Determination

Capital cost recovery: Federal repayment basis oriented to interest and principal payments determined by a repayment study that includes only transmission debt. (RA 6120.2 and FERC Orders based on FCRTSA 10 and NWPA 7(a)(2)(C))

Transmission revenue requirements have included charges for revenue financing of new investments or cash required for risk mitigation. (BPA Financial Policy)

Capital cost recovery: embedded cost basis, which is oriented to costs on utility’s (ratemaking) books: depreciation and rate of return (the company’s overall weighted average cost of capital and equity) applied to depreciated transmission plant-in-service.

• It is believed BPA’s Federal repayment requirements could be satisfied under FPA standards without additional statutory support.

• An approach similar to TVA’s margin in revenue requirements (10% of expenses) could provide necessary flexibility.

• Existing cost-recovery requirements likely would not be met nor could risk mitigation or revenue financing be accomplished under literal interpretation of embedded cost methodology for a publicly-held entity.

• FERC has taken conservative approach to BPA rate approval, requiring frequent review of cost recovery and timely repayment to Treasury.

• Long-term rates (>7 years) approved only upon showing that they accounted for small portion of total revenue requirement; long-term rates require more justification/regional support to secure FERC approval. (FERC Policy on PMA Rates)

• Intervenors, including FERC, can request at any time that rates be reopened to review.

• A potential benefit to BPA from the FPA approach would be that, if rates were set high enough based on the test year revenue requirement to cover ongoing annual financial requirements, it might not be necessary to have a rate case again until BPA determined rates needed to be changed (would not have to request particular length for rate period).

• BPA believes that it could rely on section 7(a) of the Northwest Power Act to recover power costs in transmission rates; to date, this position is untested.

• BPA takes position that FERC stranded cost rules cannot be applied to BPA to prevent recovery of costs.

• Transmission rates based on the cost of transmission service.

• FERC will determine on a case-by-case basis whether costs stranded by transmission access are recoverable from specified customers.

• Deregulation may necessitate flexibility for cross-function cost recovery assistance.

• BPA has no shareholders to assume excluded costs.

BPA DRAFT PRINCIPLES

Allocation

• Pacificorp and PGE are joint owners with BPA.

• Six utilities (Pacificorp, Puget, Seattle, Tacoma, Snohomish, PNGC) purchased a total of 725 MW of capacity ownership on BPA’s portion of the intertie.

• 96 Rate Case: After the Settlement agreement had been negotiated, Clark PU argued to roll in the Southern Intertie; no other party addressed this issue in the rate case.

• FERC has strongly encouraged the formation of IGOs/ISOs, in part to do away with pancaked rates which result when transmission customers must use more than one transmission system.

• However, FERC might be willing to continue past BPA practice, given the support of the region.

Principle 6. Consumer Protection

Rolling the cost of the Southern Intertie ($72 million per year) into the Network ($403 million) would:

• benefit the major users of the Southern Intertie by spreading SI cost over all users of transmission system.

• increase transmission cost most for customers who do little business on the Southern Intertie (e.g., BPA full requirements customers, many NTP/NT utilities).

AC Intertie Capacity Owners receive credit if Southern Intertie is rolled into Network.

• Step-up transformers are considered power costs.

The entire cost of the G-I segment is allocated to the PBL to be recovered through power rates.

• However, recent FERC decisions have called into question rolling in step-up facilities and certain other generation integration costs.

• Currently, proposed IndeGO pricing excludes step-up transformers.

Rolling the cost of the G-I segment ($15 million per year) into the Network ($403 million) has a small effect on transmission rates.

• BPA power customers would benefit the most, since the cost would now be spread over all users of the transmission system instead of only BPA power customers.

• The additional cost of the step-up transformers (Corps and Bureau facilities) is unknown at this time.

• However, FERC will allow the transmission provider to propose an alternative method that assigns costs consistently to firm PTP and NT services.

Under FERC’s cost allocation method applied to network costs only, the PTP/IR rates would increase about 15%; the NT/NTP rates would decrease about 20-25%.

• PTP/IR customers are generally the PBL, IOUs, and large generating publics.

• NTP/NT customers include BPA 1981 PSC customers, and smaller utilities (including PNGC).

BPA DRAFT PRINCIPLES

• BPA’s NT rate schedule includes 2 average embedded charges:

• Base charge (NT customers may exclude from the NT Base charge the load served: with internal generation, over another provider’s transmission systems, and using the power provider’s BPA transmission contract)

• Load Shaping charge

• The load ratio method equals:

1) the annual revenue requirement reduced for firm PTP revenues 2) multiplied by (a 12-month rolling average of) the customer’s contribution to the transmission owner’s monthly transmission system peak.

2) FERC also requires a credit for the customer’s own transmission facilities that are integrated with the transmission system of the transmission provider.

• Analyses performed prior to rate case showed that BPA could conceivably end up paying some transmission-owning utilities that it provides wheeling service.

• Currently, BPA transmission customers who own transmission facilities have opted for PTP service; instituting a credit for transmission facilities (as well as changing cost allocation) may attract these utilities to NT service.

• Scheduling, System Control and Dispatch Service, and Reactive Supply and Voltage Control from Generation Sources Service are not separately identified and offered as ancillary services.

• Other BPA ancillary services are packaged differently from FERC’s schedule of ancillary services.

• BPA includes transmission losses as an ancillary service, which is not required by FERC.

No cost shifts: ancillary services are primarily generation-related services; only small amounts of transmission costs are included in the cost of ancillary services.

BPA DRAFT PRINCIPLES

BPA DRAFT PRINCIPLES