Daily Rules, Proposed Rules, and Notices of the Federal Government
The Pacific Northwest Electric Power Planning and Conservation Act (Northwest Power Act) provides that BPA must establish and periodically review and revise its rates so that they recover, in accordance with sound business principles, the costs associated with the acquisition, conservation, and transmission of electric power, including amortization of the Federal investment in the Federal Columbia River Power System (FCRPS) over a reasonable number of years and BPA's other costs and expenses. The Northwest Power Act also requires that BPA's rates be established based on the record of a formal hearing, and for transmission rates only, that the costs of the Federal transmission system be equitably allocated between Federal and non-Federal power utilizing the system. By this notice, BPA announces the commencement of a power and transmission rate adjustment proceeding for power, transmission, control area services, and ancillary services rates proposed to be effective on October 1, 2013.
Written comments by non-party participants must be received by February 15, 2013, to be considered in the Administrator's Record of Decision (ROD).
1. Petitions to intervene should be directed to: Hearing Clerk--L-7, Bonneville Power Administration, 905 NE 11th Avenue, Portland, Oregon 97232, or may be emailed to
2. Written comments by participants should be submitted to the Public Engagement Office, DKE-7, Bonneville Power Administration, P.O. Box 14428, Portland, Oregon 97293. Participants may also submit comments by email at:
Section 7(i) of the Northwest Power Act, 16 U.S.C. 839e(i), requires that BPA's rates be established according to certain procedures, including publication in the
This proceeding is being conducted under the rule for general rate proceedings, section 1010.4 of BPA's Procedures. A proposed schedule for the proceeding is provided below. A final schedule will be established by the Hearing Officer at the prehearing conference.
Section 1010.7 of BPA's Procedures prohibits
BPA is holding one power and transmission rate proceeding with one procedural schedule, one record, and one ROD.
BPA began its 2012 Integrated Program Review (IPR) process in June 2012. The IPR process is designed to allow persons interested in BPA's program levels an opportunity to review and comment on BPA's expense and capital spending level estimates prior to the use of those estimates in setting rates.
The 2012 IPR focused on FY 2014 and FY 2015 program levels for BPA's Power Services and Transmission Services as well as a review of FY 2013 program levels. After the opening workshop on June 5 and release of information, participants were allowed three weeks to request specific workshops. Participants requested additional information through the end of July 2012. BPA responded to participants' requests for additional information and held two days of technical workshops through July 18, 2012. BPA took public comment through August 10, 2012.
Between March and April 2012, prior to the initiation of the IPR, BPA hosted the 2012 Capital Investment Review (CIR), a new public process focused on reviewing and discussing draft asset strategies and 10-year capital forecasts. Public comments received during the CIR informed capital cost projections for FY 2014-2015 in the 2012 IPR.
On October 26, 2012, BPA issued the Final Close-Out Report for the IPR. In the Final Close-Out Report, BPA established the program level cost estimates that are used in the Initial Proposal to establish both the power and transmission rates. BPA does not anticipate additional public review of proposed spending levels. However, BPA is open to revisiting spending levels in an “IPR-2” process if conditions in FY 2013 warrant it. BPA would conduct this process separately from the rate proceeding to share updates and solicit feedback from customers and constituents before the final program levels are incorporated into the final rates.
In preparation for the BP-14 rate proceeding, BPA held several public pre-rate case workshops with customers and interested parties from March through early October 2012. During the workshops, BPA staff presented and discussed information about costs, load and resource forecasting, generation inputs pricing, segmentation, cost allocation, redispatch, utility delivery, Montana Intertie, revenue forecasts, load forecasts, risk analysis and mitigation, products, pricing, and rate design. Customers and interested parties had extensive opportunity to participate, raise issues, present alternative proposals, and comment on the information BPA staff presented. The comments and alternative proposals received during these workshops have assisted in the preparation of the Initial Proposal.
This section provides guidance to the Hearing Officer as to those matters that are within the scope of the rate proceeding and those that are outside the scope.
Some of the decisions that determine program costs and spending levels have been made in the IPR public review process outside the rate proceeding. See section II.B. BPA's spending levels for investments and expenses are not determined or subject to review in rate proceedings.
Pursuant to section 1010.3(f) of BPA's Procedures, the Administrator directs the Hearing Officer to exclude from the record all argument, testimony, or other evidence that challenges the appropriateness or reasonableness of the Administrator's decisions on cost and spending levels. If, and to the extent that, any re-examination of spending levels is necessary, such re-examination will occur outside of the rate proceeding. This exclusion does not extend to those portions of the revenue requirements related to interest rate forecasts, interest expense and credit, Treasury repayment schedules, forecasts of depreciation and amortization expense, forecasts of system replacements used in repayment studies, Residential Exchange Program benefits, purchased power expenses, transmission acquisition expense incurred by Power Services, generation acquisition expense incurred by Transmission Services, minimum required net revenue, and the costs of risk mitigation actions resulting from the expense and revenue uncertainties included in the risk analysis. The Administrator also directs the Hearing Officer to exclude argument and evidence regarding BPA's debt management practices and policies. See section II.D.5.
The TRM restricts BPA and customers with Contract High Water Mark (CHWM) contracts from proposing changes to the TRM's ratesetting guidelines unless certain procedures have been successfully concluded. No proposed changes have been subjected to the required procedures.
Pursuant to § 1010.3(f) of BPA's Procedures, the Administrator hereby directs the Hearing Officer to exclude from the record all argument, testimony,
The manner and method by which BPA provides service to its DSI customers was recently addressed in the
Pursuant to § 1010.3(f) of BPA's Procedures, the Administrator directs the Hearing Officer to exclude from the record all argument, testimony, or other evidence that seeks in any way to revisit the appropriateness or reasonableness of BPA's decisions regarding service to the DSIs, including BPA's decision to offer contracts to the DSIs and the method or level of service.
BPA provides a portion of the available generation from the FCRPS to enable Transmission Services to meet its various requirements. Transmission Services uses these generation inputs to provide ancillary and control area services. To recover the costs associated with providing generation inputs, BPA determines prices for the generation inputs that become the basis of the reserves-based ancillary and control area services. The forecast amount of generation inputs, the pricing methodologies BPA is proposing to use to determine the generation input costs, and associated proposed Ancillary and Control Area Service rates are matters that are included within the scope of the BP-14 proceeding.
Pursuant to § 1010.3(f) of BPA's Procedures, the Administrator directs the Hearing Officer to exclude from the record all argument, testimony, or other evidence that seeks in any way to revisit the appropriateness or reasonableness of any other issues related to the generation inputs or Ancillary and Control Area Services. This exclusion includes, but is not limited to, issues regarding reliability of the transmission system, dispatcher standing orders, e-Tag requirements and definitions, open acess transmission tariff provisions, and business practices. These non-rates issues are generally addressed by BPA in accordance with industry, reliability, and other compliance standards and criteria and are not matters appropriate for the rate proceeding.
During the 2012 IPR and in other forums, BPA provided the public with background information on BPA's internal Federal and non-Federal debt management policies and practices. While these policies and practices are not decided in the IPR forum, these discussions were intended to inform interested parties about these matters so that they would better understand BPA's debt structure. BPA's debt management policies and practices remain outside the scope of the rate proceeding.
Pursuant to § 1010.3(f) of BPA's Procedures, the Administrator hereby directs the Hearing Officer to exclude from the record all argument, testimony, or other evidence that seeks in any way to address the appropriateness or reasonableness of BPA's debt management policies and practices. This exclusion does not encompass how debt management actions are reflected in ratemaking.
Environmental impacts are addressed in a concurrent National Environmental Policy Act (NEPA) process. See section II.E.
Pursuant to § 1010.3(f) of BPA's Procedures, the Administrator directs the Hearing Officer to exclude from the record all argument, testimony, or other evidence that seeks in any way to address the potential environmental impacts of the rates being developed in this rate proceeding.
Section 5(c) of the Northwest Power Act established the Residential Exchange Program, which provides benefits to residential and small-farm consumers of Pacific Northwest utilities based, in part, on a utility's “average system cost” (ASC) of resources. Section 5(c)(7) of the Act requires the Administrator to consult with regional interests to develop an ASC Methodology (ASCM), which prescribes the methodology that the Administrator uses to calculate a utility's ASC. On September 4, 2009, the Federal Energy Regulatory Commission (Commission) granted final approval of BPA's 2008 ASCM. The 2008 ASCM is not subject to challenge or review in a section 7(i) proceeding. Determinations of the ASCs of participating utilities are made in separate processes conducted pursuant to the ASCM. Those processes began with ASC filings on June 1, 2012, and are continuing through July 2013. The determinations of ASCs are not subject to challenge or review in a section 7(i) proceeding.
Pursuant to § 1010.3(f) of BPA's Procedures, the Administrator hereby directs the Hearing Officer to exclude from the record all argument, testimony, or other evidence that seeks in any way to visit or revisit the appropriateness or reasonableness of the 2008 ASCM. The Administrator also directs the Hearing Officer to exclude from the record all argument, testimony, or other evidence that seeks in any way to visit or revisit the appropriateness or reasonableness of any of the ongoing ASC determinations.
Under the Tiered Rate Methodology (TRM), BPA has established FY 2014-2015 RHWMs for Public customers that signed contracts for firm requirements power service providing for tiered rates, referred to as CHWM contracts. In this RHWM Process, which preceded the BP-14 rate proceeding, BPA established the maximum planned amount of power a customer is eligible to purchase at Tier 1 rates during the rate period, the Above-RHWM Loads for each customer, the System Shaped Load for each customer, the Tier 1 System Firm Critical Output, RHWM Augmentation, the Rate Period Tier 1 System Capability (RT1SC), and the monthly/diurnal shape of RT1SC. The RHWM Process provided customers an opportunity to review, comment, and, if necessary, challenge BPA's determinations
Pursuant to § 1010.3(f) of BPA's Procedures, the Administrator hereby directs the Hearing Officer to exclude from the record all argument, testimony, or other evidence that seeks in any way to visit or revisit BPA's determination of a customer's FY 2014-2015 RHWM or other RHWM Process determinations.
On July 26, 2011, the Administrator executed the 2012 REP Settlement with over one hundred customers and other regional parties resolving longstanding litigation over BPA's implementation of the Residential Exchange Program (REP) under section 5(c) of the Northwest Power Act, 16 U.S.C. 839c(c). Parties were afforded an opportunity to challenge the legal, factual, and policy merits of the 2012 REP Settlement in the REP-12 administrative hearing, an eight-month administrative proceeding conducted under the procedural rules of section 7(i) of the Northwest Power Act, 16 U.S.C. 839e(i). The Administrator's findings regarding the legal, factual, and policy challenges to the 2012 REP Settlement are thoroughly explained in the 419-page REP-12 Record of Decision (REP-12 ROD). The 2012 REP Settlement and REP-12 ROD are currently under review before the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).
Because BPA's decision to adopt the 2012 REP Settlement was made as part of the REP-12 ROD, which is already under review by the Court, challenges to BPA's decision to adopt the 2012 REP Settlement and implement its terms in BPA's rate proceedings are not within the scope of this case. Pursuant to § 1010.3(f) of BPA's Procedures, the Administrator hereby directs the Hearing Officer to exclude from the record all argument, testimony, or other evidence that seeks in any way to visit or revisit BPA's determination to adopt the 2012 REP Settlement or implement its terms in this rate proceeding.
Although challenges to BPA's decision to adopt the 2012 REP Settlement and implement its terms in BPA's rate proceedings are not within the scope of this case, the Hearing Officer shall permit BPA and the rate case parties, through a “standstill” agreement, to incorporate by reference material from the BP-12 proceeding, which includes the record from the REP-12 proceeding.
BPA is in the process of assessing the potential environmental effects of its proposed power and transmission rates, consistent with NEPA. The NEPA process is conducted separately from the rate proceeding. As discussed in section II.D.6., all evidence and argument addressing potential environmental impacts of rates being developed in the BP-14 rate proceeding are excluded from the rate proceeding hearing record. Instead, comments on environmental effects should be directed to the NEPA process.
Because this proposal involves BPA's ongoing business practices related to rates, BPA is reviewing the proposal for consistency with BPA's Business Plan Environmental Impact Statement (Business Plan EIS), completed in June 1995 (BOE/EIS-0183). This policy-level EIS evaluates the environmental impacts of a range of business plan alternatives for BPA that could be varied by applying various policy modules, including one for rates. Any combination of alternative policy modules should allow BPA to balance its costs and revenues. The Business Plan EIS also includes response strategies, such as adjustments to rates, that BPA could implement if BPA's costs exceed its revenues.
In August 1995, the BPA Administrator issued a ROD (Business Plan ROD) that adopted the Market-Driven Alternative from the Business Plan EIS. This alternative was selected because, among other reasons, it allows BPA to: (1) Recover costs through rates; (2) competitively market BPA's products and services; (3) develop rates that meet customer needs for clarity and simplicity; (4) continue to meet BPA's legal mandates; and (5) avoid adverse environmental impacts. BPA also committed to apply as many response strategies as necessary when BPA's costs and revenues do not balance.
In April 2007, BPA completed and issued a Supplement Analysis to the Business Plan EIS. This Supplement Analysis found that the Business Plan EIS's relationship-based and policy-level analysis of potential environmental impacts from BPA's business practices remains valid, and that BPA's current business practices remain consistent with BPA's Market-Driven Alternative approach. The Business Plan EIS and ROD thus continue to provide a sound basis for making determinations under NEPA concerning BPA's policy-level decisions, including rates.
Because the proposed rates likely would assist BPA in accomplishing the goals identified in the Business Plan ROD, the proposal appears consistent with these aspects of the Market-Driven Alternative. In addition, this rate proposal is similar to the type of rate designs evaluated in the Business Plan EIS; thus, implementation of this rate proposal would not be expected to result in environmental impacts significantly different from those examined in the Business Plan EIS. Therefore, BPA expects that this rate proposal will likely fall within the scope of the Market-Driven Alternative that was evaluated in the Business Plan EIS and adopted in the Business Plan ROD.
As part of the Administrator's ROD that will be prepared for the BP-14 rate proceeding, BPA may tier its decision under NEPA to the Business Plan ROD. However, depending upon the ongoing environmental review, BPA may instead issue another appropriate NEPA document. Comments regarding the potential environmental effects of the proposal may be submitted to Katherine Pierce, NEPA Compliance Officer, KEC-4, Bonneville Power Administration, 905 NE 11th Avenue, Portland, OR 97232. Any such comments received by the comment deadline for Participant Comments identified in section III.A. below will be considered by BPA's NEPA compliance staff in the NEPA process that will be conducted for this proposal.
BPA distinguishes between “participants in” and “parties to” the hearings. Apart from the formal hearing process, BPA will receive written comments, views, opinions, and information from “participants,” who may submit comments without being subject to the duties of, or having the privileges of, parties. Participants' written comments will be made part of the official record and considered by the Administrator. Participants are not entitled to participate in the prehearing conference; may not cross-examine parties' witnesses, seek discovery, or serve or be served with documents; and are not subject to the same procedural requirements as parties. BPA customers whose rates are subject to this proceeding, or their affiliated customer groups, may not submit participant comments. Members or employees of organizations that have intervened in the rate proceeding may submit general comments as participants but may not
Written comments by participants will be included in the record if they are received by February 15, 2013. Written views, supporting information, questions, and arguments should be submitted to the address listed in the
Entities or persons become parties to the proceeding by filing petitions to intervene, which must state the name and address of the entity or person requesting party status and the entity's or person's interest in the hearing. BPA customers and affiliated customer groups will be granted intervention based on petitions filed in conformance with BPA's Procedures. Other petitioners must explain their interests in sufficient detail to permit the Hearing Officer to determine whether the petitioners have a relevant interest in the hearing. Pursuant to Rule 1010.1(d) of BPA's Procedures, BPA waives the requirement in Rule 1010.4(d) that an opposition to an intervention petition be filed and served 24 hours before the prehearing conference. The time limit for opposing a timely intervention will be established at the prehearing conference. Any party, including BPA, may oppose a petition for intervention. All petitions will be ruled on by the Hearing Officer. Late interventions are strongly disfavored. Opposition to an untimely petition to intervene must be filed and received by BPA within two days after service of the petition. BPA is holding the OS-14 Oversupply rate proceeding at the same time as the BP-14 rate proceeding. However, these proceedings are separate. As a result, entities or persons wishing to intervene in both dockets must file a separate petition to intervene in each rate proceeding, and all filings must be made in the rate proceeding to which the filing pertains.
The hearing record will include, among other things, the transcripts of the hearing, written evidence and argument entered into the record by BPA and the parties, written comments from participants, and other material accepted into the record by the Hearing Officer. The Hearing Officer will review the record and certify the record to the Administrator for final decision.
The Administrator will develop final rates based on the record and such other materials and information as may have been submitted to or developed by the Administrator. The Administrator will serve copies of the Final ROD on all parties. BPA will file its rates with the Commission for confirmation and approval after issuance of the Final ROD.
BPA is proposing five different rates for Federal power sales and services. In 2012, BPA signed the 2012 REP Settlement. See section II.D.9. Ratesetting in this proceeding implements the Settlement according to its terms.
Priority Firm Power Rate (PF-14)—The PF rate schedule applies to net requirements power sales to public body, cooperative, and Federal agency customers made pursuant to section 5(b) of the Northwest Power Act and includes the PF Public rates for the sale of firm requirements power under CHWM Contracts and the PF Exchange rates for sales under Residential Purchase and Sale Agreements. The PF Public rate applies to customers taking load following or Slice/block service. Consistent with the TRM, Tier 1 rates include three charges: (1) Customer charges; (2) a demand charge; and (3) a load shaping charge. In addition, three Tier 2 rates, corresponding to contract options, are provided for customers that have chosen to purchase power from BPA for service to their load above high water mark.
About 75 percent of BPA's power revenues are paid under the PF rate schedule and 95 percent of the power revenues under rates adjusted in this proceeding (PF, IP, NR and FPS). Therefore, BPA expresses its overall rate increase in terms measured by the increase in the PF rate. However, the PF rate is a collection of rates charged on the basis of percentage of cost responsibility, marginal changes in demand and energy usage, purchase elections for loads in excess of power purchased at Tier 1 rates, product and service choices, and applicability of rate discounts. Very few of BPA's customers have exactly the same mix of PF rate components in common. Therefore, BPA has developed a quantification of the PF rate that measures the impact on an average customer purchasing at Tier 1 rates. This quantification, the Tier 1 Average Net Cost, is increasing 9.6 percent in this proposal. Individual customer impacts vary around this increase, but most PF customers will experience a lower increase in its power bills, and customers that purchase the Slice product will experience a large portion of this increase through the lower value of Slice surplus power rather than through their BPA power bills. Altogether, BPA expects that this rate proposal will increase its revenues by $158 million per year, an 8 percent increase over revenues if rates did not change.
The Base PF Exchange rate and its associated surcharges apply to the sale of power to regional utilities that participate in the REP established under section 5(c) of the Northwest Power Act. 16 U.S.C. 839c(c). The Base PF Exchange rate establishes the threshold for participation in the REP; only utilities with ASCs above the appropriate Base PF Exchange rate may receive REP benefits. If a utility meets the threshold, a utility-specific PF Exchange rate will be established in this proceeding for each eligible utility. The utility-specific PF Exchange rate is used in calculating the REP benefits each participant will receive during FY 2014-2015.
In addition, the proposed PF-14 rate schedule includes rates for customers with non-Federal resources that have elected to take Diurnal Flattening Service or Secondary Crediting Service, and a melded PF rate for any Public customers that elects a power sales contract other than a CHWM Contract for firm requirements service.
New Resource Firm Power Rate (NR-14)—The NR-14 rate applies to net requirements power sales to investor-owned utilities (IOUs) made pursuant to section 5(b) of the Northwest Power Act for resale to ultimate consumers, direct consumption, construction, testing and start-up, and station service. The NR-14 rate is also applied to sales of firm power to Public customers serving new large single loads. In the Initial Proposal BPA is forecasting no sales at the NR rate. The average NR-14 rate in the Initial Proposal is $73.63/MWh, an increase of 5.9 percent from the NR-12 rate.
Industrial Firm Power Rate (IP-14)—The IP rate is applicable to firm power sales to DSI customers authorized by section (5)(d)(1)(A) of the Northwest Power Act. 16 U.S.C. 839c(d)(1)(A). In the Initial Proposal BPA is forecasting annual sales of 312 average megawatts (aMW) to DSIs. See section IV.A.2c. The average IP-14 rate in the Initial Proposal is $38.98/MWh, an increase of 7.4 percent over the IP-12 rate.
Firm Power Products and Services Rate (FPS-14)—The FPS rate schedule is applicable to purchasers of Firm Power, Capacity Without Energy, Supplemental Control Area Services, Shaping Services, Reservation and Rights to Change Services, and Reassignment or Remarketing of Surplus Transmission Capacity, for use inside and outside the Pacific Northwest. The
General Transfer Agreement Service Rate (GTA-14)—The GTA rate schedule includes the GTA Delivery Charge and Transfer Service Operating Reserve Charge. The GTA Delivery Charge applies to customers that purchase Federal power that is delivered over non-Federal low-voltage transmission facilities. BPA is proposing to change the basis for determining the GTA Delivery Charge. The proposed rate is based on the cost of low-voltage non-Federal delivery service provided by third-party transmission providers. In addition, the proposed billing determinant uses the customer system peak. BPA is also proposing to continue an Operating Reserves rate for transfer service customers that will become effective when proposed changes to Western Electricity Coordinating Council (WECC) Operating Reserve Requirements become effective.
No significant changes are proposed for the tiered PF rate. Several minor changes are proposed to address issues that have arisen during the first year of application of the tiered rate design, including modifications to the demand rate billing determinants and to certain aspects of Tier 2 rates, and wording corrections to some power rate schedules.
For FY 2014-2015, BPA expects to purchase balancing reserve capacity from non-Federal sources to provide balancing services within its balancing authority area. BPA is proposing a methodology to assign the costs of Federal balancing reserve capacity and non-Federal balancing reserve capacity.
VERBS provides the generation capability (ability to both increase and decrease generation) to follow within-hour variations of variable energy resources in the BPA Balancing Authority Area. The proposed methodology for calculating the Variable Energy Resource Balancing Service rate for service from Federal resources is similar to the BP-12 methodology. However, BPA is proposing to make several changes to its rate options under VERBS. The proposed VERBS rate recovers the cost of regulating reserves, following reserves, and imbalance reserves that are necessary to balance the within-hour schedule deviations of variable energy resources. The proposed VERBS rate will also recover certain directly assigned costs that are associated with providing VERBS.
The proposed VERBS rate is comprised of a base rate and four formula rate adjustments, which are designed to recover the costs associated with: (1) The purchase of non-Federal balancing reserve capacity on a planning basis to provide VERBS; (2) replacing, if necessary, FCRPS balancing reserve capacity that becomes unavailable during the rate period with reserve acquisitions from non-Federal sources in order to continue providing VERBS and Dispatchable Energy Resource Balancing Service (DERBS) for the rate period; (3) purchases of non-Federal balancing reserve capacity to support a “Full Service” VERBS option for customers that elect this service; and (4) acquisitions of non-Federal balancing reserve capacity to support an unplanned increase in balancing services. BPA is also proposing to provide a rate credit to VERBS customers for embedded and variable costs associated with FCRPS balancing reserve capacity that becomes unavailable during the rate period because of hydro-related conditions.
BPA is proposing to provide a discounted base rate to VERBS customers that participate in “committed intra-hour scheduling,” in which customers agree to schedule on a half-hour basis in every schedule interval at a specific level of scheduling accuracy.
BPA is proposing to discontinue Provisional Variable Energy Resource Balancing Service (also known as “Provisional Balancing Service”) and its associated rate.
DERBS is necessary to support the within-hour deviations of thermal generation from the hourly generation estimate (
BPA proposes to change the calculation of its incremental cost for Energy and Generation Imbalance Services from an hourly market index to a weighted average cost of energy deployed. BPA also proposes to provide no credit for generator imbalances (actual generation exceeds scheduled amounts) under Generation Imbalance Service that occur during a scheduling period in which BPA issues a curtailment order. In addition, BPA proposes to exempt customers that participate in committed intra-hour scheduling from Deviation Band 2 penalty charges under Generation Imbalance Service. Finally, BPA proposes to exempt customers that participate in committed intra-hour scheduling or committed hourly scheduling from the Persistent Deviation penalty charge.
In the Initial Proposal, BPA is forecasting sales of 312 aMW to Alcoa and Port Townsend Paper for the FY 2014-2015 rate period. BPA proposed and received public comment on a ten-year contract with Port Townsend Paper that would provide service through FY 2022. BPA is currently receiving public comment on a proposed ten-year contract with Alcoa that would also provide service through FY 2022. The Initial Proposal does not make an explicit assumption about the outcome of either proposed contract; however, the Initial Proposal does assume that BPA will serve the two industries during the forthcoming rate period.
The main financial risk mitigation tool BPA relies upon is financial liquidity, comprising cash, other investments in the Bonneville Fund at the U.S. Treasury, and a short-term liquidity facility with the U.S. Treasury. BPA proposes to include provisions for two rate adjustments: the Cost Recovery Adjustment Clause (CRAC), which can generate additional cash within the rate period, and the Dividend Distribution Clause (DDC), which can return cash to customers when BPA's financial reserves are larger than needed to meet its Treasury Payment Probability (TPP) standard. When available liquidity and the CRAC are insufficient to meet the TPP standard, BPA includes Planned
In the Initial Proposal, BPA proposes to include no PNRR and to cap the maximum revenue recoverable through the CRAC at $300 million per year. BPA is proposing some minor changes to the risk mitigation tools in the BP-14 Initial Proposal, including a revision to the metric used to determine whether a CRAC or DDC triggers. The thresholds for triggering the CRAC and DDC remain unchanged from the BP-12 rate case (equivalent reserve levels of $0 and $750 million respectively in financial reserves attributed to Power). BPA also proposes to continue the National Marine Fisheries Service FCRPS Biological Opinion Adjustment (NFB Adjustment) and the Emergency NFB Surcharge, given that litigation regarding the Biological Opinion continues.
BPA is proposing an overall 13 percent increase in transmission rates. This increase includes a proposed 25 percent increase in the Utility Delivery rate.
BPA is proposing four different rates for the use of its Integrated Network segment, four different rates for use of intertie segments, and several other rates for various purposes.
The four rates for use of the Integrated Network segment are:
Formula Power Transmission Rate (FPT-14)—The FPT rate is based on the cost of using specific types of facilities, including a distance component for the use of transmission lines, and is charged on a contract demand basis.
Integration of Resources Rate (IR-14)—The IR rate is a postage stamp, contract demand rate for the use of the Integrated Network, similar to Point-to-Point (PTP) service (see below).
Network Integration Transmission Rate (NT-14)—The NT rate applies to customers taking network integration service under the Open Access Transmission Tariff (OATT) and allows customers to flexibly serve their retail load.
Point-to-Point Rate (PTP-14)—The PTP rate is a contract demand rate that applies to customers taking point-to-point service on BPA's network facilities under the OATT. It provides customers with flexible service from identified Points of Receipt to identified Points of Delivery. There are separate PTP rates for long-term firm service; daily firm and non-firm service; and hourly firm and non-firm service.
BPA is proposing four rates for intertie use:
The Southern Intertie Rate (IS-14) and the Montana Intertie Rate (IM-14) are contract demand rates that apply to customers taking Point-to-Point service under the OATT on the Southern Intertie and Montana Intertie. These rates are structured similarly to the rate for Point-to-Point service on Network facilities.
The Townsend-Garrison Transmission Rate (TGT-14) and the Eastern Intertie Rate (IE-14) are developed pursuant to the Montana Intertie agreement.
Other proposed transmission rates are:
The Use-of-Facilities Rate (UFT-14) establishes a formula for charging for the use of a specific facility based on the annual cost of that facility.
The Advance Funding Rate (AF-14) allows Transmission Services to collect the capital and related costs of specific facilities through an advance-funding mechanism.
Other charges that may apply include a Delivery Charge for the use of low-voltage delivery substations; a Power Factor Penalty Charge; a Reservation Fee for customers that postpone their service commencement dates; incremental rates for transmission requests that require new facilities; a penalty charge for failure to comply with dispatch, curtailment, redispatch, or load shedding orders; and an Unauthorized Increase Charge for customers that exceed their contracted amounts.
BPA is proposing rates for six ancillary services: Scheduling, System Control, and Dispatch Service; Reactive Supply and Voltage Control from Generation Sources Service; Regulation and Frequency Response Service; Energy Imbalance Service; Operating Reserve-Spinning Reserve Service; and, Operating Reserve-Supplemental Reserve Service. In addition to the rates for Ancillary Services, BPA is proposing rates for six control area services: Regulation and Frequency Response Service; Generation Imbalance Service; Operating Reserve-Spinning Reserve Service; Operating Reserve-Supplemental Reserve Service; Variable Energy Resource Balancing Service; and Dispatchable Energy Resource Balancing Service.
BPA is proposing to change its cost allocation methodology for allocating Integrated network costs to NT and PTP rates from a 1 coincidental peak (1CP) method to a 12 non-coincidental peak (12 NCP) method. The rate impact of this change is approximately a 1.5 percent increase in the PTP rate and a 5.9 percent decrease in the NT rate.
BPA is proposing to change the billing determinants for NT service and Utility Delivery service to be consistent with the Network cost allocation methodology.
Changes to ancillary and control area services rates are discussed in section IV.A.2.b.
The initial rate proposal for power rates, transmission rates, and ancillary service and control area service rates is explained and documented in the following studies.
The Power Rates Study explains and documents the development of power rates and billing determinants for BPA's power products and services. The results of the study are reflected in the proposed power rate schedules.
The Power Loads and Resources Study explains and documents the compilation of the load and resource data and forecasts necessary for developing BPA's wholesale power rates. The Study has three major interrelated components: the Federal system load forecast; the Federal system resource forecast; and the Federal system loads and resources balance.
The Power Revenue Requirement Study explains and documents the level of revenues from power rates necessary to recover, in accordance with sound business principles, the FCRPS costs associated with the production, acquisition, marketing, and conservation of electric power. Cost estimates in the Power Revenue Requirement Study are based on the results of the IPR, as presented in the Final Close-Out Report dated October 26, 2012. The repayment studies reflect actual and projected repayment obligations and transactions related to
The Power Risk and Market Price Study has three major components: the electricity market price forecast used in setting power rates; the quantification of the risks accounted for in setting power rates; and the set of risk mitigation measures to include in rates that ensure that power rates meet the established TPP. The TPP is a measure of the probability that BPA will make its Treasury payments on time and in full during the rate period. If the TPP is below BPA's two-year 95 percent standard, a combination of risk mitigation tools is proposed to meet the TPP standard.
The electricity market price forecast portion of the study explains and documents forecasts of the variable cost of the marginal resource for transactions in the wholesale energy market. The market used in this analysis is the Mid-Columbia trading hub in the state of Washington, although this forecast is influenced by conditions in other regions within the Western Interconnection. The Power Risk and Market Price Study also explains and documents the natural gas price forecast used in setting rates.
The Generation Inputs Study includes the study and documentation for generation inputs costs and other inter-business line costs. The study also includes the development and design of the proposed ACS-14 Ancillary and Control Area Services rate schedule. The forecasts for balancing reserve capacity to provide regulation and frequency response, variable energy resource balancing service, dispatchable energy resource balancing service, operating reserve, and load following are explained and documented in the Generation Inputs Study. The Study explains and documents the embedded and variable cost methodologies for these balancing reserve capacity obligations and the resulting revenue credits reflected in the power rates.
The Transmission Rates Study explains the rate design process for developing transmission, ancillary and control area service rates. The purpose of the TRS is to derive rates that will recover transmission costs. The rate study also explains proposed changes to the Transmission Service Rate Schedules and General Rate Schedule Provisions.
The Transmission Revenue Requirement Study establishes the level of revenue needed from transmission rates to recover, in accordance with sound business principles, the costs associated with the transmission of electric power. The Transmission Revenue Requirement Study includes a risk analysis to ensure that the proposed transmission rates are sufficient to achieve a 95 percent probability of making end-of-year U.S. Treasury payments in full and on time during the two-year rate period.
The Transmission Segmentation Study classifies transmission facilities by usage and assigns them to segments. Segments are groups of facilities that serve distinct functions (for example, integration of power into the transmission system or delivery of power at low voltage). The Segmentation Study also determines the plant investment and historical operations and maintenance expense for each segment based on the facilities that have been assigned to that segment.
BPA's proposed 2014 Power Rate Schedules and proposed 2014 Transmission Rate Schedules are a part of this notice and are available for viewing and downloading on BPA's Web site at