B O N N E V I L L E P O W E R A D M I N I S T R A T I O N
BP-24 Rate Proceeding
Final Proposal
Transmission Revenue Requirement
Study
BP-24-FS-BPA-06
July 2023
BP-24-FS-BPA-06
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TRANSMISSION REVENUE REQUIREMENT STUDY
Table of Contents
Page
COMMONLY USED ACRONYMS AND SHORT FORMS ................................................................. iii
1. INTRODUCTION ......................................................................................................................... 1
1.1 Purpose of the Study ............................................................................................................... 1
1.2 Legal Requirements ................................................................................................................. 5
1.2.1 Governing Authorities .............................................................................................. 5
1.2.1.1 Legal Requirements Governing BPA’s Revenue
Requirement ............................................................................................... 6
1.2.1.2 The BPA Appropriations Refinancing Act ....................................... 8
1.2.2 Repayment Requirements and Policies ............................................................. 8
1.2.2.1 Separate Repayment Studies ............................................................... 8
1.2.2.2 Repayment Schedules ............................................................................. 9
2. DEVELOPMENT OF REVENUE REQUIREMENT .............................................................. 15
2.1 Forecast Cost Development ................................................................................................15
2.2 Capital Investments ...............................................................................................................16
2.2.1 Bonds Issued to the Treasury ..............................................................................16
2.2.2 Federal Appropriations .........................................................................................17
2.2.3 Revenues for Capital Investment .......................................................................17
2.2.4 Non-Federal Payment Obligations ....................................................................17
2.2.5 Customer-Financed Projects ................................................................................18
2.3 Modeling of BPA’s Repayment Obligations ..................................................................20
2.4 Change to Plant and Debt Assumptions .........................................................................22
3. TRANSMISSION REVENUE REQUIREMENTS .................................................................. 23
3.1 Revenue Requirement Format ..........................................................................................23
3.2 Current Revenue Test ...........................................................................................................24
3.3 Revised Revenue Test ...........................................................................................................24
3.4 Repayment Test at Proposed Rates .................................................................................25
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FIGURE AND TABLES
Figure 1: Transmission Revenue Requirement Process ...................................................................... 3
Table 1: Projected Net Revenues from Proposed Rates ..................................................................29
Table 2: Planned Repayments to U.S. Treasury ..................................................................................29
Table 3: Transmission Revenue Requirement Income Statement ..............................................30
Table 4: Transmission Revenue Requirement Statement of Cash Flows ..................................31
Table 5: Transmission Current Revenue Test Income Statement ...............................................32
Table 6: Transmission Current Revenue Test Statement of Cash Flows ...................................33
Table 7: Transmission Revenues from Current Rates – Results through the
Repayment Period .........................................................................................................................34
Table 8: Transmission Revised Revenue Test Income Statement ...............................................35
Table 9: Transmission Revised Revenue Test Statement of Cash Flows ..................................37
Table 10: Transmission Revenues from Proposed Rates through the Repayment
Period .................................................................................................................................................38
Table 11: Amortization of Transmission Investments Over Repayment Period ......................40
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COMMONLY USED ACRONYMS AND SHORT FORMS
AAC Anticipated Accumulation of Cash
ACNR Accumulated Calibrated Net Revenue
ACS Ancillary and Control Area Services
AF Advance Funding
AFUDC Allowance for Funds Used During Construction
AGC automatic generation control
aMW average megawatt(s)
ANR Accumulated Net Revenues
ASC Average System Cost
BAA Balancing Authority Area
BiOp Biological Opinion
BPA Bonneville Power Administration
BPAP Bonneville Power Administration Power
BPAT Bonneville Power Administration Transmission
Bps basis points
Btu British thermal unit
CAISO California Independent System Operator
CIP Capital Improvement Plan
CIR Capital Investment Review
CDQ Contract Demand Quantity
CGS Columbia Generating Station
CHWM Contract High Water Mark
CNR Calibrated Net Revenue
COB California-Oregon border
COI California-Oregon Intertie
Commission Federal Energy Regulatory Commission (see also “FERC”)
Corps U.S. Army Corps of Engineers
COSA Cost of Service Analysis
COU consumer-owned utility
Council Northwest Power and Conservation Council (see also “NPCC”)
COVID-19 coronavirus disease 2019
CP Coincidental Peak
CRAC Cost Recovery Adjustment Clause
CRFM Columbia River Fish Mitigation
CSP Customer System Peak
CT combustion turbine
CWIP Construction Work in Progress
CY calendar year (January through December)
DD Dividend Distribution
DDC Dividend Distribution Clause
dec decrease, decrement, or decremental
DERBS Dispatchable Energy Resource Balancing Service
DFS Diurnal Flattening Service
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DNR Designated Network Resource
DOE Department of Energy
DOI Department of Interior
DSI direct-service industrial customer or direct-service industry
DSO Dispatcher Standing Order
EE Energy Efficiency
EESC EIM Entity Scheduling Coordinator
EIM Energy imbalance market
EIS environmental impact statement
EN Energy Northwest, Inc.
ESA Endangered Species Act
ESS Energy Shaping Service
e-Tag electronic interchange transaction information
FBS Federal base system
FCRPS Federal Columbia River Power System
FCRTS Federal Columbia River Transmission System
FELCC firm energy load carrying capability
FERC Federal Energy Regulatory Commission
FMM-IIE Fifteen Minute Market – Instructed Imbalance Energy
FOIA Freedom of Information Act
FORS Forced Outage Reserve Service
FPS Firm Power and Surplus Products and Services
FPT Formula Power Transmission
FRP Financial Reserves Policy
F&W Fish & Wildlife
FY fiscal year (October through September)
G&A general and administrative (costs)
GARD Generation and Reserves Dispatch (computer model)
GDP Gross Domestic Product
GI generation imbalance
GMS Grandfathered Generation Management Service
GSP Generation System Peak
GSR Generation Supplied Reactive
GRSPs General Rate Schedule Provisions
GTA General Transfer Agreement
GWh gigawatthour
HLH Heavy Load Hour(s)
HYDSIM Hydrosystem Simulator (computer model)
IE Eastern Intertie
IIE Instructed Imbalance Energy
IM Montana Intertie
inc increase, increment, or incremental
IOU investor-owned utility
IP Industrial Firm Power
IPR Integrated Program Review
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IR Integration of Resources
IRD Irrigation Rate Discount
IRM Irrigation Rate Mitigation
IRPL Incremental Rate Pressure Limiter
IS Southern Intertie
kcfs thousand cubic feet per second
kW kilowatt
kWh kilowatthour
LAP Load Aggregation Point
LDD Low Density Discount
LGIA Large Generator Interconnection Agreement
LLH Light Load Hour(s)
LMP Locational Marginal Price
LPP Large Project Program
LT long term
LTF Long-term Firm
Maf million acre-feet
Mid-C Mid-Columbia
MMBtu million British thermal units
MNR Modified Net Revenue
MRNR Minimum Required Net Revenue
MW megawatt
MWh megawatthour
NCP Non-Coincidental Peak
NEPA National Environmental Policy Act
NERC North American Electric Reliability Corporation
NFB National Marine Fisheries Service (NMFS) Federal Columbia
River Power System (FCRPS) Biological Opinion (BiOp)
NLSL New Large Single Load
NMFS National Marine Fisheries Service
NOAA Fisheries National Oceanographic and Atmospheric Administration
Fisheries
NOB Nevada-Oregon border
NORM Non-Operating Risk Model (computer model)
NWPA Northwest Power Act/Pacific Northwest Electric Power
Planning and Conservation Act
NWPP Northwest Power Pool
NP-15 North of Path 15
NPCC Northwest Power and Conservation Council
NPV net present value
NR New Resource Firm Power
NRFS NR Resource Flattening Service
NRU Northwest Requirements Utilities
NT Network Integration
NTSA Non-Treaty Storage Agreement
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NUG non-utility generation
OATT Open Access Transmission Tariff
O&M operations and maintenance
OATI Open Access Technology International, Inc.
ODE Over Delivery Event
OS oversupply
OY operating year (August through July)
P10 tenth percentile of a given dataset
PDCI Pacific DC Intertie
PF Priority Firm Power
PFp Priority Firm Public
PFx Priority Firm Exchange
PNCA Pacific Northwest Coordination Agreement
PNRR Planned Net Revenues for Risk
PNW Pacific Northwest
POD Point of Delivery
POI Point of Integration or Point of Interconnection
POR point of receipt
PPC Public Power Council
PRSC Participating Resource Scheduling Coordinator
PS Power Services
PSC power sales contract
PSW Pacific Southwest
PTP Point-to-Point
PUD public or people’s utility district
RAM Rate Analysis Model (computer model)
RAS Remedial Action Scheme
RCD Regional Cooperation Debt
RD Regional Dialogue
RDC Reserves Distribution Clause
REC Renewable Energy Certificate
Reclamation U.S. Bureau of Reclamation
REP Residential Exchange Program
REPSIA REP Settlement Implementation Agreement
RevSim Revenue Simulation Model
RFA Revenue Forecast Application (database)
RHWM Rate Period High Water Mark
ROD Record of Decision
RPSA Residential Purchase and Sale Agreement
RR Resource Replacement
RRHL Regional Residual Hydro Load
RRS Resource Remarketing Service
RSC Resource Shaping Charge
RSS Resource Support Services
RT1SC RHWM Tier 1 System Capability
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RTD-IIE Real-Time Dispatch – Instructed Imbalance Energy
RTIEO Real-Time Imbalance Energy Offset
SCD Scheduling, System Control, and Dispatch Service
SCADA Supervisory Control and Data Acquisition
SCS Secondary Crediting Service
SDD Short Distance Discount
SILS Southeast Idaho Load Service
Slice Slice of the System (product)
SMCR Settlements, Metering, and Client Relations
SP-15 South of Path 15
T1SFCO Tier 1 System Firm Critical Output
TC Tariff Terms and Conditions
TCMS Transmission Curtailment Management Service
TDG Total Dissolved Gas
TGT Townsend-Garrison Transmission
TOCA Tier 1 Cost Allocator
TPP Treasury Payment Probability
TRAM Transmission Risk Analysis Model
Transmission System Act Federal Columbia River Transmission System Act
Treaty Columbia River Treaty
TRL Total Retail Load
TRM Tiered Rate Methodology
TS Transmission Services
TSS Transmission Scheduling Service
UAI Unauthorized Increase
UDE Under Delivery Event
UFE unaccounted for energy
UFT Use of Facilities Transmission
UIC Unauthorized Increase Charge
UIE Uninstructed Imbalance Energy
ULS Unanticipated Load Service
USFWS U.S. Fish & Wildlife Service
VER Variable Energy Resource
VERBS Variable Energy Resource Balancing Service
VOR Value of Reserves
VR1-2014 First Vintage Rate of the BP-14 rate period (PF Tier 2 rate)
VR1-2016 First Vintage Rate of the BP-16 rate period (PF Tier 2 rate)
WECC Western Electricity Coordinating Council
WPP Western Power Pool
WRAP Western Resource Adequacy Program
WSPP Western Systems Power Pool
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1. INTRODUCTION 1
2
1.1 Purpose of the Study 3
The purpose of the Transmission Revenue Requirement Study is to establish the revenues 4
from transmission and ancillary services that are necessary to recover, in accordance with 5
sound business principles, the Federal Columbia River Transmission System (FCRTS) costs 6
associated with the transmission of electric power. The FCRTS is part of the Federal 7
Columbia River Power System (FCRPS), which also includes the multipurpose generation 8
facilities constructed and operated by the U.S. Army Corps of Engineers (Corps) and the 9
U.S. Bureau of Reclamation (Reclamation) in the Pacific Northwest. The FCRPS costs that 10
are not associated with the FCRTS are funded and repaid through the Bonneville Power 11
Administration’s (BPA) power rates. The revenue requirement developed in this study 12
includes recovery of the Federal investment in transmission and transmission-related 13
assets; the operations and maintenance (O&M) and other annual expenses associated with 14
the provision of transmission and ancillary services; the cost of generation inputs for 15
ancillary services and other inter-business line services necessary for the transmission of 16
power; and all other transmission-related costs incurred by BPA. 17
18
The cost evaluation period, as defined by the Federal Energy Regulatory Commission 19
(FERC or Commission), is the period extending from the last year for which historical 20
information is available through the proposed rate period. The cost evaluation period for 21
this filing includes Fiscal Year (FY) 2023 and the proposed rate period, FY 2024-2025. This 22
study is based on transmission revenue requirements that include the results of 23
transmission repayment studies. This study does not include the revenue requirement or 24
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a cost recovery demonstration for BPA’s power function. See Power Revenue Requirement 1
Study, BP-24-FS-BPA-02. 2
3
This Study outlines the policies, forecasts, assumptions, and calculations used to determine 4
the transmission revenue requirement. The Transmission Revenue Requirement Study 5
Documentation, BP-24-FS-BPA-06A, contains key technical assumptions and calculations, 6
the results of the transmission repayment studies, and further explanation of the 7
repayment program and its outputs. 8
9
The revenue requirement for this study is developed using a cost-accounting analysis 10
composed of three parts. First, repayment studies for the transmission function are 11
prepared to determine the schedule of amortization payments and to project annual 12
interest expense for bonds and appropriations that fund the Federal investment in 13
transmission and transmission-related assets. Repayment studies are conducted for each 14
year of the rate period and extend over the 35-year repayment period. Second, 15
transmission operating expenses and Minimum Required Net Revenue (MRNR) are 16
projected for each year of the rate period. Third, annual Planned Net Revenues for Risk 17
(PNRR) are determined after taking into account risks, and other risk mitigation measures, 18
as described in the Power and Transmission Risk Study, BP-24-FS-BPA-05. From these 19
three steps, the revenue requirement is set at the level necessary to fulfill cost recovery 20
requirements. This process is depicted in Figure 1, below. 21
22
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Figure 1: Transmission Revenue Requirement Process 1
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Consistent with Department of Energy (DOE) Order RA 6120.2 and the standards applied 1
by the Commission on review of BPA’s rates, BPA must determine the adequacy of both 2
current and proposed rates to recover the revenue requirement. BPA conducts a current 3
revenue test to determine whether revenues projected from current rates meet cost 4
recovery requirements for the rate period and the repayment period. If the current 5
revenue test indicates that cost recovery and risk mitigation requirements are met, current 6
rates could be extended through the proposed rate approval period. The current revenue 7
test, described in Section 3.2 of this study, demonstrates that revenues from current rates 8
would not be adequate to recover the transmission revenue requirement for the rate 9
period. 10
11
The revised revenue test, which is performed after calculation of the proposed 12
transmission rates, determines whether projected revenues from proposed rates meet cost 13
recovery requirements for the rate test and repayment periods. The revised revenue test, 14
Section 3.3 of this study, demonstrates that revenues from the proposed transmission rates 15
will recover transmission costs in the rate period and over the ensuing 35-year repayment 16
period. Revenues from the proposed rates, together with risk mitigation tools, are 17
sufficient to meet BPA’s 95 percent Treasury Payment Probability standard that all 18
U.S. Treasury payments will be paid on time and in full, as discussed in the Power and 19
Transmission Risk Study, BP-24-FS-BPA-05, § 5.2.4.2. 20
21
Table 1 (see Tables at the back of this document) summarizes the revised revenue test and 22
shows projected net revenues from proposed transmission rates for FY 2024-2025. These 23
net revenues are the lowest level sufficient to achieve, in combination with other risk 24
mitigation tools, cost recovery in the face of transmission-related risks. 25
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Table 2 shows planned transmission amortization payments to the U.S. Treasury for each 1
year of the rate period. 2
3
1.2 Legal Requirements 4
This section summarizes the statutory framework that guides the development of BPA’s 5
transmission revenue requirement, the recovery of BPA’s transmission costs from the 6
various users of the FCRTS, and the repayment policies BPA follows in the development of 7
its revenue requirement. 8
9
1.2.1 Governing Authorities 10
BPA’s revenue requirements are governed primarily by four legislative acts: the Bonneville 11
Project Act of 1937, Pub. L. No. 75-329, 50 Stat. 731, amended 1977; the Flood Control Act 12
of 1944, Pub. L. No. 78-534, 58 Stat. 890, amended 1977; the Federal Columbia River 13
Transmission System Act of 1974 (Transmission System Act), Pub. L. No. 93-454, 14
88 Stat. 1376, amended 1977; and the Pacific Northwest Electric Power Planning and 15
Conservation Act (Northwest Power Act), Pub. L. No. 96-501, 94 Stat. 2697. The Omnibus 16
Consolidated Rescissions and Appropriations Act of 1996, Pub. L. No. 104-134, 110 Stat. 17
1321, also guides the development of BPA’s revenue requirements. 18
19
DOE Order “Power Marketing Administration Financial Reporting,” RA 6120.2, issued by 20
the Secretary of Energy, also provides guidance to Federal power marketing 21
administrations regarding repayment of the Federal investment. In addition, policies 22
issued by the Commission provide guidance on separate accounting for transmission 23
system costs. See, e.g., Bonneville Power Admin., 25 FERC ¶ 61,140 (1983). 24
25
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1.2.1.1 Legal Requirements Governing BPA’s Revenue Requirement 1
BPA constructs, operates, and maintains the FCRTS within the Pacific Northwest and makes 2
improvements or replacements to the transmission system as are appropriate and required 3
to (a) integrate and transmit electric power from existing or additional Federal or 4
non-Federal generating units; (b) provide service to BPA customers; (c) provide inter-5
regional transmission facilities; and (d) maintain the electrical stability and reliability of 6
the Federal system. Transmission System Act § 4, 16 U.S.C. § 838b. 7
8
BPA’s rates must be set to ensure that revenues are sufficient to recover costs. This 9
requirement was first set forth in Section 7 of the Bonneville Project Act, 16 U.S.C. § 832f, 10
which provides that: 11
Rate schedules shall be drawn having regard to the recovery (upon the basis 12
of the application of such rate schedules to the capacity of the electric facilities 13
of [the] Bonneville project) of the cost of producing and transmitting such 14
electric energy, including the amortization of the capital investment over a 15
reasonable period of years. 16
This cost recovery principle was repeated for Army reservoir projects in Section 5 of the 17
Flood Control Act of 1944, 16 U.S.C. § 825s. In 1974, Section 9 of the Transmission System 18
Act, 16 U.S.C. § 838g, expanded the cost recovery principle so that BPA’s rates also would 19
be set to recover: 20
[P]ayments provided [in the Administrator’s annual budget] . . . at levels to 21
produce such additional revenues as may be required, in the aggregate with 22
all other revenues of the Administrator, to pay when due the principal of, 23
premiums, discounts, and expenses in connection with the issuance of and 24
interest on all bonds issued and outstanding pursuant to [this Act,] and 25
amounts required to establish and maintain reserve and other funds and 26
accounts established in connection therewith. 27
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The Northwest Power Act reiterates and clarifies the cost recovery principle. 1
Section 7(a)(1) of the Northwest Power Act, 16 U.S.C. § 839e(a)(1), provides: 2
The Administrator shall establish, and periodically review and revise, rates for 3
the sale and disposition of electric energy and capacity and for the 4
transmission of non-Federal power. Such rates shall be established and, as 5
appropriate, revised to recover, in accordance with sound business principles, 6
the costs associated with the acquisition, conservation, and transmission of 7
electric power, including the amortization of the Federal investment in the 8
Federal Columbia River Power System (including irrigation costs required to 9
be repaid out of power revenues) over a reasonable period of years and the 10
other costs and expenses incurred by the Administrator pursuant to this 11
chapter and other provisions of law. Such rates shall be established in 12
accordance with Sections 9 and 10 of the Federal Columbia River 13
Transmission System Act (16 U.S.C. § 838), Section 5 of the Flood Control Act 14
of 1944, and the provisions of this chapter. 15
Section 7(a)(2) of the Northwest Power Act, 16 U.S.C. § 839e(a)(2), provides that the 16
Commission shall issue a confirmation and approval of BPA’s rates upon a finding that the 17
rates 18
(A) are sufficient to assure repayment of the Federal investment in the 19
Federal Columbia River Power System over a reasonable number of 20
years after first meeting the Administrator’s other costs; 21
(B) are based upon the Administrator’s total system costs; and 22
(C) insofar as transmission rates are concerned, equitably allocate the 23
costs of the Federal transmission system between Federal and non-24
Federal power utilizing such system. 25
Development of the revenue requirement is a critical component of meeting the statutory 26
cost recovery principles relevant to BPA. The costs associated with the FCRTS and 27
associated services and expenses, as well as other costs incurred by the Administrator in 28
furtherance of BPA’s mission, are included in the study. 29
30
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1.2.1.2 The BPA Appropriations Refinancing Act 1
The Refinancing Act, 16 U.S.C. § 838l, part of the Omnibus Consolidated Rescissions and 2
Appropriations Act of 1996, Pub. L. No. 104-134, 110 Stat. 1321, was enacted in April 1996. 3
The Refinancing Act required that unpaid principal on BPA appropriations (“old capital 4
investments”) at the end of FY 1996 be reset at the present value of the principal and 5
annual interest payments BPA would make to the U.S. Treasury for these obligations absent 6
the Refinancing Act, plus $100 million. 16 U.S.C. § 838l(b). The Refinancing Act also 7
specified that the new principal amounts of the old capital investments be assigned new 8
interest rates from the U.S. Treasury yield curve prevailing at the time of the refinancing 9
transaction. 16 U.S.C. § 838l(a)(6)(A). All of the appropriations refinanced by this Act have 10
been repaid. 11
12
1.2.2 Repayment Requirements and Policies 13
1.2.2.1 Separate Repayment Studies 14
Section 10 of the Transmission System Act, 16 U.S.C. § 838h, and Section 7(a)(2)(C) of the 15
Northwest Power Act, 16 U.S.C. § 839e(a)(2)(C), provide that the recovery of the costs of 16
the Federal transmission system will be equitably allocated between Federal and non-17
Federal power utilizing such system. In 1982, the Commission first directed BPA to 18
provide accounting and repayment statements for its transmission system separate and 19
apart from the accounting and repayment statements for the Federal generation system. 20
Bonneville Power Admin., 20 FERC ¶ 61,142 (1982). The Commission required BPA to 21
establish books of account for the FCRTS separate from its generation books of account; 22
explained that the FCRTS will be composed of all investments, including administrative and 23
management costs, related to the transmission of electric power; and directed BPA to 24
develop repayment studies for its transmission function separate from those for its 25
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generation function. Such studies must set forth the date of each investment, the 1
repayment date, and the amount repaid from transmission revenues. Bonneville Power 2
Admin., 26 FERC ¶ 61,096 (1984). 3
4
The Commission approved BPA’s methodology for separate repayment studies in 1984. 5
Bonneville Power Admin., 28 FERC ¶ 61,325 (1984). Thus, BPA has prepared separate 6
repayment studies for its transmission and generation functions since 1984. This 7
methodology has enabled BPA to set power and transmission rates separately with 8
minimal change in repayment policy and the process for developing each revenue 9
requirement. This study incorporates only the repayment study for the transmission 10
function for FY 2024-2025. 11
12
1.2.2.2 Repayment Schedules 13
The statutes applicable to BPA do not include directives for scheduling repayment of 14
capital appropriations and bonds issued to the U.S. Treasury other than a directive that the 15
Federal investment be amortized over a reasonable period of years. BPA’s repayment 16
policy has been established largely through administrative interpretation of its statutory 17
requirements. 18
19
There have been a number of changes in BPA’s repayment policy over the years concurrent 20
with expansion of the Federal system and changing conditions. In general, current 21
repayment criteria were approved by the Secretary of the Interior on April 3, 1963. These 22
criteria were refined and submitted to the Secretary and the Federal Power Commission 23
(the predecessor agency to the Federal Energy Regulatory Commission) in support of BPA’s 24
rate filing in September 1965. 25
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The repayment policy was presented to Congress for its consideration for the authorization 1
of the Grand Coulee Dam Third Powerhouse in June 1966. The underlying theory of 2
repayment was discussed in the House of Representatives’ report related to authorization 3
of this project, H.R. Rep. No. 89-1409, 2d Sess., at 9-10 (1966). As stated in that report: 4
Accordingly, [in a repayment study] there is no annual schedule of capital 5
repayment. The test of the sufficiency of revenues is whether the capital 6
investment can be repaid within the overall repayment period established for 7
each power project, each increment of investment in the transmission system, 8
and each block of irrigation assistance. Hence, repayment may proceed at a 9
faster or slower pace from year-to-year as conditions change. . . . 10
This approach to repayment scheduling has the effect of averaging the year-to-year 11
variations in costs and revenues over the repayment period. This results in a uniform cost 12
per unit of power sold, and permits the maintenance of stable rates for extended periods. It 13
also facilitates the orderly marketing of power and permits BPA customers to plan for the 14
future with assurance. 15
16
The Secretary of the Interior issued a statement of power policy on September 30, 1970, 17
setting forth general principles that reaffirmed the repayment policy as previously 18
developed. The most pertinent of these principles were set forth in the Department of the 19
Interior Manual, Part 730, Chapter 1: 20
A. Hydroelectric power, although not a primary objective, will be 21
proposed to Congress and supported for inclusion in multiple-purpose 22
Federal projects when . . . it is capable of repaying its share of the 23
Federal investment, including operation and maintenance costs and 24
interest, in accordance with the law. 25
B. Electric power generated at Federal projects will be marketed at the 26
lowest rates consistent with sound financial management. Rates for 27
the sale of Federal electric power will be reviewed periodically to 28
assure their sufficiency to repay operating and maintenance costs and 29
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the capital investment within 50 years with interest that more 1
accurately reflects the cost of money. 2
To achieve a greater degree of uniformity in repayment policy for all Federal power 3
marketing administrations, the Deputy Assistant Secretary of the Department of the 4
Interior (DOI) issued a memo on August 2, 1972, outlining (1) a uniform definition of the 5
start of the repayment period for a particular project; (2) the method for including future 6
replacement costs in repayment studies; and (3) a provision that the investment or 7
obligation bearing the highest interest rate will be amortized first, to the extent possible, 8
while ensuring that BPA still complies with the prescribed repayment period established 9
for each increment of investment. 10
11
A further clarification of the repayment policy was outlined in a joint memo on January 7, 12
1974, from the Assistant Secretary for Reclamation and Assistant Secretary for Energy and 13
Minerals. This memo states that in addition to meeting the overall objective of repaying the 14
Federal investment and obligations within the prescribed repayment periods, revenues 15
must be adequate, except in unusual circumstances, to repay annually all costs for O&M, 16
purchased power, and interest. 17
18
On March 22, 1976, the DOI issued Chapter 4 of Part 730 of the DOI Manual to codify 19
financial reporting requirements for the Federal power marketing administrations; it 20
describes standard policies and procedures for preparing system repayment studies. 21
22
BPA and the other Federal power marketing agencies were transferred to the newly 23
established DOE on October 1, 1977. Department of Energy Organization Act, 42 U.S.C. 24
§ 7101 et seq. DOE adopted the policies set forth in Part 730 of the DOI Manual by issuing 25
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Interim Management Directive No. 1701 on September 28, 1977, which subsequently was 1
replaced by RA 6120.2, issued on September 20, 1979, and amended on October 1, 1983. 2
3
The repayment policy outlined in DOE Order RA 6120.2, paragraph 12, provides that BPA’s 4
total revenues from all sources must be sufficient to: 5
1. Pay all annual costs of operating and maintaining the Federal power 6
system; 7
2. Pay the cost of obtaining power through purchase and exchange 8
agreements, the cost for transmission services, and other costs during 9
the year in which such costs are incurred; 10
3. Pay interest each year on the unamortized portion of the commercial 11
power investment financed with appropriated funds at the interest 12
rates established for each generating project and for each annual 13
increment of such investment in the BPA transmission system, except 14
that recovery of annual interest expense may be deferred in unusual 15
circumstances for short periods of time; 16
4. Pay when due the interest and amortization portion on outstanding 17
bonds sold to the U.S. Treasury; 18
5. Repay: 19
• each dollar of power investments and obligations in the FCRPS 20
generating projects within 50 years after the projects become 21
revenue-producing (50 years has been deemed a “reasonable 22
period” as intended by Congress, except for the 23
Yakima-Chandler Project, which has a legislated amortization 24
period of 66 years); 25
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• each annual increment of transmission financed by Federal 1
investments and obligations within the average service life of 2
such transmission facilities (currently 40 years) or within a 3
maximum of 50 years, whichever is less (BPA has interpreted 4
RA 6120.2 to require repayment of bonds sold to finance 5
conservation to be within the average service lives of these 6
projects, currently estimated to be five years, and for fish and 7
wildlife facilities to be 15 years); 8
• the Federally financed amount of each replacement within its 9
service life up to a maximum of 50 years; and 10
6. As required by Pub. L. No. 89-448, § 2, repay the portion of 11
construction costs at Federal reclamation projects that is beyond the 12
repayment ability of the irrigators, and which is assigned for 13
repayment from commercial power revenues, within the same overall 14
period available to the irrigation water users for making their 15
payments on construction costs. 16
17
The typical repayment period for appropriated capital investments for generation is 18
50 years from the year in which the plant is placed in service. Due dates for appropriated 19
transmission investments were set at no more than 45 years. The Refinancing Act 20
(Section 1.2.1.2) overrides provisions in DOE Order RA 6120.2 related to determining 21
interest during construction and assigning interest rates to Federal investments financed 22
by appropriations. This Act also contains provisions on repayment periods (due dates) for 23
the refinanced investments. 24
25
BP-24-FS-BPA-06
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DOE Order RA 6120.2 also requires that any outstanding deferred interest payments must 1
be repaid before any planned amortization payments are made. Also, repayments are to be 2
made by amortizing those Federal investments and obligations bearing the highest interest 3
rate first, to the extent possible, while ensuring that BPA still completes repayment of each 4
increment of Federal investment and obligation within its prescribed repayment period. 5
BP-24-FS-BPA-06
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2. DEVELOPMENT OF REVENUE REQUIREMENT 1
2
2.1 Forecast Cost Development 3
The development of program spending levels occurs outside the rate process. For the 4
FY 2024-2025 rate period it began in June 2022, when BPA hosted the first 2022 Integrated 5
Program Review (IPR) workshop. This public process focused on reviewing and discussing 6
expense projections and capital forecasts. The process provided customers and 7
constituents an opportunity to examine, understand, and comment on BPA’s cost 8
projections for BPA’s power and transmission functions. 9
10
BPA began the 2022 IPR discussion with the release of the IPR initial publication and an 11
opening workshop containing an overview of Power Services’, Transmission Services’, and 12
corporate agency services’ forecast expense and capital costs for FY 2024-2025. The 13
opening workshop launched a public comment period, providing participants the 14
opportunity to provide feedback on the forecast costs and program objectives. The initial 15
publication and workshop discussed forecast costs and program objectives for the 16
FY 2024-2025 rate period, with comparisons to previous IPR costs. The initial report also 17
included capital cost projections for FY 2024-2025. 18
19
Following the opening workshop, BPA held a series of workshops to discuss spending 20
levels for the program areas, including the Columbia Generating Station (CGS); Corps; 21
Reclamation; BPA’s energy efficiency, transmission, and fish and wildlife programs; and 22
BPA’s Information Technology program. After considering the comments received, BPA 23
released a final IPR closeout report in October 2022. 24
25
BP-24-FS-BPA-06
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This study incorporates the spending levels identified in the 2022 IPR closeout report, 1
which can be found on BPA’s public website: https://www.bpa.gov/about/finance/bp-24-2
ipr. 3
4
2.2 Capital Investments 5
The forecast of BPA’s capital investments for FY 2024-2025 used to develop the BP-24 6
transmission final proposal rates was published in the IPR closeout reports. The following 7
section describes the capital investment forecasts. 8
9
BPA transmission capital spending projections including allowance for funds used during 10
construction (AFUDC) for the FY 2024-2025 rate period are $1.132 billion. These 11
investments are: 12
• Transmission programs ($1.089 billion) 13
• Environmental program ($12.5 million) 14
• Corporate capital program ($29.9 million) 15
Transmission Revenue Requirement Study Documentation, BP-24-FS-BPA-06A, Table 7-2. 16
17
2.2.1 Bonds Issued to the Treasury 18
Bonds issued to the U.S. Treasury will be the primary source of capital used to finance 19
projected FY 2024-2025 transmission capital program investments. Interest rates on 20
bonds issued by BPA to the U.S. Treasury are set at market interest rates comparable to the 21
interest rates for securities issued by other agencies of the U.S. Government. For interest 22
rates on bonds projected to be issued, see id., Ch. 6. 23
24
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2.2.2 Federal Appropriations 1
All Congressional Appropriations related to the Transmission system have been fully 2
repaid. As a result, the repayment study no longer includes any obligation to repay 3
appropriations. 4
5
2.2.3 Revenues for Capital Investment 6
The revenue requirement assumes that $55 million per year of the capital program is 7
funded with current revenues. This revenue financing was added consistent with the 8
Sustainable Capital Financing Policy adopted in August 2022. 9
10
2.2.4 Non-Federal Payment Obligations 11
The transmission revenue requirements reflect two forms of non-Federal payment 12
obligations. The first is lease purchase arrangements for assets. BPA entered into its first 13
transaction in 2004 with the Northwest Infrastructure Financing Corporation (NIFC), a 14
subsidiary of JH Management, to provide for the construction of the 500-kV Schultz-15
Wautoma transmission line. Since the completion of the Schultz-Wautoma project, BPA has 16
entered into additional lease financing arrangements with NIFC, Port of Morrow, and Idaho 17
Energy Resources Authority. BPA constructs the facilities financed by the lease holder and 18
makes periodic lease payments. During the term of the lease, BPA operates the facilities. 19
At the end of the lease, BPA has an option to purchase the facilities for a nominal fee. The 20
revenue requirement includes all transactions BPA expects to complete by the date of the 21
Final Proposal. BPA does not currently anticipate entering into new lease purchase 22
arrangements in the rate period. 23
24
BP-24-FS-BPA-06
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The second form of non-Federal payment obligations included in the revenue requirement 1
is the functional reassignment to Transmission Services of debt service (interest and 2
principal) payment obligations associated with non-Federal Energy Northwest (EN) bonds. 3
This reassignment is a result of BPA’s Debt Optimization Program (DOP), which refinances 4
and repays existing EN bonds before they come due and uses the revenues made available 5
from such refinancing to replenish or create opportunities to replenish BPA’s Treasury 6
borrowing authority by retiring additional Treasury obligations in amounts equal to the 7
principal of the new EN bonds. When Treasury obligations associated with transmission 8
investments are repaid under DOP, the debt service obligation associated with new EN 9
debt in equivalent principal amounts is assigned to Transmission Services. The revenue 10
requirements reflect refinancing actions that have occurred through FY 2009, when DOP 11
ended. The revenue requirement does not include forecasts of additional refinancing 12
activities during the rate period. 13
14
For specific calculations regarding non-Federal payment obligations, see id., Ch. 8. 15
16
2.2.5 Customer-Financed Projects 17
The revenue requirements also reflect the impacts of customer-financed projects. 18
Customers have financed capital construction projects under generation interconnection 19
agreements (LGIA or SGIA). BPA amended its Open Access Transmission Tariff and 20
adopted the LGIA and SGIA in voluntary compliance with Commission Order Nos. 2003 and 21
2006. Under the generator interconnection agreements, interconnection customers 22
finance the cost of network upgrades (facilities at or beyond the point at which the 23
customer’s interconnection facilities connect to BPA’s transmission system) needed to 24
interconnect their generating facilities to BPA’s transmission system if BPA, as the 25
BP-24-FS-BPA-06
Page 19
transmission owner/provider, does not provide the funding. BPA requires the 1
interconnection customer to advance funds in an amount sufficient to cover the cost of 2
construction. These advance funds, with interest on the outstanding balance, are then 3
returned to the interconnection customer in the form of transmission credits. These 4
credits either offset charges for eligible transmission service in the customer’s bill or are 5
provided as monthly cash payments based on the generating facility’s capacity and its plant 6
capacity factor. 7
8
These customer-financed transactions and the associated transmission credits affect 9
several areas of the revenue requirement. Depreciation of the associated assets appears in 10
total transmission depreciation. The interest that accrues on the outstanding credit 11
balances is included in non-Federal interest, a component of the net interest calculation on 12
the income statement. Both of these items increase transmission expenses. These items 13
also appear in the statement of cash flows, because they are non-cash expenses. In 14
addition, the revenues associated with customer-financed projects for which customers 15
receive credits affect the statement of cash flows because they are non-cash revenues—16
they provide no cash for cost recovery. Therefore, they generally increase the need for 17
MRNR, which is added to the income statement if necessary, to ensure that all cash 18
requirements are met. 19
20
Non-cash expenses (depreciation and interest on outstanding credit balances) offset non-21
cash revenues and decrease the need for MRNR. The non-cash expenses are subtracted 22
from the non-cash revenues. If the difference is positive, meaning that non-cash revenues 23
exceed non-cash expenses, the need for MRNR increases. If the difference is negative, 24
meaning that non-cash expenses exceed non-cash revenues, the need for MRNR decreases. 25
BP-24-FS-BPA-06
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2.3 Modeling of BPA’s Repayment Obligations 1
Repayment studies are performed as part of the process for determining revenue 2
requirements. The studies establish a schedule of annual U.S. Treasury amortization for 3
the rate period and the resulting interest payments. Each repayment study covers a rate 4
test year and the ensuing repayment period, which extends to the last year by which all 5
outstanding and projected obligations must be repaid. For transmission repayment 6
studies, that period is 35 years. This study horizon reflects the fact that bonds are not 7
issued for terms longer than 35 years and that the outstanding appropriations and bonds 8
that finance the transmission system are fully repaid within this period. This study horizon 9
is also appropriate in that it does not exceed the estimated average service life of a 10
transmission system plant. 11
12
In conducting the repayment studies, BPA includes as fixed inputs the annual debt service 13
payments associated with its non-Federal capitalized contract obligations and the fixed 14
annual payments associated with long-term energy resource acquisition contracts. All 15
outstanding and projected transmission repayment obligations for appropriated 16
investments and bonds issued to the U.S. Treasury are included to be scheduled for 17
repayment. Forecast transmission repayment obligations related to the lease purchase 18
program are also modeled and scheduled for repayment. Funding for replacements 19
projected during the repayment period is also included in the repayment study, consistent 20
with the requirements of DOE Order RA 6120.2. 21
22
Appropriations and bonds are scheduled to be repaid within the expected useful life of the 23
associated facility, or the maximum repayment period (50 years for generation and 24
35 years for transmission), whichever is less. Bonds issued by BPA to the U.S. Treasury 25
BP-24-FS-BPA-06
Page 21
have varying terms, taking into account the estimated average service lives for investments 1
and prudent financing and cash management factors. Projected lease purchase obligations 2
assumed in the repayment study are held to the same parameters. 3
4
In the repayment studies, all projected bonds are issued with maturities not to exceed 5
30 years for transmission investment, although they can be refinanced within the 35-year 6
repayment period. Environmental investments have a maximum term of 15 years. 7
Corporate investments, generally for information technology, are for a five-year period. 8
Generally bonds are issued with a provision that allows the bonds to be called any time. 9
Bonds also may be issued with provisions such as a five-year call or a no call provision. 10
Early retirement of eligible bonds may require that BPA pay a bond premium to the 11
Treasury. Bonds may also be called and repaid at a discount. Bonds are issued to finance 12
BPA transmission, environment, and corporate investments and are repaid within the 13
provisions of each bond agreement with the Treasury. 14
15
Based on these parameters, the repayment study establishes a schedule of planned 16
amortization payments and resulting interest expense by determining the lowest levelized 17
debt service stream necessary to repay all transmission obligations within the required 18
repayment period. 19
20
For further discussion of the repayment program, see Transmission Revenue Requirement 21
Study Documentation, BP-24-FS-BPA-06A, Ch. 12. 22
23
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2.4 Change to Plant and Debt Assumptions 1
The revenue requirement study includes a forecast of the Grand Coulee switchyard transfer 2
anticipated to be completed in FY 2023, when Reclamation will transfer ownership of 3
switchyard assets located at the Grand Coulee dam to BPA. The assets, with a net book 4
value of approximately $124 million, are currently part of Power’s asset base. The assets 5
will be functionalized to Transmission. BPA will also transfer debt, estimated to be 6
$109 million, from Power to Transmission. The amount of debt will be equal to the net 7
book value multiplied by Power’s debt-to-asset ratio. 8
9
BP-24-FS-BPA-06
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3. TRANSMISSION REVENUE REQUIREMENTS 1
2
3.1 Revenue Requirement Format 3
For each year of a rate period, BPA prepares two tables that reflect the process by which 4
revenue requirements are determined. The Income Statement includes projections of total 5
expenses, any PNRR and, if necessary, an MRNR component. The Statement of Cash Flows 6
shows the analysis used to determine MRNR and the cash available for risk mitigation. 7
8
The Income Statement (Table 3) displays the components of the annual revenue 9
requirements, which include total operating expenses (line 9), net interest expense 10
(line 23), MRNR (line 27), and PNRR (line 28). The sum of these four major components is 11
the total revenue requirement (line 31) for each year of the rate period. (Note: all tables 12
referenced in this section are located at the back of this document.) 13
14
The MRNR (Table 3, line 27) results from an analysis of the Statement of Cash Flows 15
(Table 4). MRNR may be necessary to ensure that revenue requirements are sufficient to 16
cover all cash requirements, including annual amortization of the Federal investment as 17
determined in the transmission repayment studies. 18
19
The Statement of Cash Flows (Table 4) analyzes annual cash inflows and outflows. Cash 20
provided by current operations (line 11), driven by expenses not requiring cash and non-21
cash revenues, shown in lines 3 through 10, must be sufficient to compensate for the 22
difference between cash used for capital investments (line 16) and cash from Treasury 23
borrowing (line 24). If cash provided by current operations is not sufficient, MRNR (line 2) 24
must be included in revenue requirements to accommodate the shortfall, yielding at least 25
BP-24-FS-BPA-06
Page 24
a zero annual increase in cash (line 26). The MRNR amount shown on the Statement of 1
Cash Flows (line 2) then is incorporated in the Income Statement (Table 3, line 27). 2
3
3.2 Current Revenue Test 4
Consistent with DOE Order RA 6120.2, the continuing adequacy of existing rates must be 5
tested annually. The current revenue test, exhibited in Tables 5 and 6, determines whether 6
the revenue expected from current rates will meet cost recovery requirements during the 7
FY 2024-2025 rate period and the ensuing repayment period. For revenue at current rates, 8
see Transmission Revenue Requirement Study Documentation, BP-24-FS-BPA-06A, Ch. 13. 9
10
The result of the current revenue test demonstrates that projected revenue from current 11
rates, without the proposed application of financial reserves from the FY 2022 12
Transmission Reserves Distribution Clause and implementation of the BP-24 Rates 13
Settlement, is inadequate to meet the cost recovery criteria of Order RA 6120.2 because the 14
net position is negative in the rate period and for some years of the repayment period. See 15
Table 7, column K. 16
17
3.3 Revised Revenue Test 18
Consistent with DOE Order RA 6120.2, the adequacy of proposed rates must be 19
demonstrated. The revised revenue test determines whether the revenue projected from 20
proposed rates developed consistent with the FY 2022 Transmssion Reserves Distribution 21
Clause proposal and the terms of the BP-24 Rates Settlement will meet cost recovery 22
requirements for the rate period. The revised revenue test is conducted using the forecast 23
of revenue under proposed rates. Transmission Revenue Requirement Study 24
Documentation, BP-24-FS-BPA-06A, Ch. 13. 25
BP-24-FS-BPA-06
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The results of the revised revenue test demonstrate that proposed rates are adequate to 1
fulfill the basic cost recovery requirements for the rate period, FY 2024-2025. For the rate 2
period, the demonstration of the adequacy of proposed rates is shown in Tables 8 and 9 of 3
this study. Table 9 tests the sufficiency of the resulting net revenues from Table 8, line 23, 4
for making the planned annual amortization payments. The sufficiency of net revenues is 5
demonstrated by the annual increase (or decrease) in cash (Table 9, line 25). The annual 6
cash flow must be at least zero to demonstrate the adequacy of the projected revenues to 7
cover all cash requirements. 8
9
3.4 Repayment Test at Proposed Rates 10
Table 10, Transmission Revenues from Proposed Rates, demonstrates whether projected 11
revenue from proposed rates is adequate to meet the cost recovery criteria of DOE Order 12
RA 6120.2 over the repayment period. The data are presented in a format consistent with 13
the revised revenue tests, Tables 8 and 9, and the separate accounting analysis that is an 14
attachment to the rate filing BPA submits to the Commission. The focal point of Table 10 is 15
the net position (column K), which is the amount of funds provided by revenues that 16
remain after meeting annual expenses requiring cash for the rate period and repayment of 17
the Federal investment. Thus, if the net position is zero or greater in each of the years of 18
the rate period through the repayment period, the projected revenues demonstrate BPA’s 19
ability to repay the Federal investment in the FCRPS within the allowable time. As shown 20
in column K, the resulting net position is zero or greater for each year of the rate period 21
and in each year of the repayment period. 22
23
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Page 26
The historical data on this table have been taken from BPA’s separate accounting analysis. 1
The rate period data have been developed specifically for this study. The repayment period 2
data are presented consistent with the requirements of DOE Order RA 6120.2. 3
Table 11, Amortization of Transmission Investments Over Repayment Period, summarizes 4
the amortization of Federal investments over the repayment period. It displays the total 5
investment costs through the cost evaluation period, forecast replacements required to 6
maintain the system through the repayment period, the cumulative dollar amount of 7
investments placed in service, scheduled amortization payments for each year of the 8
repayment period (due and discretionary), unamortized investments including 9
replacements through the repayment period, unamortized obligations as determined by a 10
term schedule (if all obligations were paid at maturity and never early), and the 11
predetermined amortization payments and the unamortized amount of irrigation 12
assistance for each year of the repayment period. 13
14
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TABLES
This page intentionally left blank.
BP-24-FS-BPA-06
Page 29
Table 1: Projected Net Revenues from Proposed Rates
($000s)
Table 2: Planned Repayments to U.S. Treasury
($000s)
BP-24-FS-BPA-06
Page 30
Table 3: Transmission Revenue Requirement Income Statement
($000s)
BP-24-FS-BPA-06
Page 31
Table 4: Transmission Revenue Requirement Statement of Cash Flows
($000s)
BP-24-FS-BPA-06
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Table 5: Transmission Current Revenue Test Income Statement
($000s)
A
B
2024 2025
1 REVENUES FROM CURRENT RATES 1,246,362 1,270,570
2
3 OPERATING EXPENSES
4 TRANSMISSION OPERATIONS 191,615 198,324
5 TRANSMISSION ENGINEERING 60,231 61,194
6 TRANSMISSION MAINTENANCE 193,212 199,230
7 TRANSMISSION ACQUISITION & ANCILLARY SERVICES 117,998 117,998
8 BPA INTERNAL SUPPORT 136,034 139,965
9 OTHER INCOME, EXPENSES & ADJUSTMENTS - -
10 DEPRECIATION & AMORTIZATION 357,998
343,958
11 TOTAL OPERATING EXPENSES 1,057,089 1,060,670
12
13 INTEREST EXPENSE
14 INTEREST EXPENSE
15 FEDERAL APPROPRIATIONS - -
16 CAPITALIZATION ADJUSTMENT (18,968) (18,968)
17 ON LONG-TERM DEBT 123,338 139,964
18 AMORTIZATION OF CAPITALIZED BOND PREMIUMS 559 559
19 DEBT SERVICE REASSIGNMENT INTEREST 843 -
20 NON-FEDERAL INTEREST 61,885 62,050
21 PREMIUMS/DISCOUNTS - -
22 AFUDC (15,100) (13,934)
23 INTEREST INCOME (1,889)
(2,614)
24 NET INTEREST EXPENSE 150,667 167,057
25
26 TOTAL EXPENSES 1,207,757 1,227,727
27
28 NET REVENUES 38,605 42,843
BP-24-FS-BPA-06
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Table 6: Transmission Current Revenue Test Statement of Cash Flows
($000s)
BP-24-FS-BPA-06
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Table 7: Transmission Revenues from Current Rates –
Results through the Repayment Period
($000s)
A B
C D E F
DEBT SERVICE
OPERATION & OFFSETS NET NET
REVENUES MAINTENANCE (REV REQ INTEREST REVENUES
YEAR (STATEMENT A) (STATEMENT E) STUDY DOC)
DEPRECIATION
(TABLE D)
(F=A-B-C-D-E)
1
Thru 2017
27,114,903 12,239,189 348,748 6,224,662 6,914,738 1,387,566
2
3 2018 1,090,198 596,563 - 286,284 140,788 66,563
4 2019 1,039,877 597,226 - 305,720 147,600 (10,669)
5 2020 1,094,215 612,982 - 339,833 148,894 (7,494)
6 2021 1,107,889 631,300 - 338,371 135,657 2,561
7 2022 1,249,958 662,229 - 338,768 140,625 108,336
8
9 COST EVALUATION
10 PERIOD
11 2023 1,151,547 623,509 - 349,991 144,815 33,232
12
13 RATE APPROVAL
14 PERIOD
15 2024 1,246,362 699,091 - 357,998 150,667 38,605
16 2025 1,270,570 716,712 - 343,958 167,057 42,843
17
18 REPAYMENT
19 PERIOD
20 2026 1,270,570 716,712 (9,275) 343,958 177,801 41,374
21 2027 1,270,570 716,712 (9,275) 343,958 175,027 44,148
22 2028 1,270,570 716,712 (9,275) 343,958 171,534 47,641
23 2029 1,270,570 716,712 (9,275) 343,958 167,801 51,374
24 2030 1,270,570 716,712 (9,275) 343,958 162,321 56,854
25 2031 1,270,570 716,712 (9,275) 343,958 158,755 60,420
26 2032 1,270,570 716,712 (9,275) 343,958 154,059 65,116
27 2033 1,270,570 716,712 (9,275) 343,958 152,473 66,702
28 2034 1,270,570 716,712 (9,275) 343,958 148,510 70,665
29 2035 1,270,570 716,712 (9,275) 343,958 148,271 70,904
30 2036 1,270,570
716,712 (9,275) 343,958 147,190 71,985
31 2037 1,270,570 716,712 (9,275) 343,958 144,681 74,493
32 2038 1,270,570 716,712 (9,275) 343,958 142,743 76,432
33 2039 1,270,570 716,712 (9,275) 343,958 141,357 77,818
34 2040 1,270,570 716,712 (9,275) 343,958 140,239 78,936
35 2041 1,270,570 716,712 (9,275) 343,958 140,098 79,077
36 2042 1,270,570 716,712 (9,275) 343,958 138,577 80,598
37 2043 1,270,570 716,712 (9,275) 343,958 135,974 83,201
38 2044 1,270,570 716,712 (9,275) 343,958 136,359 82,816
39 2045 1,270,570 716,712 (9,275) 343,958 136,073 83,102
40 2046 1,270,570 716,712 (9,275) 343,958 136,031 83,144
41 2047 1,270,570 716,712 (9,275) 343,958 133,116 86,059
42 2048 1,270,570 716,712 (9,275) 343,958 127,801 91,374
43 2049 1,270,570 716,712 (9,275) 343,958 123,296 95,878
44 2050 1,270,570 716,712 (9,275) 343,958 118,626 100,549
45 2051 1,270,570 716,712 (9,275) 343,958 113,783 105,392
46 2052 1,270,570 716,712 (9,275) 343,958 108,761 110,414
47 2053 1,270,570 716,712 (9,275) 343,958 103,553 115,621
48 2054 1,270,570 716,712 (9,275) 343,958 98,154 121,021
49 2055 1,270,570 716,712 (9,275) 343,958 92,554 126,621
50 2056 1,270,570
716,712 (9,275) 343,958 86,748 132,427
51 2057 1,270,570 716,712 (9,275) 343,958 80,727 138,448
52 2058 1,270,570 716,712 (9,275) 343,958 74,483 144,692
53 2059 1,270,570 716,712 (9,275) 343,958 68,008 151,167
54 2060 1,270,570 716,712 (9,275) 343,958 61,318 157,857
55
56 TRANSMISSION
57 TOTALS 80,835,465 42,463,704 24,137 20,924,117 12,637,924 4,785,583
BP-24-FS-BPA-06
Page 35
Table 7 (continued)
G H I J K
FUNDS NON-FEDERAL
NONCASH FROM AMORTIZATION
PRINCIPAL NET
EXPENSES 1/ OPERATION
(REV REQ STUDY (REV REQ STUDY POSITION
(COLUMN D) (H=F+G) DOC,Chapter 11) DOC,Chapter 7) (K=H-I-J)
1 Thru 2017 5,764,188 8,338,469 6,915,652 974,995 447,821
2
3 2018 272,676 316,185 47,906 193,402 74,877
4 2019 6,461 (4,208) 235,016 17,304 (256,527)
5 2020 297,230 289,736 199,900 98,999 (9,163)
6 2021 317,907 320,467 284,700 99,352 (63,585)
7 2022 263,268 371,604 214,900 98,296 58,408
8
9 COST EVALUATION
10 PERIOD
11 2023 313,096 306,328 209,379 96,373 576
12
13 RATE APPROVAL
14 PERIOD
15 2024 315,342 298,947 205,012 110,081 (16,146)
16 2025 298,441 286,284 187,438 110,726 (11,880)
17
18 REPAYMENT
19 PERIOD
20 2026 298,441 339,815 180,519 111,344 47,952
21 2027 298,441 342,589 205,646 88,851 48,092
22 2028 298,441 346,082 204,442 78,077 63,563
23 2029 298,441 349,815 284,623 3,094 62,098
24 2030 298,441 355,295 296,877 3,194 55,224
25 2031 298,441 358,861 303,308 3,270 52,283
26 2032 298,441 363,557 310,906 3,115 49,536
27 2033 298,441 365,143 317,179 3,267 44,697
28 2034 298,441 369,106 219,347 104,891 44,868
29 2035 298,441 369,345 196,347 128,423 44,575
30 2036 298,441 370,426 197,456 128,589 44,381
31 2037 298,441 372,934 232,375 98,179 42,380
32 2038 298,441
374,873 232,262 98,050 44,561
33 2039 298,441 376,259 233,100 98,240 44,919
34 2040 298,441 377,377 234,609 98,412 44,356
35 2041 298,441 377,518 226,510 106,525 44,483
36 2042 298,441 379,039 245,761 88,854 44,424
37 2043 298,441 381,642 235,337 104,052 42,253
38 2044 298,441 381,257 238,845 105,505 36,906
39 2045 298,441 381,543 239,710 104,961 36,872
40 2046 298,441 381,585 233,074 105,065 43,445
41 2047 298,441 384,500 257,024 83,086 44,391
42 2048 298,441 389,815 343,441 2,202 44,171
43 2049 298,441 394,319 347,828 2,325 44,166
44 2050 298,441 398,990 352,375 2,455 44,160
45 2051 298,441 403,833 357,087 2,593 44,154
46 2052 298,441 408,855 361,970 2,737 44,148
47 2053 298,441 414,062 367,031 2,890 44,141
48 2054 298,441 419,462 372,276 3,052 44,135
49 2055 298,441 425,062 377,711 3,222 44,128
50 2056 298,441 430,868 383,345 3,402 44,121
51 2057 298,441 436,889 389,183 3,593 44,113
52 2058 298,441 443,133 395,234 3,793 44,105
53 2059 298,441 449,608 401,505 4,005 44,097
54 2060 298,441 456,298 411,494 723 44,080
55
56 TRANSMISSION
57 TOTALS 18,294,041 24,093,285 18,685,640 3,583,568 1,824,077
1/
Consists of depreciation plus other non-cash expenses and other adjustments and any accounting write-offs included in expenses.
Also removed revenue financing. FY 2019 includes a one-time decrease of $182 million to rebalance financial reserves between
the transmission and generation functions to correct for a misallocation error in the calculation of financial reserves attributed to
the business units.
BP-24-FS-BPA-06
Page 36
Table 8: Transmission Revised Revenue Test Income Statement
($000s)
A B
2024 2025
1 REVENUES FROM PROPOSED RATES 1,253,300 1,275,142
2
3 OPERATING EXPENSES
4 TRANSMISSION OPERATIONS 191,615 198,324
5 TRANSMISSION ENGINEERING 60,231 61,194
6 TRANSMISSION MAINTENANCE 193,212 199,230
7 TRANSMISSION ACQUISITION & ANCILLARY SERVICES 117,998 117,998
8 BPA INTERNAL SUPPORT 136,034 139,965
9 OTHER INCOME, EXPENSES & ADJUSTMENTS (9,200) (7,200)
10 DEPRECIATION & AMORTIZATION 357,998
343,958
11 TOTAL OPERATING EXPENSES 1,047,889 1,053,470
12
13 INTEREST EXPENSE
14 INTEREST EXPENSE
15 FEDERAL APPROPRIATIONS - -
16 CAPITALIZATION ADJUSTMENT (18,968) (18,968)
17 ON LONG-TERM DEBT 123,338 139,964
18 AMORTIZATION OF CAPITALIZED BOND PREMIUMS 559 559
19 DEBT SERVICE REASSIGNMENT INTEREST 843 -
20 NON-FEDERAL INTEREST 61,885 62,050
21 PREMIUMS/DISCOUNTS - -
22 AFUDC (15,100) (13,934)
23 INTEREST INCOME (1,920)
(2,734)
24 NET INTEREST EXPENSE 150,636 166,937
25
26 TOTAL EXPENSES 1,198,525 1,220,406
27
28 NET REVENUES 54,775 54,736
BP-24-FS-BPA-06
Page 37
Table 9: Transmission Revised Revenue Test Statement of Cash Flows
($000s)
A
B
2024 2025
1 CASH FROM CURRENT OPERATIONS:
2 NET REVENUES 54,775 54,736
3 DRAWDOWN OF CASH RESERVES FOR CAPITAL FUNDING - -
4 EXPENSES NOT REQUIRING CASH:
5 DEPRECIATION & AMORTIZATION 357,998 343,958
6 TRANSMISSION CREDIT PROJECTS NET INTEREST 3,656 2,918
7 AMORTIZATION OF CAPITALIZED BOND PREMIUMS 559 559
8 CAPITALIZATION ADJUSTMENT (18,968) (18,968)
9 NON-CASH REVENUES/ACCRUAL REVENUES
10 LGIA (24,112) (26,502)
11 AC INTERTIE CO/FIBER (3,791) (3,524)
12 CASH FLOW ADJUSTMENT (RESERVE)/APPLICATION
13 CASH PROVIDED BY CURRENT OPERATIONS 370,117 353,176
14
15 CASH USED FOR CAPITAL INVESTMENTS:
16 INVESTMENT IN:
17 UTILITY PLANT
(573,492)
(557,985)
18 CASH USED FOR CAPITAL INVESTMENTS (573,492) (557,985)
19
20 CASH FROM TREASURY BORROWING AND APPROPRIATIONS:
21 INCREASE IN LONG-TERM DEBT 518,492 502,985
22 DEBT SERVICE REASSIGNMENT PRINCIPAL (17,640) -
23 REPAYMENT OF CAPITAL LEASES (92,441) (110,726)
24 REPAYMENT OF LONG-TERM DEBT (205,012) (187,438)
25 REPAYMENT OF CAPITAL APPROPRIATIONS
-
-
26 CASH FROM TREASURY BORROWING AND APPROPRIATIONS 203,399 204,821
27
28 ANNUAL INCREASE (DECREASE) IN CASH 23 12
BP-24-FS-BPA-06
Page 38
Table 10: Transmission Revenues from Proposed Rates
through the Repayment Period
($000s)
A B C D E F
DEBT SERVICE
OPERATION & OFFSETS NET NET
REVENUES MAINTENANCE (REV REQ INTEREST REVENUES
YEAR (STATEMENT A) (STATEMENT E) STUDY DOC) DEPRECIATION (TABLE D) (F=A-B-C-D-E)
1 Thru 2017 27,114,903 12,239,189 348,748 6,224,662 6,914,738 1,387,566
2
3 2018 1,090,198 596,563 286,284 140,788 66,563
4 2019 1,039,877 597,226 - 305,720 147,600 (10,668)
5 2020 1,094,215 612,982 - 339,833 148,894 (7,494)
6 2021 1,107,889 631,300 - 338,371 135,657 2,561
7 2022 1,249,958 662,229 338,768 140,625 108,336
8
9 COST EVALUATION
10 PERIOD
11 2023 1,151,547 623,509 - 349,991 144,815 33,232
12
13 RATE APPROVAL
14 PERIOD
15 2024 1,253,300 689,891 - 357,998 150,636 54,775
16 2025 1,275,142 709,512 - 343,958 166,937 54,736
17
18 REPAYMENT
19 PERIOD
20 2026 1,275,142 709,512 (9,275) 343,958 177,801 53,146
21 2027 1,275,142 709,512 (9,275) 343,958 175,027 55,920
22 2028 1,275,142 709,512 (9,275) 343,958 171,534 59,413
23 2029 1,275,142 709,512 (9,275) 343,958 167,801 63,146
24 2030 1,275,142 709,512 (9,275) 343,958 162,321 68,626
25 2031 1,275,142 709,512 (9,275) 343,958 158,755 72,192
26 2032 1,275,142 709,512 (9,275) 343,958 154,059 76,888
27 2033 1,275,142 709,512 (9,275) 343,958 152,473 78,474
28 2034 1,275,142 709,512 (9,275) 343,958 148,510 82,437
29 2035 1,275,142 709,512 (9,275) 343,958 148,271 82,676
30 2036 1,275,142 709,512 (9,275) 343,958 147,190 83,757
31 2037 1,275,142 709,512 (9,275) 343,958 144,681 86,265
32 2038 1,275,142 709,512 (9,275) 343,958 142,743 88,204
33 2039 1,275,142 709,512 (9,275) 343,958 141,357 89,590
34 2040 1,275,142 709,512 (9,275) 343,958 140,239 90,708
35 2041 1,275,142 709,512 (9,275) 343,958 140,098 90,849
36 2042 1,275,142 709,512 (9,275) 343,958 138,577 92,370
37 2043 1,275,142 709,512 (9,275) 343,958 135,974 94,973
38 2044 1,275,142 709,512 (9,275) 343,958 136,359 94,588
39 2045 1,275,142 709,512 (9,275) 343,958 136,073
94,874
40 2046 1,275,142 709,512 (9,275) 343,958 136,031 94,916
41 2047 1,275,142 709,512 (9,275) 343,958 133,116 97,831
42 2048 1,275,142 709,512 (9,275) 343,958 127,801 103,146
43 2049 1,275,142 709,512 (9,275) 343,958 123,296 107,650
44 2050 1,275,142 709,512 (9,275) 343,958 118,626 112,321
45 2051 1,275,142 709,512 (9,275) 343,958 113,783 117,164
46 2052 1,275,142 709,512 (9,275) 343,958 108,761 122,186
47 2053 1,275,142 709,512 (9,275) 343,958 103,553 127,394
48 2054 1,275,142 709,512 (9,275) 343,958 98,154 132,793
49 2055 1,275,142 709,512 (9,275) 343,958 92,554 138,393
50 2056 1,275,142 709,512 (9,275) 343,958 86,748 144,199
51 2057 1,275,142 709,512 (9,275) 343,958 80,727 150,220
52 2058 1,275,142 709,512 (9,275) 343,958 74,483 156,464
53 2059 1,275,142 709,512 (9,275) 343,958 68,008 162,939
54 2060 1,275,142 709,512 (9,275) 343,958 61,318 169,629
55
56 TRANSMISSION
57 TOTALS 81,006,996 42,195,304 24,137 20,924,117 12,637,772 5,225,666
BP-24-FS-BPA-06
Page 39
Table 10 (continued)
G H I J
K
FUNDS
NON-FEDERAL
NONCASH FROM
AMORTIZATION PRINCIPAL NET
EXPENSES 1/
OPERATION
(REV REQ STUDY (REV REQ STUDY POSITION
YEAR (COLUMN D) (H=F+G) DOC,Chapter 11) DOC,Chapter 7) (K=H-I-J)
1 Thru 2017
5,764,188
8,338,469
6,915,652 974,995 447,821
3 2018 272,676 316,185
47,906
193,402 74,877
4
2019
6,461
(4,207) 235,016
17,304
(256,526)
5 2020 297,230
289,736
199,900 98,999 (9,163)
6 2021 317,907 320,467
284,700
99,352 (63,585)
7
2022 263,268
371,604
214,900
98,296
58,408
COST EVALUATION
PERIOD
11 2023
313,096
306,328
209,379
96,373
576
RATE APPROVAL
PERIOD
15 2024 315,342
315,117
205,012 110,081 23
16 2025
298,441
298,176 187,438 110,726 12
REPAYMENT
PERIOD
20 2026 298,441 351,587 180,519
111,344 59,724
21 2027 298,441
354,361 205,646 88,851
59,864
22 2028 298,441 357,854 204,442
78,077 75,336
23 2029 298,441
361,587
284,623
3,094
73,870
24 2030 298,441
367,067 296,877
3,194 66,996
25 2031
298,441 370,633 303,308 3,270 64,055
26 2032 298,441 375,329 310,906 3,115 61,308
27 2033 298,441 376,915
317,179
3,267 56,469
28 2034 298,441 380,878 219,347
104,891 56,640
29 2035 298,441 381,117 196,347 128,423 56,347
30 2036 298,441 382,198 197,456
128,589 56,153
31 2037 298,441 384,706 232,375 98,179 54,152
32 2038
298,441 386,645 232,262 98,050 56,333
33 2039 298,441 388,031 233,100 98,240 56,691
34 2040 298,441 389,149
234,609 98,412 56,128
35 2041 298,441 389,290 226,510 106,525 56,255
36 2042
298,441 390,811
245,761
88,854
56,196
37 2043
298,441 393,414 235,337
104,052
54,025
38 2044 298,441
393,029
238,845 105,505 48,679
39 2045
298,441
393,315
239,710 104,961
48,644
40 2046 298,441 393,357 233,074
105,065
55,217
41 2047
298,441 396,272 257,024 83,086 56,163
42 2048 298,441
401,587
343,441
2,202 55,943
43 2049
298,441 406,091 347,828
2,325 55,938
44 2050
298,441 410,762 352,375 2,455 55,932
45 2051 298,441 415,605 357,087 2,593 55,926
46 2052 298,441
420,627 361,970 2,737 55,920
47 2053 298,441
425,834 367,031 2,890
55,913
48
2054 298,441 431,234
372,276 3,052 55,907
49 2055 298,441 436,834
377,711 3,222
55,900
50 2056 298,441 442,640 383,345
3,402 55,893
51 2057
298,441 448,661 389,183
3,593 55,885
52 2058 298,441
454,905 395,234
3,793 55,877
53 2059 298,441
461,380 401,505 4,005
55,869
54
2060 298,441 468,070 411,494
723
55,852
TRANSMISSION
57 TOTALS 18,294,041
24,533,368 18,685,640 3,583,568
2,264,160
1/
Consists of depreciation plus other non-cash expenses and other adjustments and any accounting write-offs included in
expenses. Also removed revenue financing. FY 2019 includes a one-time decrease of $182 million to rebalance financial
reserves between the transmission and generation functions to correct for a misallocation error in the calculation of
financial reserves attributed to the business units.
BP-24-FS-BPA-06
Page 40
Table 11: Amortization of Transmission Investments Over Repayment Period
($000s)
A B C D E F G H
Fiscal Year
Original &
New
Obligations
Replacements
Cumulative
Amount In
Service
Due
Amortization
Discretionary
Amortization
Unamortized
Investment
Te rm
Investment
Schedule
(1) (2) (3) (4) (5) (6) (7) (8)
1 2023 15,684,798 - 15,684,798 144,000 65,379 4,222,161 7,941,683
2 2024 518,001 - 16,202,799 205,012 - 4,535,150 8,254,672
3 2025 603,000 - 16,805,799 187,438 - 4,950,712 8,670,234
4 2026 - 222,840 17,028,639 125,000 55,519 4,993,033 8,768,074
5 2027 - 222,840 17,251,479 122,000 83,646 5,010,227 8,868,914
6 2028 - 222,840 17,474,319 70,456 133,985 5,028,626 8,815,954
7 2029 - 222,840 17,697,159 110,000 174,623 4,966,842 8,928,794
8 2030 - 222,840 17,919,999 133,896 162,981 4,892,806 9,017,738
9 2031 - 222,840 18,142,839 76,000 227,308 4,812,338 9,164,578
10 2032 - 222,840 18,365,679 - 310,906 4,724,272 9,288,518
11 2033 - 222,840 18,588,519 59,000 258,179 4,629,933 9,412,358
12 2034 - 222,840 18,811,359 82,300 137,047 4,633,426 9,469,898
13 2035 - 222,840 19,034,199 24,000 172,347 4,659,919 9,523,738
14 2036 - 222,840 19,257,039 29,000 168,456 4,685,303 9,492,578
15 2037 - 222,840 19,479,879 112,940 119,435 4,675,768 9,591,478
16 2038 - 222,840 19,702,719 50,000 182,262 4,666,346 9,709,318
17 2039 - 222,840 19,925,559 90,000 143,100 4,656,086 9,767,158
18 2040 - 222,840 20,148,399 70,000 164,609 4,644,317 9,847,749
19 2041 - 222,840 20,371,239 94,000 132,510 4,640,646 9,940,589
20 2042 - 222,840 20,594,079 109,000 136,761 4,617,726 10,040,429
21 2043 - 222,840 20,816,919 77,000 158,337 4,605,229 10,124,269
22 2044 - 222,840 21,039,759 39,000 199,845 4,589,224 10,214,109
23 2045 - 222,840 21,262,599 19,000 220,710 4,572,354 10,300,949
24 2046 - 222,840 21,485,439 57,000 176,074 4,562,120 10,363,789
25 2047 - 222,840 21,708,279 - 257,024 4,527,936 10,432,629
26 2048 - 222,840 21,931,119 - 343,441 4,407,335 10,470,469
27 2049 - 222,840 22,153,959 - 347,828 4,282,346 10,549,509
28 2050 - 222,840 22,376,799 - 352,375 4,152,812 10,624,561
29 2051 222,840 22,599,639 - 357,087 4,018,565 10,681,734
30 2052 - 222,840 22,822,479 - 361,970 3,879,435 10,642,574
31 2053 - 222,840 23,045,319 - 367,031 3,735,245 10,464,997
32 2054 - 222,840 23,268,159 - 372,276 3,585,809 10,441,837
33 2055 - 222,840 23,490,999 - 377,711 3,430,937 10,343,343
34 2056 - 222,840 23,713,839 - 383,345 3,270,432 10,566,183
35 2057 - 222,840 23,936,679 - 389,183 3,104,089 10,789,023
36 2058 - 222,840 24,159,519 - 395,234 2,931,695 11,011,863
37 2059 - 222,840 24,382,359 - 401,505 2,753,030 11,234,703
38 2060 - 222,840 24,605,199 - 411,494 2,564,375 11,457,543
39 $16,805,799 $7,799,400 $2,086,043 $8,701,523
INVESTMENTS PLACED IN SERVICE
BONNEVILLE POWER ADMINISTRATION
DOE/BP-5248 • July 2023