PART 301—AVERAGE SYSTEM COST METHODOLOGY FOR SALES FROM UTILITIES TO BONNEVILLE POWER ADMINISTRATION UNDER NORTHWEST POWER ACT Authority: 16 U.S.C. 839-839h. Source: Order 726, 74 FR 47059, Sept. 15, 2009, unless otherwise noted. § 301.1 Applicability. The regulations in this part apply to the sales of electric power by any Utility to the Bonneville Power Administration (Bonneville) under section 5(c) of the Pacific Northwest Electric Power Planning and Conservation Act (Northwest Power Act). 16 U.S.C. 839c(c). § 301.2 Definitions. For purposes of this section, the following definitions apply: Account(s). Appendix 1. Average System Cost (ASC). Average System Cost delta (ASC delta). Average System Cost forecast model (ASC forecast model). Average System Cost review process (ASC review process). Base Period. Base Period ASC. Contract High Water Mark (CHWM). Commission. Consumer-owned Utility. Contract System Cost. Contract System Load. Direct Analysis. Escalator. Exchange Load. Exchange Period(s). Exchange Period ASC. FERC Form 1. Functionalization. Global Insight. Jurisdiction. Labor Ratios. pro rata Net Requirements. New Large Single Load. Priority Firm Power. Public Purpose Charge. (a) Conservation programs in lieu of Utility conservation programs; or (b) Acquisition of renewable resources. Rate Period. Rate Period High Water Mark (RHWM). Rate Period High Water Mark Process (RHWM Process). Regional Power Sales Customer. Residential Purchase and Sales Agreement. Review Period. Regulatory Body. RHWM Exchange Load. RHWM System Resources. Tier 1 Priced-Power. Tier 1 System Resources. Tiered Rates Methodology. Utility. § 301.3 Filing procedures. (a) Bonneville's ASC review procedures. (b) Exchange Period. § 301.4 Exchange Period Average System Cost determination. (a) Escalation to Exchange Period. (2) Bonneville will escalate the Bonneville-approved Base Period ASC to the midpoint of the fiscal year for a one-year Rate Period/Exchange Period, and to the midpoint of the two-year period for a two-year Rate Period/Exchange Period to calculate Exchange Period ASCs. (3) For purposes of the escalation referenced in paragraph (a)(2) of this section, Bonneville will use the following codes in the ASC forecast model to calculate the Exchange Period ASCs: (i) A&G—Administrative and General. (ii) CACNT—Customer Account. (iii) CD—Construction, Distribution Plant. (iv) CONSTANT—Constant. (v) CSALES—Customer Sales. (vi) CSERVE—Customer Service. (vii) COAL—Coal. (viii) DMN—Distribution Maintenance. (ix) DOPS—Distribution Operations (x) HMN—Hydro Maintenance. (xi) HOPS—Hydro Operations. (xii) INF—Inflation. (xiii) NATGAS—Natural Gas. (xiv) NFUEL—Nuclear Fuel. (xv) NMN—Nuclear Maintenance. (xvi) NOPS—Nuclear Operations. (xvii) OMN—Other Production Maintenance. (xviii) OOPS—Other Production Operations. (xix) SNM—Steam Maintenance. (xx) SOPS—Steam Operations. (xxi) TMN—Transmission Maintenance. (xxii) TOPS—Transmission Operations. (xxiii) WAGES—Wages. (4) Table 1 identifies which codes from paragraph (a)(3) of this section apply to the line items and associated FERC Accounts in the Appendix 1. Bonneville will use Global Insight as the source of data for the escalation codes identified in paragraph (a)(3) of this section, except for the NATGAS and CONSTANT codes. For the NATGAS code identified in paragraph (a)(3)(xiii) of this section, Bonneville will calculate the escalation rate using Bonneville's most current forecast of natural gas prices. The code CONSTANT in paragraph (a)(3)(iv) of this section indicates that no escalation to the Account will be made. (5) Bonneville will base the costs of power products purchased from Bonneville on Bonneville's forecast of prices for its products. (6) Bonneville will escalate the Public Purpose Charge forward to the midpoint of the Exchange Period by the same rate of growth as total Contract System Load. (7) If any of the escalators specified in paragraph (a) of this section are no longer available, Bonneville will designate a replacement source of such escalator(s) that, as near as possible, replicates the results produced by the prior escalator. If a replacement source is not available, Bonneville will use the INF escalation code identified in paragraph (a)(3)(xii) of this section as the replacement escalator. (b) Calculation of sales for resale and power purchases Long-term and intermediate-term sales for resale and power purchases. (2) Short-term sales for resale and power purchases. (ii) Bonneville will use the following method to determine separate market prices to forecast short-term purchased power expenses and sales for resale revenues to calculate Exchange Period ASCs: (A) The Utility's average short-term purchased power price and short-term sales for resale price will be calculated for each year for the most recent three years of actual data (Base Period and prior two years). (B) The midpoint between the Utility's average short-term purchased power price and the average short-term sales for resale price will be calculated for each of the years in paragraph (b)(2)(ii)(A) of this section. (C) The percentage spread around the Utility's midpoint between the average short-term purchase power price and short-term sales for resale price will be calculated for each of the years identified in paragraph (b)(2)(ii)(A) of this section. (D) A weighted average spread for the Utility's most recent three years of actual data (Base Period and prior two years) will be calculated. The following weighting scale will be used: ( 1 ( 2 ( 3 (E) The Base Period midpoint calculated in paragraph (b)(2)(ii)(B) of this section will be escalated at the same rate as Bonneville's electric market price forecast. (F) The weighted average spread calculated in paragraph (b)(2)(ii)(D) of this section will be applied to the escalated midpoint price calculated in paragraph (b)(2)(ii)(E) of this section to determine the purchased power price and sales for resale price to value purchased power expenses and sales for resale revenues to be included in the Exchange Period ASC. (iii) The method described in paragraph (b)(2)(ii) of this section will be used to forecast the electric market price for power purchases needed to meet load growth not met by major resource additions, and to forecast the electric market price for any additional surplus power sales resulting from major resource additions. (c) Major resource additions and reductions and materiality thresholds. (2) For major resource additions, the change to ASC will become effective when the resource begins commercial operation, or power is received under the purchased power contract. For major resource reductions, the change to ASC will become effective when the resource is sold, retired, or transferred. (3) A major resource addition or reduction must be related to one or more of the following categories to be eligible for consideration as a major resource: (i) Production or generating resource investments; (ii) Transmission investments; (iii) Long-term generating contracts; (iv) Pollution control and environmental compliance investments relating to generating resources; (v) Long-term transmission contracts; (vi) Hydroelectric relicensing costs and fees; and (vii) Plant rehabilitation investments. (4) Major resource additions or reductions that meet the criteria identified in paragraph (c)(3) of this section will be allowed to change a Utility's ASC within an Exchange Period provided that the major resource addition or reduction results in a 2.5 percent or greater change in a Utility's Base Period ASC. Bonneville will allow a Utility to submit stacks of individual resources that, when combined, meet the 2.5 percent or greater materiality threshold, provided, however, that each resource in the stack must result in a change to the Utility's Base Period ASC of 0.5 percent or more. (5) At the time the Utility submits its Appendix 1 filing, the Utility will provide its forecast of major resource additions or reductions and all associated costs. The forecast will cover the period from the end of the Base Period to the end of the Exchange Period. (6) Bonneville will calculate new transmission wheeling revenues associated with new transmission investment using the following formula: TTWR = WR (before additions) * [(NTP (before additions) + NTA)/NTP (before additions)] Where: TTWR = total transmission wheeling revenues WR (before additions) = wheeling revenues (before additions) NTA = new transmission additions NTP (before additions) = Net Transmission Plant (before additions) (7) The forecast of major resource additions or reduction costs to be included in the Utility's Exchange Period ASC will be reviewed by Bonneville in the ASC review process that is conducted during the Review Period. (8) All major resources included in an ASC calculation prior to the start of the Exchange Period will be projected forward to the midpoint of the Exchange Period. (9) For each major resource addition or reduction that is forecasted to occur during the Exchange Period, Bonneville will calculate the difference in ASC between the ASC without the major resource addition or reduction and the ASC with the major resource addition or reduction (ASC delta) at the midpoint of the Exchange Period. (10) Once the major resource addition or reduction becomes effective, as determined by paragraph (c)(2) of this section, Bonneville will add the ASC delta to the Utility's existing ASC to determine its new ASC. (11) For purposes of calculating ratios with Distribution Plant, Bonneville will escalate the Base Period average per-MWh cost of Distribution Plant forward to the midpoint of the Exchange Period, and use the escalated average cost to determine the distribution-related cost of meeting load growth since the Base Period. (12) Bonneville will escalate the cost of General Plant, Accounts 389 through 399.1, forward to the midpoint of the Exchange Period by calculating the ratio of each Account's value in the Base Period to the sum of Production, Transmission, and Distribution plant values in the Base Period, and then multiplying the Base Period ratio times the forecasted value for Production, Transmission, and Distribution plant. (13) Bonneville will issue procedural rules to ensure the confidentiality of information provided by Utilities regarding any major resource additions or reductions as part of its review process. Bonneville will provide parties with an opportunity to comment on the rules prior to their implementation in the review process. Failure to provide needed information may result in exclusion of the related costs from the Utility's ASC. However, load growth will be assumed to be met with purchases in the wholesale market, as described in paragraph (e) of this section. If the Utility fails to supply confidential resource data, it loses the difference between the cost of the resource and the price of electricity in the wholesale market. (d) Forecasted Contract System Load and Exchange Load. (e) Load growth not met by major resource additions. (1) The Utility's forecast Load Growth will be met with electric market purchases priced at the Utility's forecast short-term purchased power price as determined in paragraph (b) of this section unless the Utility forecasts major resource additions. (2) In the event of major resource additions, forecast Load Growth will be met by the major resource(s). If the major resource is less than total forecast load growth, the unmet Load Growth will be met with electric market purchases priced at the Utility's forecast short-term purchased power price. (3) In the event the power provided by a major resource exceeds the Utility's forecast Load Growth, the excess power will be used to reduce the Utility's short-term purchases. If short-term power purchases are reduced to zero, any remaining power will be sold as surplus power at the short-term sales for resale price as determined in paragraph (b) of this section. (f) Changes to service territory. (1) First, a Base Period ASC that does not reflect the acquisition or loss of service territory; and (2) Second, a Base Period ASC that incorporates the following changes: (i) A forecast of the increase or reduction in Contract System Load associated with the acquisition or reduction in service territory. (ii) A forecast of the increase or reduction in Contract System Cost associated with the acquisition or reduction of the service territory. (iii) A forecast of capital and operating cost increases or reductions associated with the change in service territory. (iv) A forecast of the changes in purchased power expenses, sales for resale revenues, and other debits or credits based on the changes in the service territory. (3) Because the date of the actual change to the Utility's service territory could differ from the forecast date used to determine the ASC during the Review Period, Bonneville will not adjust the Utility's ASC until the change in service territory takes place. (g) ASC determination for Consumer-owned Utilities that elect to execute Regional Dialogue High Water Mark contracts. (1) Use the RHWM System Resources as determined in the Tiered Rates Methodology (TRM) process. (2) Determine the RHWM Exchange Load. (3) Calculate the Utility's Contract System Cost as described in the ASC Methodology. (4) Determine the fully allocated cost of resources used to meet Contract System Load that is not met by: (i) The lesser of the Utility's RHWM or Forecast New Requirement, plus (ii) Existing Resources for CHWM (as defined in the Tiered Rates Methodology). (5) RHWM Contract System Cost = Contract System Cost minus fully allocated cost of resources (from paragraph (g)(4) of this section). (6) RHWM Average System Cost = RHWM Contract System Cost (from paragraph (g)(5) of this section)/RHWM System Resource (from paragraph (g)(1) of this section). (h) Filing of Appendix 1. § 301.5 Changes in Average System Cost methodology. (a) The Administrator, at his or her discretion, or upon written request from three-quarters of the utilities that are parties to contracts authorized by section 5(c) of the Northwest Power Act, or from three-quarters of Bonneville's preference customers, or from three-quarters of Bonneville's direct-service industrial customers may initiate a consultation process as provided in section 5(c) of the Northwest Power Act. After completion of this process, Bonneville's Administrator may file the new ASC methodology with the Commission. (b) The Administrator will not initiate any consultation process until one year of experience has been gained under the then-existing ASC methodology, that is, one year after the then-existing ASC methodology is adopted by Bonneville and approved by the Commission, through interim or final approval, whichever occurs first. (c) The Administrator may, from time to time, issue interpretations of the ASC methodology. The Administrator also may modify the functionalization code of any Account to comply with the limitations identified in sections 5(c)(7)(A)-(C) of the Northwest Power Act or to conform to Commission revisions to the Uniform System of Accounts. § 301.6 Appendix 1 instructions. (a) Appendix 1 is the form on which a Utility reports its Contract System Cost, Contract System Load, and other necessary data for the calculation of ASC. Appendix 1 is an electronic template consisting of seven schedules and several supporting files that must be completed by the Utility in accordance with these instructions and with the provisions of the endnotes following the schedules. (b) Appendix 1 filings must be accompanied by an attestation statement of the Chief Financial Officer of the Utility or other responsible official who possesses the financial and accounting knowledge necessary to complete the attestation statement. (c) The primary source of data for the Investor-owned Utilities' Appendix 1 filings is the Utility's prior year FERC Form 1 filings with the Commission. Any items not applicable to the Utility must be identified. (d) For Consumer-owned Utilities that do not follow the Commission's Uniform System of Accounts, filings must include reconciliation between Utility Accounts and the items allowed as Contract System Cost. In addition, the cost-of-service report must be reviewed by an independent accounting or consulting firm, and must be accompanied by a report from that independent accounting or consulting firm that outlines the review work that was performed in preparing the cost-of-service report along with an assurance statement that the information contained in the cost-of-service report is presented fairly in all material respects. (e) The Appendix 1 template is available electronically at http://www.bpa.gov/corporate/finance/ascm/. (1) Schedule 1: Plant Investment/Rate Base (2) Schedule 1A: Cash Working Capital (3) Schedule 2: Capital Structure and Rate of Return (4) Schedule 3: Expenses (5) Schedule 3A: Taxes (6) Schedule 3B: Other Included Items (7) Schedule 4: Average System Cost (f) The filing Utility must reference and attach work papers, documentation and other required information that support costs and loads, including details of allocation and functionalization. All references to the Commission's Accounts are to the Commission's Uniform System of Accounts, as amended by subsequent Commission actions. The costs includable in the attached schedules are those includable by reason of the definitions in the Commission's Accounts. If the Commission's Accounts are later revised or renumbered, any changes will be incorporated into the Appendix 1 by reference, except to the extent Bonneville determines that a particular change results in a change in the type of costs allowable for Residential Exchange Program purposes. In that event, Bonneville will address the changes, including escalation rules, in its review process for the following Exchange Period. (g) Bonneville may require a Utility to account for all transactions with affiliated entities as though the affiliated entities were owned in whole or in part by the Utility, if necessary, to properly determine and/or functionalize the Utility's costs. (h) A Utility operating in more than one Pacific Northwest Jurisdiction must file one Appendix 1. (i)(1) A Utility operating in a Jurisdiction within the Pacific Northwest and within Jurisdictions outside the Pacific Northwest must allocate its total system costs among its Jurisdictions within the Pacific Northwest and outside the Pacific Northwest in accord with the same allocation methods and procedures used by the Regulatory Body(ies) to establish Jurisdictional costs and resulting revenue requirements. The Utility's Appendix filing must include details of the allocation. (2) The allocation must exclude all costs of additional resources used to meet loads outside the Pacific Northwest, as required by section 5(c)(7) of the Northwest Power Act. All schedule entries and supporting data must be in accord with Generally Accepted Accounting Principles and Practices as these principles and practices apply to the electric utility industry. (j) A Utility must file an attestation statement with each Appendix 1 filing and supporting documentation for each Review Period. § 301.7 Average System Cost methodology functionalization. (a) Functionalization of each Account included in a Utility's ASC must be according to the functionalization prescribed in Table 1, Functionalization and Escalation Codes. (b) Functionalization codes. (1) DIRECT—Direct Analysis. (2) PROD—Production. (3) TRANS—Transmission. (4) DIST—Distribution/Other. (5) PTD—Production, Transmission, Distribution/Other Ratio. (6) TD—Transmission, Distribution/Other Ratio. (7) GP—General Plant Ratio. (8) GPM—General Plant Maintenance Ratio. (9) PTDG—Production, Transmission, Distribution/Other, General Plant Ratio. (10) LABOR—Labor Ratio. (c) Functionalization requirements. (1) Functionalization of certain Accounts may be based on Direct Analysis or with a default ratio associated with that specific Account as shown in Table 1. Once a Utility uses a specific functionalization method for an Account, the Utility may not change the functionalization method for that Account without prior written approval from Bonneville. (2) The Utility must submit with its Appendix 1 all work papers, documents, or other materials that demonstrate that the functionalization under its Direct Analysis assigns costs, revenues, debits or credits based upon the actual and/or intended functional use of those items. Failure to submit the documentation will result in the entire account being functionalized to Distribution/Other, or Production, or Transmission, as appropriate. (d) Functionalization methods. (2) Bonneville will not allow a Utility to use a combination of Direct Analysis and a prescribed functionalization method for the same Account. The Utility can develop and use a functionalization ratio, or use a prescribed functionalization method, if the Utility, through Direct Analysis, can justify how the ratio reflects the functional nature of the costs, revenues, debits, or credits included in any Account. (3) A Utility that wishes to include advertising and promotion costs related to conservation will use Direct Analysis. (4) If a Utility records conservation costs in an Account that is functionalized to Distribution/Other, the Utility will identify and document the conservation-related costs included in the Account, and the balance of the costs will be functionalized to Distribution/Other. The presence of conservation-related costs in an Account does not authorize the Utility to perform a Direct Analysis on the entire Account. This option allows a Utility to assign conservation costs in the specified Account to Production based on analysis and support from the Utility that demonstrates the cost assignment is appropriate. The Utility must submit with its ASC filing all work papers, documents, and other materials that demonstrate the functionalization contained in its Direct Analysis and assign costs based upon the actual and/or intended functional use of those items. Failure to submit the documentation will result in the entire Account being functionalized to Distribution/Other for all schedules with the exception of items included in Schedule 3B, Other Included Items, Table 1 to Part 301—Functionalization and Escalation Codes Appendix 1 to Part 301—ASC Utility Filing Template