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HomeMy WebLinkAbout20221026Appendix 7.1 Idaho ROO Process Guide.pdfAppendix 7.1 – Idaho ROO Process Guide Page 1 of 6 Appendix 7.1 – Idaho 2021 Results of Operations Process Guide The 2021 Results of Operations (“ROO”) study, 12-months ending December 31, 2021, was developed using a methodology similar to that approved in the Company’s last general rate case, Case No. IPC-E-11-08 (“2011 rate case”). However, unlike the 2011 rate case, no financial data was grown or forecasted. Because the purpose of this study is to serve as the basis for a class cost-of-service study, this study does not include a requested rate of return. Rather, the return component included in the ROO study represents the difference between 2021 normalized revenues and the 2021 cost-of- service components. The following summarizes the process Idaho Power Company (“Idaho Power” or “Company”) undertook for the completion of the jurisdictional separation study (“JSS”) for the 12-months ending December 31, 2021:  The Company began with actual, audited and reported to the U.S. Securities and Exchange Commission, 2021 financial data (“2021 Actuals”) including (1) other operating revenues, (2) other revenues and expenses, (3) operation and maintenance (“O&M”) expenses, (4) property insurance expenses, (5) regulatory commission expenses, (6) depreciation and amortization expense, (7) electric plant/regulatory assets – amortizations, adjustments, gains, and losses, (8) regulatory debits and credits, (9) taxes other than income taxes, (10) Idaho Energy Resources Company’s (“IERCo”) statement of income and rate base components, (11) allowance for funds used during construction (“AFUDC”) related to the Hells Canyon relicensing, (12) electric plant in service and related items, (13) materials and supplies, (14) other deferred programs, (15) plant held for future use, (16) accumulated deferred income taxes, and (17) customer advances for construction.  Next the Company made standard regulatory adjustments, or adjustments in conformance with prior Idaho Public Utilities Commission (“Commission”) orders, to the 2021 Actuals. The adjustments, which are explained and quantified in further detail below, included the removal of: o general advertising expenses, o specific memberships and contributions, o prepayments, o a portion of incentive compensation, o financial impacts of the Idaho and Oregon Energy Efficiency Rider revenues and expenses, and o plant held for future use to remove structures and specific properties for which the future use is uncertain.  In addition, Idaho Power adjusted the 2021 Actuals to reflect updated normalized power supply expenses (“NPSE”). Normalized or base NPSE is calculated by modeling the test period under multiple historical water conditions; in this case, the Company modeled 67 historical water conditions (1954-2021). The term “net power supply expense” refers to the sum of the following Federal Energy Regulatory Commission (“FERC”) accounts: fuel expense (FERC Accounts 501 Appendix 7.1 – Idaho ROO Process Guide Page 2 of 6 and 547), and purchased power expenses (FERC Account 555), minus surplus sales revenues (FERC Account 447). The Company modeled NPSE using the AURORA model, which is a comprehensive electric resource dispatch model that simulates the economic dispatch of the Company’s resources to determine NPSE. The Commission has accepted the use of AURORA to determine base level NPSE for general rate cases or other one off base level NPSE update filings (most recently, Case No. IPC-E- 13-20), marginal cost analyses, and resource modeling for the Company’s Integrated Resource Plan. In modeling NPSE in AURORA, the Company updated a number of input variables including fuel prices, transportation costs, heat rates, forced outage rates, planned outages, normalized load and sales, contracts for wholesale power and power purchases and sales, Public Utility Regulatory Policies Act contract expenses, and wheeling expenses.  Because the Company has an established recovery mechanism in place for the Valmy coal-fired plant, Idaho Power has removed all cost-of-service components associated with this coal plant that is recovered through the levelized revenue requirement mechanism. Recognition of the Valmy related levelized revenue requirement is applied as an adjustment to the class cost-of-service process as described in Appendix 7.3.  Finally, annualizing adjustments were made. The financial data is then input into the JSS to determine the Idaho jurisdictional ROO. The resulting JSS is included as Appendix 7.2. The JSS is a three-step process - the classification, functionalization, and allocation of costs - that separates costs among jurisdictions. In all three steps, recognition is given to the way in which costs are incurred by relating these costs to utility operations. Classification groups the costs into three categories: demand-related, energy-related, and customer-related. Costs are also functionalized, or identified as generation, transmission, and distribution operating functions. Finally, the costs are allocated between the Idaho and Oregon jurisdictions, apportioning the total system costs among jurisdictions by introducing allocation factors. An allocation factor specifies the jurisdictional value as a share or percent of the total system quantity. The classification, functionalization, and allocation of costs was performed in accordance with the approved 2011 rate case methodologies1. Once the individual accounts have been allocated to the various jurisdictions, it is possible to summarize these into total utility rate base and net income by jurisdiction. The results are stated in a summary form and measure the difference between 2021 normalized revenues and the 2021 cost-of- service components. 1 With the exception of Electric Plant-in-Service FERC Account 368 – Line Transformers, which was allocated using the D60 allocator, distribution at generation level, as was approved in the last Oregon general rate case, Case No. UE 233. Appendix 7.1 – Idaho ROO Process Guide Page 3 of 6 JURISDICTIONAL SEPARATION STUDY FOR THE 12-MONTHS ENDING DECEMBER 31, 2021 The following is a description and quantification of adjustments made to 2021 Actuals in the order they appear in the JSS and a brief description of how the adjusted 2021 Actuals were allocated to each jurisdiction:  The first adjustment, on line 78, adds to the Idaho jurisdictional earnings deficiency $6,815,472, the level of recovery of AFUDC associated with the Hells Canyon relicensing project construction work in progress originally approved in the Company’s 2008 rate case (Case No. IPC-E-08-10) and again in the 2011 rate case.  Table 1 – Electric Plant-In-Service o Table 1 reflects Idaho Power’s 13-month average electric plant-in-service values, excluding Valmy and any remaining Boardman asset balances, at December 31, 2021. No other adjustments or additions were made to electric plant-in-service. o Production plant was allocated to the jurisdictions based on the average of the 12 monthly coincident peak demands and unless noted otherwise, allocation of transmission and distribution plant was based on the same methodology. Some transmission and distribution facilities were directly assigned to the customers who paid upfront for the facilities installed to serve them. General plant was allocated on the same basis as the sum of the allocated investments in production, transmission, and distribution plant.  Table 2 – Accumulated Provision for Depreciation o Accumulated Provision for Depreciation is reflected as the 13-month average at December 31, 2021. A reserve adjustment was made to reflect half of the annualized depreciation expense adjustment that occurs in Table 6 and detailed below. The Accumulated Provision for Depreciation balances exclude Valmy and any remaining Boardman values. o The Accumulated Provision for Depreciation was allocated by total for each production plant type and for each primary plant account in other functional groups based on the related plant account in Table 1. Amortization of other utility plant was functionalized then allocated based on the related plant items in Table 1.  Table 3 – Additions and Deletions to Rate Base o Balances of customer advances for construction (FERC Account 252), accumulated deferred income taxes (FERC Accounts 190, 282, and 283), materials and supplies (FERC Accounts 154 and 163), and IERCo rate base components reflect the 13-month average. However, other deferred programs reflect the account balances as of December 31, 2021. Appendix 7.1 – Idaho ROO Process Guide Page 4 of 6 o A number of adjustments are included in Table 3:  Fuel stock inventory includes only required fuel stock inventory of $29,293,629.  Removal of the following from rate base:  $24,557,592 in prepayments,  $1,069,812 in plant held for future use for which the plant use is uncertain at this time, the plant may be split, or for plant structures that will be razed,  $9,419,457 associated with the Siemen’s long-term program contract regulatory asset that received deferred rate base treatment with IPUC Order No. 33420, and  $85,531 of plant that was determined in the 2011 rate case to no longer be used and useful at the Bridger Coal plant. o Additions and deletions to rate base were allocated under a number of different methodologies: (1) customer advances for construction were directly assigned to customers by jurisdiction, (2) accumulated deferred income taxes are allocated by plant, customer advances for construction, or labor, (3) materials and supplies by their respective plant allocators, (4) fuel inventory on the basis of energy, (5) components of IERCo on energy, and (6) Commission-ordered deferred investments were either directly assigned to a specific jurisdiction or allocated based on energy.  Table 4 – Operating Revenues o Operating Revenues includes an adjustment of ($187,931,014) to 2021 Actuals to reflect the normalization and annualization of revenues and an adjustment of ($48,845,418) for the removal of revenues associated with the Valmy plant. In addition, an adjustment of ($65,077,513) to FERC Account 447, Opportunity Sales, was made to reflect the normalized NPSE results from AURORA. Finally, $29,920,448 associated with the Idaho and Oregon Energy Efficiency Rider revenues was removed from FERC Account 456, Other Electric Revenues. o Operating Revenues were directly assigned to each jurisdiction. Opportunity Sales are credited to each jurisdiction in proportion to generation-level energy use. Other Operating Revenues were allocated in a manner that offsets related allocations of rate base, or where a particular revenue item could be associated with a specific jurisdiction, directly assigned. Appendix 7.1 – Idaho ROO Process Guide Page 5 of 6  Table 5 – Operations and Maintenance Expenses o The following is a summary of the adjustments made to 2021 Actual O&M expenses:  An annualizing adjustment was made to operating payroll to reflect as though the year-end amounts had been in existence for the entire year,  All 2021 actual non-fuel O&M attributable to the Valmy plant was removed as the expenses are recovered through the Valmy levelized revenue requirement mechanism,  NPSE were updated to reflect normalized conditions from the updated AURORA run,  $29,920,448 in Idaho Energy Efficiency Rider expenses (FERC Account 908) were removed,  $7,636,409 of incentive expense (FERC Account 920) was removed so that only the normalized incentive components that are attributable to Customer Satisfaction and Reliability were included,  $122,954 of property insurance expense associated with Valmy was removed from FERC Account 924 as those expenses are recovered through the Valmy levelized revenue requirement mechanism, and  a deduction of $635,984 was made for general advertising expenses, certain memberships and contributions, and miscellaneous other expenses, consistent with the methodology approved in the 2011 rate case. o The allocation of O&M expenses is detailed in Table 5. In general, the basis for each allocation is identifiable with the source code listed in the JSS provided as Appendix 7.2. Demands are identified by source code beginning with the prefix “D”, energy use is identified by a source code beginning with an “E” prefix, related plant is identified by a line number source code, and customer-weighted allocation factors begin with a “CW” prefix. For each functional group, the labor component was separately allocated in accordance with the detail provided in Table 13 – Development of Labor Related Allocator. Total allocated labor expense served the additional purpose of allocating employee pension and other labor-related taxes and expenses.  Table 6 – Depreciation and Amortization Expense o Annualizing adjustments were made to reflect depreciation and amortization expense amounts as though they had been in existence for the entire year. o Depreciation and amortization expenses were identified by production plant type or by primary plant account for other functional plant groups and allocated consistent with the related plant account. Valmy and Boardman depreciation and amortization expense were removed as amounts were recovered through the levelized revenue requirement mechanisms. Appendix 7.1 – Idaho ROO Process Guide Page 6 of 6  Table 7 – Taxes Other than Income Taxes o Federal unemployment, Social Security, and state unemployment taxes are eliminated by the state and federal payroll loading reversal. The expenses are removed to demonstrate that these amounts are not double counted. The hydro generation kilowatt-hour tax and irrigation tax refund expenses are normalized. o Individual taxes other than income tax items were allocated in a manner consistent with the bases by which the respective taxes were assessed.  Table 8 – Regulatory Debits and Credits o No adjustment was made to 2021 Actuals. o The amortization expense is assigned by jurisdiction for which the regulatory debit or credit was established.  Table 9 – Income Taxes: Federal, Oregon, Idaho, and Other State o Normalized state and federal income tax liabilities are summarized on Tables 9 through 12. o The deferred income taxes and the investment tax credit adjustments were allocated based on the Company’s plant investment and net income before tax adjustments. The respective tax bases were developed and calculated directly for each jurisdiction. Operating income before taxes represents adjusted operating revenues less all adjusted operating expense with the exception of deferred income taxes and investment tax credits. Adjusted interest expense was allocated by the combined rate base to develop net operating income before taxes. Subsequent additions to or deductions from the respective tax bases were allocated to each jurisdiction by aligning it with its causation or fundamental association, resulting in taxable income for each jurisdiction. The appropriate tax rate was applied and the resulting final tax amounts by jurisdiction derived.  Tables 13 through 15 – Development of Labor Related Allocator, Allocation Factors, and Allocation Factors - Ratios o No adjustment was made to 2021 Actuals. o The tables include the principal allocation factors used in the JSS and the respective jurisdictional values for each allocation factor. Table 15 lists the ratios of the principal allocation included in Table 14. The summary of the JSS results are presented on page 1 of Appendix 7.2. The development of the Idaho jurisdictional ROO is presented in the column entitled “Idaho Retail”. When comparing the difference between 2021 normalized revenues and the 2021 cost-of-service components, the resulting Idaho consolidated operating income is $190,831,772 (line 45).