand or to disapprove such rates to the Federal Energy Regulatory Commission (FERC). Existing DOE procedures for public participation in power rate adjustments (10 CFR part 903) were published on September 18, 1985.

Acronyms and Definitions

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

AHP: Available Hydropower.

ATRR: Annual Transmission Revenue Requirement.

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

Basin Fund: Upper Colorado River Basin Fund.

BFBB: Basin Fund Beginning Balance as used in the CRC formula.

BFTB: Basin Fund Target Balance as used in the CRC formula.

Capacity: The electric capability of a generator, transformer, transmission circuit, or other equipment. It is expressed in kW.

Capacity Rate: The rate which sets forth the charges for capacity. It is expressed in $/kWmonth and applied to each kW of the Contract Rate of Delivery (CROD).

CDP: Customer Displacement Power.

Composite Rate: The rate for firm power which is the total annual revenue requirement for capacity and energy divided by the total annual energy sales. It is expressed in mills/kWh and used for comparison purposes.

CRC: Cost Recovery Charge. A mechanism to assist in recovery of purchased power costs during financial hardship.

CRCE: CRC Energy (GWh) as used in the CRC and PYA formulas.

CRCEP: CRC Energy Percentage of full SHP as used in the CRC and PYA formulas.

CROD: Contract Rate of Delivery. The maximum amount of capacity made available to a preference customer for a period specified under a contract.

CRSP: Colorado River Storage Project.

CRSP Act: An act to authorize the Secretary of the Interior to construct, operate, and maintain the Colorado River Storage Project and Participating Projects, and for other purposes. (Act of April 11, 1956, ch. 203, 70 Stat. 105.)

CRSP MC: The CRSP Management Center of Western Area Power Administration.

Customer: An entity with a contract that is receiving firm electric service and transmission from Western's CRSP MC.

DOE Order RA 6120.2: A DOE order outlining power marketing administration financial reporting and ratemaking procedures.Start Printed Page 53295

DSW: The Desert Southwest Region of Western Area Power Administration.

EA: SHP Energy Allocation (GWh) as used in the CRC formula.

EAC: Sum of customers' energy allocations subject to the PYA formula.

Energy: Power produced or delivered over a period of time. It is expressed in kilowatthours.

Energy Rate: The rate which sets forth the charges for energy. It is expressed in mills/kWh and applied to each kWh delivered to each customer.

FA: Funds Available as used in the CRC formula.

FA1: Basin Fund Balance Factor as used in the CRC formula.

FA2: Revenue Factor as used in the CRC formula.

FARR: Additional revenue to be recovered as used in the CRC formula.

FE: Forecasted purchased energy as used in the CRC formula.

FFC: Forecasted average energy price per MWh as used in the CRC and PYA formulas.

Firm: A type of product and/or service always available at the time requested by the customer.

FRN: Federal Register notice.

FX: Forecasted energy purchased expense as used in the CRC formula.

FY: Fiscal year is the period from October 1 to September 30.

GWh: Gigawatthour. The electrical unit of energy that equals 1 billion watt-hours or 1 million kWh.

HE: Forecasted hydro energy as used in the CRC formula.

Integrated Projects: The resources and revenue requirements of the Collbran, Dolores, Rio Grande, and Seedskadee projects blended together with the CRSP to create the SLCA/IP resources and rate.

kW: Kilowatt. The electrical unit of capacity that equals 1,000 watts.

kWh: Kilowatthour. The electrical unit of energy that equals 1,000 watts produced or delivered in 1 hour.

kWmonth: Kilowattmonth. The electrical unit of a monthly amount of capacity.

kWyear: Kilowattyear. The electrical unit of a yearly amount of capacity.

Load: The amount of electric power or energy delivered or required at any specified point(s) on a system.

Load-Ratio Share: Network customer's hourly load (including its designated network load not physically interconnected with Western) coincident with Western's monthly CRSP transmission system peak.

MAF: Million Acre-Feet. The amount of water required to cover 1 million acres, 1 foot in depth.

Mill: A monetary denomination of the United States that equals one-tenth of a cent or one-thousandth of a dollar.

Mills/kWh: Mills per kilowatthour. A unit of charge for energy.

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

MWh: One million watt-hours of electric energy. A unit of electrical energy which equals 1 megawatt of power used for 1 hour.

NATRR: Net Annual Transmission Revenue Requirement.

NB: Net Balance as used in the CRC formula.

NEPA: National Environmental Policy Act of 1969 (42 U.S.C. 4321, et seq.).

Non-firm: A type of product and/or service not always available for use when requested by the customer.

NR: The net revenue remaining after paying all annual expenses as used in the CRC formula.

OASIS: Open Access Same-Time Information System.

O&M: Operation and Maintenance.

OM&R: Operation, Maintenance, and Replacements.

PAE: Projected Annual Expenses as used in the CRC formula.

PAR: Projected Annual Revenue without the CRC as used in the CRC formula.

Participating Projects: The projects participating with CRSP according to the CRSP Act of 1956 (43 U.S.C. 620).

PFE: Prior year actual firming energy as used in the PYA formula.

PFX: Prior year actual firming expenses as used in the PYA formula.

Pinch Point: The nearest future year in the PRS where cumulative expenses and required payments equal cumulative revenues.

Power: Capacity and energy.

Preference: The provisions of Reclamation Law which require Western to first make Federal power available to certain entities. For example, section 9(c) of the Reclamation Project Act of 1939 (43 U.S.C. 485h(c)) states that preference in the sale of Federal power shall be given to municipalities and other public corporations or agencies and also to cooperatives and other nonprofit organizations financed in whole or in part by loans made under the Rural Electrification Act of 1936.

Price: Average price per MWh for purchased power as used in the CRC formula.

Project Use: Power used to operate the CRSP Participating Projects facilities under Reclamation Law.

Proposed Rate: A rate that has been recommended by Western to the Deputy Secretary of Energy for approval.

Provisional Rate: A rate which has been confirmed, approved, and placed into effect on an interim basis by the Deputy Secretary of Energy.

PRS: Power Repayment Study.

PYA: Prior Year Adjustment as used in the CRC formula.

RA: Revenue Adjustment as used in the PYA formula.

Rate Brochure: A document explaining the rationale and background for the rate proposal contained in this Rate Order dated January 2015.

Ratesetting PRS: The PRS used for the rate adjustment proposal.

Reclamation Law: A series of Federal laws, viewed as a whole, that create the originating framework under which Western markets power.

Revenue Requirement: The revenue required to recover annual expenses, such as O&M, purchased power, transmission service expenses, interest, deferred expenses, repayment of Federal investments, and other assigned costs.

RMR: Rocky Mountain Region of Western Area Power Administration.

SHP: Sustainable Hydropower as defined in the firm power contracts for SLCA/IP.

SLCA/IP: Salt Lake City Area Integrated Projects. The resources and revenue requirements of the Collbran, Dolores, Rio Grande, and Seedskadee projects blended together with the CRSP to create the SLCA/IP rate.

Supporting Documentation: A compilation of data and documents that support the Rate Brochure and the Proposed Rate.

TRC: Transmission Revenue Credits.

True-up: True-up to actuals. Western will reconcile actual transmission costs against projections and adjust the transmission revenue requirements in a subsequent fiscal year. This ensures Western will recover no more and no less than the actual costs for that year.

TSTL: CRSP Transmission System Total Load.

WACM: Western Area Colorado Missouri.

WL: Waiver Level as used in the CRC formula.

WLP: Waiver Level Percentage of full SHP as used in the CRC formula.

WPR: Work Program Review. The work plan is a draft estimate of costs that are expected to be included in the Congressional Budget for Western and Reclamation and the basis for budget estimates to be used in the PRS.

WRP: Western Replacement Power as defined in the firm electric service contracts for SLCA/IP.Start Printed Page 53296

Effective Date

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

Public Notice and Comment

Western followed the Procedures for Public Participation in Power and Transmission Rate Adjustments and Extensions, 10 CFR part 903, in developing these rates. The steps Western took to involve interested parties in the rate process were:

1. Western publicly announced the rate action on June 24, 2014, during the formal customer meeting, to all SLCA/IP customers and interested parties.

2. Western published an FRN on December 9, 2014 (79 FR 73067), announcing the proposed rates for the SLCA/IP firm power and CRSP transmission and ancillary services rates, initiating a public consultation and comment period and setting forth the dates and locations of public information and public comment forums.

3. On December 12, 2014, Western's CRSP MC mailed an announcement of the January 15, 2015, public information forum to all SLCA/IP Preference customers, CRSP transmission customers, and interested parties, along with the Rate Brochure, which contains a copy of the published FRN proposal. This information was also posted to the CRSP MC Web page, http://www.wapa.gov/​crsp/​ratescrsp.

4. On January 15, 2015, Western held a public information forum in Salt Lake City, Utah. Western provided detailed explanations about the proposed SLCA/IP firm power rate and the CRSP transmission and ancillary services rates. Western provided the Rate Brochure, supporting documentation, and informational handouts at this meeting.

5. On February 5, 2015, Western held a public comment forum in Salt Lake City, Utah, to provide the public an opportunity to comment for the record. Western reiterated that the comment and consultation period ended March 13, 2015.

6. Western received eight comment letters during the consultation and comment period. All comments have been considered in preparing this Rate Order.

Comments

Written comments were received from the following organizations:

Arizona's Generation and Transmission Cooperatives, Arizona

Arizona Tribal Energy Association, Arizona

Colorado River Commission of Nevada, Nevada

Colorado River Energy Distributors Association, Arizona

Deseret Power Electric Cooperative, Utah

Irrigation and Electric Districts of Arizona, Arizona

Tri-State Generation and Transmission Association, Colorado

Utah Associated Municipal Power Systems, Utah

Representatives of the following organizations made oral comments:

Colorado River Energy Distributors Association, Arizona

Deseret Power Electric Cooperative, Utah

Project Description

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

Power Repayment Study—Firm Power Rate

Western prepares a PRS each year to determine if revenues will be sufficient to repay, within the required time, all costs assigned to the SLCA/IP. Repayment criteria are based on applicable laws and policies, including DOE Order RA 6120.2. To meet Cost Recovery Criteria outlined in DOE Order RA 6120.2, revised studies and rate adjustments have been developed to demonstrate that sufficient revenues will be collected under provisional Rates to meet future obligations.

The current capacity rate and energy rate under Rate Schedule SLIP-F9 remain sufficient to cover OM&R and required repayment. Western will continue to use the existing energy charge of 12.19 mills/kWh and capacity charge of $5.18/kWmonth. However, the composite rate, which is used for comparison purposes only and is not part of the billing component, will decrease from 29.62 to 29.42 mills/kWh. The composite rate is calculated by dividing the average revenue requirement for the ratesetting period by the average energy sales. The change in the composite rate is driven in large part by changes in the average energy sales due to changes in Project Use energy requirements.

Comparison of Current and Proposed Firm Power Rates

Current Rate October 1, 2008- September 30, 2015 *Proposed Rate October 1, 2015Total Percent Increase
Rate ScheduleSLIP-F9SLIP-F10
Energy (mills/kWh)12.1912.190
Capacity ($/kWmonth)5.185.180
Composite Rate (mills/kWh)29.6229.42−1
*Approved under Rate Order No. WAPA-137 for a 5-year period beginning October 1, 2008, and ending September 30, 2013. The Deputy Secretary of Energy approved Rate Order No. WAPA-161 on September 6, 2013, extending the rates through September 30, 2015.
Start Printed Page 53297

Cost Recovery Charge

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

CRC Based on the Tiers Below
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 FY
iiiLess than $120 million but greater than $90 million, with an expected 40-percent decrease in the next FY
ivLess than $90 million but greater than $60 million, with an expected 25-percent decrease in the next FYSemi-annual (May/November).
vLess than $60 million but greater than $40 million with an expected decrease to below $40 million in the next FYMonthly.

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

CRSP Transmission Service Rates

Transmission formula rates, including those for Firm and Non-Firm Point-To-Point Transmission Service and Network Integration Transmission Service, are designed to recover the annual costs of the CRSP Transmission System. The transmission rates include the cost of Scheduling, System Control, and Dispatch Service. Western will continue to bundle CRSP transmission service in the SLCA/IP Power rate.

A penalty for unauthorized use of transmission will now be assessed under a new rate schedule, SP-UU1. Unreserved Use Penalties will include the basic rate for the transmission service used and not reserved plus a penalty equal to 200 percent of the basic rate.

Transmission losses, as posted on the RMR OASIS, are assessed for all real-time and prescheduled transactions on transmission facilities inside the Western Area Colorado Missouri (WACM) balancing authority.

According to DOE Order RA 6120.2, Western is required to recover revenues for investments in the first year following the FY in which the investment goes into commercial service. Adopting the forward-looking methodology to calculate the Annual Transmission Revenue Requirement (ATRR) will allow Western to better recover costs in the FY following occurrence. In addition to annual audited financial data, Western will use projections from the 10-Year Plan, the Budget Year Workplan, and current year-to-date financial data for the annual rate calculation. The 10-Year Plan and the Budget Year Workplan used in the forward-looking calculations are provided to customers at annual customer meetings. This is a change in the manner in which the inputs for the rate are developed, rather than a change to the formula rate itself.

Western will use a true-up procedure to ensure that the actual transmission costs are recovered for that year. When the annual audited financial data is available, Western will calculate the actual ATRR for that year. Western will compare the actual ATRR to the projected ATRR and apply the difference as an adjustment to the ATRR in a subsequent year.

Firm Point-to-Point

The firm point-to-point transmission rate will be based upon annual audited financial data and projections to the end of the current FY, using the annual forward-looking methodology described in the preceding paragraphs. The ATRR, as also described above, will be offset by appropriate revenue credits. The resultant NATRR will be divided by the capacity reserved for firm power and transmission commitments, including the total network integration loads at system peak, to derive a cost/kWyear. Rate Schedules SLIP-F10, SP-PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-RS4, SP-EI4, SP-FR4, SP-SSR4, and SP-UU1 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will be in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded. The cost/kWyear is calculated using the following formula:

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

Where:

ATRR = Annual Transmission Revenue Requirement: The costs associated with facilities that support the transfer capability of the CRSP transmission system, excluding generation facilities. These costs include investment costs, interest expenses, depreciation expense, administrative and general expenses, and operation and maintenance expense, including transmission purchases. Transmission purchases reflect those costs associated with CRSP contractual rights.

TRC = Transmission Revenue Credits: The revenues generated by the CRSP transmission system not related to the revenues from the sale of long-term firm transmission.

NATRR = Net Annual Transmission Revenue Requirement: The Annual Revenue Requirement minus Transmission Revenue Credits.

TSTL = CRSP Transmission System Total Load: The sum of the total CRSP transmission capacity under long-term reservation including the total network integration loads at system peak.

Non-Firm, Point-to-Point Transmission

The provisional rate for non-firm, point-to-point, CRSP transmission service is a mills/kWh rate, which is Start Printed Page 53298based upon the firm point-to-point rate and may be discounted. This rate will be concurrent with the firm, point-to-point rate and will also be reviewed annually. Transmission availability will be posted on Western's OASIS.

Network Transmission

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

Ancillary Services Discussion

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

Certification of Rates

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

SLCA/IP Firm Power Rate Discussion

Pursuant to Reclamation Law, Western must establish power rates sufficient to recover O&M expenses, purchased power expenses, interest expenses, and repayment of power investment and irrigation aid.

The CRSP MC forecasts 5 years of firming purchased power in the PRS using the April, 24-month hydrology study from Reclamation. This 5-year forecast reflects the firming purchase power requirements between projected generation and contract obligations. For the remaining out-years, a forecast of $4 million a year is projected to cover operational costs for the Energy Management and Marketing Office in Montrose, Colorado. Western proposed to add the projected $4 million to the first 5 years based on anticipated annual operational needs beyond firming purchases. Western will not include the addition of the $4 million per year increase at this time and will, consistent with the procedures at 10 CFR part 903, consider whether to refine the purchase power cost estimates.

The current capacity rate and energy rate under Rate Schedule SLIP-F9 remains sufficient to cover OM&R and required repayment. Western will continue to use the existing energy charge of 12.19 mills/kWh and capacity charge of $5.18/kWmonth. However, the composite rate, which is used for comparison purposes only and is not part of the billing component, will decrease from 29.62 to 29.42 mills/kWh. The composite rate is calculated by dividing the average revenue requirement for the ratesetting period by the average energy sales. The change in the composite rate is driven in large part by changes in the average energy sales due to changes in Project Use energy requirements.

Statement of Revenue and Related Expenses

SLCA/IP Firm Power Comparison of 5-Year Rate Period (FY 2016-FY 2020) Total Revenues and Expenses

[$000]

ItemExisting Rate 2010 WorkplanProvisional 2017 WorkplanChange Amount
Ratesetting Period:
Beginning year20102016
Pinchpoint year20252025
Number of ratesetting years1610
Annual Revenue Requirements:
Expenses
Operation and Maintenance:
Western$40,514$52,631$12,117
Reclamation30,09234,5354,443
Total O&M70,60687,16616,560
Purchased Power5,16310,2795,116
Transmission10,52510,421(104)
Integrated Projects requirements7,2868,6111,325
Interest3,6936,1772,484
Other2,98414,58711,603
Total Expenses100,257137,24036,983
Principal payments
Deficits000
Replacements28,65232,0843,432
Original Project and Additions17,9362,232(15,704)
Irrigation38,74412,317(26,427)
Start Printed Page 53299
Total principal payments85,33246,633(38,699)
Total Annual Revenue Requirements:185,589183,873(1,716)
(Less Offsetting Annual Revenue:)
Transmission (firm and non-firm)18,04519,6401,595
Merchant Function8,3099,9181,609
Other7,6875,118(2,569)
Total Offsetting Annual Revenue34,04134,676635
Net Annual Revenue Requirements:151,548149,197(2,351)
Energy Sales5,116,3465,071,804(44,542)
Capacity Sales1,434,9461,407,920(27,026)
Composite Rate (mills/kWh)29.6229.42−.20

Basis for Rate Development

The provisional rates will provide sufficient revenue to pay all annual costs, including interest expense, and repayment of power investment and irrigation aid within the allowable periods. Rate Schedules SLIP-F10, SP-PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-RS4, SP-EI4, SP-FR4, SP-SSR4, and SP-UU1 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will be in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded. Provisions for transformer losses adjustment, power factor adjustment, WRP administrative charge, and CDP administrative charge adjustments are part of the provisional rates for SLCA/IP firm power. Western will not modify the provisions and methodologies for these adjustments, which will remain as specified in Rate Schedule SLIP-F10.

CRSP Transmission Service Discussion

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

Change to Forward-Looking Transmission Rates

Western changed the inputs used to calculate the ATRR to recover transmission expenses and investments on a current basis rather than a historical basis. The change allows Western to more accurately match cost recovery with cost incurrence. Western will use current, year-to-date costs as the basis for projecting the full current year's transmission costs for the upcoming year in the annual rate calculation, rather than using only historical information.

When the actual annual audited financial data are available, Western will calculate the actual revenue requirement for that year. Revenue collected in excess of the actual revenue requirement will be included as a credit in the ATRR in a subsequent year. Similarly, any under-collection of the revenue requirement will be included as a charge in the ATRR in a subsequent year. This true-up procedure will ensure that Western recovers no more and no less than the actual transmission costs for that year.

Unreserved Use Penalties

Unreserved use of the transmission system (Unreserved Use) occurs when a transmission customer uses transmission service that exceeds its reserved capacity or an eligible customer uses transmission service it has not reserved. Western will assess Unreserved Use Penalties against a customer that has not secured reserved capacity or exceeds its reserved capacity at any point of receipt or any point of delivery. Unreserved Use may also be assessed due to a transmission customer's failure to curtail transmission when requested.

A customer that engages in Unreserved Use will be assessed a penalty charge of 200 percent of the CRSP transmission service rate for Firm Point-to-Point Transmission Service as follows:

1. The Unreserved Use penalty for a single hour of Unreserved Use will be based upon the rate for daily Firm Point-to-Point Service.

2. The Unreserved Use penalty for more than one assessment for a given duration (e.g., daily) will increase to the next longest duration (e.g., weekly).

3. The Unreserved Use penalty charge for multiple instances of Unreserved Use (e.g., more than one hour) within a day will be based on the rate for daily Firm Point-to-Point Service. Multiple instances of Unreserved Use isolated to 1 calendar week will result in a penalty based on the charge for weekly Firm Point-to-Point Service. The penalty charge for multiple instances of Unreserved Use during more than 1 week during a calendar month will be based on the charge for monthly Firm Point-to-Point Service.

A transmission customer that exceeds its firm reserved capacity at any point of receipt or point of delivery or an eligible customer that uses transmission service at a point of receipt or point of delivery that it has not reserved will be required to pay, in addition to the Unreserved Use Penalties, for all applicable Ancillary Services identified in Western's Tariff based on the amount of transmission service it used and did not reserve.

Unreserved Use Penalties collected will be included as a credit in the calculation of the ATRR in a subsequent year.Start Printed Page 53300

Comments

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

1. Purchased Power Component

Comment: Many customers commented that Western should, in consultation with customers, refine the purchased-power, cost-estimating tools, rather than adopting the proposed methodology.

Response: Western will not add $4 million to the first 5 years of purchased power projections to meet the operational contingencies of the Energy Management and Marketing Office in Montrose, Colorado. Consistent with the procedures at 10 CFR part 903, Western will consider whether to refine the purchase power cost estimation.

2. Transmission and Ancillary Services

Comment: Several commenters expressed concerns about Western changing to a forward-looking transmission rate methodology, stating Western has no data to show the historical method of using actual data from 2 years prior is insufficient in collecting adequate revenues.

Response: Western appreciates the customers' concerns. The change allows Western to more accurately match cost recovery with cost incurrence. Western will use current, year-to-date costs in addition to a review of the Construction Work in Progress financial report and the 10-Year Capital Plan by the CRSP MC as the basis for projecting the full, current year's transmission costs for the upcoming year in the annual rate calculation, rather than using only historical information. The method is a change in the manner in which the inputs for the rate are developed, rather than a change to the formula rate itself.

Comment: A commenter raised concern about how the forecast and true-up information would interface and be consistent with the work program review and asset management processes.

Response: The data sources, which will be used for the transmission cost projections, are reviewed annually at the 10-Year Capital Plan customer meeting prior to the annual rate calculation. In addition to these current year financial data, coupled with a mid-year review by the CRSP MC of which investments should be completed by the end of the current FY, will ensure that the most accurate projections will be used in the annual transmission rate recalculation. The true-up process is independent of the work program review and asset management process.

Comment: Some commenters stated that the additional labor for Western associated with the forward-looking methodology would also likely create additional burden on the customers.

Response: Western's staff appreciates and understands the customers' concern, but does not foresee any burden to the customer in this process. Western's staff prepared a parallel transmission rate recalculation for the FY 2014 rate using the forward-looking methodology, and this required only 8 hours of additional labor to process the true-up to actuals from the previous FY projections. Western believes the impact on the workload will be negligible.

Comment: A commenter expressed concern that the forward-looking methodology may result in an over-collection of funds from the SLIP customers.

Response: Western will true-up the estimates with actual costs and loads at the end of each FY. Revenue collected in excess of Western's actual net revenue requirement will be returned through a credit adjustment to the ATRR in a subsequent year. Actual revenues that are less than the net revenue requirement will be recovered through an adjustment to the ATRR in a subsequent year. The true-up procedure will ensure that Western will recover no more and no less than the actual costs for the year from the SLIP customers.

3. Unreserved Use Charge

Comment: A commenter stated “There is insufficient due process afforded a customer if Western adopts a change to terms and conditions for transmission service in the context of a rate proposal.”

Response: The public process followed in implementing this new rate schedule for an Unreserved Use Charge affords transmission customers adequate opportunity to comment on the proposed penalty.

4. Firm Electric Service Rate Adjustment

Comment: Many comments were received expressing a concern that the SLIP-F9 rate is sufficient to pay all required costs and should not be adjusted at this time.

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

5. Cost Recovery Charge (CRC)

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

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

6. Miscellaneous

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

Response: Western appreciates the customers' support.

Availability of Information

Information about this rate adjustment, including PRSs, comments, letters, memorandums, and other supporting material made or kept by Western and used to develop the provisional rates, is available for public review at the Colorado River Storage Project Management Center, Western Area Power Administration, 150 East Social Hall Avenue, Suite 300, Salt Lake City, Utah, or at Western's Web page: Start Printed Page 53301 https://www.wapa.gov/​regions/​CRSP/​rates/​Pages/​rate-order-169.aspx.

RATEMAKING PROCEDURE REQUIREMENTS

Environmental Compliance

In compliance with the National Environmental Policy Act (NEPA) of 1969 (42 U.S.C. 4321, et seq.), Council on Environmental Quality Regulations (40 CFR parts 1500-1508), and DOE NEPA Regulations (10 CFR part 1021), Western has determined that this action is categorically excluded from preparing an environmental assessment or an environmental impact statement. A copy of the categorical exclusion determination is posted at the CRSP MC Web page, https://www.wapa.gov/​regions/​CRSP/​rates/​Pages/​rate-order-169.aspx.

Determination Under Executive Order 12866

Western has an exemption from centralized regulatory review under Executive Order 12866; accordingly, no clearance of this notice by the Office of Management and Budget is required.

Submission to the Federal Energy Regulatory Commission

The interim rates herein confirmed, approved, and placed into effect, together with supporting documents will be submitted to FERC for confirmation and final approval.

ORDER

In view of the foregoing and under the authority delegated to me, I confirm and approve on an interim basis Rate Schedules SLIP-F10, SP-PTP8, SP-NW4, SP-NFT7, SP-SD4, SP-RS4, SP-EI4, SP-FR4, SP-SSR4, and SP-UU1 to become effective on the first day of the first full-billing period beginning on or after October 1, 2015, and will remain in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Dated: August 28, 2015.

Elizabeth Sherwood-Randall,

Deputy Secretary of Energy.

Rate Schedule SLIP-F10

(Supersedes Schedule SLIP-F9)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

SALT LAKE CITY AREA INTEGRATED PROJECTS

SCHEDULE OF RATES FOR FIRM POWER SERVICE

(Approved Under Rate Order No. WAPA-169)

Effective:

Rate Schedule SLIP-F10 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will remain in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Available:

In the area served by the Salt Lake City Area Integrated Projects.

Applicable:

To the wholesale power customer for firm power service supplied through one meter at one point of delivery or as otherwise established by contract.

Character:

Alternating current, 60 hertz, three-phase, delivered and metered at the voltages and points established by contract.

Monthly Rate:

DEMAND CHARGE: $5.18 per kilowatt of billing demand.

ENERGY CHARGE: 12.19 mills per kilowatthour of use.

COST RECOVERY CHARGE:

To adequately recover and maintain a sufficient balance in the Basin Fund, Western uses a cost recovery mechanism, called a Cost Recovery Charge (CRC). The CRC is a charge on all SHP energy.

This charge will be recalculated before May 1 of each year, and Western will provide notification to the customers. The charge, if needed, will be placed into effect on the first day of the first full-billing period beginning on or after October 1, 2015, through September 30, 2020. If a Shortage Criteria is necessary, the CRC will be re-calculated at that time. (See Shortage Criteria Trigger explanation below.) The CRC will be calculated as follows:

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

Table—CRC Tiers

TierCriteria, If the BFBB is:Review
iGreater than $150 million, with an expected decrease to below $75 million
iiLess than $150 million but greater than $120 million, with an expected 50-percent decrease in the next FYAnnually.
iiiLess than $120 million but greater than $90 million, with an expected 40-percent decrease in the next FY
ivLess than $90 million but greater than $60 million, with an expected 25-percent decrease in the next FYSemi-Annual (May/November).
vLess than $60 million but greater than $40 million with an expected decrease to below $40 million in the next FYMonthly.

Table—Sample CRC Calculation

DescriptionExampleFormula
STEP ONEDetermine the Net Balance available in the Basin Fund.
BFBBBasin Fund Beginning Balance ($)$85,860,265Financial forecast.
BFTBBasin Fund Target Balance ($)$64,395,199BFBB − (Tier % * BFBB), or BFTB for Tier i and Tier v 1.
PARProjected Annual Revenue ($) w/o CRC$232,780,000Financial forecast.
PAEProjected Annual Expenses ($)$226,649,066Financial forecast.
Start Printed Page 53302
NRNet Revenue ($)$6,130,934PAR − PAE.
NBNet Balance ($)$91,991,199BFBB + NR.
STEP TWODetermine the Forecasted Energy Purchase Expenses.
EASHP Energy Allocation (GWh)4,952Customer contracts.
HEForecasted Hydro Energy (GWh)4,924Hydrologic & generation forecast.
FEForecasted Energy Purchase (GWh)504EA − HE or anticipated.
FFCForecasted Average Energy Price per MWh ($)$34.23From commercially available price indices.
FXForecasted Energy Purchase Expense ($)$17,262,512FE * FFC *1000.
STEP THREEDetermine the amount of Funds Available for firming energy purchases, and then determine additional revenue to be recovered. The following two formulas will be used to determine FA; the lesser of the two will be used.
FA1Basin Fund Balance Factor ($)$17,262,512If (NB > BFBB, FX, FX − (BFTB − NB)).
FA2Revenue Factor ($)$17,262,512If (NR > − (BFBB − BFTB), FX, FX + NR + (BFBB − BFTB)).
FAFunds Available ($)$17,262,512Lesser of FA1 or FA2 (not less than $0).
FARRAdditional Revenue to be Recovered ($)$0FX − FA.
STEP FOUROnce the FA for purchases have been determined, the CRC can be calculated, and the WL can be determined.
WLWaiver Level (GWh)5428If (EA < HE, EA, HE + (FE * (FA/FX))), but not less than HE.
WLPWaiver Level Percentage of Full SHP110%WL/EA * 100.
CRCECRC Energy (GWh)0EA − WL.
CRCEPCRC Energy Percentage of Full SHP0%CRCE/EA * 100.
CRCCost Recovery Charge (mills/kWh)0FARR/(EA * 1,000).
Notes: 1—Use CRC Tiers Table to calculate applicable value.

Narrative CRC Example

STEP ONE: Determine the net balance available in the Basin Fund.

BFBB—Western will forecast the Basin Fund Beginning Balance for the next FY.

BFBB = $85,860,265

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

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

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

PAR = $232,780,000

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

PAE = $226,649,066

NR—Net Revenue equals revenues minus expenses.

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

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

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

STEP TWO: Determine the forecasted energy purchases expenses.

EA—The Sustainable Hydro Power Energy Allocation (from Customer contracts). This does not include Project Use customers.

EA = 4,952 (GWh)

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

HE = 4,924 (GWh)

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

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

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

FFC = $34.23 per MWh

Start Printed Page 53303

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

FX = FE * FFC * 1000 = 504.33 * $34.23 * 1000 = $17,263,215.90

STEP THREE: Determine the amount of Funds Available (FA) to expend on firming energy purchases and then determine additional revenue to be recovered (FARR). The following two formulas will be used to determine FA; the lesser of the two will be used. Funds available shall not be less than zero.

A. Basin Fund Balance Factor (FA1)

If the Net Balance is greater than the Basin Fund Target Balance, use the value for forecasted energy purchase power expenses (FX). If the net balance is less than the Basin Fund Target Balance, reduce the value of the Forecasted Energy Purchase Power Expenses by the difference between the Basin Fund Target Balance and the Net Balance.

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

= $91,991,199 (NB) is greater than $64,395,199 (BFTB) then:

= $17,263,215.90 (FX)

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

If the Net Balance is less than the Basin Fund Target Balance, then FA1 = FX − (BFTB − NB).

B. Basin Fund Revenue Factor (FA2)

The second factor ensures that Western collects sufficient funds to meet the Basin Fund Target Balance so long as the amount needed does not exceed the forecasted purchase expense (FX):

In the situation when there is no projected revenue:

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

= $6,130,934(NR) is greater than ($21,464,066) then:

= $17,263,215.90 (FX)

If the Net Revenue (loss) value does not result in a loss that exceeds the allowable decrease value of the Basin Fund Beginning Balance ( − (BFBB − BFTB)), then FA2 = FX.

If the Net Revenue (loss) results in a loss that exceeds the allowable decrease value of the Basin Fund Beginning Balance ( − (BFBB − BFTB)), then FX + NR + (BFBB − BFTB).

FA—Determine the funds available for purchasing firming energy by using the lesser of FA1 and FA2.

FA1 and FA2 are equal, so:

FA = $17,263,215.90 (FX)

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

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

STEP FOUR: Once the funds available for purchases have been determined, the CRC can be calculated and the Waiver Level (WL) can be determined.

A. Cost Recovery Charge: The CRC will be a charge to recover the additional revenue required as calculated in Step 3. The CRC will apply to all customers who choose not to request a waiver of the CRC, as discussed below. The CRC equals the additional revenue to be recovered divided by the total energy allocation to all customers for the FY.

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

B. Waiver Level (WL): Western will establish an energy WL that provides Western the ability to reduce purchase power expenses by scheduling less energy than what is contractually required. Therefore, for those customers who voluntarily schedule no more energy than their proportionate share of the WL, Western will waive the CRC for that year.

After the Funds Available has been determined, the WL will be set at the sum of the energy that can be provided through hydro generation and purchased with Funds Available. The WL will not be less than the forecasted Hydro Energy.

WL = If (EA < HE, EA, HE + (FE * (FA/FX))

= 4,952 (EA) is not less than 4,924 (HE) then:

= 4,924 (HE) + (504.33 (FE) * ($17,263,215.90 (FA)/$17,263,215.90 (FX)) = 5,428 (GWh) is the Waiver Level

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

If SHP Energy Allocation is greater than the forecasted Hydro Energy available, then

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

PRIOR YEAR ADJUSTMENT:

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

PYA CALCULATION

DescriptionFormula
STEP ONEDetermine actual expenses and purchases for previous year's firming. This data will be obtained from Western's financial statements at the end of the FY.
PFXPrior Year Actual Firming Expenses ($)Financial Statements.
PFEPrior Year Actual Firming Energy (GWh)Financial Statements.
STEP TWODetermine the actual firming cost for the CRC portion.
EACSum of the energy allocations of customers subject to the PYA (GWh)
FFCForecasted Firming Energy Cost—($/MWh)From CRC Calculation.
AFCActual Firming Energy Cost—($/MWh)PFX/PFE.
CRCEPCRC Energy PercentageFrom CRC Calculation.
CRCEPurchased Energy for the CRC (GWh)EAC * CRCEP.
STEP THREEDetermine Revenue Adjustment (RA) and PYA.
RARevenue Adjustment ($)(AFC-FFC) * CRCE * 1,000.
Start Printed Page 53304
PYAPrior Year Adjustment (mills/kWh)(RA/EAC)/1,000.

Narrative PYA Calculation

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

PFX—Prior year actual firming expense

PFE—Prior year actual firming energy

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

EAC—Sum of the energy allocations of customers subject to the PYA

CRCE—The amount of CRC Energy needed

AFC—The Actual Firming Energy Cost are the PFX divided by the PFE

AFC = (PFX/PFE)/1,000

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

RA—The Revenue Adjustment is AFC less FFC times CRCE

RA = (AFC − FFC) * CRCE) * 1,000

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

PYA = (RA/EAC)/1,000

The customer's PYA will be based on its prior year's energy multiplied by the resulting mills/kWh to determine the dollar amount that will be assessed. The customers will be charged or credited for this dollar amount equally in the remaining months of the next year's billing cycle. Western will attempt to complete this calculation by December of each year. Therefore, if the PYA is calculated in December, the charge/credit will be spread over the remaining 9 months of the FY (January through September).

Shortage Criteria Trigger:

In the event that Reclamation's 24-month study projects that Glen Canyon Dam water releases will drop below 8.23 MAF in a water year (October through September), Western will recalculate the CRC to include those lower estimates of hydropower generation and the estimated costs for the additional purchase power necessary. Western, as in the yearly projection for the CRC, will give the customers a 45-day notice to request a waiver of the CRC, if they do not want to have the CRC charge added to their energy bill. This recalculation will remain in effect for the remainder of the current FY.

In the event that hydropower generation returns to an 8.23 MAF or higher during the trigger implementation, a new CRC will be calculated for the next month, and the customers will be notified.

CRC Schedule for customers

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

CRC Schedule

TaskRespective dates under Table CRC tiers1
i, ii, and iiiiv2v3
24-Month Study (Forecast to Model Projections)April 1April 1 October 1Monthly Study.
CRC Notice to CustomersMay 1May 1 November 1Monthly.
Waiver Request Submitted by CustomersJune 15Within 45 daysWithin 30 days.
CRC EffectiveOctober 1August 1 February 1Updated Monthly.
Notes:
1 This schedule does not apply if the CRC is triggered by the Glen Canyon Dam annual releases dropping below 8.23 MAF.
2 If it is determined during the additional reviews, under tier iv, that a CRC is necessary, customers will be notified that a CRC will be implemented in 90 days. Western will provide its customers with information concerning the anticipated CRC and give them 45 days to request a waiver or accept the CRC. The established CRC will be in effect for 12 months from the date implemented unless superseded by another CRC.
3 If it is determined during the additional reviews, under tier v, that a CRC is necessary, customers will be notified that a CRC will be implemented in 60 days. Western will provide its customers with information concerning the anticipated CRC and give them 30 days to request a waiver or accept the CRC. The established CRC will be in effect for 12 months from the date implemented unless superseded by another CRC.

Billing Demand:

The billing demand will be the greater of:

1. The highest 30-minute integrated demand measured during the month up to, but not more than, the delivery obligation under the power sales contract, or

2. The Contract Rate of Delivery.

Billing Energy:

The billing energy will be the energy measured during the month up to, but not more than, the delivery obligation under the power sales contract.

Adjustment for Waiver:

Customers can choose not to take the full SHP energy supplied as determined in the attached formulas for CRC and will be billed the Energy and Capacity rates listed above, but not the CRC.

Adjustment for Transformer Losses:

If delivery is made at transmission voltage but metered on the low-voltage side of the substation, the meter readings will be increased to compensate for transformer losses as provided in the contract.

Adjustment for Power Factor:

The customer will be required to maintain a power factor at all points of measurement between 95 percent lagging and 95 percent leading.

Adjustment for Western Replacement Power:

Pursuant to the contractor's Firm Electric Service Contract, as amended, Start Printed Page 53305Western will bill the contractor for its proportionate share of the costs of Western Replacement Power (WRP) within a given time period. Western will include in the contractor's monthly power bill the cost of the WRP and the incremental administrative costs associated with WRP.

Adjustment for Customer Displacement Power Administrative Charges:

Western will include in the contractor's regular monthly power bill the incremental administrative costs associated with Customer Displacement Power.

Rate Schedule SP-NW4

ATTACHMENT H to Tariff

(Supersedes Schedule SP-NW3)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

NETWORK INTEGRATION TRANSMISSION SERVICE

(Approved Under Rate Order No. WAPA-169)

Effective:

Rate Schedule SP-NW4 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will remain in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Applicable:

The transmission customer will compensate the Colorado River Storage Project Management Center each month for Network Integration Transmission Service under the applicable Network Integration Transmission Service Agreement and the formula rate described herein.

A recalculated Annual Transmission Revenue Requirement for Network Integration Transmission Service will go into effect every October 1 based on the above formula and updated financial and operational data. Western will notify the transmission customer annually of the recalculated annual revenue requirement on or before September 1.

Billing:

Billing determinants for the formula rate above will be as specified in the service agreement. Billing will occur monthly under the formula rate.

Adjustment for Losses:

Losses incurred for service under this rate schedule will be accounted as agreed to by the parties in accordance with the service agreement. If losses are not fully provided by a transmission customer, charges for financial compensation may apply.

Rate Schedule SP-SD4

SCHEDULE 1 to Tariff

(Supersedes Schedule SP-SD3)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

SCHEDULING, SYSTEM CONTROL, AND DISPATCH SERVICE

(Approved Under Rate Order No. WAPA-169)

Effective:

Rate Schedule SP-SD4 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will remain in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Applicable:

Scheduling, System Control, and Dispatch service is required to schedule the movement of power through, out of, within, or into a control area. The transmission customer must purchase this service from the transmission provider. The charges for this service will be included in the CRSP transmission service rates.

Formula Rate:

Provided through the Western Area Colorado Missouri (WACM) Balancing Authority under Rate Schedule L-AS1, or as superseded.

Rate Schedule SP-RS4

SCHEDULE 2 to Tariff

(Supersedes Schedule SP-RS3)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

REACTIVE SUPPLY AND VOLTAGE CONTROL FROM GENERATION AND OTHER SOURCES SERVICE

(Approved Under Rate Order No. WAPA-169)

Effective:

Rate Schedule SP-RS4 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will remain in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Applicable:

To all CRSP transmission customers receiving this service.

Formula Rate:

Provided through the Western Area Colorado Missouri (WACM) Balancing Authority under Rate Schedule L-AS2, or as superseded.

Rate Schedule SP-FR4

SCHEDULE 3 to Tariff

(Supersedes Schedule SP-FR3)Start Printed Page 53306

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

REGULATION AND FREQUENCY RESPONSE SERVICE

(Approved Under Rate Order No. WAPA-169)

Effective:

Rate Schedule SP-FR4 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will remain in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Applicable:

To all CRSP customers receiving this service.

Formula Rate:

Provided through the Western Area Colorado Missouri (WACM) Balancing Authority under Rate Schedule L-AS3 or as superseded. If the CRSP MC has regulation available for sale from Salt Lake City Area Integrated Projects resources, the rate will be calculated using the formula below.

Rate Schedule SP-EI4

SCHEDULE 4 to Tariff

(Supersedes Schedule SP-EI3)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

ENERGY IMBALANCE SERVICE

(Approved Under Rate Order No. WAPA-169)

Effective:

Rate Schedule SP-EI4 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will remain in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Applicable:

To all CRSP transmission customers receiving this service.

Formula Rates:

Provided through the Western Area Colorado Missouri (WACM) Balancing Authority under Rate Schedule L-AS4, or as superseded.

Rate Schedule SP-SSR4

SCHEDULES 5 & 6 TO TARIFF

(Supersedes Schedule SP-SSR3)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

OPERATING RESERVES—SPINNING AND SUPPLEMENTAL RESERVE SERVICES

(Approved Under Rate Order No. WAPA-169)

Effective:

Rate Schedule SP-SSR4 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will remain in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Applicable:

To all CRSP transmission customers receiving this service.

Character of Service:

Spinning Reserve is defined in Schedule 5 of Western Area Power Administration's Open Access Transmission Tariff.

Supplemental Reserve is defined in Schedule 6 of Western Area Power Administration's Open Access Transmission Tariff.

Formula Rate:

The transmission customer serving loads within the transmission provider's balancing authority must acquire Spinning and Supplemental Reserve services from CRSP, from a third party, or by self-supply.

Rate Schedule SP-PTP8

SCHEDULE 7 to Tariff

(Supersedes Schedule SP-PTP7)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

FIRM POINT-TO-POINT TRANSMISSION SERVICE

(Approved Under Rate Order No. WAPA-169)

Effective:

Rate Schedule SP-PTP8 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will remain in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Applicable:

The transmission customer will compensate the Colorado River Storage Project each month for Reserved Capacity under the applicable Firm Point-To-Point Transmission Service Agreement and the formula rate described herein.

Start Printed Page 53307

A recalculated rate will go into effect every October 1 based on the above formula and updated financial and operational data. Western will notify the transmission customer annually of the recalculated rate on or before September 1. Discounts may be offered from time-to-time in accordance with Western's Open Access Transmission Tariff.

Billing:

The formula rate above applies to the maximum amount of capacity reserved for periods ranging from 1 hour to 1 month, payable whether used or not. Billing will occur monthly.

Adjustment for Losses:

Losses incurred for service under this rate schedule will be accounted for as agreed to by the parties in accordance with the service agreement. If losses are not fully provided by a transmission customer, charges for financial compensation may apply.

Rate Schedule SP-NFT7

SCHEDULE 8 to Tariff

(Supersedes Schedule SP-NFT6)

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE

(Approved Under Rate Order No. WAPA-169)

Effective:

Rate Schedule SP-NFT7 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will remain in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Applicable:

The transmission customer will compensate the Colorado River Storage Project each month for Non-Firm, Point-to-Point Transmission Service under the applicable Non-Firm, Point-to-Point Transmission Service Agreement and the formula rate described herein.

Formula Rate:

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

A recalculated rate will go into effect every October 1 based on the above formula and updated financial and load data. Western will notify the transmission customer annually of the recalculated rate on or before September 1. Discounts may be offered from time-to-time in accordance with Western's Open Access Transmission Tariff.

Billing:

The formula rate above applies to the maximum amount of capacity reserved for periods ranging from 1 hour to 1 month, payable whether used or not. Billing will occur monthly.

Adjustment for Losses:

Power and energy losses incurred in connection with the transmission and delivery of power and energy under this rate schedule shall be supplied by the customer in accordance with the service contract. If losses are not fully provided by a transmission customer, charges for financial compensation may apply.

Rate Schedule SP-UU1

SCHEDULE 10 to Tariff

UNITED STATES DEPARTMENT OF ENERGY

WESTERN AREA POWER ADMINISTRATION

COLORADO RIVER STORAGE PROJECT MANAGEMENT CENTER

COLORADO RIVER STORAGE PROJECT

UNRESERVED USE PENALTIES

(Approved Under Rate Order No. WAPA-169)

Effective:

Rate Schedule SP-UU1 will be placed into effect on an interim basis on the first day of the first full-billing period beginning on or after October 1, 2015, and will remain in effect until FERC confirms, approves, and places the rate schedules in effect on a final basis through September 30, 2020, or until the rate schedules are superseded.

Applicable:

The transmission customer shall compensate the Colorado River Storage Project (CRSP) each month for any unreserved use of the transmission system (Unreserved Use) under the applicable transmission service rates as outlined herein. Unreserved Use occurs when an eligible customer uses transmission service that it has not reserved or a transmission customer uses transmission service in excess of its reserved capacity. Unreserved Use may also include a customer's failure to curtail transmission when requested.

Penalty Rate:

The penalty rate for a transmission customer that engages in Unreserved Use is 200 percent of CRSP's approved transmission service rate for point-to-point (PTP) transmission service assessed as follows:

(i) The Unreserved Use Penalty for a single hour of Unreserved Use is based upon the rate for daily firm PTP service.

(ii) The Unreserved Use Penalty for more than one assessment for a given duration (e.g., daily) increases to the next longest duration (e.g., weekly).

(iii) The Unreserved Use Penalty for multiple instances of Unreserved Use (e.g., more than 1 hour) within a day is based on the rate for daily firm PTP service. The Unreserved Use Penalty charge for multiple instances of Unreserved Use isolated to 1 calendar week would result in a penalty based on the rate for weekly firm PTP service. The Unreserved Use Penalty charge for multiple instances of Unreserved Use during more than 1 week in a calendar month will be based on the rate for monthly firm PTP service.

A transmission customer that exceeds its firm reserved capacity at any point of receipt or point of delivery or an eligible customer that uses transmission service at a point of receipt or point of delivery that it has not reserved is required to pay for all ancillary services identified in Western's Open Access Transmission Tariff that were provided by the CRSP and associated with the Unreserved Use. The customer will pay for ancillary services based on the amount of transmission service it used and did not reserve.

Rate:

The rate for Unreserved Use Penalties is 200 percent of Western's approved rate for firm point-to-point transmission service assessed as described above. Any change to the rate for Unreserved Use Penalties will be listed in a revision to this rate schedule issued under applicable Federal laws and policies Start Printed Page 53308and made part of the applicable service agreement.

End Supplemental Information

Footnotes

1.  FERC confirmed and approved Rate Order No. WAPA-137 on June 19, 2009, in Docket EF08-5171. See United States Department of Energy, Western Area Power Administration, Salt Lake City Area Integrated Projects, 127 FERC ¶ 62,220 (June 19, 2009).

Back to Citation

2.  Rate Order No. WAPA-161, approved by the Deputy Secretary of Energy on September 6, 2013 (78 FR 56692, September 13, 2013), and filed with FERC for informational purposes only.

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

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[FR Doc. 2015-21904 Filed 9-2-15; 8:45 am]

BILLING CODE 6450-01-P