[Federal Register Volume 65, Number 51 (Wednesday, March 15, 2000)]
[Notices]
[Pages 14102-14126]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-6105]



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Part IV





Department of Energy





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Bonneville Power Administration



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2002-2003 Proposed Transmission Rate Adjustment Public Hearing and 
Opportunities for Public Review and Comment; Notice

  Federal Register / Vol. 65, No. 51 / Wednesday, March 15, 2000 / 
Notices  

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DEPARTMENT OF ENERGY


Bonneville Power Administration

AGENCY: Bonneville Power Administration (BPA), Department of Energy 
(DOE).

ACTION: Notice of 2002-2003 Proposed Transmission Rate Adjustment.

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SUMMARY: BPA Files No. TR-02. BPA requests that all comments and 
documents intended to become part of the Official Record in this 
proceeding contain the file number designation TR-02.
    The Pacific Northwest Electric Power Planning and Conservation Act 
(Northwest Power Act) provides that BPA must establish and periodically 
review and revise its transmission rates so that they are adequate to 
recover, in accordance with sound business principles, the costs 
associated with the transmission of electric power, the Federal 
investment in the Federal Columbia River Transmission System (FCRTS), 
and other costs and expenses incurred by BPA. The Northwest Power Act 
also requires that BPA's rates be established based on the record of a 
formal hearing. The Federal Columbia Transmission System Act requires 
that transmission costs be equitably allocated between Federal and non-
Federal power using the system. The Federal Power Act requires that no 
BPA transmission rate applicable to transmission service ordered by the 
Federal Energy Regulatory Commission shall be unjust, unreasonable, or 
unduly discriminatory or preferential as determined by the Commission. 
By this notice, BPA announces its proposed transmission and ancillary 
service rates to be effective on October 1, 2001, and the commencement 
of a transmission rate adjustment proceeding.

DATES: Persons wishing to become formal parties to the proceeding must 
notify BPA in writing of their intention to do so by the requirements 
stated in this Notice. Petitions to intervene must be received by BPA 
no later than 4:30 pm on March 27, 2000.
    The rate adjustment proceeding will begin with a pre-hearing 
conference at 9:00 am on March 29, 2000, in Portland, Oregon.
    Written comments by non-party participants must be received by June 
15, 2000, to be considered in the Record of Decision (ROD).

ADDRESSES: 1. Petitions to intervene should be directed to Todd Miller, 
Hearing Clerk--LT-7, Bonneville Power Administration, 905 NE 11th Ave., 
Portland, Oregon, 97232. In addition, a copy of the petition must be 
served concurrently on BPA's General Counsel and directed to Stephen R. 
Larson--LT-7, Office of General Counsel, 905 NE 11th Ave., Portland, 
Oregon 97232 (see Part III, A for more information).
    2. Written comments by participants should be submitted to the 
Manager, Corporate Communication--KC-7, Bonneville Power 
Administration, P.O. Box 12999, Portland, Oregon, 97212. You may also 
e-mail your comments to: [email protected].
    3. The pre-hearing conference will be held in the BPA Rates Hearing 
Room, 2nd floor, 911 NE 11th Ave., Portland, Oregon.

FOR FURTHER INFORMATION CONTACT: Information may also be obtained from 
Mr. Michael Hansen--KC-7, Public Involvement and Information 
Specialist, Bonneville Power Administration, P.O. Box 3621, Portland, 
Oregon, 97208-3621; by phone at (503) 230-4328 or toll free at 1-800-
622-4519; or via e-mail to [email protected].
    Responsible Official: Mr. Dennis Metcalf, Transmission Rate Case 
Manager, is the official responsible for the development of BPA's 
transmission and ancillary service rates.

SUPPLEMENTARY INFORMATION: BPA will be holding a formal proceeding to 
establish its Open Access Transmission terms and conditions 
concurrently with this transmission rate adjustment proceeding. BPA is 
also publishing a separate notice in the Federal Register regarding the 
Open Access terms and conditions proceeding.

    Issued in Portland, Oregon, on February 28, 2000.
Judith A. Johansen,
Administrator and Chief Executive Officer.

Table of Contents

Part I--Introduction and Procedural Background
Part II--Purpose and Scope of Hearing
Part III--Public Participation
Part IV--Major Studies and Summary of Proposal
Part V--2002 Transmission and Ancillary Service Rate Schedules

2002 Transmission and Ancillary Service Rate Schedules and General 
Rate Schedule Provisions

FPT-02.1  Formula Power Transmission Rate
FPT-02.3  Formula Power Transmission Rate
IR-02  Integration of Resources Rate
NT-02  Network Integration Rate
NCD-02  Network Contract Demand Rate
PTP-02  Point-to-Point Rate
IS-02  Southern Intertie Rate
IM-02  Montana Intertie Rate
UFT-02  Use-of-Facilities Transmission Rate
AF-02  Advance Funding Rate
TGT-02  Townsend-Garrison Transmission Rate
IE-02  Eastern Intertie Rate
ACS-02  Ancillary Services and Control Area Services Rate

Section I. Generally Applicable Provisions

A. Approval of Rates
B. General Provisions
C. Notices
D. Billing and Payment

Section II. Adjustments, Charges, and Special Rate Provisions

A. Delivery Charge
B. Failure to Comply Penalty
C. Power Factor Penalty Charge
D. Rate Adjustment Due to FERC Order Under FPA Sec. 212
E. Redispatch Adjustment for Accepted Bids
F. Redispatch Charge
G. Reservation Fee
H. Transmission and Ancillary Services Rate Discounts

Section III. Definitions

1. Ancillary Services
2. Billing Factor
3. Control Area
4. Control Area Services
5. Daily Firm Service
6. Daily Nonfirm Service
7. Direct Assignment Facilities
8. Direct Service Industry (DSI) Delivery
9. Dynamic Schedule
10. Eastern Intertie
11. Energy Imbalance Service
12. Federal Columbia River Transmission System
13. Federal System
14. Generation Imbalance
15. Generation Imbalance Service
16. Heavy Load Hours (HLH)
17. Hourly Firm Service
18. Hourly Nonfirm Service
19. Integrated Demand
20. Intentional Deviation
21. Light Load Hours (LLH)
22. Long-Term Firm Service
23. Main Grid
24. Main Grid Distance
25. Main Grid Interconnection Terminal
26. Main Grid Miscellaneous Facilities
27. Main Grid Terminal
28. Measured Demand
29. Metered Demand
30. Montana Intertie
31. Monthly Transmission Peak Load
32. Network (or Integrated Network)
33. Network Load
34. Network Upgrades
35. Nonfirm Service
36. Operating Reserve--Spinning Reserve Service
37. Operating Reserve--Supplemental Reserve Service
38. Operating Reserve Requirement
39. Point of Delivery (POD)
40. Point of Integration (POI)
41. Point of Interconnection (POI)
42. Point of Receipt (POR)
43. Ratchet Demand
44. Reactive Power
45. Reactive Supply and Voltage Control from Generation Sources 
Service
46. Regulation and Frequency Response Service
47. Reliability Obligations
48. Scheduled Demand

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49. Scheduling, System Control and Dispatch Service
50. Secondary System
51. Secondary System Distance
52. Secondary System Interconnection Terminal
53. Secondary System Intermediate Terminal
54. Secondary Transformation
55. Short-Term Firm Service
56. Southern Intertie
57. Spill Condition
58. Spinning Reserve Requirement
59. Supplemental Reserve Requirement
60. Total Transmission Demand
61. Transmission Customer
62. Transmission Demand
63. Transmission Provider
64. Utility Delivery

Part I--Introduction and Procedural Background

    Section 7(i) of the Northwest Power Act, 16 U.S.C. Sec. 839e(i), 
requires that BPA's rates be established according to certain 
procedures. These procedures include, among other things, publication 
of notice of the proposed rates in the Federal Register; one or more 
hearings conducted as expeditiously as practicable by a Hearing 
Officer; opportunity for both oral presentation and written submission 
of views, data, questions, and arguments related to the proposed rates; 
and a decision by the Administrator based on the record. BPA's rate 
proceedings are governed by BPA's Procedures Governing Bonneville Power 
Administration Rate Hearings, 51 FR 7611 (1986) (Procedures). These 
Procedures implement the statutory Section 7(i) requirements. This rate 
proceeding will be governed by section 1010.9 of the Procedures 
providing for a general rate proceeding, as modified by the Hearing 
Officer at the pre-hearing conference. BPA, however, will not hold any 
field hearings to provide for non-party participant oral comments. 
Section 1010.7 of the Procedures prohibits ex parte communications. BPA 
imposed ex parte limitations beginning January 24, 2000.
    The Bonneville Project Act, 16 U.S.C. 832; the Flood Control Act of 
1944, 16 U.S.C. section 825s; the Federal Columbia River Transmission 
System Act, 16 U.S.C. 838; the Northwest Power Act, 16 U.S.C. 839; and 
the Federal Power Act, 16 U.S.C. 212(i)(1)(B)(ii) provide guidance 
regarding BPA's ratemaking. With regard to transmission rates, the 
Northwest Power Act requires BPA to set rates that are sufficient to 
recover, in accordance with sound business principles, the cost of 
transmitting electric power, including amortization of the Federal 
investment over a reasonable period of years, and the other costs and 
expenses incurred by the Administrator. The Federal Columbia 
Transmission System Act requires that the costs of the Federal Columbia 
River Transmission System be equitably allocated between Federal and 
non-Federal power utilizing the system. In addition, rates for 
Commission-ordered transmission service shall be at rates and charges 
that permit the recovery of all costs incurred in connection with the 
transmission service and necessary associated services. BPA must 
satisfy section 212(i) of the Federal Power Act, 16 U.S.C. 824k(i), 
which requires that no BPA transmission rate applicable to transmission 
service ordered by the Commission shall be unjust, unreasonable, or 
unduly discriminatory or preferential as determined by the Commission.
    BPA's proposed 2002 Transmission Rate Schedules are published in 
Part V below. Rate studies and documentation listed in Part IV will be 
provided to parties at the pre-hearing conference to be held on March 
29, 2000, from 9:00 am to 12:00 pm, BPA Rates Hearing Room, 2nd floor, 
911 NE 11th Ave., Portland, Oregon.
    To request any of the studies by telephone, call BPA's document 
request line, (503) 230-4328 or call toll-free 1-800-622-4519. Please 
request the document by its listed title. Also state whether you 
require the accompanying documentation (these can be quite lengthy), 
otherwise the study alone will be provided. The studies and 
documentation will also be available on BPA's website at http://www.transmission.bpa.gov/ratecase.
    A proposed schedule for the formal hearing is stated below. A final 
schedule will be established by the Hearing Officer at the pre-hearing 
conference.

March 27, 2000: Petitions to Intervene
March 29, 2000: Pre-hearing Conference and Filing of BPA Direct Case
May 22, 2000: Parties File Direct Cases
June 15, 2000: Close of Participant Comments
June 19, 2000: Litigants File Rebuttal Testimony
July 11, 2000: Cross-Examination Begins
August 14, 2000: Initial Briefs Filed
August 18, 2000: Oral Argument Before the Administrator
September 11, 2000: Hearing Officer's Recommendations
September 29, 2000: Draft ROD Issued
October 13, 2000: Briefs on Exceptions
November 3, 2000: Final ROD--Final Studies

Part II--Purpose and Scope of Hearing

A. Key Components

1. Overview
    BPA is committed to marketing its power and transmission services 
separately in a manner that is modeled after the regulatory initiatives 
to promote competition in wholesale power markets that were adopted by 
the Commission in 1996. The Commission's initiatives in Orders 888 \1\ 
and 889 \2\ directed public utilities regulated under the Federal Power 
Act to separate their power merchant functions from their transmission 
reliability functions; unbundle transmission and ancillary services 
from wholesale power services; and set separate rates for wholesale 
generation, transmission, and ancillary services. Although BPA is not 
required by statute to follow the Commission's regulatory directives 
promoting competition and open access transmission service, BPA has 
elected to separate its power and transmission operations and unbundle 
its rates in a manner consistent with the directives to the extent 
permitted by law. Accordingly, in 1996 BPA established separate 
business lines: BPA's Power Business Line (PBL) which performs BPA's 
wholesale merchant functions, and BPA's Transmission Business Line 
(TBL) which performs BPA's transmission system operations and 
reliability functions.
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    \1\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Pubic Utilities; Recovery of 
Stranded Costs by Public Utilities and Transmitting Utilities, FERC 
Stats & Regs para. 31,036 (1996).
    \2\ Open Access Same-Time Information System (formerly Real-Time 
Information Networks) and Standards of Conduct, FERC Stats & Regs 
para. 31,035 (1996).
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2. Bifurcated Rate Case
    In setting rates for the period beginning October 1, 2001, BPA 
decided to bifurcate its general rate proceeding into separate power 
and transmission rate proceedings. Establishing BPA's power rates and 
transmission and ancillary services rates in separate rate cases is 
consistent with the Commission's functional separation and unbundling 
paradigm because it permits BPA to resolve power and transmission 
issues in separate rate proceedings. The proceeding to establish BPA's 
wholesale power rates was noticed in the Federal Register on August 13, 
1999, and a formal proceeding began on August 24, 1999.
    This notice announces a proceeding to establish BPA's transmission 
and ancillary services rates for the period October 1, 2001, to 
September 30, 2003.

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BPA's Standards of Conduct do not permit preferential access by the PBL 
to information about BPA's transmission or ancillary service pricing. 
The PBL will therefore be a party to the transmission rate proceeding. 
The PBL will file its own testimony and briefs, and will be subject to 
the rules regarding ex parte communications.
3. Two-Year Transmission Rate Period
    Based on customer input in BPA's transmission workshops, the rate 
period for the rates proposed in this transmission rate adjustment 
proceeding will be two years (FY2002-2003). The two-year rate period 
was adopted in anticipation of the formation of a Regional Transmission 
Organization (RTO). BPA considers that setting rates for this interim 
period will bridge a gap between the expiration of its current rates on 
September 30, 2001, and the formation of an RTO which could incorporate 
BPA's transmission facilities.

B. Cost Increases

    In the 1996 Rate proceeding, BPA originally proposed a 36 percent 
transmission rate increase to cover forecasted costs over the five-year 
rate period (FY1997-2001). As part of the global settlement of power 
and transmission issues, the 1996 transmission rate increase was 
limited to 13.5 percent for the five-year rate period. The TBL 
implemented cost cuts and efficiencies in its transmission operation 
and maintenance programs over the last few years, and deferred 
transmission system improvements in an attempt to stay within the cost 
levels forecasted for the FY1997-2001 rate period. A number of factors 
have caused costs to be greater than levels forecasted in the 1996 case 
and BPA expects further increases in the next rate period. These 
factors include:
     Business line separation costs including the 
implementation of separate systems for scheduling, billing, contracting 
and marketing functions.
     TBL's obligation to fully fund payments to the Civil 
Service Retirement System (an additional $27.6 million in FY02 and 
$17.6 million in FY03), and negotiated wage and benefits increases for 
the 50 percent of all TBL positions covered by the Columbia Power 
Trades Council (CPTC) Agreement.
     Increased capital investments that are needed due to load 
growth, reactive needs, new generation reinforcements, constrained 
paths, changes in reliability criteria, and system replacements.
     Increased investments in technology and personnel to 
address significantly higher and more complex uses of BPA's 
transmission system.
     Planning for replacements of an aging TBL workforce, one-
half of which is eligible to retire within five (5) years.
     The costs of generation inputs needed to provide ancillary 
services which are now the responsibility of the TBL as a result of 
functional unbundling. A portion of these costs were previously bundled 
in the power rates.

C. Overview of the Public Process

1. Transmission Rate Case Customer Workshops
    In preparation for the formal rate hearing, 17 customer workshops 
were held during 1999. TBL held 12 rate case workshops in early 1999 
with individual customer and constituent groups to solicit feedback on 
broad alternatives for the transmission and ancillary services rates 
and the transmission terms and conditions proposals, the timing of the 
formal proceedings, and the term of the rate period. In an August 1999 
workshop, TBL discussed how it had incorporated customer input 
regarding the timing of the proceeding, the length of the rate period, 
proposed transmission terms and conditions and key rate issues. Four 
additional workshops were held in the fall of 1999 to discuss specific 
rate and terms and conditions issues. Two final workshops were held in 
January 2000 to present preliminary transmission and ancillary service 
rates, and proposed open access terms and conditions to interested 
parties.
2. Program Level Funding Workshops
    Issues concerning future capital investments in the transmission 
system and transmission expense levels for transmission system 
development, operation and reliability are being addressed in a public 
process separate from the transmission rate adjustment proceeding 
announced in this notice. The public process consists of numerous 
regional workshops to solicit public comment on BPA's proposed spending 
levels for transmission system operations and reliability. Oral and 
written comments are provided by workshop participants regarding the 
planned transmission capital spending and expenses associated with 
supporting a reliable and safe transmission system. Notices of the 
workshops were widely distributed to TBL's customers and interested 
parties and were published on BPA's Transmission external website. Five 
public workshops were held in November 1999 and two in February 2000. 
Written comments on the planned transmission capital spending and 
expenses were accepted through February 25, 2000. The workshops 
explored customer and constituent views on:
     Maintaining system reliability commensurate with national 
and regional guidelines.
     Meeting local load growth.
     Improving areas where the transmission system is 
constrained.
     Upgrading communications systems with fiber optics.
     Replacing aging equipment.
     Succession planning for the aging workforce, specifically 
in critical positions.
    BPA will close out the public process by issuing a decision by the 
Administrator on transmission spending levels. The results of the 
Administrator's decision on transmission program spending levels will 
be reflected in the revenue requirement study in the final rate 
proposal.

D. Scope of the Transmission Rate Proceeding

    Many of the decisions that determine TBL's costs have been or will 
be made in public review processes other than the transmission rate 
proceeding. This section provides guidance to the Hearing Officer as to 
those matters that are within the scope of the transmission rate 
proceeding and those that are outside the scope.
1. Spending Levels
    As described above, Program Level Funding workshops were held 
throughout the region to clarify, discuss, and provide the public the 
opportunity to comment orally and in writing on the proposed capital 
expenditures and expenses for transmission. BPA will consider the 
comments. The Administrator will close out the public process by 
issuing a final decision on the spending levels. The results of that 
decision will serve as the basis for the transmission capital and 
expense levels that will be reflected in the revenue requirements study 
in the final rate proposal. In addition, decisions may be made by 
Congress during this proceeding regarding spending levels for 
transmission investments and expenses including fiber optic 
communication equipment on federal transmission facilities. Pursuant to 
section 1010.3(f) of BPA's Procedures, the Administrator directs the 
Hearing Officer to exclude from the record any material attempted to be 
submitted or arguments attempted to be made in the hearing which seek 
in any way to

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challenge the appropriateness or reasonableness of the Administrator's 
decision on transmission spending levels, including capital and expense 
budgets currently under review in the Program Level Funding public 
process. If, and to the extent, any re-examination of spending levels 
is necessary, that re-examination will occur outside of the rate 
proceeding. Excluded from this direction are matters such as sources of 
capital for investments, interest rate forecasts, scheduled 
amortization, forecasted depreciation, forecasts of system replacements 
for repayment studies, and interest expense. Also excluded are expense 
and revenue uncertainties and risks included in the risk analysis.
2. Issues Decided in Power Rate Proceeding
    As BPA's August 13, 1999, Federal Register notice indicates, a 
number of issues that affect BPA's transmission and ancillary service 
rates are addressed in BPA's wholesale power rate proceeding. In the 
Power rate proceeding, BPA proposed the following: A methodology for 
functionalizing generation and transmission costs, including a 
methodology for functionalizing corporate overhead costs to the 
business lines; unit costs for generation inputs for operating reserves 
and regulation ancillary services; the generation input cost for 
reactive supply and voltage control from generation resources; the 
generation costs of station service and remedial action schemes; and 
the allocation of generation integration and generator step-up 
transformers costs to the business lines. BPA also proposed in that 
proceeding a treatment for costs over third party transmission systems 
(General Transfer Agreements or their replacement) for the delivery of 
Federal and non-Federal power.
    A decision in the Power rate proceeding is expected before the 
conclusion of the Transmission rate proceeding. Therefore, the initial 
proposal in the Transmission rate proceeding reflects BPA's proposals 
in the Power rate proceeding. It is BPA's intent that the 
Administrator's final decision on these issues in the Power rate 
proceeding will be reflected and implemented in the final studies in 
the final transmission rate proposal. The Administrator directs the 
Hearing Officer to exclude from the record any material attempted to be 
submitted or arguments attempted to be made in the hearing which seek 
in any way to address final decisions in the Power rate proceeding.
    The National Environmental Policy Act. BPA's initial rate proposal 
falls within the scope of the final Business Plan Environmental Impact 
Statement (DOE/EIS-0183, June 1995), completed in June 1995. The 
analysis in the EIS includes an evaluation of the environmental impacts 
of rate design issues for BPA's transmission products and services. 
Comments on the Business Plan EIS were received outside the formal rate 
hearing process and were included in the 1996 rate case record and 
considered by the Administrator in the final rate proposal. BPA will 
review the Business Plan EIS to ensure the impacts of BPA's 2002 
Transmission rate proposal is within the range of alternatives. If a 
supplemental analysis is needed, BPA will seek comments outside of the 
formal rate proceeding. Comments, if received, will be included in the 
rate case record and considered by the Administrator in making a final 
decision establishing BPA's 2002 transmission and ancillary services 
rates.

Part III--Public Participation

A. Distinguishing Between ``Participants'' and ``Parties''

    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 are defined in the BPA Procedures as persons 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 pre-hearing 
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.
    Written comments by participants will be included in the record if 
they are received by June 15, 2000. This date follows the anticipated 
submission of BPA's and all other parties' direct cases. Written views, 
supporting information, questions, and arguments should be submitted to 
BPA's Manager of Corporate Communications at the address listed in the 
ADDRESSES section of this Notice.
    Persons wishing to become a party to this transmission rate 
adjustment proceeding must notify BPA in writing. Petitioners may 
designate no more than two (2) representatives upon whom service of 
documents will be made. Petitions to intervene shall state the name and 
address of the person requesting party status, and the person's 
interest in the hearing.
    Petitions to intervene as parties in the rate proceeding are due to 
the Hearing Officer by 4:30 pm on March 27, 2000. The petition should 
be directed to: Todd Miller, Hearing Clerk--LT-7, Bonneville Power 
Administration, 905 NE 11th Avenue, Portland, Oregon 97232.
    Petitioners must explain their interests in sufficient detail to 
permit the Hearing Officer to determine whether they 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 pre-hearing conference. Any opposition to an intervention 
petition may instead be made at the pre-hearing conference. Any party, 
including BPA, may oppose a petition for intervention. Persons who have 
been denied party status in any past BPA rate proceeding shall continue 
to be denied party status unless they establish a significant change of 
circumstances. All timely applications will be ruled on by the Hearing 
Officer. Late interventions are strongly disfavored. Opposition to a 
petition to intervene filed after the pre-hearing conference shall be 
filed and received by BPA within two (2) days after service of the 
petition.

B. Developing the Record

    The hearing record will include, among other things, the 
transcripts of the hearing, written material 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 then will review the record, will supplement, if necessary, and 
will certify the record to the Administrator for decision.
    The Administrator will develop final proposed rates based on the 
record, information from the program level funding workshops, documents 
prepared pursuant to the National Environmental Policy Act and other 
environmental statutes and such other material or information as may 
have been submitted to or developed by the Administrator. The basis for 
the final proposed rates first will be expressed in the Administrator's 
Draft Record of Decision. Parties will have an opportunity to respond 
to the Draft Record of Decision as provided in BPA's Procedures. The 
Administrator will serve copies of the Final Record of Decision on all 
parties. BPA will file its rates with the Commission for

[[Page 14106]]

confirmation and approval after issuance of the Final Record of 
Decision.
    BPA must continue to meet with customers in the ordinary course of 
business during the rate proceeding. To comport with the rate case 
procedural rule prohibiting ex parte communications, BPA will provide 
necessary notice of meetings involving rate proceeding issues to 
provide an opportunity for participation by all rate proceeding 
parties. Parties should be aware, however, that such meetings may be 
held on very short notice and should be prepared to devote the 
necessary resources to participate fully in every aspect of the rate 
proceeding.

Part IV--Major Studies and Summary of Proposal

A. Major Studies

    1. Revenue Requirement--Calculates transmission revenue 
requirements for the FY 2002-2003 rate period and assigns revenue 
requirements to transmission segments and ancillary services. The 
Revenue Requirement Study also demonstrates cost recovery for the 
transmission function.
    2. Segmentation--Assigns the transmission facilities to segments 
according to the types of services they provide. Six transmission 
segments are identified: Generation Integration, Integrated Network, 
Southern Intertie, Eastern Intertie, Utility Delivery, and DSI 
Delivery. In addition, a new Ancillary Services segment is identified 
which is subdivided into the specific ancillary services.
    3. Transmission Rate Study--Forecasts sales, allocates costs to the 
various services, and designs rates to recover allocated costs.

B. Summary of Proposal

1. Transmission Rates
    TBL is proposing five different rates for the use of its Integrated 
Network segment:
     Formula Power Transmission (FPT-02) rate--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. FPT customers are not subject to charges for 
the two required ancillary services, Reactive Supply and Voltage 
Control from Generation Sources, and Scheduling, System Control and 
Dispatch. Although TBL is not offering new FPT contracts, a number of 
FPT contracts continue in place during the rate period.
     Integration of Resources (IR-02) rate--The IR rate is a 
postage stamp, contract demand rate for the use of the Integrated 
Network, similar to the PTP service. It includes a Short Distance 
discount. Although TBL is not offering new IR contracts, a number of IR 
contracts remain in place during the rate period.
     Network Integration Transmission (NT-02) rate--The NT rate 
applies to customers taking service under the NT open access tariff, 
which allows customers to flexibly serve their retail load. It includes 
a Load Shaping Charge applied to the customer's total load, and a Base 
Charge applied to the total load less Customer Served Load, if any. 
Customer Served Load is the amount of load that the customer agrees to 
serve without using its NT service. NT customers also must participate 
in redispatch protocols and pay a share of redispatch costs.
     Point to Point (PTP-02) rate--The PTP rate is a contract 
demand rate that applies to customers taking service on BPA's network 
facilities under the PTP open access tariff, which provides customers 
with flexible service from identified Points of Receipt (PORs) to 
identified Points of Delivery (PODs). There are separate PTP rates for 
long-term firm service; daily firm and non-firm service; and hourly 
firm and non-firm service. The rate for long-term firm service contains 
a Short Distance discount. All daily and hourly PTP rates are 
downwardly flexible.
     Network Contract Demand (NCD-02) rate--The NCD rate is a 
contract demand rate that applies to service under the NCD open access 
tariff, which provides customers with flexible long term service from 
Network Resources to identified Points of Delivery. The flexibility 
that NCD customers have to utilize Network Resources is matched by the 
flexibility to receive firm service at secondary PODs. NCD customers 
also must participate in redispatch protocols and pay a share of 
redispatch costs.
    In addition to the five rates for network use, other proposed 
transmission rates include:
     Southern Intertie (IS-02) and the Montana Intertie (IM-02) 
rates are contract demand rates that apply to customers taking service 
under the PTP open access tariff on the Southern Intertie and Montana 
Intertie. These rates are structured similarly to the PTP rate for 
service on network facilities.
     The Townsend-Garrison Transmission (TGT-02) rate and the 
Eastern Intertie rate (IE-02) are developed pursuant to the Montana 
Intertie agreement.
     The Use-of-Facilities (UFT-02) rate establishes a formula 
for charging for the use of a specific facility based on the annual 
cost of that facility.
     The Advance Funding (AF-02) rate allows TBL 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 who delay start of requested long-term 
firm service, a redispatch charge to NT and NCD customers for the net 
cost of redispatch, Incremental Rates for transmission requests that 
require new facilities, a penalty charge for failure to comply with 
TBL's curtailment, redispatch or load shedding orders, and an 
Unauthorized Increase Charge for customers who exceed their contracted 
amounts.
2. Ancillary Services Rates
    TBL is proposing rates for the six (6) ancillary services that FERC 
Order 888 requires transmission providers to offer:
     Scheduling, System Control, and Dispatch Service is 
required to schedule and secure the movement of power through, out of, 
within, or into the BPA Control Area. All transmission contract 
holders, except FPT customers, are required to purchase this service 
from BPA. The billing factor is the same as the billing factor for the 
transmission service being provided. For NT customers, the billing 
factor is the same as for the NT Base charge.
     Reactive Supply and Voltage Control from Generation 
Sources Service provides reactive support to the transmission system, 
and is required to maintain transmission system voltages within 
acceptable limits. All transmission contract holders, except FPT 
customers, are required to purchase this service from BPA. The billing 
factor is the same as the billing factor for the transmission service 
being provided. For NT customers, the billing factor will be the same 
as for the NT Base charge.
     Regulation and Frequency Response Service provides the 
continuous balancing of resources (generation and interchange) with 
load and maintains frequency at 60 Hz. This service is accomplished by 
committing on-line generation (predominantly through the use of 
automatic generation control equipment) whose output is raised or 
lowered to follow the moment to moment changes in load. Rates for this 
service will be applied to load in the BPA control area.
     Energy Imbalance Service is delivered when a difference 
occurs between the scheduled and actual

[[Page 14107]]

delivery of energy to a load located within the control area over a 
single hour. The rate for energy imbalance differs based on whether the 
imbalance is inside or outside tolerance limits.
     Operating Reserve-Spinning Reserve Service is needed to 
serve load immediately in the event of a system contingency. The 
billing factor for this service is the customer's share of the reserve 
obligation of the control area, as defined by the Western Systems 
Coordinating Council and the Northwest Power Pool.
     Operating Reserve-Supplemental Reserve Service is 
available within a short period of time to serve load in the event of a 
system contingency. This service may be provided by units that are on-
line but unloaded, quick-start generation, or by interruptible load. 
The billing factor for this service is the customer's share of the 
reserve obligation of the control area, as defined by the WSCC and the 
Northwest Power Pool.
    In addition to the rates for Ancillary Services, the TBL is 
proposing rates for four (4) Control Area services.
3. Issues
    Risk Analysis: For the first time, BPA will include an independent 
risk analysis performed for the transmission function. The Risk 
Analysis is used to ensure that BPA has sufficient end-of-year cash 
reserves to meet its U.S. Treasury payment obligations on time and in 
full during the two-year rate period with a 95 percent probability of 
success. In prior rate cases, the Risk Analysis was performed at the 
agency level and focused on power-related risks. The Risk Analysis for 
this transmission rate proposal evaluates uncertainty in transmission 
costs and revenues to estimate the amount of planned net revenue for 
risk needed to achieve the BPA Treasury payment probability standard 
associated with transmission cost recovery.
    Segmentation: TBL proposes to divide its transmission system into 
segments in order to assign the costs of the Federal transmission 
system to the users of those segments. Those segments include the 
Generation Integration, Integrated Network, Southern Intertie, Eastern 
Intertie, Utility Delivery, and DSI Delivery segments. BPA also 
proposes a new segment in this rate proceeding to determine the revenue 
requirement for Ancillary Services.
    Transmission Rate Development: The Transmission Rate Study 
forecasts sales and calculates the transmission rates based on the 
segmented revenue requirement. Revenues from various rates and charges 
that will not be adjusted or revised in this rate case are forecasted 
and revenue credited against the segmented revenue requirements. The 
FPT rate, which includes many separate charges for the use of specific 
types of transmission facilities, is then calculated. For the 2002 rate 
case, TBL proposes that all the FPT-96 component charges be scaled up 
by the overall increase in unit Network costs. Unit Network costs are 
calculated by adding the Network component of required ancillary 
services to Network costs and dividing by annual peak usage as 
determined in a power flow analysis.
    Rates for Contract Demand service on the Network (PTP, NCD, and IR) 
are calculated by dividing the remaining Network costs after crediting 
revenues from FPT by total peak load. Peak load for the contract demand 
services is equal to the forecasted contract demands; for NT service, 
the peak load used in the divisor is the NT load on the hour of the 
annual transmission system peak. TBL proposes to use a 1CP (one 
coincidental peak) method for calculating rates in this rate period.
    The rates for short-term PTP use are developed from the annual 
rates. The TBL is proposing to eliminate monthly and weekly PTP service 
and instead allow customers to purchase any number of consecutive days, 
providing the total is less than one year. Transmission system loads 
are higher during weekdays than weekends, so TBL is proposing a higher 
rate for the first five (5) days of any daily block than for all 
remaining days. Similarly, the transmission system usage is higher 
during the 16 daily peak hours, so the hourly rate is set by dividing 
the daily rate by only 16 hours. All of the short-term PTP rates can be 
discounted.
    The NT base charge, applied to the Network Load (i.e., total retail 
load), minus Customer-Served Load, on the hour of the transmission 
system's monthly peak, is set equal to the PTP rate. The NT load-
shaping charge, applied to the total Network Load, is calculated to 
recover the remaining NT revenue requirement.
    The rates for the use of the Southern Intertie are calculated from 
the segmented costs and forecasted use in a manner similar to the PTP 
calculations on the Network. Usage of the Southern Intertie tends to be 
higher during the summer, when more power from hydro is available in 
the PNW and power usage and prices are higher in California. To reflect 
this fact, the TBL is proposing higher rates for North-to-South use in 
the summer months and lower prices for North-to-South use in the 
winter. Rates for South-to-North use are not seasonally differentiated.
    At some of the workshops the TBL has conducted, a number of 
customers suggested that the TBL should sell Southern Intertie capacity 
using an auction. The TBL believes that the idea of an auction has 
considerable merit, but has not developed a specific proposal for an 
auction. The TBL invites parties that favor the use of an auction to 
make specific proposals in their testimony in the rate case.
    The proposed 2002 rates include charges for the use of the Utility 
Delivery Segment and DSI Delivery segment. The Utility Delivery charge 
is a uniform charge applied to all use of the segment. The DSI Delivery 
charge is a Use-of-Facility charge based on the cost of the individual 
delivery substation being used. The TBL is proposing some changes to 
the charge and how it is applied to insure that the charge fully 
recovers the cost of the segment.
    The TBL is changing the name of the Reactive Power Charge to the 
Power Factor Penalty charge to avoid confusion with the Ancillary 
Service, Reactive Supply and Voltage Control from Generation Sources 
service. The Charge is increased due to the ``penalty'' nature of the 
charge and BPA's desire to send an appropriate price signal to 
customers to install equipment and manage their reactive requirements.

Part V--2002 Transmission and Ancillary Service Rate Schedules

Bonneville Power Administration Transmission Business Line; 2002 
Transmission and Ancillary Service Rate Schedules and General Rate 
Schedule Provisions

Schedule FPT-02.1  Formula Power Transmission Rate

Section I. Availability

    This schedule supersedes Schedule FPT-96.1 for all firm 
transmission agreements which provide for application of FPT rates that 
may be adjusted not more frequently than once a year. This schedule is 
applicable only to such transmission agreements executed prior to 
October 1, 1996. It is available for firm transmission of non-Federal 
power using the Main Grid and/or Secondary System of the Federal 
Columbia River Transmission System. This schedule is for full-year and 
partial-year service and for either continuous or intermittent service 
when firm transmission service is required. For facilities at voltages 
lower than the Secondary System, a different rate schedule may be 
specified. Service under this schedule is subject to TBL's

[[Page 14108]]

General Rate Schedule Provisions (GRSPs).

Section II. Rate

    The monthly charge per kilowatt shall be one-twelfth of the sum of 
the Main Grid Charge and the Secondary System Charge, as applicable and 
as specified in the agreement.
A. Main Grid Charge
    The Main Grid Charge per kilowatt shall be the sum of one or more 
of the following annual charges as specified in the agreement:
    1. Main Grid Distance: $0.0557 per mile.
    2. Main Grid Interconnection Terminal: $0.58.
    3. Main Grid Terminal: $0.65.
    4. Main Grid Miscellaneous Facilities: $3.18.
B. Secondary System Charge
    The Secondary System Charge per kilowatt shall be the sum of one or 
more of the following annual charges as specified in the agreement:
    1. Secondary System Distance: $0.5478 per mile.
    2. Secondary System Transformation: $5.99.
    3. Secondary System Intermediate Terminal: $2.31.
    4. Secondary System Interconnection Terminal: $1.64.

Section III. Billing Factors

    Unless otherwise stated in the agreement, the Billing Factor for 
the rates specified in section II shall be the largest of:
    1. The Transmission Demand;
    2. The highest hourly Scheduled Demand for the month; or
    3. The Ratchet Demand.

Section IV. Adjustments, Charges, and Other Rate Provisions

A. Ancillary Services
    Ancillary Services that may be required to support FPT transmission 
service are available under the ACS rate schedule. FPT customers do not 
pay the ACS charges for Scheduling, System Control and Dispatch Service 
and Reactive Supply and Voltage Control from Generation Sources 
Service, because these services are included in FPT service.
B. Power Factor Penalty
    Customers taking service under this rate schedule are subject to 
the Power Factor Penalty Charge specified in section II.C. of the 
GRSPs.
C. Failure To Comply Penalty
    Customers taking service under this rate schedule are subject to 
the Failure to Comply Penalty Charge specified in section II.B of the 
GRSPs.

Schedule FPT-02.3  Formula Power Transmission Rate

Section I. Availability

    This schedule supersedes Schedule FPT-96.3 for all firm 
transmission agreements which provide for application of FPT rates that 
may be adjusted not more frequently than once every three years. This 
schedule is applicable only to such transmission agreements executed 
prior to October 1, 1996. It is available for firm transmission of non-
Federal power using the Main Grid and/or Secondary System of the 
Federal Columbia River Transmission System. This schedule is for full-
year and partial-year service and for either continuous or intermittent 
service when firm transmission service is required. For facilities at 
voltages lower than the Secondary System, a different rate schedule may 
be specified. Service under this schedule is subject to TBL's General 
Rate Schedule Provisions (GRSPs).

Section II. Rate

    The monthly charge per kilowatt shall be one-twelfth of the sum of 
the Main Grid Charge and the Secondary System Charge, as applicable and 
as specified in the agreement.
A. Main Grid Charge
    The Main Grid Charge per kilowatt shall be the sum of one or more 
of the following annual charges as specified in the agreement:
    1. Main Grid Distance: $0.0557 per mile.
    2. Main Grid Interconnection Terminal: $0.58.
    3. Main Grid Terminal: $0.65.
    4. Main Grid Miscellaneous Facilities: $3.18.
B. Secondary System Charge
    The Secondary System Charge per kilowatt shall be the sum of one or 
more of the following annual charges as specified in the agreement:
    1. Secondary System Distance: $0.5478 per mile.
    2. Secondary System Transformation: $5.99.
    3. Secondary System Intermediate Terminal: $2.31.
    4. Secondary System Interconnection Terminal: $1.64.

Section III. Billing Factors

    Unless otherwise stated in the agreement, the Billing Factor for 
the rates specified in section II shall be the largest of:
    1. The Transmission Demand;
    2. The highest hourly Scheduled Demand for the month; or
    3. The Ratchet Demand.

Section IV. Adjustments, Charges, and Other Rate Provisions

A. Ancillary Services
    Ancillary Services that may be required to support FPT transmission 
service are available under the APS rate schedule. FPT customers do not 
pay the ACS charges for Scheduling, System Control and Dispatch Service 
and Reactive Supply and Voltage Control from Generation Sources 
Service, because these services are included in FPT service.
B. Power Factor Penalty
    Customers taking service under this rate schedule are subject to 
the Power Factor Penalty Charge specified in section II.C. of the 
GRSPs.
C. Failure To Comply Penalty
    Customers taking service under this rate schedule are subject to 
the Failure to Comply Penalty specified in section II.B of the GRSPs.

Schedule IR-02  Integration of Resources Rate

Section I. Availability

    This schedule supersedes Schedule IR-96 and is available for 
transmission of non-Federal power for full-year firm transmission 
service and nonfirm transmission service in amounts not to exceed the 
customer's total Transmission Demand using Federal Columbia River 
Transmission System Network and Delivery facilities. This schedule is 
applicable only to Integration of Resource (IR) agreements executed 
prior to October 1, 1996. Service under this schedule is subject to 
TBL's General Rate Schedule Provisions (GRSPs).

Section II. Rate

    The monthly charge shall be A or B.
A. Base Rate
    $1.132 per kilowatt.
B. Short Distance Discount (SDD) Rate
    For Points of Integration (POI) specified in the IR agreement as 
being short-distance POIs, for which Network facilities are used for a 
distance of less than 75 circuit miles, the monthly rate shall be:

[0.6 + (0.4  x  transmission distance/75)] * $1.132 per kilowatt

Where:
    The transmission distance is the circuit miles between the POI for 
a generating resource of the customer and

[[Page 14109]]

a designated Point of Delivery serving load of the customer. Short-
distance POIs are determined by BPA after considering factors in 
addition to transmission distance.

Section III. Billing Factors

    To the extent that the agreement provides for the customer to be 
billed for transmission in excess of the Transmission Demand or Total 
Transmission Demand, as defined in the agreement, at the Point-to-Point 
Hourly Nonfirm Rate, such transmission service shall not contribute to 
the Billing Factor for the IR rate provided that the customer requests 
such treatment and TBL approves in accordance with the prescribed 
provisions in the agreement.
    The Billing Factor for rates specified in section II shall be the 
largest of:
    1. The annual Transmission Demand, or, if defined in the agreement, 
the annual Total Transmission Demand;
    2. The highest hourly Scheduled Demand for the month; or
    3. The Ratchet Demand.
    When the Scheduled Demand or Ratchet Demand is the Billing Factor, 
short-distance POIs shall be charged the Base Rate specified in section 
II.A for the amount in excess of Transmission Demand.

Section IV. Adjustments, Charges, and Other Rate Provisions

A. Ancillary Services
    Customers taking service under this rate schedule are subject to 
the ACS-02 Scheduling, System Control and Dispatch Service Rate and the 
Reactive Supply and Voltage Control from Generation Sources Service 
Rate. Other Ancillary Services that may be required to support IR 
transmission service are available under the ACS rate schedule.
B. Power Factor Penalty
    Customers taking service under this rate schedule are subject to 
the Power Factor Penalty Charge specified in section II.C of the GRSPs.
C. Failure To Comply Penalty
    Customers taking service under this rate schedule are subject to 
the Failure to Comply Penalty Charge specified in section II.B of the 
GRSPs.
D. Delivery Charge
    Customers taking service under this rate schedule are subject to 
the Delivery Charge specified in section II.A. of the GRSPs.

Schedule NT-02  Network Integration Rate

Section I. Availability

    This schedule supersedes Schedule NT-96. It is available to 
Transmission Customers taking Network Integration Transmission (NT) 
Service over Federal Columbia River Transmission System Network and 
Delivery facilities. Terms and conditions of service are specified in 
the Open Access Transmission Tariff. This schedule is available also 
for transmission service of a similar nature ordered by the Federal 
Energy Regulatory Commission (FERC) pursuant to sections 211 and 212 of 
the Federal Power Act (16 U.S.C. Secs. 824j and 824k). Service under 
this schedule is subject to TBL's General Rate Schedule Provisions 
(GRSPs).

Section II. Rate

    The monthly charge will be the sum of A and B.
A. Base Charge
    $1.132 per kilowatt per month.
B. Transmission Load Shaping Charge
    $0.326 per kilowatt per month.

Section III. Billing Factors

A. Base Charge
    1. If no Declared Customer-Served Load (CSL) is specified in the 
customer's NT Service Agreement, the monthly Billing Factor for the 
Base Charge specified in section II.A shall be the customer's Network 
Load on the hour of the Monthly Transmission Peak Load.
    2. If an amount of Declared CSL is specified in the customer's NT 
Service Agreement, the monthly Billing Factor for the Base Charge 
specified in section II.A shall be a or b:
    a. For the billing month, if the sum of the Actual CSLs occurring 
during Heavy Load Hours (HLH) is greater than or equal to 60 percent of 
the Declared CSL multiplied by the number of HLHs in the billing month, 
the monthly Billing Factor shall be the customer's Network Load on the 
hour of the Monthly Transmission Peak Load, less Declared CSL.
    b. For the billing month, if the sum of the Actual CSLs occurring 
during HLH is less than 60 percent of the Declared CSL multiplied by 
the number of HLHs in the billing month, the monthly Billing Factor 
shall be the customer's Network Load on the hour of the Monthly 
Transmission Peak Load. The Billing Factor will be reduced by any 
megawatts charged the NT Unauthorized Increase Charge under section 
IV.D. for the month.

Where:
    ``Declared Customer-Served Load (CSL)'' is the monthly amount of 
the Transmission Customer's Network Load in megawatts that the 
Transmission Customer elects to serve on a firm basis from sources 
internal to its system or over non-Federal transmission facilities or 
pursuant to contracts other than the Network Integration Service 
Agreement. The customer's Declared CSL is contractually specified for 
each month.
    ``Actual Customer-Served Load (CSL)'' is the actual hourly amount 
of the Network Load in megawatts that the customer serves on a firm 
basis from sources internal to its system or over non-Federal 
transmission facilities or pursuant to contracts other than the Network 
Integration Service Agreement.
B. Transmission Load Shaping Charge
    The monthly Billing Factor for the Transmission Load Shaping Charge 
specified in section II.B shall be the Network Load on the hour of the 
Monthly Transmission Peak Load.

Section IV. Adjustments, Charges, and Other Rate Provisions

A. Ancillary Services
    Customers taking service under this rate schedule are subject to 
the ACS Scheduling, System Control and Dispatch Service Rate and the 
Reactive Supply and Voltage Control from Generation Sources Service 
Rate. Other Ancillary Services that are required to support NT 
transmission service are also available under the ACS rate schedule.
B. Delivery Charge
    Customers taking service under this rate schedule are subject to 
the Delivery Charge specified in section II.A of the GRSPs.
C. Metering Adjustment
    At those Points of Delivery that do not have meters capable of 
determining the demand on the hour of the Monthly Transmission Peak 
Load, the Billing Demand shall be calculated by substituting (1) the 
sum of the highest hourly demand that occurs during the billing month 
at all Points of Delivery multiplied by 0.66 for (2) Network Load on 
the hour of the Monthly Transmission Peak Load.
D. NT Unauthorized Increase Charge
    If the customer's Actual Customer-Served Load (CSL) is less than 
its Declared CSL, the NT Unauthorized Increase Charge shall be 
assessed.
    1. Rate: $6.79 per kilowatt per month.
    2. Billing Factor: In each billing month on the hour of the Monthly

[[Page 14110]]

Transmission Peak Load, the Billing Factor shall equal the Declared CSL 
minus the Actual CSL.
E. Power Factor Penalty
    Customers taking service under this rate schedule are subject to 
the Power Factor Penalty Charge specified in section II.C of the GRSPs.
F. Redispatch
    For each hour that TBL implements redispatch procedures pursuant to 
the Open Access Transmission Tariff, NT and NCD Transmission Customers 
shall be subject to:
    1. The Redispatch Adjustment for Accepted Bids specified in section 
II.E of the GRSPs, and
    2. The Redispatch Charge specified in section II.F of the GRSPs.
G. Failure To Comply Penalty
    Customers taking service under this rate schedule are subject to 
the Failure to Comply Penalty specified in section II.B of the GRSPs.
H. Direct Assignment Facilities
    TBL shall collect the capital and related costs of a Direct 
Assignment Facility under the Advance Funding (AF) rate or the Use-of-
Facilities (UFT) rate. Other associated costs, including but not 
limited to operations, maintenance, and general plant costs, also shall 
be recovered from the Network Integration Transmission customer under 
an applicable rate schedule.
I. Incremental Cost Rates
    The rates specified in section II are applicable to service over 
available transmission capacity. NT customers that integrate new 
Network Resources, new Member Systems, or new native load customers 
that would require TBL to construct Network Upgrades shall be subject 
to the higher of the rates specified in section II. or incremental cost 
rates for service over such facilities. Incremental cost rates would be 
developed pursuant to section 7(i) of the Northwest Power Act.
J. Rate Adjustment Due to FERC Order Under FPA Sec. 212
    Customers taking service under this rate schedule are subject to 
the Rate Adjustment Due to FERC Order under FPA Sec. 212 specified in 
section II.D of the GRSPs.

Schedule NCD-02  Network Contract Demand Rate

Section I. Availability

    This schedule is available to Transmission Customers taking Network 
Contract Demand (NCD) Transmission Service over Federal Columbia River 
Transmission System (FCRTS) Network and Delivery facilities. Terms and 
conditions of service are specified in the Open Access Transmission 
Tariff. This schedule is available also for transmission service of a 
similar nature ordered by the Federal Energy Regulatory Commission 
(FERC) pursuant to sections 211 and 212 of the Federal Power Act (16 
U.S.C. Secs. 824j and 824k). Service under this schedule is subject to 
TBL's General Rate Schedule Provisions (GRSPs).

Section II. Rate

    $1.132 per kilowatt per month.

Section III. Billing Factor

    The Billing Factor shall be the sum of the Point of Delivery 
Transmission Demands.

Section IV. Adjustments, Charges, and Other Rate Provisions

A. Ancillary Services
    Customers taking service under this rate schedule are subject to 
the ASC-02 Scheduling, System Control and Dispatch Service Rate and the 
Reactive Supply and Voltage Control from Generation Sources Service 
Rate. Other Ancillary Services that are required to support NCD 
Transmission Service are available under the ASC rate schedule.
B. Delivery Charge
    Customers taking service under this rate schedule are subject to 
the Delivery Charge specified in section II.A of the GRSPs.
C. Power Factor Penalty
    Customers taking service under this rate schedule are subject to 
the Power Factor Penalty Charge specified in section II.C of the GRSPs.
D. NCD Unauthorized Increase Charge
    Customers who exceed their Point of Delivery (POD) Transmission 
Demand at their PODs or at their Network Resources shall be subject to 
the NCD Unauthorized Increase Charge.
    1. Rate: $6.79 per kilowatt per month.
    2. Billing Factor: The billing factor shall be the higher of a or 
b.
    a. POD Unauthorized Increase. For each hour of the monthly billing 
period, BPA shall determine the amount by which the Transmission 
Customer exceeds its Transmission Demands at each POD, to the extent 
practicable. BPA shall use hourly measurements based on a 10-minute 
moving average to calculate actual demands at PODs associated with 
loads that are one-way dynamically scheduled. Actual demands at all 
other PODs will be based on 60-minute integrated demands or 
transmission schedules.
    For each hour, BPA will sum these amounts that exceed Transmission 
Demands for all PODs. The POD unauthorized increase for the monthly 
billing period shall be the highest one-hour POD sum.
    b. Network Resource Unauthorized Increase. For each hour of the 
monthly billing period, BPA shall determine the amount by which the sum 
of the actual demands at Network Resources exceeds the total 
Transmission Demand, to the extent practicable. BPA shall use hourly 
measurements based on a 10-minute moving average to calculate actual 
demands at Network Resources that are one-way dynamically scheduled. 
Actual demands at all other Network Resources will be based on 60-
minute integrated demands or transmission schedules.
    For each hour, BPA will determine the amount that the demand at 
Network Resources exceeds the total Transmission Demand. The Network 
Resource unauthorized increase for the monthly billing period shall be 
the highest hourly amount.
E. Redispatch
    For each hour that TBL implements redispatch procedures pursuant to 
the Open Access Transmission Tariff, NT and NCD Transmission Customers 
shall be subject to:
    1. The Redispatch Adjustment for Accepted Bids specified in section 
II.E of the GRSPs, and
    2. The Redispatch Charge specified in section II.F of the GRSPs.
F. Failure To Comply Penalty
    Customers taking service under this rate schedule are subject to 
the Failure to Comply Penalty Charge specified in section II.B of the 
GRSPs.
G. Reservation Fee
    Customers who request new or increased firm transmission service 
under this rate schedule and want to reserve transmission capacity to 
accommodate such service are subject to the Reservation Fee specified 
in section II.G of the GRSPs.
H. Direct Assignment Facilities
    TBL shall collect the capital and related costs of a Direct 
Assignment Facility under the Advance Funding (AF) rate or the Use-of-
Facilities (UFT) rate. Other associated costs, including but not 
limited to operations, maintenance, and general plant costs, also shall 
be recovered from the Network Contract Demand

[[Page 14111]]

Transmission customer under an applicable rate schedule.
I. Incremental Cost Rates
    The rates specified in section II are applicable to service over 
available transmission capacity. Customers requesting new or increased 
firm service that would require TBL to construct Network Upgrades to 
alleviate a capacity constraint may be subject to incremental cost 
rates for such service if incremental cost is higher than embedded 
cost. Incremental cost rates would be developed pursuant to section 
7(i) of the Northwest Power Act.
J. Rate Adjustment Due to FERC Order Under FPA Sec. 212
    Customers taking service under this rate schedule are subject to 
the Rate Adjustment Due to FERC Order under FPA Sec. 212 specified in 
section II.D of the GRSPs.

Schedule PTP-02  Point-to-Point Rate

Section I. Availability

    This schedule supersedes Schedules PTP-96, RNF-96, and ET-96. It is 
available to Transmission Customers taking Point-to-Point (PTP) 
Transmission Service over Federal Columbia River Transmission System 
(FCRTS) Network and Delivery facilities. Terms and conditions of 
service are specified in the Open Access Transmission Tariff. This 
schedule is available also for transmission service of a similar nature 
ordered by the Federal Energy Regulatory Commission (FERC) pursuant to 
sections 211 and 212 of the Federal Power Act (16 U.S.C. Secs. 824j and 
824k). Service under this schedule is subject to TBL's General Rate 
Schedule Provisions (GRSPs).

Section II. Rate

A. Long-Term Firm Service
    $1.132 per kilowatt per month.
B. Short-Term Firm and Nonfirm Service
    The charges for Short-Term Firm and Nonfirm Service shall not 
exceed:

    1. Daily: For each reservation:
    a. Days 1 to 5: $0.052 per kilowatt per day.
    b. Day 6 and beyond: $0.037 per kilowatt per day.
    2. Hourly: 3.26 mills per kilowatthour.

Section III. Billing Factors

    A. The Billing Factor for Long-Term Firm Service, Short-Term Firm 
Service, and Daily Nonfirm Service shall be the greater of:
    1. The sum of the Point of Receipt Transmission Demands, or
    2. The sum of the Point of Delivery Transmission Demands.
    B. The Billing Factor for Hourly Nonfirm Service shall be the 
monthly sum of scheduled kilowatthours.

Section IV. Adjustments, Charges, and Other Rate Provisions

A. Ancillary Services
    Customers taking service under this rate schedule are subject to 
the ACS-02 Scheduling, System Control and Dispatch Service Rate and the 
Reactive Supply and Voltage Control from Generation Sources Service 
Rate. Other Ancillary Services that are required to support PTP 
transmission service on the Network are available under the ACS rate 
schedule.
B. Delivery Charge
    Customers taking service under this rate schedule are subject to 
the Delivery Charge specified in section II.A of the GRSPs.
C. Power Factor Penalty
    Customers taking service under this rate schedule are subject to 
the Power Factor Penalty Charge specified in section II.C of the GRSPs.
D. Short-Distance Discount (SDD)
    When a Point of Receipt (POR) and Point of Delivery (POD) use FCRTS 
facilities for a distance of less than 75 circuit miles and are 
designated as being short distance in the PTP Service Agreement, the 
monthly Transmission Demands for the relevant POI and POD shall be 
adjusted, for the purpose of computing the monthly bill for annual 
service, by the following factor:

0.6 + (0.4  x  transmission distance/75)

    Such adjusted monthly POR and POD Transmission Demands shall be 
used to compute the billing factors in section III.A.1. to calculate 
the monthly bill for Long-Term Firm PTP service. The POD Transmission 
Demand eligible for the SDD may be no larger than the POR Transmission 
Demand. The distance used to calculate the SDD will be contractually 
specified and based upon path(s) identified in power flow studies.
E. Unauthorized Increase Charge
    Customers who exceed their Transmission Demand at any Point of 
Receipt (POR) or Point of Delivery (POD) shall be subject to the 
Unauthorized Increase Charge.
    1. Rate: $6.79 per kilowatt per month.
    2. Billing Factor: For each hour of the monthly billing period, BPA 
shall determine the amount by which the Transmission Customer exceeds 
its Transmission Demands at each POD and POR, to the extent 
practicable. BPA shall use hourly measurements based on a 10-minute 
moving average to calculate actual demands at PODs associated with 
loads that are one-way dynamically scheduled and at PORs associated 
with resources that are one-way dynamically scheduled. Actual demands 
at all other PODs and PORs will be based on 60-minute integrated 
demands or transmission schedules.
    For each hour, BPA will sum these amounts that exceed Transmission 
Demands: (a) For all PODs, and (b) for all PORs. The Billing Factor for 
the monthly billing period shall be the greater of the highest one-hour 
POD sum or highest one-hour POR sum.
F. Reservation Fee
    Customers who request new or increased firm transmission service 
under this rate schedule and want to reserve transmission capacity to 
accommodate such service are subject to the Reservation Fee specified 
in section II.G of the GRSPs.
G. Failure To Comply Penalty
    Customers taking service under this rate schedule are subject to 
the Failure to Comply Penalty Charge specified in section II.B of the 
GRSPs.
H. Direct Assignment Facilities
    TBL shall collect the capital and related costs of a Direct 
Assignment Facility under the Advance Funding (AF) rate or the Use-of-
Facilities (UFT) rate. Other associated costs, including but not 
limited to operations, maintenance, and general plant costs, also shall 
be recovered from the Point-to-Point Customer under an applicable rate 
schedule.
I. Incremental Cost Rates
    The rates specified in section II are applicable to service over 
available transmission capacity. Customers requesting new or increased 
firm service that would require TBL to construct Network Upgrades to 
alleviate a capacity constraint may be subject to incremental cost 
rates for such service if incremental cost is higher than embedded 
cost. Incremental cost rates would be developed pursuant to section 
7(i) of the Northwest Power Act.
J. Interruption of Daily Nonfirm Service
    If Daily Nonfirm Service is interrupted, the rates charged under 
section II.B.1 shall be prorated over the total hours in the day to 
give credit for the hours of such interruption.

[[Page 14112]]

K. Rate Adjustment Due to FERC Order Under FPA Sec. 212
    Customers taking service under this rate schedule are subject to 
the Rate Adjustment Due to FERC Order under FPA Sec. 212 specified in 
section II.D of the GRSPs.

Schedule IS-02  Southern Intertie Rate

Section I. Availability

    This schedule supersedes Schedule IS-96. It is available to 
Transmission Customers taking Point-to-Point Transmission Service over 
Federal Columbia River Transmission System (FCRTS) Southern Intertie 
facilities. Terms and conditions of service are specified in the Open 
Access Transmission Tariff or, for customers who executed Southern 
Intertie agreements with BPA before October 1, 1996, will be as 
provided in the customer's agreement with BPA. This schedule is 
available also for transmission service of a similar nature ordered by 
the Federal Energy Regulatory Commission (FERC) pursuant to sections 
211 and 212 of the Federal Power Act (16 U.S.C. Secs. 824j and 824k). 
Service under this schedule is subject to TBL's General Rate Schedule 
Provisions (GRSPs).

Section II. Rates

A. Long-Term Firm Service
    1. North to South:
    a. April-September: $1.299 per kilowatt per month.
    b. October-March $0.974 per kilowatt per month.
    2. South to North: $1.157 per kilowatt per month.
B. Short-Term Firm and Nonfirm Service--North to South
    The charges for Short-Term Firm and Nonfirm Service shall not 
exceed:
    1. Daily: For each reservation:
    a. April-September:
    (1) Days 1 to 5: $0.060 per kilowatt per day.
    (2) Day 6 and beyond: $0.043 per kilowatt per day.
    b. October-March:
    (1) Days 1 to 5: $0.045 per kilowatt per day.
    (2) Day 6 and beyond: $0.032 per kilowatt per day.
    2. Hourly
    a. April-September: 3.74 mills per kilowatthour.
    b. October-March: 2.81 mills per kilowatthour.
C. Short-Term Firm and Nonfirm Service--South to North
    The charges for Short-Term Firm and Nonfirm Service shall not 
exceed:
    1. Daily: For each reservation:
    a. Days 1 to 5: $0.053 per kilowatt per day.
    b. Day 6 and beyond: $0.038 per kilowatt per day.
    2. Hourly: 3.33 mills per kilowatthour.

Section III. Billing Factors

    A. The Billing Factor for Long-Term Firm Service, Short-Term Firm 
Service, and Daily Nonfirm Service, shall be the greater of:
    1. The sum of the Point of Receipt Transmission Demands, or
    2. The sum of the Point of Delivery Transmission Demands. For 
Southern Intertie transmission agreements executed prior to October 1, 
1996, the Billing Factor shall be as specified in the agreement.
    B. The Billing Factor for Hourly Nonfirm Service shall be the 
monthly sum of scheduled kilowatthours.

Section IV. Adjustments, Charges, and Other Rate Provisions

A. Ancillary Services
    Customers taking service under this rate schedule are subject to 
the ACS-02 Scheduling, System Control and Dispatch Service Rate and the 
Reactive Supply and Voltage Control from Generation Sources Service 
Rate. Other Ancillary Services that are required to support PTP 
Transmission Service on the Southern Intertie are available under the 
ACS rate schedule.
B. Interruption of Daily Nonfirm Service
    If Daily Nonfirm Service is interrupted, the rates charged under 
sections II.B.1. and II.C.1. shall be prorated over the total hours in 
the day to give credit for the hours of such interruption.
C. Reservation Fee
    Customers who request new or increased firm transmission service 
under this rate schedule and want to reserve transmission capacity to 
accommodate such service will be subject to the Reservation Fee 
specified in section II.G of the GRSPs.
D. Power Factor Penalty
    Customers taking service under this rate schedule are subject to 
the Power Factor Penalty Charge specified in section II.C of the GRSPs
E. Unauthorized Increase Charge
    Customers who exceed their Transmission Demand at any Point of 
Receipt (POR) or Point of Delivery (POD) shall be subject to the 
Unauthorized Increase Charge.
    1. Rate: $6.79 per kilowatt per month.
    2. Billing Factor: For each hour of the monthly billing period, BPA 
shall determine the amount by which the Transmission Customer exceeds 
its Transmission Demands at each POD and POR, to the extent 
practicable. BPA shall use hourly measurements based on a 10-minute 
moving average to calculate actual demands at PODs associated with 
loads that are one-way dynamically scheduled and at PORs associated 
with resources that are one-way dynamically scheduled. Actual demands 
at all other PODs and PORs will be based on 60-minute integrated 
demands or transmission schedules.
    For each hour, BPA will sum these amounts that exceed Transmission 
Demands: (a) For all PODs, and (b) for all PORs. The Billing Factor for 
the monthly billing period shall be the greater of the highest one-hour 
POD sum or highest one-hour POR sum.
F. Failure To Comply Penalty
    Customers taking service under this rate schedule are subject to 
the Failure to Comply Penalty Charge specified in section II.B of the 
GRSPs.
G. Direct Assignment Facilities
    TBL shall collect the capital and related costs of a Direct 
Assignment Facility under the Advance Funding (AF) rate or the Use-of-
Facilities (UFT) rate. Other associated costs, including but not 
limited to operations, maintenance, and general plant costs, also shall 
be recovered from the Transmission Customer under an applicable rate 
schedule.
H. Incremental Cost Rates
    The rates specified in section II are applicable to service over 
available transmission capacity. Customers requesting new or increased 
firm service that would require TBL to construct new facilities or 
upgrades to alleviate a capacity constraint may be subject to 
incremental cost rates for such service if incremental cost is higher 
than embedded cost. Incremental cost rates would be developed pursuant 
to section 7(i) of the Northwest Power Act.
I. Rate Adjustment Due to FERC Order Under FPA Sec. 212
    Customers taking service under this rate schedule are subject to 
the Rate Adjustment Due to FERC Order under FPA Sec. 212 specified in 
section II.D of the GRSPs.

Schedule IM-02  Montana Intertie Rate

Section I. Availability

    This schedule supersedes Schedule IM-96. It is available to 
Transmission

[[Page 14113]]

Customers taking Point-to-Point (PTP) Transmission Service on BPA's 
share of Montana Intertie transmission capacity. Terms and conditions 
of service are specified in the Open Access Transmission Tariff. This 
schedule is available also for transmission service of a similar nature 
ordered by the Federal Energy Regulatory Commission (FERC) pursuant to 
sections 211 and 212 of the Federal Power Act (16 U.S.C. Secs. 824j and 
824k). Service under this schedule is subject to TBL's General Rate 
Schedule Provisions (GRSPs).

Section II. Rate

A. Long-Term Firm Service
    $1.239 per kilowatt per month.
B. Short-Term Firm and Nonfirm Service
    The charges for Short-Term Firm and Nonfirm Service shall not 
exceed:
    1. Daily: For each reservation:
    a. Days 1 to 5: $0.057 per kilowatt per day.
    b. Day 6 and beyond: $0.041 per kilowatt per day.
    2. Hourly: 3.56 mills per kilowatthour.

Section III. Billing Factors

    A. The Billing Factor for Long-Term Firm Service, Short-Term Firm 
Service, and Daily Nonfirm Service shall be the greater of:
    1. the sum of the Point of Receipt Transmission Demands, or
    2. the sum of the Point of Delivery Transmission Demand.
    B. The Billing Factor for Hourly Nonfirm Service shall be the 
monthly sum of scheduled kilowatthours.

Section IV. Adjustments, Charges, and Other Rate Provisions

A. Ancillary Services
    Customers taking service under this rate schedule are subject to 
the ACS-02 Scheduling, System Control and Dispatch Service Rate and the 
Reactive Supply and Voltage Control from Generation Sources Service 
Rate. Other Ancillary Services that are required to support PTP 
Transmission Service on the Montana Intertie are available under the 
ACS rate schedule.
B. Unauthorized Increase Charge
    Customers who exceed their Transmission Demand at any Point of 
Receipt (POR) or Point of Delivery (POD) shall be subject to the 
Unauthorized Increase Charge.
    1. Rate: $6.79 per kilowatt per month.
    2. Billing Factor: For each hour of the monthly billing period, TBL 
shall determine the amount by which the Transmission Customer exceeds 
its Transmission Demands at each POD and POR, to the extent 
practicable. TBL shall use hourly measurements based on a 10-minute 
moving average to calculate actual demands at PODs associated with 
loads that are one-way dynamically scheduled and at PORs associated 
with resources that are one-way dynamically scheduled. Actual demands 
at all other PODs and PORs will be based on 60-minute integrated 
demands or transmission schedules.
    For each hour, TBL will sum these amounts that exceed Transmission 
Demands: a) for all PODs, and b) for all PORs. The Billing Factor for 
the monthly billing period shall be the greater of the highest one-hour 
POD sum or highest one-hour POR sum.
C. Interruption of Daily Nonfirm Service
    If Daily Nonfirm Service is interrupted, the rates charged under 
section II.B.1. shall be prorated over the total hours in the day to 
give credit for the hours of such interruption.
D. Reservation Fee
    Customers who request new or increased firm transmission service 
under this rate schedule and want to reserve transmission capacity to 
accommodate such service will be subject to the Reservation Fee 
specified in section II.G of the GRSPs.
E. Failure To Comply Penalty
    Customers taking service under this rate schedule are subject to 
the Failure to Comply Penalty Charge specified in section II.B of the 
GRSPs.
F. Direct Assignment Facilities
    TBL shall collect the capital and related costs of a Direct 
Assignment Facility under the Advance Funding (AF) rate or the Use-of-
Facilities (UFT) rate. Other associated costs, including but not 
limited to operations, maintenance, and general plant costs, also shall 
be recovered from the Transmission Customer under an applicable rate 
schedule.
G. Incremental Cost Rates
    The rates specified in section II are applicable to service over 
available transmission capacity. Customers requesting new or increased 
firm service that would require TBL to construct new facilities or 
upgrades to alleviate a capacity constraint may be subject to 
incremental cost rates for such service if incremental cost is higher 
than embedded cost. Incremental cost rates would be developed pursuant 
to section 7(i) of the Northwest Power Act.
H. Rate Adjustment Due to FERC Order Under EPA Sec. 212
    Customers taking service under this rate schedule are subject to 
the Rate Adjustment Due to FERC Order under FPA Sec. 212 specified in 
section II.D of the GRSPs.

Schedule UFT-02  Use-of-Facilities Transmission Rate

Section I. Availability

    This schedule supersedes Schedule UFT-96 unless otherwise provided 
in the agreement, and is available for firm transmission over specified 
Federal Columbia River Transmission System (FCRTS) facilities. Service 
under this schedule is subject to TBL's General Rate Schedule 
Provisions (GRSPs).

Section II. Rate

    The monthly charge per kilowatt of Transmission Demand specified in 
the agreement shall be one-twelfth of the annual cost of capacity of 
the specified facilities divided by the sum of Transmission Demands (in 
kilowatts) using such facilities. Such annual cost shall be determined 
in accordance with section III.

Section III. Determination of Transmission Rate

    A. From time to time, but not more often than once a year, TBL 
shall determine the following data for the facilities which have been 
constructed or otherwise acquired by TBL and which are used to transmit 
electric power:
    1. The annual cost of the specified FCRTS facilities, as determined 
from the capital cost of such facilities and annual cost ratios 
developed from the Federal Columbia River Power System financial 
statement, including interest and amortization, operation and 
maintenance, administrative and general, and general plant costs.
    The annual cost per kilowatt of facilities listed in the agreement, 
which are owned by another entity, and used by TBL for making 
deliveries to the transferee, shall be determined from the costs 
specified in the agreement between TBL and such other entity.
    2. The yearly noncoincident peak demands of all users of such 
facilities or other reasonable measurement of the facilities' peak use.
    B. The monthly charge per kilowatt of billing demand shall be one-
twelfth of the sum of the annual cost of the FCRTS facilities used 
divided by the sum of Transmission Demands. The annual cost per 
kilowatt of Transmission Demand for a facility constructed or otherwise

[[Page 14114]]

acquired by TBL shall be determined in accordance with the following 
formula:
[GRAPHIC] [TIFF OMITTED] TN15MR00.002

Where:

A = The annual cost of such facility as determined in accordance with 
A.1. above.
D = The sum of the yearly noncoincident demands on the facility as 
determined in accordance with A.2. above.

    1. For facilities used solely by one customer, TBL may charge a 
monthly amount equal to the annual cost of such sole-use facilities, 
determined in accordance with section III.A.1, divided by 12.
    2. For facilities used by more than one customer, TBL may charge a 
monthly amount equal to the annual cost of such facilities prorated 
based on relative use of the facilities, divided by 12.

Section IV. Determination of Billing Factor

    Unless otherwise stated in the agreement, the factor to be used in 
determining the kilowatts of Billing Factor shall be the largest of:
    A. The Transmission Demand in kilowatts specified in the agreement;
    B. The highest hourly Measured or Scheduled Demand for the month; 
or
    C. The Ratchet Demand.

Section V. Adjustments, Charges, and Other Rate Provisions

A. Ancillary Services
    Ancillary services that are required to support UFT transmission 
service are available under the ACS rate schedule.
B. Power Factor Penalty Charge
    Customers taking service under this rate schedule are subject to 
the Power Factor Penalty Charge specified in section II.C of the GRSPs.

Schedule AF-02  Advance Funding Rate

Section I. Availability

    This schedule supersedes Schedule AF-96 and is available to 
customers who execute an agreement that provides for TBL to collect 
capital and related costs through advance funding or other financial 
arrangement for specified BPA-owned Federal Columbia River Transmission 
System (FCRTS) facilities used for:
    A. Interconnection or integration of resources and loads to the 
FCRTS;
    B. Upgrades, replacements, or reinforcements of the FCRTS for 
transmission service; or
    C. Other transmission service arrangements, as determined by TBL.
    Service under this schedule is subject to TBL's General Rate 
Schedule Provisions (GRSPs).

Section II. Rate

    The charge is the sum of the actual capital and related costs for 
specified FCRTS facilities, as provided in the agreement. Such actual 
capital and related costs include, but are not limited to, costs of 
design, materials, construction, overhead, spare parts, and all 
incidental costs necessary to provide service as identified in the 
agreement.

Section III. Payment

A. Advance Payment
    Payment to TBL shall be specified in the agreement as either:
    1. A lump sum advance payment;
    2. Advance payments pursuant to a schedule of progress payments; or
    3. Other payment arrangement, as determined by TBL.
    Such advance payment or payments shall be based on an estimate of 
the capital and related costs for the specified FCRTS facilities as 
provided in the agreement.
B. Adjustment to Advance Payment
    TBL shall determine the actual capital and related costs of the 
specified FCRTS facilities as soon as practicable after the date of 
commercial operation, as determined by TBL. The customer will either 
receive a refund from TBL or be billed for additional payment for the 
difference between the advance payment and the actual capital and 
related costs.

Schedule TGT-02  Townsend-Garrison Transmission Rate

Section I. Availability

    This schedule supersedes Schedule TGT-96 and is available to 
Companies that are parties to the Montana Intertie Agreement (Contract 
No. DE-MS79-81BP90210, as amended) which provides for firm transmission 
over TBL's section (Garrison to Townsend) of the Montana Intertie. 
Service under this schedule is subject to TBL's General Rate Schedule 
Provisions (GRSPs).

Section II. Rate

    The monthly charge shall be one-twelfth of the sum of the annual 
charges listed below, as applicable and as specified in the agreements 
for firm transmission. The Townsend-Garrison 500-kV lines and 
associated terminal, line compensation, and communication facilities 
are a separately identified portion of the Federal Transmission System. 
Annual revenues plus credits for government use should equal annual 
costs of the facilities, but in any given year there may be either a 
surplus or a deficit. Such surpluses or deficits for any year shall be 
accounted for in the computation of annual costs for succeeding years. 
Revenue requirements for firm transmission use will be decreased by any 
revenues received from nonfirm use and credits for all government use. 
The general methodology for determining the firm rate is to divide the 
revenue requirement by the total firm capacity requirements. Therefore, 
the higher the total capacity requirements, the lower will be the unit 
rate.
    If the government provides firm transmission service in its section 
of the Montana [Eastern] Intertie in exchange for firm transmission 
service in a customer's section of the Montana Intertie, the payment by 
the government for such transmission services provided by such customer 
will be made in the form of a credit in the calculation of the Intertie 
Charge for such customer. During an estimated 1-to 3-year period 
following the commercial operation of the third generating unit at the 
Colstrip Thermal Generating Plant at Colstrip, Montana, the capability 
of the Federal Transmission System west of Garrison Substation may be 
different from the long-term situation. It may not be possible to 
complete the extension of the 500-kV portion of the Federal 
Transmission System to Garrison by such commercial operation date. In 
such event, the 500/230 kV transformer will be an essential extension 
of the Townsend-Garrison Intertie facilities, and the annual costs of 
such transformer will be included in the calculation of the Intertie 
Charge.
    However, starting 1 month after extension to Garrison of the 500-kV 
portion of the Federal Transmission System, the annual costs of such

[[Page 14115]]

transformer will no longer be included in the calculation of the 
Intertie Charge.
A. Nonfirm Transmission Charge
    This charge will be filed as a separate rate schedule, the Eastern 
Intertie (IE) rate, and revenues received thereunder will reduce the 
amount of revenue to be collected under the Intertie Charge below.

B. Intertie Charge for Firm Transmission Service

Intertie Charge = [((TAC/12)-NFR)  x  (CR-EC)] TCR

Section III. Definitions

    A. TAC = Total Annual Costs of facilities associated with the 
Townsend-Garrison 500-kV Transmission line including terminals, and 
prior to extension of the 500-kV portion of the Federal Transmission 
System to Garrison, the 500/230 kV transformer at Garrison. Such annual 
costs are the total of: (1) Interest and amortization of associated 
Federal investment and the appropriate allocation of general plant 
costs; (2) operation and maintenance costs; (3) allowance for BPA's 
general administrative costs which are appropriately allocable to such 
facilities, and (4) payments made pursuant to section 7(m) of Public 
Law 96-501 with respect to these facilities. Total Annual Costs shall 
be adjusted to reflect reductions to unpaid total costs as a result of 
any amounts received, under agreements for firm transmission service 
over the Montana Intertie, by the government on account of any 
reduction in Transmission Demand, termination or partial termination of 
any such agreement or otherwise to compensate BPA for the unamortized 
investment, annual cost, removal, salvage, or other cost related to 
such facilities.
    B. NFR = Nonfirm Revenues, which are equal to: (1) The product of 
the Nonfirm Transmission Charge described in II(A) above, and the total 
nonfirm energy transmitted over the Townsend-Garrison line segment 
under such charge for such month; plus (2) the product of the Nonfirm 
Transmission Charge and the total nonfirm energy transmitted in either 
direction by the Government over the Townsend-Garrison line segment for 
such month.
    C. CR = Capacity Requirement of a customer on the Townsend-Garrison 
500-kV transmission facilities as specified in its firm transmission 
agreement.
    D. TCR = Total Capacity Requirement on the Townsend-Garrison 500-kV 
transmission facilities as calculated by adding (1) the sum of all 
Capacity Requirements (CR) specified in transmission agreements 
described in section I; and (2) the Government's firm capacity 
requirement. The Government's firm capacity requirement shall be no 
less than the total of the amounts, if any, specified in firm 
transmission agreements for use of the Montana Intertie.
    E. EC = Exchange Credit for each customer which is the product of: 
(1) the ratio of investment in the Townsend-Broadview 500-kV 
transmission line to the investment in the Townsend-Garrison 500-kV 
transmission line; and (2) the capacity which the Government obtains in 
the Townsend-Broadview 500-kV transmission line through exchange with 
such customer. If no exchange is in effect with a customer, the value 
of EC for such customer shall be zero.

Schedule IE-02  Eastern Intertie Rate

Section I. Availability

    This schedule supersedes IE-96 and is available to Companies that 
are parties to the Montana Intertie Agreement (Contract No. DE-MS79-
81BP90210, as amended), for nonfirm transmission service on the portion 
of Eastern Intertie capacity above TBL's firm transmission rights. 
Service under this schedule is subject to TBL's General Rate Schedule 
Provisions (GRSPs).

Section II. Rate

    The charge shall not exceed 1.38 mills per kilowatthour.

Section III. Billing Factors

    The Billing Factor shall be the monthly sum of the scheduled 
kilowatthours, unless otherwise specified in the agreement.

Section IV. Adjustments, Charges, and Other Rate Provisions

A. Ancillary Services
    Ancillary services that may be required to support IE transmission 
service are available under the ACS rate schedule.
B. Failure To Comply Penalty
    Customers taking service under this rate schedule are subject to 
the Failure to Comply Penalty specified in section II.B of the GRSPs.

Schedule ACS-02  Ancillary Services and Control Area Services Rate

Section I. Availability

    This schedule supersedes Schedule APS-96. It is available to all 
Transmission Customers taking service under the Open Access 
Transmission Tariff and other contractual arrangements. This schedule 
is available also for transmission service of a similar nature ordered 
by the Federal Energy Regulatory Commission (FERC) pursuant to sections 
211 and 212 of the Federal Power Act (16 U.S.C. 824j and 824k). Service 
under this schedule is subject to TBL's General Rate Schedule 
Provisions (GRSPs).
    Ancillary Services are needed with transmission service to maintain 
reliability within and among the Control Areas affected by the 
transmission service. The Transmission Provider is required to provide, 
and the Transmission Customer is required to purchase, the following 
Ancillary Services: (a) Scheduling, System Control and Dispatch, and 
(b) Reactive Supply and Voltage Control from Generation Sources.
    The Transmission Provider is required to offer to provide the 
following Ancillary Services to Transmission Customers serving load or 
integrating generation within the Transmission Provider's Control Area: 
(a) Regulation and Frequency Response, (b) Energy Imbalance, (c) 
Operating Reserve--Spinning, and (d) Operating Reserve--Supplemental. 
The Transmission Customer serving load or integrating generation within 
the Transmission Provider's Control Area is required to acquire these 
Ancillary Services, whether from the Transmission Provider, from a 
third party, or by self-supply. The Transmission Customer may not 
decline the Transmission Provider's offer of Ancillary Services unless 
it demonstrates that it has acquired the Ancillary Services from 
another source in a manner that is technically achievable, which 
conforms to the criteria and standards established by the Transmission 
Provider for the provision of the specific Ancillary Services including 
the relevant North American Electric Reliability Council (NERC), 
Western Systems Coordinating Council (WSCC) and Northwest Power Pool 
(NWPP), criteria. Any such self-supply or third-party supply 
arrangements shall be specified in the Transmission Customer's Service 
Agreement.
    Ancillary Service rates available under this rate schedule are:
    1. Scheduling, System Control, and Dispatch Service.
    2. Reactive Supply and Voltage Control from Generation Sources 
Service.
    3. Regulation and Frequency Response Service.
    4. Energy Imbalance Service.
    5. Operating Reserve--Spinning Reserve Service.
    6. Operating Reserve--Supplemental Reserve Service.

[[Page 14116]]

    Control Area Services are available to meet the Reliability 
Obligations of a party with resources or loads in the BPA Control Area. 
A party that is not satisfying all of its Reliability Obligations 
through the purchase or self-provision of Ancillary Services must 
purchase Control Area Services to meet its Reliability Obligations. 
Control Area Services are also available to parties with resources or 
loads in the BPA Control Area that have Reliability Obligations, but do 
not have a transmission agreement with BPA. Reliability Obligations for 
resources or loads in the BPA Control Area shall be determined 
consistent with the applicable NERC, WSCC, and NWPP criteria.
    Control Area Service rates available under this rate schedule are:
    1. Load Regulation and Frequency Response Service.
    2. Generation Imbalance Service.
    3. Operating Reserve--Spinning Reserve Service.
    4. Operating Reserve--Supplemental Reserve Service.

Section II. Ancillary Service Rates

A. Scheduling, System Control and Dispatch Service
    The rates below apply to Transmission Customers taking Scheduling, 
System Control and Dispatch Service from TBL. These rates apply to both 
firm and non-firm transmission transactions. Transmission on the 
Network, on the Southern Intertie, and on the Montana Intertie are each 
charged separately for Scheduling, System Control and Dispatch Service.
    1. Rate:
    a. Long-Term Firm Service.
    The rate shall not exceed $0.170 per kilowatt per month.
    b. Short Term Firm and Nonfirm Service.
    The rates for Short-Term Firm and Nonfirm Service shall not exceed:
    (1) Daily: For each reservation:
    Days 1 through 5 $0.008 per kilowatt per day.
    Day 6 and beyond $0.005 per kilowatt per day.
    (2) Hourly: 0.49 mills per kilowatthour.
    2. Billing Factors: For Transmission Customers taking Point-to-
Point Transmission Service (PTP, IS, and IM rates), Network Contract 
Demand Transmission Service (NCD rate), and Integration of Resources 
service (IR rate), the Billing Factor is Transmission Demand. 
Transmission Demands on the Network, on the Southern Intertie, and on 
the Montana Intertie are each charged separately.
    For Transmission Customers taking Network Integration Transmission 
Service, the Billing Factor shall equal the NT Base Charge Billing 
Factor determined pursuant to section III.A of the Network Integration 
Rate Schedule (NT-02).
B. Reactive Supply and Voltage Control From Generation Sources Service
    The rates below apply to Transmission Customers taking Reactive 
Supply and Voltage Control from Generation Sources Service from TBL. 
These rates apply to both firm and non-firm transmission transactions. 
Transmission on the Network, on the Southern Intertie, and on the 
Montana Intertie are each charged separately for Reactive Supply and 
Voltage Control from Generation Sources Service.
    1. Rate: a. Long Term Firm Service.
    The rate shall not exceed $0.080 per kilowatt per month.
    b. Short Term Firm and Nonfirm Service.
    The rates for Short-Term Firm and Nonfirm Service shall not exceed:
    (1) Daily: For each reservation:
    Days 1 through 5: $0.004 per kilowatt per day.
    Day 6 and beyond: $0.003 per kilowatt per day.
    (2) Hourly: 0.23 mills per kilowatt per hour.
    2. Billing Factors: a. For Transmission Customers taking Point-to-
Point Transmission Service (PTP, IS, and IM rates), Network Contract 
Demand Transmission Service (NCD rate), and Integration of Resources 
service (IR rate), the Billing Factor is Transmission Demand. 
Transmission Demands on the Network, on the Southern Intertie, and on 
the Montana Intertie are each charged separately.
    For Transmission Customers taking Network Integration Transmission 
Service, the Billing Factor shall equal the NT Base Charge Billing 
Factor determined pursuant to section III.A of the Network Integration 
Rate Schedule (NT-02).
    b. The Billing Factor in section 2.a. above may be reduced as 
specified in the Transmission Customer's Service Agreement to the 
extent the Transmission Customer demonstrates to TBL's satisfaction 
that it can self-provide Reactive Supply and Voltage Control from 
Generation Sources Service.
C. Regulation and Frequency Response Service
    The rate below for Regulation and Frequency Response Service 
applies to Transmission Customers serving loads in the BPA Control 
Area. Regulation and Frequency Response Service provides the generation 
capability to follow the moment-to-moment variations of loads in the 
BPA Control Area and maintain the power system frequency at 60 Hz in 
conformance with NERC and WSCC reliability standards.
    1. Rate: The rate shall not exceed 0.30 mills per kilowatthour.
    2. Billing Factor: The Billing Factor is the customer's total load 
in the BPA Control Area, in kilowatthours.
D. Energy Imbalance Service
    The rates below apply to Transmission Customers taking Energy 
Imbalance Service from TBL. Energy Imbalance Service is taken when 
there is a difference between scheduled and actual energy delivered to 
a load in the BPA Control Area during a schedule hour. The rates for 
this service differ depending upon whether the Energy Imbalance occurs 
within the Energy Imbalance Deviation Band or outside the Energy 
Imbalance Deviation Band. The Energy Imbalance Deviation Band is + 
or-1.5% of the schedule amount of energy or 2 MW, whichever is larger 
(absolute value).
    1. Rate: a. For Energy Imbalance Within the Energy Imbalance 
Deviation Band.
    TBL will maintain a deviation account showing the net Energy 
Imbalance (the sum of positive and negative deviations from schedule 
for each hour). Return energy must be scheduled to bring the deviation 
account balance to zero each month. TBL will designate the hours and 
amounts of return energy for each hour that will be scheduled. The 
customer shall make the arrangements and submit the schedule for the 
balancing transaction.
    b. For Energy Imbalance Outside the Energy Imbalance Deviation 
Band.
    (1) When energy taken in a schedule hour by the Transmission 
Customer exceeds the energy scheduled, the charge will be the greater 
of (i) BPA's incremental cost plus 10%, or (ii) 100 mills per 
kilowatthour.
    BPA's incremental cost will be based on an hourly energy index in 
the PNW, if one exists. If one does not exist, an alternative index 
will be used based on: the Dow-Jones Mid-Columbia, California PX, or 
NYMEX Mid-Columbia index prices. On September 30 of each year, TBL will 
post on the OASIS the index to be used for the ensuing fiscal year.
    (2) When energy taken by the Transmission Customer is less than the 
scheduled amount, a credit equal to 90% of BPA's decremental cost may 
be given for deviations.

[[Page 14117]]

    2. Billing Factors: For each hour an Energy Imbalance occurs, the 
Billing Factor for the rates specified in section 1.b., Energy 
Imbalance Outside the Energy Imbalance Deviation Band, is:
    a. the amount of energy that the Transmission Customer takes, in 
kilowatthours, in excess of the Energy Imbalance Deviation Band, or
    b. the Transmission Customer's qualifying energy difference, in 
kilowatthours, between the energy taken and the lower limit of the 
Energy Imbalance Deviation Band (a negative balance).
    No credit will be given for an energy difference if: (a) The 
imbalance was an Intentional Deviation (as determined by TBL); or (b) 
the Federal System was in a Spill Condition at any time during the 
month.
E. Operating Reserve--Spinning Reserve Service
    The rates below apply to Transmission Customers taking Operating 
Reserve--Spinning Reserve Service from TBL. Spinning Reserve Service is 
needed to serve load immediately in the event of a system contingency. 
For a Transmission Customer's load served by generation located in the 
BPA Control Area, the Transmission Customer's Spinning Reserve 
Requirement shall be determined consistent with applicable NERC, WSCC 
and NWPP standards.
    1. Rate:
    a. The rate shall not exceed 8.27 mills per kilowatthour of 
Spinning Reserve Requirement.
    b. For energy delivered, the Transmission Customer may:
    (i) Purchase the energy at the hourly market index price applicable 
at the time of occurrence, or
    (ii) Return the energy at the times specified by TBL.
    2. Billing Factors:
    a. The Billing Factor for Spinning Reserve Service is determined in 
accordance with applicable WSCC and NWPP standards. Application of 
current standards establish a minimum Spinning Reserve Requirement 
equal to the sum of:
    (i) Two and a half percent (2\1/2\%) of the hydroelectric 
generation dedicated to the Transmission Customer's firm load 
responsibility; and
    (ii) Three and a half percent (3\1/2\%) of non-hydroelectric 
generation dedicated the Transmission Customer's firm load 
responsibility.
    b. The Billing Factor for energy delivered when Spinning Reserve 
Service is called upon is the energy delivered, in kilowatthours.
F. Operating Reserve--Supplemental Reserve Service
    The rates below apply to Transmission Customers taking Operating 
Reserve--Supplemental Reserve Service from TBL. Supplemental Reserve 
Service is available within a short period of time to serve load in the 
event of a system contingency. For a Transmission Customer's load 
served by generation located in the BPA Control Area, the Transmission 
Customer's Supplemental Reserve Requirement shall be determined 
consistent with applicable NERC, WSCC and NWPP standards.
    1. Rate:
    a. The rate shall not exceed 8.27 mills per kilowatthour of 
Supplemental Reserve Requirement.
    b. For energy delivered, the Transmission Customer may:
    (i) Purchase the energy at the hourly market index price applicable 
at the time of occurrence, or
    (ii) Return the energy at the times specified by TBL.
    2. Billing Factors:
    a. The Billing Factor for Supplemental Reserve Service is 
determined in accordance with applicable WSCC and NWPP standards. 
Application of current standards establish a minimum Supplemental 
Reserve Requirement equal to the sum of:
    (i) Two and one half percent (2\1/2\%) of the hydroelectric 
generation dedicated to the Transmission Customer's firm load 
responsibility, plus
    (ii) Three and one half percent (3\1/2\%) of non-hydroelectric 
generation dedicated the Transmission Customer's firm load 
responsibility, plus
    (i) Any power scheduled into the BPA Control Area that can be 
interrupted on ten (10) minutes' notice.
    b. The Billing Factor for energy delivered when Supplemental 
Reserve Service is called upon is the energy delivered, in 
kilowatthours.

Section III. Control Area Service Rates

A. Regulation and Frequency Response Service
    The rate below applies to all loads in the BPA Control Area that 
are receiving Regulation and Frequency Response Service from the BPA 
Control Area, and such Regulation and Frequency Response Service is not 
provided for under a TBL transmission agreement. Regulation and 
Frequency Response Service provides the generation capability to follow 
the moment-to-moment variations of loads in the BPA Control Area and 
maintain the power system frequency at 60 Hz in conformance with NERC 
and WSCC reliability standards.
    1. Rate: The rate shall not exceed 0.30 mills per kilowatthour.
    2. Billing Factor: The Billing Factor is the customer's total load 
in the BPA Control Area, in kilowatthours.
B. Generation Imbalance Service
    The rates below apply to all generation resources in the BPA 
Control Area. Generation Imbalance Service is taken when there is a 
difference between scheduled and actual energy delivered from 
generation resources in the BPA Control Area during a schedule hour. 
The rates for this service differ depending upon whether the Generation 
Imbalance occurs within the Generation Imbalance Deviation Band or 
outside the Generation Imbalance Deviation Band. The Generation 
Imbalance Deviation Band is + or -1.5% of the scheduled amount of 
energy, or 2 MW, whichever is larger (absolute value).
    1. Rates:
    a. For Imbalance Within the Generation Imbalance Deviation Band: 
TBL will maintain a deviation account showing the net Generation 
Imbalance (the sum of positive and negative deviations from schedule 
for each hour). Return energy must be scheduled to bring the deviation 
account balance to zero each month. TBL will designate the hours and 
amounts of return energy for each hour that will be scheduled. The 
customer shall make the arrangements and submit the schedule for the 
balancing transaction.
    b. For Imbalance Outside the Generation Imbalance Deviation Band: 
i. When energy delivered in a schedule hour by the generation resource 
is less than the energy scheduled, the charge will be the greater of 
(i) BPA's incremental cost plus 10%, or (ii) 100 mills per 
kilowatthour.
    BPA's incremental cost will be based on an hourly energy index in 
the PNW, if one exists. If one does not exist, an alternative index 
will be based on: the Dow-Jones Mid-Columbia, California PX, or NYMEX 
Mid-Columbia index prices. On September 30 each year, TBL will post on 
the OASIS the index to be used for the ensuing fiscal year.
    ii. When energy delivered by the generation resource is greater 
than the scheduled amount, a credit equal to 90% of BPA's decremental 
cost may be given for deviations.
    2. Billing Factor: For each hour a Generation Imbalance occurs, the 
Billing Factor for the rates specified in section 1.b., Imbalance 
Outside the Generation Imbalance Deviation Band, is:

[[Page 14118]]

    a. the amount of energy that the customer delivers, in 
kilowatthours, less than the lower limit of the Generation Imbalance 
Deviation Band, or
    b. the amount of energy the customer delivers, in kilowatthours, in 
excess of the upper limit of the Generation Imbalance Deviation Band.
    No credit will be given for an energy difference if: (a) The 
imbalance was an Intentional Deviation (as determined by TBL); or (b) 
the Federal System was in a Spill Condition at any time during the 
month.
C. Operating Reserve--Spinning Reserve Service
    Operating Reserve--Spinning Reserve Service must be purchased by a 
party with generation in the BPA Control Area that is receiving this 
service from TBL, and such Spinning Reserve Service is not provided for 
under a TBL transmission agreement. Service is being received if there 
are no other qualifying resources providing this required reserve 
service in conformance with NERC, WSCC and NWPP standards.
    1. Rate:
    a. The rate shall not exceed 8.27 mills per kilowatthour of 
Spinning Reserve Requirement
    b. For energy delivered, the customer may:
    (i) Purchase the energy at the hourly market index price applicable 
at the time of occurrence, or
    (ii) Return the energy at the times specified by BPA.
    2. Billing Factors:
    a. The Billing Factor for Spinning Reserve Service is determined in 
accordance with applicable WSCC and NWPP standards. Application of 
current standards establish a minimum Spinning Reserve Requirement 
equal to the sum of:
    (i) Two and one half percent (2\1/2\%) of the hydroelectric 
generation dedicated to the customer's firm load responsibility, plus
    (ii) Three and one half percent (3\1/2\%) of non-hydroelectric 
generation dedicated the customer's firm load responsibility.
    b. The Billing Factor for energy delivered when Spinning Reserve 
Service is called upon is the energy delivered, in kilowatthours.
D. Operating Reserve--Supplemental Reserve Service
    Operating Reserve--Supplemental Reserve Service must be purchased 
by a party with generation in the BPA Control Area that is receiving 
this service from TBL, and such Supplemental Reserve Service is not 
provided for under a TBL transmission agreement. Service is being 
received if there are no other qualifying resources providing this 
required reserve service in conformance with NERC, WSCC and NWPP 
standards.
    1. Rates:
    a. The rate shall not exceed 8.27 mills per kilowatthour of 
Supplemental Reserve Requirement.
    b. For energy delivered, the customer may:
    (i) Purchase the energy at the hourly market index price applicable 
at the time of occurrence, or
    (ii) Return the energy at the times specified by BPA.
    2. Billing Factors:
    a. The Billing Factor for Supplemental Reserve Service is 
determined in accordance with applicable WSCC and NWPP guidelines. 
Application of current guidelines establish a minimum Supplemental 
Reserve Requirement equal to the sum of:
    (i) Two and one half percent (2\1/2\%) of the hydroelectric 
generation dedicated to the customer's firm load Responsibility, plus
    (ii) Three and one half percent (3\1/2\%) of non-hydroelectric 
generation dedicated the customer's firm load responsibility, plus
    (iii) Any power scheduled into the BPA Control Area that can be 
interrupted on ten (10) minutes' notice.
    b. The Billing Factor for energy delivered when Supplemental 
Reserve Service is called upon is the energy delivered, in 
kilowatthours.

Section IV. Adjustments, Charges, and Other Rate Provisions

A. Rate Adjustment Due to FERC Order Under FPA Sec. 212
    Customers taking service under this rate schedule are subject to 
the Rate Adjustment Due to FERC Order under FPA Sec. 212 specified in 
section II.D of the GRSPs.

General Rate Schedule Provisions for Transmission and Ancillary 
Service Rates

Section I. Generally Applicable Provisions

A. Approval of Rates
    These 2002 rate schedules and General Rate Schedule Provisions for 
Transmission and Ancillary Service Rates (GRSPs) shall become effective 
upon interim approval or upon final confirmation and approval by the 
Federal Energy Regulatory Commission (FERC). Bonneville Power 
Administration (BPA) has requested that FERC make these rates and GRSPs 
effective on October 1, 2001. All rate schedules shall remain in effect 
until they are replaced or expire on their own terms.
B. General Provisions
    These 2002 rate schedules and the GRSPs associated with these 
schedules supersede BPA's 1996 rate schedules (which became effective 
October 1, 1996) to the extent stated in the Availability section of 
each rate schedule. These schedules and GRSPs shall be applicable to 
all TBL contracts, including contracts executed both prior to, and 
subsequent to, enactment of the Pacific Northwest Electric Power 
Planning and Conservation Act (Northwest Power Act). All sales under 
these rate schedules are subject to the following acts as amended: the 
Bonneville Project Act (Pub. L. 75-329), the Regional Preference Act 
(Pub. L. 88-552), the Federal Columbia River Transmission System Act 
(Pub. L. 93-454), the Northwest Power Act (Pub. L. 96-501), and the 
Energy Policy Act of 1992 (Pub. L. 102-486).
    These 2002 rate schedules do not supersede any previously 
established rate schedule that is required, by agreement, to remain in 
effect.
    If a provision in an executed agreement is in conflict with a 
provision contained herein, the former shall prevail.
C. Notices
    For the purpose of determining elapsed time from receipt of a 
notice applicable to rate schedule and GRSP administration, a notice 
shall be deemed to have been received at 0000 hours on the first 
calendar day following actual receipt of the notice.
D. Billing and Payment
    1. Billing: BPA's Transmission Business Line (TBL) shall render 
monthly bills to the Transmission Customer for transmission services. 
Failure to receive a bill shall not release the Transmission Customer 
from liability for payment. If requested by the Transmission Customer, 
the TBL shall electronically transmit the Transmission Customer's 
monthly bill to the Transmission Customer on the issue date of the 
bill, provided the parties have compatible electronic equipment. The 
TBL may elect to electronically transmit only that portion of the bill 
showing the amount owed. If the entire bill is not provided by 
electronic means, the TBL shall also send the Transmission Customer a 
complete copy of its monthly bill by mail.
    (a) Due Date:
    Payment shall be due by close of business on the twentieth (20th) 
day

[[Page 14119]]

after the issue date of the bill (Due Date). If the 20th day is a 
Saturday, Sunday, or Federal holiday, the Due Date shall be the next 
Business Day.
    (b) Payments:
    (1) The Transmission Customer must pay by electronic funds transfer 
using procedures established by the TBL. However, exceptions to the 
method of payment may be made on a case by case basis according to the 
criteria listed below. All payment amounts are due and payable on the 
Due Date.
    (2) The Transmission Customer may pay its bill by an alternate 
method, provided the following criteria can be met:
    (A) The Transmission Customer requests to pay by an alternate 
method at least thirty (30) days in advance of the billing date; and
    (B) The Transmission Customer ensures that the TBL receives full 
payment by the above-stated Due Date; and
    (C) The Transmission Customer has not previously incurred late 
payment charges while paying its bills by an alternate method; and
    (D) The TBL approves the alternate payment method requested by the 
Transmission Customer.
    (c) Payments by Mail:
    If the Transmission Customer requests to pay its bill by mail as an 
alternate payment method, meets the requirements of section D.1(b)(2) 
above, and the TBL approves such request, payments shall be mailed to: 
Bonneville Power Administration, PO Box 6040, Portland, OR 97228-6040.
    The TBL must receive payment for such bills by the Due Date.
    (d) Pre-authorized Debit:
    The Transmission Customer may elect, with the TBL's concurrence, to 
pay through the use of a pre-authorized debit which is an electronic 
payment option authorizing the TBL to automatically withdraw a 
Transmission Customer's payments from its bank account.
    (e) Computation of Bills:
    Bills for products and services may be rounded to whole dollar 
amounts, by eliminating any amount which is less than 50 cents, and 
increasing any amount from 50 cents through 99 cents to the next higher 
dollar.
    (f) Estimated Bills:
    At its option, the TBL may elect to render an estimated bill for a 
month to be followed at a subsequent billing date by a final bill for 
that month. Such estimated bill shall have the validity of, and is 
subject to, the same payment provisions as a final bill.
    (g) Late Payment:
    Bills not paid in full with payment received by the TBL before 
close of business on the Due Date shall be subject to a late payment 
charge of one-twentieth percent (0.05 percent) applied each day to the 
unpaid balance. This late payment charge shall be assessed on a daily 
basis until such time as the TBL receives the unpaid amount.
    (h) Revised Bills:
    As necessary, the TBL may render revised bills. The date of a 
revised bill shall be its issue date.
    (1) If the amount of the revised bill is more than the amount of 
the previous bill, the previous bill remains due on its Due Date, and 
the additional amount is due on the Due Date of the revised bill.
    (2) If the amount of the revised bill is less than the amount of 
the previous bill, the obligation to pay the previous bill is satisfied 
by payment of the revised bill on the Due Date of the previous bill.
    (3) If the revised bill changes the party to whom money is due 
prior to payment of the previous bill, the previous bill is canceled 
and the amount owed the other party is due on the Due Date of the 
revised bill.
    (4) If payment of the previous bill results in an overpayment, a 
refund is due on the later of (a) the Due Date of the revised bill, or 
(b) twenty (20) days from the receipt of the payment for the original 
bill. Should refund not be made by the TBL by the above date, late 
payment interest shall accrue and be paid by the TBL pursuant to the 
Prompt Payment Act.
    (i) Disputed Bills:
    (1) In the event of a billing dispute between the TBL and the 
Transmission Customer, the TBL will continue to provide service under 
the Service Agreement as long as the Transmission Customer: (1) 
Continues to make all payments not in dispute; and (2) pays into an 
escrow account the portion of the invoice in dispute. If the 
Transmission Customer fails to meet these two requirements for 
continuation of service, then the TBL may provide notice of its intent 
to suspend service to the Transmission Customer in sixty (60) days.
    (2) If it is determined that the Transmission Customer is entitled 
to a refund of any portion of the disputed amount, then TBL will make 
such refund with interest computed from the date of receipt of the 
disputed payment to the date the refund is made. The TBL shall make 
such refund with simple interest. The daily interest rate used to 
determine the interest is calculated by dividing the Prompt Payment Act 
Interest by 365. The applicable Prompt Payment Act Interest Rate shall 
be the rate that is in effect on the date in which the TBL receives 
payment. Should a third party escrow account service be necessary, the 
escrow fees will be split evenly between the TBL and the Transmission 
Customer and interest on the disputed funds will be the interest paid 
by the institution providing the escrow service.
    2. Customer Default: In the event the Transmission Customer fails, 
for any reason other than a billing dispute as described above, to make 
payment to the TBL on or before the Due Date as described above, and 
such failure of payment is not corrected within thirty (30) calendar 
days after the TBL notifies the Transmission Customer to cure such 
failure, a default by the Transmission Customer shall be deemed to 
exist. Upon the occurrence of default the TBL may notify the 
Transmission Customer that it plans to terminate service in sixty (60) 
days. The Transmission Customer may use dispute resolution procedures 
in its agreement to contest such termination.
    3. Records: The TBL and the Transmission Customer shall keep such 
records as may be needed to afford a clear history of all transactions. 
The originals of all such records shall be retained for a minimum of 
two (2) years plus the current year (or such longer period as may be 
required by any regulatory commission having jurisdiction), and copies 
shall be delivered to the other party on request.

Section II. Adjustments, Charges, and Special Rate Provisions

A. Delivery Charge
    Transmission Customers shall pay a Delivery Charge for service over 
DSI Delivery facilities, Utility Delivery facilities.
    1. Rates:
    a. DSI Delivery:
    i. Use-of-Facilities (UFT-02) Rate, section III.B.1 or III.B.2, 
multiplied by
    ii. 1.197.
    b. Utility Delivery:
    $1.299 per kilowatt per month.
    2. Billing Factors:
    a. Utility Delivery:
    The monthly Billing Factor for the Utility Delivery rate in section 
1.b. shall be the total load on the hour of the Monthly Transmission 
Peak Load at the Points of Delivery specified as Utility Delivery 
facilities.
    b. Metering Adjustment:
    At those Points of Delivery that do not have meters capable of 
determining the demand on the hour of the Monthly Transmission Peak 
Load, the Billing Factor under section 2.a. shall equal the highest 
hourly demand that occurs during the billing month at the Point of 
Delivery multiplied by 0.66.

[[Page 14120]]

    c. Utility Delivery Charge Billing Factor Adjustment:
    The monthly Utility Delivery Billing Factor in section 2.a shall be 
adjusted for customers who pay for Utility Delivery facilities under 
the Use-of-Facilities (UFT) rate schedule. The kilowatt credit shall 
equal the transmission service over the Delivery facilities used to 
calculate the UFT charge. This adjustment shall not reduce the Utility 
Delivery Charge billing factor below zero.
B. Failure To Comply Penalty
    If a party fails to comply with the TBL's curtailment, redispatch, 
or load shedding orders, the party will be assessed the Failure to 
Comply Penalty charge.
    Parties who are unable to comply with a curtailment, load shedding, 
or redispatch order due to a force majeure on their system will not be 
subject to this penalty provided that they immediately notify the TBL 
of the situation upon occurrence of the force majeure.
    1. Rate:
    a. 100 mills per kilowatthour;
    b. any costs incurred by the TBL in order to manage the reliability 
of the FCRTS due to the failure to comply;
    c. an hourly market price index plus 10%.
    The hourly market price index will be the larger of the California 
ISO Ex-Post Supplemental Energy Price or the Dow Jones Mid-Columbia 
Firm Index Price for the hour(s) when the failure to comply occurred.
    2. Billing Factor: The Billing Factor shall be the kilowatthours 
that were not curtailed or redispatched in any of the following 
situations:
    a. Failure to raise generation if chosen as an incremental bidder 
for redispatch.
    b. Failure to lower generation if chosen as a decremental bidder 
for redispatch.
    c. Failure to shed load when required as specified by the Load 
Shedding provisions of the Tariff or any other applicable agreement 
between the parties. This includes failure to respond within the time 
period specified by NERC, WSCC, or NWPP criteria.
    d. Failure of a generator in the BPA Control Area or which directly 
interconnects to the FCRTS to change generation levels when directed to 
do so by the TBL. This includes failure to respond within the time 
period specified by NERC, WSCC, or NWPP criteria.
    e. Failure to curtail a schedule in the time period specified by 
NERC, WSCC, or NWPP criteria when directed to do so by the TBL.
C. Power Factor Penalty Charge
    1. Description of the Power Factor Penalty Charge: Any party that 
is interconnected with the Federal Columbia River Transmission System 
(FCRTS) shall be charged for its reactive power requirements as 
described in this section, unless otherwise specified in an agreement 
existing prior to October 1, 1995. Each point of interconnection or 
point of delivery shall be monitored and billed independently for 
determining the party's total reactive power requirements and all 
associated billing factors, including the Reactive Deadband. If a party 
is taking transmission service under multiple rate schedules, the party 
will pay for its reactive power requirements as if it is taking 
delivery under only one rate schedule.
    2. Conditions for Application of the Power Factor Penalty Charge
    a. Measured Data:
    The Power Factor Penalty Charge will apply to only the party's 
reactive power requirements for which measured data exist.
    b. Party's Generating Resource Connected to the FCRTS:
    Irrespective of the direction of real power flow, the Power Factor 
Penalty Charge shall apply to points of interconnection where a party's 
generating resource is directly connected to the FCRTS, unless the 
party's generating resource is either:
    i. a synchronous generator equipped with a voltage regulator, or
    ii. equipped with reactive power control devices that comply with 
TBL's applicable interconnection standards.
    Such resource must actively support the voltage schedule at the 
point of integration at all times when the resource is in service, as 
determined by BPA Transmission Business Line, for this exemption to 
apply. Generating resources that do not satisfy the above criteria 
shall not be exempt from the Power Factor Penalty Charge.
    c. Bi-directional Real Power Flow:
    For points other than those specified in section 2(b), the Power 
Factor Penalty Charge will not be applied, and no new Ratchet Demand 
for reactive power will be established, at a specific point if the 
metered real power (on an hourly integrated basis) flows from the 
party's system to the FCRTS at that point for as little as one hour 
during the billing period. However, the party will still pay any 
previously incurred demand ratchet charges. The direction of the real 
power flow will be determined based on metered quantities, not on 
scheduled quantities.
    d. Service by Transfer:
    Points of delivery that are served by transfer over another 
utility's transmission system will not be subject to the Power Factor 
Penalty Charge unless there are significant TBL Network facilities 
between the party's points of delivery and the transferor's system.
    e. Specific Points Exempt from the Power Factor Penalty Charge:
    The Power Factor Penalty Charge will not apply to the following 
points: Nevada-Oregon Border (NOB), Big Eddy 500 kV, Big Eddy 230 kV, 
John Day 500 kV, Malin 500 kV, Captain Jack 500 kV, Garrison 500 kV, 
Townsend 500 kV.
    f. Special Circumstances:
    The party may submit requests to BPA Transmission Business Line for 
consideration of unique circumstances. BPA Transmission Business Line 
will evaluate the request and may make arrangements with the party to 
address the special circumstances.
    3. Rate: TBL will bill the party for reactive power at each point 
each month as follows:
    Reactive Demand:
    $0.28 per kVAr of lagging reactive demand in excess of the Reactive 
Deadband during HLH in all months of the year.
    $0.24 per kVAr of leading reactive demand in excess of the Reactive 
Deadband during LLH in all months of the year.
    No charge for leading reactive demand during HLH.
    No charge for lagging reactive demand during LLH.
    4. Billing Factors:
    a. Reactive Deadband:
    The Reactive Deadband (measured in kVAr) is used to determine the 
Reactive Billing Demand and Ratchet Demand for the Power Factor Penalty 
Charge.
    The Reactive Deadband for each billing period is the maximum hourly 
integrated metered real power demand (measured in kW) at each point 
during the billing period multiplied by 25 percent.
    The Reactive Deadband for either HLH or LLH:
    i. is computed once per billing period (the same quantity is used 
for both HLH and LLH),
    ii. does not vary during the billing period, and
    iii. is based on the maximum hourly integrated metered real power 
demand during that billing period.
    b. Reactive Billing Demand:
    The party's Reactive Billing Demand shall be calculated 
independently for lagging reactive power and leading reactive power at 
each point for which a Power Factor Penalty Charge is assessed.

[[Page 14121]]

    All reactive demands shall be established in the particular HLH or 
LLH at each point during which the party's maximum applicable reactive 
demand is placed on TBL, regardless of the time of the real power peak 
at each point.
    All reactive demand at each point shall be established on a non-
coincidental basis, regardless of whether the party is billed for real 
power or transmission at such point on a coincidental or non-
coincidental basis, unless otherwise specified in the agreement between 
TBL and the party, or coincidental billing is, in TBL's sole 
determination, more practical for TBL.
    There will be separate reactive demands for lagging (HLH) and 
leading (LLH) demands. The party's Reactive Billing Demand for each 
point for the billing month shall be the larger of:
    i. the largest measured reactive demand in excess of the Reactive 
Deadband during the billing period, or
    ii. the Ratchet Demand for reactive power.
    The Ratchet Demand for reactive power is equal to 100 percent of 
the largest measured reactive demand in excess of the Reactive Deadband 
during the preceding 11-month period. Each point shall have a separate 
Ratchet Demand for lagging (HLH) and leading (LLH) reactive demand.
    5. Adjustments for Reactive Losses: Measured data shall be adjusted 
for reactive losses, if applicable, before determination of the 
Reactive Billing Demand.
D. Rate Adjustment Due to FERC Order Under FPA Sec. 212
    If, after review by FERC, the NT, NCD, PTP, IS, IM or ACS rate 
schedule, as initially submitted to FERC, is modified to satisfy the 
standards of section 212(i)(1)(B)(ii) of the Federal Power Act (16 
U.S.C. Sec. 824k(i)(1)(B)(ii)) for FERC-ordered transmission service, 
then such modifications shall automatically apply to the rate schedule 
for non-section 212(i)(1)(B)(ii) transmission service. The 
modifications for non-section 212(i)(1)(B)(ii) transmission service, as 
described above, shall be effective, however, only prospectively from 
the date of the final FERC order granting final approval of the rate 
schedule for FERC-ordered transmission service pursuant to section 
212(i)(1)(B)(ii). No refunds shall be made or additional costs charged 
as a consequence of this prospective modification for any non-section 
212(i)(1)(B)(ii) transmission service that occurred under the rate 
schedule prior to the effective date of such prospective modification.
E. Redispatch Adjustment for Accepted Bids
    When the TBL implements redispatch procedures pursuant to the Open 
Access Transmission Tariff, the party submitting a bid that is accepted 
for redispatch shall receive a credit or charge for such accepted bid. 
The amount of the credit or charge shall be based on the incremental or 
decremental bid, respectively, submitted by the party and the amount of 
power redispatched. The credit or charge shall appear on the party's 
monthly transmission bill. If a credit is due to a party not taking 
other transmission services, TBL will pay the party for such redispatch 
within 30 days following the end of the month that the redispatch 
occurred.
F. Redispatch Charge
    For each hour that TBL implements redispatch procedures pursuant to 
the Open Access Transmission Tariff (Tariff), all NT and NCD 
Transmission Customers using the congested path during the hour(s) that 
redispatch is implemented shall be subject to the Redispatch Charge.
    1. Rate: For each hour and each congested transmission path that 
TBL implements redispatch procedures pursuant to the Open Access 
Transmission Tariff, the rate shall be:
[GRAPHIC] [TIFF OMITTED] TN15MR00.003

    where:
    ``Redispatch Cost'' is the hourly net cost in dollars incurred by 
TBL to implement redispatch procedures.
    ``Total NT/NCD Customer Usage of Congested Path'' is the total NT 
and NCD Transmission Customers' hourly use in megawatts of the 
congested transmission path.
    2. Billing Factor: For each hour and constrained transmission path 
that redispatch procedures are implemented, the Billing Factor shall be 
the NT or NCD Transmission Customer's use in megawatts of the congested 
path.
G. Reservation Fee
    The Reservation Fee shall be charged to PTP and NCD customers 
electing to postpone the commencement of service pursuant to sections 
29.5 or 38.7 of the Open Access Transmission Tariff.
    The Reservation Fee shall be a nonrefundable fee equal to one 
month's charge for the requested firm transmission service for each 
year or fraction of a year for which the customer chooses to postpone 
service. The Reservation Fee for the first year shall be paid in a lump 
sum within 30 days of the date the agreement is executed, and, for 
subsequent years, within 30 days of the anniversary date of execution 
of the agreement. The Reservation Fee shall be assessed annually until 
transmission service begins or the reservation period ends, whichever 
occurs first. The Reservation Fee shall be specified in the executed 
agreement for transmission service.
H. Transmission and Ancillary Services Rate Discounts
    TBL may offer discounted rates for transmission and ancillary 
services available under the Open Access Transmission Tariff and to the 
extent provided for in the specific rate schedule. Any offer of a 
discount for transmission services or for ancillary services in support 
of basic transmission services must be announced to all potential 
customers solely by posting on the OASIS. Any customer-initiated 
requests for such discounts must occur solely by posting on the OASIS. 
Once TBL and a Transmission Customer agree to a discounted transaction, 
the details shall be immediately posted on the OASIS. If TBL offers a 
transmission service discount on a particular path, it shall offer the 
same discount for the same time period on all unconstrained paths that 
go to the same point(s) of delivery on TBL's system. If TBL offers an 
ancillary service discount, it shall offer the same discount for the 
same time period to all eligible customers on TBL's system.

Section III. Definitions

1. Ancillary Services
    Ancillary Services are those services that are necessary to support 
the transmission of capacity and energy from resources to loads while 
maintaining reliable operation of TBL's Transmission System in 
accordance with Good Utility Practice. Ancillary Services include: 
Scheduling, System

[[Page 14122]]

Control and Dispatch; Reactive Supply and Voltage Control from 
Generation Sources; Regulation and Frequency Response; Energy 
Imbalance; Operating Reserve--Spinning; and Operating Reserve--
Supplemental. Ancillary Services are available under the ACS-02 rate 
schedule.
2. Billing Factor
    The Billing Factor is the quantity to which the charge specified in 
the rate schedule is applied. When the rate schedule includes charges 
for several products, there may be a Billing Factor for each product.
3. Control Area
    A Control Area is an electric power system or combination of 
electric power systems to which a common automatic generation control 
scheme is applied in order to: (1) Match, at all times, the power 
output of the generators within the electric power system(s) and 
capacity and energy purchased from entities outside the electric power 
system(s), with the load within the electric power system(s); (2) 
maintain scheduled interchange with other Control Areas, within the 
limits of Good Utility Practice; (3) maintain the frequency of the 
electric power system(s) within reasonable limits in accordance with 
Good Utility Practice; and (4) provide sufficient generating capacity 
to maintain operating reserves in accordance with Good Utility 
Practice.
4. Control Area Services
    Control Area Services are available to meet the Reliability 
Obligations of a party with resources or loads in the BPA Control Area. 
A party that is not satisfying all of its Reliability Obligations 
through the purchase or self-provision of Ancillary Services may 
purchase Control Area Services to meet its Reliability Obligations. 
Control Area Services are also available to parties with resources or 
loads in the BPA Control Area that have Reliability Obligations, but do 
not have a transmission agreement with TBL. Reliability Obligations for 
resources or loads in the BPA Control Area are determined by applying 
the North American Electric Reliability Council (NERC), Western Systems 
Coordinating Council (WSCC), and the Northwest Power Pool (NWPP) 
reliability criteria. Control Area Services, include, without 
limitation:
    a. Regulation and Frequency Response Service
    b. Generation Imbalance Service
    c. Operating Reserve--Spinning Reserve Service
    d. Operating Reserve--Supplemental Reserve Service
    e. Other Control Area services.
5. Daily Firm Service
    Daily Firm Service is firm transmission service under Part II of 
the Open Access Transmission Tariff in consecutive daily increments of 
one day or greater but less than one year.
6. Daily Nonfirm Service
    Daily Nonfirm Service is nonfirm transmission service under Part II 
of the Open Access Transmission Tariff in consecutive daily increments 
of one day or greater but less than or equal to 31 days.
7. Direct Assignment Facilities
    Facilities or portions of facilities that have been or are 
constructed by the TBL for the sole use and benefit of a particular 
Transmission Customer requesting service under the Open Access 
Transmission Tariff, the costs of which may be directly assigned to the 
Transmission Customer in accordance with applicable Federal Energy 
Regulatory Commission policy. Direct Assignment Facilities shall be 
specified in the agreement that governs service to the Transmission 
Customer.
8. Direct Service Industry (DSI) Delivery
    The DSI Delivery segment is the segment of the FCRTS that provides 
service to DSI customers at voltages of 34.5 kV and below.
9. Dynamic Schedule
    A Dynamic Schedule is a telemeter reading or value which is updated 
in real time and which is used as a schedule in the Automatic 
Generation Control (AGC) and Area Control Error (ACE) equation of the 
TBL and the integrated value of which is treated as a schedule for 
interchange accounting purposes. One way Dynamic Schedules are commonly 
used for scheduling remote generation or remote load to or from another 
Control Area. Two-way Dynamic Schedules are commonly used to provide 
supplemental regulation or operating reserve support from one entity to 
another, usually between Control Areas. The Receiving Party sends the 
Delivering Party a requested Dynamic Schedule (the first part of the 
two-way schedule). The Delivering Party then responds with the official 
Dynamic Schedule of what actually is delivered to the Receiving Party 
(the second part of the two-way schedule).
10. Eastern Intertie
    The Eastern Intertie is the segment of the Federal Columbia River 
Transmission System (FCRTS) for which the transmission facilities 
consist of the Townsend-Garrison double-circuit 500 kV transmission 
line segment, including related terminals at Garrison.
11. Energy Imbalance Service
    Energy Imbalance Service is provided when a difference occurs 
between the scheduled and the actual delivery of energy over a single 
hour to a load located within the BPA Control Area. The TBL must offer 
this service when the transmission service is used to serve load within 
its Control Area. The Transmission Customer must either purchase this 
service from the TBL or make alternative comparable arrangements 
specified in the Transmission Customer's Service Agreement to satisfy 
its Energy Imbalance Service obligation.
12. Federal Columbia River Transmission System
    The Federal Columbia River Transmission System (FCRTS) is the 
transmission facilities of the Federal Columbia River Power System, 
which include all transmission facilities owned by the government and 
operated by TBL, and other facilities over which TBL has obtained 
transmission rights.
13. Federal System
    The Federal System is the generating facilities of the Federal 
Columbia River Power System, including the Federal generating 
facilities for which BPA is designated as marketing agent; the Federal 
facilities under the jurisdiction of BPA; and any other facilities:
    a. from which BPA receives all or a portion of the generating 
capability (other than station service) for use in meeting BPA's loads 
to the extent BPA has the right to receive such capability. ``BPA's 
loads'' do not include any of the loads of any BPA customer that are 
served by a non-Federal generating resource purchased or owned directly 
by such customer which may be scheduled by BPA;
    b. which BPA may use under contract or license; or
    c. to the extent of the rights acquired by BPA pursuant to the 1961 
U.S.-Canada Treaty relating to the cooperative development of water 
resources of the Columbia River Basin.
14. Generation Imbalance
    Generation Imbalance is the difference between the hourly scheduled 
amount and actual delivered amount of energy from a generation resource 
in the BPA Control Area.

[[Page 14123]]

15. Generation Imbalance Service
    Generation Imbalance Service is taken when there is a difference 
between scheduled and actual energy delivered from generation resources 
in the BPA Control Area during a schedule hour.
16. Heavy Load Hours (HLH)
    Heavy Load Hours (HLH) are all those hours in the peak period: Hour 
ending 7:00 a.m. to the hour ending 10:00 p.m., Monday through 
Saturday, Pacific Prevailing Time (Pacific Standard Time or Pacific 
Daylight Time, as applicable). There are no exceptions to this 
definition; that is, it does not matter whether the day is a normal 
working day or a holiday.
17. Hourly Firm Service
    Hourly Firm Service is firm transmission service under Part II of 
the Open Access Transmission Tariff in consecutive hourly increments.
18. Hourly Nonfirm Service
    Hourly Nonfirm Service is nonfirm transmission service under Part 
II of the Open Access Transmission Tariff in hourly increments.
19. Integrated Demand
    Integrated Demand is the quantity derived by mathematically 
``integrating'' kilowatthour deliveries over a 60-minute period. For 
one-way dynamic schedules, demand is integrated on a rolling ten-minute 
basis.
20. Intentional Deviation
    BPA, in its sole determination, may find that an Intentional 
Deviation exists if:
    (a) a deviation is persistent during multiple consecutive hours or 
at specific times of the day;
    (b) a pattern of under-delivery or over-use of energy occurs; or
    (c) persistent over-generation or under-use during LLH, 
particularly when the customer does not respond by adjusting schedules 
for future days to correct these patterns.
21. Light Load Hours (LLH)
    Light Load Hours (LLH) are all those hours in the offpeak period: 
hour ending 11:00 p.m. to hour ending 6:00 a.m. Monday through Saturday 
and all hours Sunday, Pacific Prevailing Time (Pacific Standard Time or 
Pacific Daylight Time, as applicable).
22. Long-Term Firm Service
    Long-Term Firm Service is Firm Transmission service under Part II 
of the Open Access Transmission Tariff with a term of one year or more.
23. Main Grid
    As used in the FPT rate schedule, the Main Grid is that portion of 
the Network facilities with an operating voltage of 230 kV or more.
24. Main Grid Distance
    As used in the FPT rate schedules, Main Grid Distance is the 
distance in airline miles on the Main Grid between the Point of 
Integration (POI) and the Point of Delivery (POD), multiplied by 1.15.
25. Main Grid Interconnection Terminal
    As used in the FPT rate schedules, Main Grid Interconnection 
Terminal refers to Main Grid terminal facilities that interconnect the 
FCRTS with non-TBL facilities.
26. Main Grid Miscellaneous Facilities
    As used in the FPT rate schedules, Main Grid Miscellaneous 
Facilities refers to switching, transformation, and other facilities of 
the Main Grid not included in other components.
27. Main Grid Terminal
    As used in the FPT rate schedules, Main Grid Terminal refers to the 
Main Grid terminal facilities located at the sending and/or receiving 
end of a line, exclusive of the Interconnection terminals.
28. Measured Demand
    The Measured Demand is that portion of the customer's Metered or 
Scheduled Demand for transmission service from TBL under the applicable 
transmission rate schedule. If transmission service to a point of 
delivery, or from a point of receipt, is provided under more than one 
rate schedule, the portion of the measured quantities assigned to any 
rate schedule shall be as specified by contract. The portion of the 
total Measured Demand so assigned shall be the Measured Demand for 
transmission service for each transmission rate schedule.
29. Metered Demand
    Except for dynamic schedules, the Metered Demand in kilowatts shall 
be the largest of the 60-minute clock-hour Integrated Demands at which 
electric energy is delivered (received) for a transmission customer:
    a. at each point of delivery (receipt) for which the Metered Demand 
is the basis for the determination of the Measured Demand;
    b. during each time period specified in the applicable rate 
schedule; and
    c. during any billing period.
    Such largest Integrated Demand shall be determined from 
measurements made in accord with the provisions of the applicable 
contract and these GRSPs. This amount shall be adjusted as provided 
herein and in the applicable agreement between TBL and the customer.
    For dynamic schedules, the Metered Demand in kilowatts shall be the 
largest 10 minute moving average of the load (generation) at the point 
of delivery (receipt). The 10 minute moving average shall be assigned 
to the hour in which the 10 minute period ends.
30. Montana Intertie
    The Montana Intertie is the double-circuit 500 kV transmission line 
and associated substation facilities from Broadview Substation to 
Garrison Substation.
31. Monthly Transmission Peak Load
    Monthly Transmission Peak Load is the peak loading on the Federal 
transmission system during any hour of the designated billing month, 
determined by the largest hourly integrated demand produced from the 
sum of Federal and non-Federal generating plants in BPA's Control Area 
and metered flow into BPA's Control Area.
32. Network (or Integrated Network)
    The Network is the segment of the Federal Columbia River 
Transmission System (FCRTS) which provides the bulk of transmission of 
electric power within the Pacific Northwest.
33. Network Load
    Network Load is the load that a Network Integration Customer 
designates for Network Integration Transmission Service under Part III 
of the Open Access Transmission Tariff (Tariff). The Network 
Integration Customer's Network Load shall include all Network Load 
served by the output of any Network Resources designated by the Network 
Integration Customer. A Network Integration Customer may elect to 
designate less than its total load as Network Load but may not 
designate only part of the load as Network Load at a discrete Point of 
Delivery. Where a Network Integration Customer has elected not to 
designate a particular load at discrete Points of Delivery as Network 
Load, the Network Integration Customer is responsible for making 
separate arrangements under Part II or Part IV of the Tariff that may 
be necessary for such non-designated load.
34. Network Upgrades
    Network Upgrades are modifications or additions to transmission-
related facilities that are integrated with and

[[Page 14124]]

support the TBL's overall Transmission System for the general benefit 
of all users of such Transmission System.
35. Nonfirm Service
    Nonfirm Service is Daily Nonfirm and Hourly Nonfirm Service under 
Part II of the Open Access Transmission Tariff.
36. Operating Reserve--Spinning Reserve Service
    Operating Reserve--Spinning Reserve Service is needed to serve load 
immediately in the event of a system contingency. Spinning Reserve 
Service may be provided by generating units that are on-line and loaded 
at less than maximum output. The TBL must offer this service when the 
transmission service is provided to load served by generation located 
in the BPA Control Area. The Transmission or Control Area Service 
Customer must either purchase this service from the TBL or make 
alternative comparable arrangements to satisfy its Spinning Reserve 
Service obligation. The Transmission or Control Area Service Customer's 
obligation is determined consistent with North American Electric 
Reliability Council (NERC), Western Systems Coordinating Council (WSCC) 
and Northwest Power Pool (NWPP) criteria.
37. Operating Reserve--Supplemental Reserve Service
    Operating Reserve--Supplemental Reserve Service is needed to serve 
load in the event of a system contingency; however, it is not available 
immediately to serve load but rather within a short period of time. 
Supplemental Reserve Service may be provided by generating units that 
are on-line but unloaded, by quick-start generation or by interruptible 
load. The TBL must offer this service when the transmission service is 
provided to load served by generation located in the BPA Control Area. 
The Transmission or Control Area Service Customer must either purchase 
this service from the TBL or make alternative comparable arrangements 
to satisfy its Supplemental Reserve Service obligation. The 
Transmission Customer's obligation is determined consistent with North 
American Electric Reliability Council (NERC), Western Systems 
Coordinating Council (WSCC) and Northwest Power Pool criteria.
38. Operating Reserve Requirement
    Operating Reserve Requirement is a party's total reserve obligation 
to the BPA Control Area. A party is responsible for purchasing or 
otherwise providing Operating Reserves associated with its transactions 
which impose a reserve obligation on the BPA Control Area. Operating 
Reserve Requirement is composed of two parts: regulating reserve 
obligation and contingency reserve obligation.
    A party's regulating reserve obligation is met by purchasing 
Regulation and Frequency Response Service. The contingency reserve 
obligation is satisfied by purchasing or otherwise providing operating 
Reserve--Spinning Reserve Service and Operating Reserve--Supplemental 
Reserve Service.
    The specific amounts required are determined consistent with North 
American Electric Reliability Council (NERC) policies, the Northwest 
Power Pool (NWPP) Operating Manual, ``Contingency Reserve Sharing 
Procedure,'' and the Western Systems Coordinating Council (WSCC) 
``Minimum Operating Reliability Criteria'' (MORC).
39. Point of Delivery (POD)
    Point(s) on the TBL's Transmission System, or transfer points on 
other utility systems pursuant to Section 15.3 of the Open Access 
Transmission Tariff (Tariff), where capacity and energy transmitted by 
the TBL will be made available to the Receiving Party under Parts II, 
III, or IV of the Tariff or to the Transmission Customer under other 
BPA transmission service agreements.
40. Point of Integration (POI)
    A Point of Integration is the contractual interconnection point 
where power is received from the customer. Typically, a point of 
integration is located at a resource site, but it could be located at 
some other interconnection point.
41. Point of Interconnection (POI)
    A Point of Interconnection is a point where the facilities of two 
entities are interconnected. This term has the same meaning as ``Point 
of Integration'' and ``Point of Receipt'' in certain pre-Open Access 
Transmission Tariff service agreements.
42. Point of Receipt (POR)
    Point(s) of Receipt are the point(s) of interconnection on the 
TBL's Transmission System where capacity and energy will be made 
available to the TBL by the Delivering Party under Parts II, III, or IV 
of the Open Access Transmission Tariff. The Point(s) of Receipt shall 
be specified in the Service Agreement.
43. Ratchet Demand
    The Ratchet Demand in kilowatts or kilovars is the maximum demand 
established during a specified period of time either during, or prior 
to, the current billing period. The Ratchet Demand shall be the maximum 
demand established during the previous 11 billing months. If a 
Transmission Demand has been decreased pursuant to the terms of the 
transmission agreement during the previous 11 billing months, such 
decrease will be reflected in determining the Ratchet Demand. The 
Ratchet Demand for reactive power is defined in the Power Factor 
Penalty Charge at section II.C of these GRSPs.
44. Reactive Power
    Reactive Power is the out-of-phase component of the total 
voltamperes in an electric circuit. Reactive Power has two components: 
reactive demand (expressed in kilovars or kVAr) and reactive energy 
(expressed in kilovarhours or kVArh).
45. Reactive Supply and Voltage Control from Generation Sources Service
    Reactive Supply and Voltage Control from Generation Sources Service 
is required to maintain voltage levels on the TBL's transmission 
facilities within acceptable limits. In order to maintain transmission 
voltages on the TBL's transmission facilities within acceptable limits, 
generation facilities (in the Control Area where the TBL's transmission 
facilities are located) are operated to produce (or absorb) reactive 
power. Thus, Reactive Supply and Voltage Control from Generation 
Sources Service must be provided for each transaction on the TBL's 
transmission facilities. The amount of Reactive Supply and Voltage 
Control from Generation Sources Service that must be supplied with 
respect to the Transmission Customer's transaction will be determined 
based on the reactive power support necessary to maintain transmission 
voltages within limits that are generally accepted in the region and 
consistently adhered to by the TBL. The Transmission Customer must 
purchase this service from the TBL.
46. Regulation and Frequency Response Service
    Regulation and Frequency Response Service is necessary to provide 
for the continuous balancing of resources (generation and interchange) 
with load and for maintaining scheduled Interconnection frequency at 
sixty cycles per second (60 Hz). Regulation and Frequency Response 
Service is accomplished by committing on-line generation whose output 
is raised or lowered (predominantly through the use of automatic 
generating control equipment) as necessary to follow the moment-by-
moment changes in load.

[[Page 14125]]

The obligation to maintain this balance between resources and load lies 
with the TBL. The TBL must offer this service when the transmission 
service is used to serve load within the BPA Control Area. The 
Transmission Customer must either purchase this service from the TBL or 
make alternative comparable arrangements to satisfy its Regulation and 
Frequency Response Service obligation.
47. Reliability Obligations
    Reliability Obligations are the obligations for reliability-based 
services that a party with resources or loads in the BPA Control Area 
must provide in order to meet minimum reliability standards. 
Reliability Obligations shall be determined consistent with applicable 
North American Electric Reliability Council (NERC), Western Systems 
Coordinating Council (WSCC), and Northwest Power Pool (NWPP) standards. 
TBL offers Ancillary Services and Control Area Services to allow 
resources or loads to meet their Reliability Obligations.
48. Scheduled Demand
    Scheduled Demand is the hourly demand at which electric energy is 
scheduled for transmission on the FCRTS.
49. Scheduling, System Control and Dispatch Service
    Scheduling, System Control and Dispatch Service is required to 
schedule the movement of power through, out of, within, or into a 
Control Area. This service can be provided only by the operator of the 
Control Area in which the transmission facilities used for transmission 
service are located. Scheduling, System Control and Dispatch Service is 
to be provided directly by the TBL (if the TBL is the Control Area 
operator) or indirectly by the TBL making arrangements with the Control 
Area operator that performs this service for the TBL's Transmission 
System. The Transmission Customer must purchase this service from the 
TBL or the Control Area operator.
50. Secondary System
    As used in the FPT rate schedules, Secondary System is that portion 
of the Network facilities with an operating voltage between 69 kV to 
less than 230 kV.
51. Secondary System Distance
    As used in the FPT rate schedules, Secondary System Distance is the 
number of circuit miles of Secondary System transmission lines between 
the secondary Point of Integration and either the Main Grid or the 
secondary Point of Delivery (POD), or between the Main Grid and the 
secondary POD.
52. Secondary System Interconnection Terminal
    As used in the FPT rate schedules, Secondary System Interconnection 
Terminal refers to the terminal facilities on the Secondary System that 
interconnect the FCRTS with non-TBL facilities.
53. Secondary System Intermediate Terminal
    As used in the FPT rate schedules, Secondary System Intermediate 
Terminal refers to the first and final terminal facilities in the 
Secondary System transmission path, exclusive of the Secondary System 
Interconnection terminals.
54. Secondary Transformation
    As used in the FPT rate schedules, Secondary Transformation refers 
to transformation from Main Grid to Secondary System facilities.
55. Short-Term Firm Service
    Short-Term Firm Service is Daily Firm and Hourly Firm Transmission 
Service under Part II of the Open Access Transmission Tariff.
56. Southern Intertie
    The Southern Intertie is the segment of the FCRTS that includes, 
but is not limited to, the major transmission facilities consisting of 
two 500 kV AC lines from John Day Substation to the Oregon-California 
border; a portion of the 500 kV AC line from Buckley Substation to 
Summer Lake Substation; and the 500 kV AC Intertie facilities, which 
include Captain Jack Substation, the Alvey-Meridian AC line, one 1,000 
kV DC line between the Celilo Substation and the Oregon-Nevada border, 
and associated substation facilities.
57. Spill Condition
    Spill Condition, for the purpose of determining credit or payment 
for Deviations under the Energy Imbalance and Generation Imbalance 
rates, exists when any one or more of the following conditions exist or 
events occur on the BPA system: high flows and full reservoirs; flood 
control implementation; spill priority implementation procedures; spill 
due to lack of Federal load; spill past unloaded turbines; minimum 
generation requirements; increased spill due to storage; BPA is not 
accepting Coordination storage due to lack of storage or a specified 
flow requirement. Discretionary spill, where BPA may choose whether to 
spill does not constitute a Spill Condition.
58. Spinning Reserve Requirement
    Spinning Reserve Requirement is a portion of a party's Operating 
Reserve Requirement to the BPA Control Area. A party is responsible for 
purchasing or otherwise providing Operating Reserve--Spinning Reserve 
Service associated with its transactions which impose a reserve 
obligation on the BPA Control Area.
    The specific amounts required are determined consistent with North 
American Electric Reliability Council (NERC) policies, the Northwest 
Power Pool (NWPP) Operating Manual, ``Contingency Reserve Sharing 
Procedure,'' and the Western Systems Coordinating Council (WSCC) 
``Minimum Operating Reliability Criteria'' (MORC).
59. Supplemental Reserve Requirement
    Supplemental Reserve Requirement is a portion of a party's 
Operating Reserve Requirement to the BPA Control Area. A party is 
responsible for purchasing or otherwise providing Operating Reserve--
Supplemental Reserve Service associated with its transactions which 
impose a reserve obligation on the BPA Control Area.
    The specific amounts required are determined consistent with North 
American Electric Reliability Council (NERC) policies, the Northwest 
Power Pool (NWPP) Operating Manual, ``Contingency Reserve Sharing 
Procedure,'' and the Western Systems Coordinating Council (WSCC) 
``Minimum Operating Reliability Criteria'' (MORC).
60. Total Transmission Demand
    Total Transmission Demand is the sum of all the transmission 
demands as defined in the applicable agreement.
61. Transmission Customer
    A Transmission Customer is an entity that (a) has executed a 
Service Agreement under the Open Access Transmission Tariff; (b) 
receives transmission service under section 17.2 of the Open Access 
Transmission Tariff; or (c) has executed any other transmission 
agreement with the TBL.
62. Transmission Demand
    Transmission Demand is the maximum amount of capacity, energy, and/
or required Ancillary Services that the TBL agrees to transmit for the 
Transmission Customer over the TBL's Transmission System between the 
Point(s) of Receipt or Network

[[Page 14126]]

Resources and the Point(s) of Delivery under Parts II or IV of the Open 
Access Transmission Tariff. The Transmission Demand shall be expressed 
in terms of: (a) a demand in whole megawatts on a sixty-minute (60) 
interval (commencing on the clock hour) basis except in cases where 
Dynamic Schedules are involved; (b) a demand equal to the largest ten-
minute (10) moving average of the load or generation expected to occur 
during the contract period for one-way Dynamic Schedules used to 
transfer generation or load from one Control Area to another Control 
Area; or (c) a demand equal to the instantaneous peak demand, for each 
direction, of the supplemental Control Area service request expected to 
occur during the contract period for two-way Dynamic Transfers, used to 
provide supplemental Control Area services. The supplemental Control 
Area service response shall always be the lesser of the Control Area 
service request or the Transmission Demand associated with the 
supplemental Control Area service.
63. Transmission Provider
    The Bonneville Power Administration's Transmission Business Line 
(TBL) that owns, controls, or operates facilities used for the 
transmission of electric energy in interstate commerce and provides 
transmission service under the Open Access Transmission Tariff and 
other agreements. This excludes the Merchant Function.
64. Utility Delivery
    The Utility Delivery segment is that segment of the FCRTS that 
provides service to utility customers at voltages below 34.5 kV.

[FR Doc. 00-6105 Filed 3-14-00; 8:45 am]
BILLING CODE 6450-01-P