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Notice

Bonneville Power Administration

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AGENCY:

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

ACTION:

Notice of 2002-2003 Proposed Transmission Rate Adjustment.

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: comment@bpa.gov.

3. The pre-hearing conference will be held in the BPA Rates Hearing Room, 2nd floor, 911 NE 11th Ave., Portland, Oregon.

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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 mshansen@bpa.gov.

Responsible Official: Mr. Dennis Metcalf, Transmission Rate Case Manager, is the official responsible for the development of BPA's transmission and ancillary service rates.

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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.

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Issued in Portland, Oregon, on February 28, 2000.

Judith A. Johansen,

Administrator and Chief Executive Officer.

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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 § 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 Start Printed Page 14103

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. § 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.

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. Start Printed Page 14104BPA'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 Start Printed Page 14105challenge 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 Start Printed Page 14106confirmation 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 Start Printed Page 14107delivery 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 Start Printed Page 14108General 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 × 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 Start Printed Page 14109a 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. §§ 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 Start Printed Page 14110Transmission 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 § 212

Customers taking service under this rate schedule are subject to the Rate Adjustment Due to FERC Order under FPA § 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. §§ 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 Start Printed Page 14111Transmission 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 § 212

Customers taking service under this rate schedule are subject to the Rate Adjustment Due to FERC Order under FPA § 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. §§ 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 × 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. Start Printed Page 14112

K. Rate Adjustment Due to FERC Order Under FPA § 212

Customers taking service under this rate schedule are subject to the Rate Adjustment Due to FERC Order under FPA § 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. §§ 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 § 212

Customers taking service under this rate schedule are subject to the Rate Adjustment Due to FERC Order under FPA § 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 Start Printed Page 14113Customers 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. §§ 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 § 212

Customers taking service under this rate schedule are subject to the Rate Adjustment Due to FERC Order under FPA § 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 Start Printed Page 14114acquired by TBL shall be determined in accordance with the following formula:

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 Start Printed Page 14115transformer 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) × (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. Start Printed 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. Start Printed 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 (21/2%) of the hydroelectric generation dedicated to the Transmission Customer's firm load responsibility; and

(ii) Three and a half percent (31/2%) 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 (21/2%) of the hydroelectric generation dedicated to the Transmission Customer's firm load responsibility, plus

(ii) Three and one half percent (31/2%) 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: Start Printed 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 (21/2%) of the hydroelectric generation dedicated to the customer's firm load responsibility, plus

(ii) Three and one half percent (31/2%) 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 (21/2%) of the hydroelectric generation dedicated to the customer's firm load Responsibility, plus

(ii) Three and one half percent (31/2%) 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 § 212

Customers taking service under this rate schedule are subject to the Rate Adjustment Due to FERC Order under FPA § 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 Start Printed Page 14119after 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. Start Printed 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. Start Printed 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 § 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. § 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:

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 Start Printed Page 14122Control 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. Start Printed 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 Start Printed Page 14124support 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. Start Printed Page 14125The 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 Start Printed Page 14126Resources 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.

End Supplemental Information

Footnotes

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 ¶ 31,036 (1996).

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2.  Open Access Same-Time Information System (formerly Real-Time Information Networks) and Standards of Conduct, FERC Stats & Regs ¶ 31,035 (1996).

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[FR Doc. 00-6105 Filed 3-14-00; 8:45 am]

BILLING CODE 6450-01-P