Revisions to Attachment O-SPS Transmission Formula Rate ... · 11/27/2018 · SPS is a vertically...

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Minneapolis, Minnesota 55401 November 27, 2018 VIA ELECTRONIC FILING The Honorable Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, DC 20426

Re: Public Service Company of Colorado Southwestern Public Service Company Revisions to Attachment O-SPS Transmission Formula Rate Template in Xcel Energy Operating Companies Open Access Transmission Tariff Docket No. ER19-____-000

Dear Secretary Bose:

Pursuant to Section 205 of the Federal Power Act (“FPA”), 16 U.S.C. § 824d, and Part 35 of the Federal Energy Regulatory Commission’s (“FERC” or “Commission”) regulations, 18 C.F.R. § 35.13 (2018), Public Service Company of Colorado (“PSCo”),1 on behalf of Southwestern Public Service Company (“SPS”), submits revised tariff records to the Xcel Energy Operating Companies FERC Electric Tariff, Third Revised Volume No. 1 (“Xcel Energy Tariff” or “Tariff”) to revise Attachment O-SPS, the SPS transmission formula rate template (“Attachment O-SPS” or “Template”).

The proposed revisions will:

1. With respect to SPS’s transmission depreciation expenses, (i) update the depreciation rates used to calculate wholesale transmission rates under the Template, as well as add a new table in the Template that lists the SPS depreciation rates used in the Template, (ii) revise the Template’s Base Plan Upgrade (“BPU”) revenue requirement calculation to use a weighted average transmission depreciation rate, and (iii) revise the BPU revenue requirement net plant calculation so that historical depreciation rates apply only to the applicable years those rates were in effect.

2. Revise the Template so SPS recovers certain wholesale transmission regulatory commission expenses from its wholesale transmission service customers.

1 PSCo is the designated e-Tariff filing entity for the Xcel Energy Tariff, consistent with the requirements of Order No. 714. Electronic Tariff Filings, Order No. 714, FERC Stats. & Regs. ¶ 31,276 (2008).

Honorable Kimberly D. Bose November 27, 2018 Page 2

3. Modify the Template to correct the allocation of transmission-specific Accumulated Deferred Income Taxes (“ADIT”) so it is allocated consistently with the other transmission-specific components of SPS’s revenue requirement.

4. Revise the methodology for calculating ADIT to amortize (or flow-back) the “excess” ADIT caused by the change in the federal corporate income tax to 21 percent as part of the Tax Cuts and Jobs Act of 2017 (“TCJA”),2 consistent with the preliminary guidance provided by the Commission in its ADIT-related notice of proposed rulemaking issued November 15, 2018.3

5. Implement one ministerial change intended to improve the clarity of the Template.

SPS respectfully requests that the Commission permit the revised Template to become effective as of February 1, 2019, sixty-six (66) days after this filing, without suspension or hearing. As discussed below, granting SPS’s requested February 1, 2019 effective date is consistent with Commission policy and is supported by the testimony and associated exhibits included as part of this filing.

SPS estimates that the proposed revisions to the Template (the “Revised Template”) will result in an increase to 2019 wholesale transmission service revenues of approximately $9.427 million, with $4.958 million being recovered from wholesale transmission service customers in the SPS rate zone (Zone 11) under the Southwest Power Pool, Inc. (“SPP”) Open Access Transmission Tariff (the “SPP Tariff”), and $4.469 million being recovered from other SPP Tariff customers through regional transmission rates under the SPP Tariff. The increase is primarily the result of the updated transmission depreciation rates, partially off-set by the reduction in costs from the flow-back of excess ADIT.

Upon Commission acceptance of the Revised Template, Xcel Energy Services Inc.

(“XES”) and SPS will work with SPP to submit a companion filing to modify the SPP Tariff to reflect the Revised Template in Attachment H to the SPP Tariff, effective February 1, 2019. I. CONTENTS OF FILING

This filing consists of the following items, which are included as attachments to the XML package:

1. This transmittal letter;

2. Attachment 1: An Attestation pursuant to 18 C.F.R. § 35.13(d)(6) (2018);

3. Attachment 2: A certificate of service;

2 Tax Cuts and Jobs Act, Pub. L. No. 115-97, 131 Stat. 2054 (2017). 3 Public Utility Transmission Rate Changes to Address Accumulated Deferred Income Taxes, Notice of

Proposed Rulemaking, 165 FERC ¶ 61,117 (2018).


4. Exhibit No. SPS-0001: A copy of the Revised Template in clean format;

5. Exhibit No. SPS-0002: A copy of the Revised Template in marked format;

6. Exhibit Nos. SPS-0003 through SPS-0006: the Direct Testimony of Arthur P. Freitas, Manager, Revenue Analysis for XES (“Freitas Direct Testimony”) and associated exhibits;4

7. Exhibit Nos. SPS-0007 through SPS-0009: the Direct Testimony of Melissa L. Ostrom, Director, Capital Asset Accounting for XES (“Ostrom Direct Testimony”) and associated exhibits; and

8. Exhibit Nos. SPS-0010 through SPS-0012: the Direct Testimony of Dane A. Watson of the Alliance Consulting Group (“Watson Direct Testimony”) and associated exhibits.

II. BACKGROUND

A. The Filing Parties

SPS is a vertically integrated electric utility that, inter alia, provides generation, transmission, and distribution services in Texas and New Mexico, and owns transmission in portions of Kansas and Oklahoma. SPS provides cost-based regulated electric services to approximately 390,000 retail and wholesale customers in Texas and New Mexico. SPS’s retail electric services are subject to the jurisdiction of the Public Utility Commission of Texas (“PUCT”) and the New Mexico Public Regulation Commission (“NMPRC”). SPS’s wholesale sales and transmission services and rates are regulated by the Commission. Since 1973, SPS has been a transmission-owning member of SPP, a FERC-approved Regional Transmission Organization (“RTO”). Since June 2000, transmission service over the SPS transmission system has been available under the SPP Tariff. Approximately thirty-nine (39) percent of the transmission loads on the SPS transmission system are wholesale transmission service customers taking Network Integration Transmission Service (“Network Service”) under the SPP Tariff with load in SPP Zone 11, the SPS zone.

PSCo is an affiliate of SPS, and a vertically integrated electric utility that, inter alia,

provides generation, transmission, and distribution services in Colorado. Transmission service over the PSCo system is available under the Xcel Energy Tariff, and PSCo is the designated e-Tariff filing entity for revisions to the Xcel Energy Tariff, consistent with the requirements of Order No. 714. 5 PSCo is a party to this filing solely as the eTariff filing entity.6

4 Although Exhibit Nos. SPS-0001 and SPS-0002 are listed in this filing as stand-alone exhibits for ease of reference, for evidentiary purposes, Mr. Freitas is sponsoring Exhibit Nos. SPS-0001 and SPS-0002.

5 The Xcel Energy Tariff was filed via eTariff in Baseline Electronic Tariff Filing of the Xcel Energy Operating Companies, Public Service Company of Colorado, Docket No. ER10-2070-000 (July 30, 2010), and accepted by the Commission on September 24, 2010. See Pub. Svc. Co. of Colorado., Docket No. ER10-2070-000 (Sept. 24, 2010) (delegated letter order). The Xcel Energy Tariff was “re-baselined” in the Commission’s eTariff system effective April 16, 2016, in order to implement a new eTariff software


XES is the centralized service company subsidiary of Xcel Energy and, as such, performs

an array of administrative and general services on behalf of the Xcel Energy Operating Companies. Among other things, XES submits filings with and appears in proceedings before the Commission on behalf of SPS.

B. The Attachment O-SPS Transmission Formula Rate Template

Under the SPP Tariff, transmission facilities fall into different categories, and different cost allocation rules apply to each category. At the time SPP approves a project for construction, SPP determines the cost allocation rule that will apply to the project. As a general matter, SPS’s transmission facility costs are: (i) allocated zonally to Zone 11, (ii) allocated to Zone 11 as part of the SPP Base Plan Zonal Charge, or (iii) allocated regionally as part of the SPP Base Plan Region-wide Charge. With respect to BPUs, SPP’s cost allocation rules sometimes require that the costs of a single SPS facility be split between Zone 11 Base Plan Zonal Charge and the SPP Base Plan Region-wide Charge. For example, for certain Base Plan Upgrades, 67 percent of a facility’s costs are allocated zonally to Zone 11 while 33 percent of that same facility’s costs are allocated regionally to SPP’s Region-wide Charge. Because the Region-wide Base Plan Charge applies to all zones, Zone 11 is then allocated a portion of the SPS’s costs that are allocated regionally through the SPP Base Plan Region-wide Charge.

To reflect these SPP cost allocation rules, SPS’s Template calculates three separate annual transmission revenue requirements (“ATRRs”): (1) the Zonal Network Integration Transmission Service revenue requirement for Zone 11 (SPS) under the SPP Tariff (the “Zonal ATRR”); (2) SPS’s BPU revenue requirement, which includes all BPU facilities; and (3) the Scheduling, System Control and Dispatch revenue requirement for Schedule 1. In this filing, SPS is not proposing Template changes to the calculation of the Scheduling, System Control and Dispatch revenue requirement.

To calculate the Zonal ATRR, the Template first calculates a total annual transmission revenue requirement (“Total ATRR”). The Total ATRR is the revenue requirement for the entire SPS network transmission system regardless of which SPP cost allocation rule applies to that facility. The Total ATRR’s rate base is calculated based on SPS’s total transmission gross plant, accumulated depreciation, ADIT, and similar rate base components. The return on rate base is then calculated using the Template’s weighted average cost of capital. The return on rate base is then added to other transmission operating expenses such as operation and maintenance (“O&M”) and depreciation expense to arrive at a gross revenue requirement. Finally, applicable revenue credits are applied to calculate the Total ATRR.

system. The re-baselined Xcel Energy Tariff was accepted for filing in Docket No. ER16-1422-000. Public Service Co. of Colorado, Docket No. ER16-1422 (Aug. 16, 2016) (delegated letter order).

6 This filing does not affect rates or services on the PSCo transmission system under the Xcel Energy Tariff.


SPS calculates its Zonal ATRR and its project-specific BPU revenue requirements pursuant to the formulae set forth in the Template. SPS’s Zonal ATRR is then used by SPP to calculate rates for Firm and Non-Firm Point-to-Point Transmission Service provided under Schedules 7 and 8 of the SPP Tariff and Network Service provided under Schedule 9 of the SPP Tariff. SPS employs a forward-looking Template, whereby the ATRR is projected under the Template each year using estimated costs and loads. Pursuant to the Formula Rate Implementation Procedures (“Protocols”), which are included as Appendix 1 to the Template, SPS’s projected ATRR is then subject to an annual true-up based on actual costs and loads when actual data becomes available. SPS calculates the true-up by June of the year following the estimated Rate Year, and the true-up is applied to customer bills by the end of the year following the estimated Rate Year. The Protocols provide for postings on SPS’s Open Access Same-Time Information System, customer meetings, discovery and challenge processes, and an Annual Informational Update filing with the Commission with the Estimated Rates for the upcoming Rate Year.7

III. DESCRIPTION AND JUSTIFICATION OF PROPOSED TARIFF REVISIONS

A. SPS’s Updated Transmission Depreciation Rates and Depreciation-Related Template Changes

1. Updated Depreciation Rates

The transmission depreciation rates used to calculate SPS’s wholesale transmission rates were last updated in Docket No. EL89-50-000, et al., nearly thirty (30) years ago (the “1989 Depreciation Rates”).8 When SPS moved from stated transmission rates to the formula rate Template in Docket No. ER08-313-000, SPS continued to calculate its wholesale transmission rates using the 1989 Depreciation Rates.9 Since establishing the Template, SPS has used the 1989 Depreciation Rates when calculating the Annual Update and Annual True-up under the Template, and when submitting the Annual Informational Updates to the Commission pursuant to the Protocols.

Consistent with Order No. 618,10 this filing updates SPS’s transmission depreciation rates (“Updated Depreciation Rates”) to be implemented in the Revised Template. SPS respectfully requests that the Commission accept the Updated Depreciation Rates without suspension or

7 The informational filing is due on December 1st each year, unless December 1 falls on a weekend or holiday, and then it is filed the next business day. The informational filing for the 2018 Rate Year was submitted on December 1, 2017 in Docket No. ER08-313-000. Informational Filing: 2018 Transmission Formula Rate Annual Update, Southwestern Public Service Co., Docket No. ER08-313-000 (Dec. 1, 2017). The informational filing for the 2019 Rate Year will be submitted on December 3, 2018.

8 Southwestern Public Service Co., Docket Nos. EL89-50-000, et al. (Oct. 10, 1990) (delegated letter order). 9 The Commission issued orders approving two settlements in Docket Nos. ER08-313-000, et al. See Xcel

Energy Services Inc., 129 FERC ¶ 61,193 (2009) and Xcel Energy Services Inc., 132 FERC ¶ 61,170 (2010).

10 Depreciation Accounting, Order No. 618, FERC Stats. & Regs. ¶ 31,104 (2000).

Honorable Kimberly D. Bose November 27, 2018 Page 6 hearing to become effective as of February 1, 2019. SPS also requests that the Commission accept SPS’s proposal to reallocate its depreciation reserve as of February 1, 2019.

Order No. 618 requires that utilities use methods of depreciation accounting that “allocate the cost of utility property over its useful life in a systematic and rational manner.”11 Although Order No. 618 allows utilities to change their depreciation methodology for accounting purposes without making a formal filing at the Commission, the order requires that a utility must make an FPA Section 205 filing before a depreciation rate change can effect a change in a FERC-jurisdictional rate.12

SPS’s existing depreciation rates and the Updated Depreciation Rates are listed in Table 1 by plant account:

11 Order No. 618 at 31,694. 12 “To change prices charged for power sales or transmission services (whether determined by stated rates or

formula rates) to reflect a change in depreciation, a utility would first have to make a filing with us, pursuant to sections 205 or 206 . . . as appropriate, to that effect.” Order No. 618 at 31,695 n.25.


Table 1 Existing and Updated Depreciation Rates by FERC Account

With two exceptions, the FERC accounts for the existing depreciation rates listed in

Table 1 are identical to those for the depreciation rates implemented through the 1989 Depreciation Rates. The 1989 Depreciation Rates did not include a rate for Account No. 350.2 or a rate for Account No. 359. Historically, SPS amortized Land Rights property over 50 years, which equates to a 2 percent rate. Therefore, under the current Template, SPS has used this 2 percent depreciation (or amortization) rate to calculate its depreciation expense for Account No. 350.2.13 To calculate its depreciation expense for Account No. 359 under the current Template, SPS has used the Account No. 352 depreciation rate.14 As of June 30, 2018, SPS had approximately $146.8 million of assets in Account No. 350.2 and $0.5 million of assets in Account No. 359.

2. The Depreciation Study

As explained in the Ostrom Direct Testimony, the depreciation study was performed by the Alliance Consulting Group (“Alliance”) at SPS’s direction and under SPS’s supervision (“Depreciation Study”).15 The Depreciation Study is being sponsored by Mr. Dane A. Watson of Alliance and is attached to the Watson Direct Testimony as Exhibit No. SPS-0012.

The Depreciation Study analyzes annual transmission depreciation rates based on SPS’s depreciable plant in service as of June 30, 2018. As explained in the Watson Direct Testimony, the Depreciation Study involves only SPS’s transmission assets and was conducted in four phases: data collection, analysis, evaluation and calculation.16 After Mr. Watson assembled the

13 SPS created a sub-account under Account No. 350 for certain land rights where SPS does not hold fee title ownership and the land rights expire. The costs of these land rights are amortized.

14 Ostrom Direct Testimony at 9. 15 Ostrom Direct Testimony at 7. 16 Watson Direct Testimony at 12-13.

FERC Transmission Account

Existing Depreciation

Rate

Updated Depreciation

Rate 350.2 Land Rights 2.0000% 1.2883% 352 Structures and Improvement 2.0140% 1.7847% 353 Station Equipment 1.8840% 2.2737% 354 Towers and Fixtures 1.2510% 1.5994% 355 Poles and Fixtures 2.0050% 3.0161% 356 Overhead Conductors and Devices 1.9740% 2.9388% 357 Underground Conduit 1.2420% 1.8509% 358 Underground Conductors & Devices 1.7270% 3.0132% 359 Roads and Trails 2.0140% 1.5590%

Honorable Kimberly D. Bose November 27, 2018 Page 8 data, he performed analyses to determine the life and net salvage percentage for each of the transmission property groups and conferred with SPS personnel. He established the average service life for each account using actuarial analyses and determined that the average service lives of six of the nine transmission accounts increased and three remained the same. Mr. Watson explains that the proposed service lives of each transmission account are the same or longer than the service lives reflected in the 1989 Depreciation Rates, and are similar to the service life parameters approved by the PUCT and the NMPRC. Mr. Watson provides a detailed analysis to support his conclusions.17

To determine SPS’s net salvage rates, Mr. Watson analyzed average net salvage rates for various combinations of years to observe trends in data that signal the future net salvage in each account.18 Such observations, in combination with input from SPS personnel, resulted in Mr. Watson’s recommendation to implement net salvage rates for SPS transmission assets that are more negative than the rates established in Docket Nos. EL89-50-000, et al. Specifically, six of the nine accounts had negative net salvage amounts, two accounts remained unchanged and one account had a positive net salvage amount. Mr. Watson explains why SPS’s net salvage percentages have become more negative. In the nearly thirty years since the current net salvage rates were established there have been significant increases in the cost of removal, but there have been no commensurate increases in gross salvage value. Removal cost has increased much more rapidly than gross salvage due to changes in labor rates, environmental disposal requirements, and other factors. The proposed net salvage percentages are similar to the net salvage parameters approved by the PUCT and the NMPRC.

For Account No. 355, Poles and Fixtures, the NMPRC already has approved a negative 60 percent net salvage rate while the PUCT has approved a negative 35 percent net salvage rate. Mr. Watson explains that the Depreciation Study supports a negative 60 percent net salvage rate. Nevertheless, for purposes of this filing, SPS decided to request the lower (negative 35 percent) net salvage rate approved by the PUCT19 rather than the rate approved by the NMPRC (negative 60 percent), although the Depreciation Study would support the negative 60 percent salvage rate. If the PUCT approves the negative 60 percent net salvage rate in a proceeding to be filed by SPS in 2019, SPS anticipates submitting further revisions to the Template pursuant to FPA Section 205 to revise the Account No. 355 depreciation rate.20

Consistent with industry-accepted methodologies and Commission precedent, the Depreciation Study employs the use of straight-line, average life group, remaining life depreciation system to develop the Updated Depreciation Rates.21 Ms. Ostrom concludes that

17 Watson Direct Testimony at 15-16. 18 Watson Direct Testimony at 17. 19 Watson Direct Testimony at 21-22. Ms. Ostrom states that SPS will file with the PUCT in 2019 for

approval of the same negative salvage rate for Account No. 355 for purposes of Texas retail rates. Ostrom Direct Testimony at 12.

20 Ostrom Direct Testimony at 12. 21 Watson Direct Testimony at 5-6 and Ostrom Direct Testimony at 7-8.

Honorable Kimberly D. Bose November 27, 2018 Page 9 the methodologies used to develop the Depreciation Study and the resulting Updated Depreciation Rates permit SPS to systematically and rationally allocate the cost of property to the periods during which the assets are used in SPS’s operations.22

3. Reserve Reallocation

As explained in the Watson Direct Testimony, reserve reallocation is the process of re-spreading the book depreciation reserve within a function based on the proposed life and net salvage characteristics among the assets in each function.23 The purpose is to adjust the reserve for each account and bring it closer to its theoretical reserve, which is a calculated balance of what the reserve would be if the proposed life and net salvage estimates had always been applied to that account.24

Reserve reallocation is an accepted industry practice.25 Mr. Watson reallocated the depreciation reserves for all accounts within the Transmission function.26 The reallocation analysis using the proposed parameters in the Depreciation Study results in a reserve deficiency.27 When comparing the reallocated book reserve to the theoretical reserve, the resulting reserve deficiency increases the annual depreciation expense (total company) by $3.5 million.28 The reallocation of the depreciation reserve does not change the total reserve, and the reallocation is important to set “the reserve at a level necessary to sustain the regulatory concept of intergenerational equity among SPS’s customers, as well as set the depreciation rates at the appropriate level based on current parameters and expectations.”29

SPS respectfully requests that the Commission accept its proposal to reallocate the book reserve amounts as described above. Doing so will ensure that the Updated Depreciation Rates are just and reasonable by preserving intergenerational equities and reflecting the current parameters used to establish such rates. If the Commission accepts SPS’s Updated Depreciation

22 Ostrom Direct Testimony at 9. 23 Watson Direct Testimony at 23. 24 Ostrom Direct Testimony at 12-13. 25 Ostrom Direct Testimony at 13-14 and Watson Direct Testimony at 24-25. See, e.g., Midcontinent

Independent System Operator, Inc., Docket No. ER18-56-001 (Feb. 28, 2018) (delegated letter order); Midcontinent Independent System Operator, Inc., Docket No. ER17-1664-000 (June 29, 2017) (delegated letter order); Midcontinent Independent System Operator, Inc., Docket No. ER17-191-000 (Dec. 15, 2016) (delegated letter order); Southwestern Public Service Company, Docket No. ER15-949-003 (Jan. 29, 2016) (delegated letter order); American Transmission Company, LLC, Docket No. ER12-212-000 (Dec. 21, 2011) (delegated letter order).

26 Watson Direct Testimony at 23. 27 Ostrom Direct Testimony at 13. 28 Ostrom Direct Testimony at 13. 29 Watson Direct Testimony at 24.

Honorable Kimberly D. Bose November 27, 2018 Page 10 Rates, SPS will reallocate the reserves on its books to match the allocation in the Depreciation Study as of February 1, 2019.30

4. Use of a Weighted Average Depreciation Rate to Calculate SPS’s BPU Revenue Requirement.

In the current Template, for purposes of SPS’s BPU revenue requirement, SPS’s depreciation expense is calculated using a single depreciation rate, which is the rate that applies to facilities in Account No. 353 (Station Equipment), currently 1.8840 percent under the 1989 Depreciation Rates. The amount of transmission plant included in SPS’s BPU revenue requirement has grown significantly in the last decade. Of the approximately $3.0 billion of total transmission plant included in the 2019 Template, BPU projects account for approximately $1.8 billion. In addition, these facilities now include plant booked to all nine of the transmission plant accounts listed in Table 1 above. Those facilities range from 115 kV substations to 345 kV transmission lines. For these reasons, the single SPS depreciation rate for Account No. 353 is no longer representative of SPS’s actual transmission depreciation expenses for BPU projects.31 The Template includes only a single cell for SPS to insert a depreciation rate for BPU projects, however. To address this, SPS is proposing to replace use of the Account No. 353 depreciation rate with a weighted average transmission depreciation rate as the BPU depreciation rate.

A weighted average depreciation rate calculation provides a more accurate measure of SPS’s actual transmission depreciation expense applicable to SPS’s BPU transmission plant as a whole. The current depreciation rate for FERC Account No. 353 is lower than the average transmission depreciation rate, which means that an inaccurate and lower amount of depreciation expense is being recovered through the BPU revenue requirement. In addition, the use of a weighted average depreciation rate in the BPU revenue requirement calculation is consistent with the rest of the BPU revenue requirement calculation.32

The Revised Template has been modified to measure SPS’s depreciation expense more accurately. The Revised Template modifies the depreciation rate used to calculate the BPU revenue requirement to add a new line to Tables 2 and 7 to calculate its average transmission depreciation rate, which is then presented on Table 36, Worksheet P. This change replaces the Account No. 353 depreciation rate with an average transmission depreciation rate. The average transmission depreciation rate is simply SPS’s total transmission depreciation expense divided by SPS’s total transmission plant. This average depreciation rate calculation gives more weight to the accounts with more transmission plant. Using this average is a more accurate measure of

30 Watson Direct Testimony at 25. 31 Freitas Direct Testimony at 14-15. 32 The BPU revenue requirement calculation uses a net plant carrying charge (“NPCC”) excluding

depreciation expense times each project’s net plant balance. The NPCC is a weighted average of all transmission costs other than depreciation expense. Using a weighted average depreciation rate brings SPS’s depreciation expense calculation into alignment with the rest of the BPU revenue requirement calculation. Freitas Direct Testimony at 16.

Honorable Kimberly D. Bose November 27, 2018 Page 11 SPS’s actual depreciation expense for the facilities whose costs go into SPS’s BPU venue requirement.33

5. Revising the Calculation of Historical Depreciation Expenses in the BPU Revenue Requirement.

The current Template calculates a BPU revenue requirement for each BPU project using an NPCC method. The NPCC, excluding depreciation expense, is calculated on Tables 2 and 7 of the Template. To calculate this NPCC, each project’s net plant balance must be calculated. To calculate each project’s net plant balance, the current Template takes a gross plant balance minus a depreciation expense. This depreciation expense is the sum of the annual depreciation expense amounts from the project’s first year to the current year.34

Currently, the Template uses a single depreciation rate—a currently effective depreciation rate—to calculate both the current year’s annual transmission depreciation expense and the annual depreciation expense for prior years. In this filing, SPS is changing its depreciation rates for the first time since the Template was first placed in effect. Therefore, using a currently effective depreciation rate to calculate historical expenses is not accurate. SPS is thus proposing to change the BPU revenue requirement depreciation expense calculation so that the depreciation rate used in a given year’s calculation is not the depreciation current rate, but is instead the rate in effect for that year.35 For periods up through 2018, the depreciation rate would be the Account No. 353 depreciation rate (1.88400 percent) used to date. Starting February 1, 2019, the depreciation rate would be the weighted average rate under the new BPU methodology for that year. This change will ensure the Template calculates the correct level of depreciation expense for both prior and future years.

6. Summary of Depreciation-Related Template Changes

The current Template does not list the transmission, general, and intangible plant depreciation rates that SPS uses to calculate depreciation expense. In this filing, SPS is amending the Template to add Table 45, a new table that lists those depreciation rates. With respect to SPS’s transmission plant depreciation rates, Table 45 (which is Worksheet S in the electronic formula rate Template file) lists the Updated Depreciation Rates. With respect to SPS’s general and intangible plant depreciation rates, which SPS is not changing in this filing, Table 45 lists the depreciation rates that SPS currently applies in the Template’s calculation of depreciation expense.36 The depreciation rates listed on Table 45 (which are the Updated

33 Freitas Direct Testimony at 15. 34 Freitas Direct Testimony at 16-17. 35 Freitas Direct Testimony at 17. 36 The currently effective general and intangible plant depreciation rates used to calculate SPS’s wholesale

transmission rates were updated in Docket No. ER15-949-000. In that docket, SPS filed to update its production and general and intangible plant depreciation rates used for the calculation of SPS’s cost-based production formula rates. See Tariff Filing, Southwestern Public Service Co., Docket No. ER15-949-000 (Jan. 30, 2015); Compliance Filing to Implement Approved Changes to SPS’s Production Formula Templates and Protocols Through eTariff, Southwestern Public Service Co., Docket No. ER15-949-003

Honorable Kimberly D. Bose November 27, 2018 Page 12 Depreciation Rates and the unchanged general and intangible plant depreciation rates) then flow through SPS’s formula rate Template as it currently exists.37

With respect to SPS’s BPU revenue requirement, SPS has added a new line to Tables 2 and 7 to calculate its average transmission depreciation rate. The average transmission depreciation rate is the total transmission depreciation expense divided by total transmission plant. The average depreciation rate for the current year is then an input to Table 36, Worksheet P. The average depreciation rate for 2019 is 2.5399 percent, as compared to the current 1.8840 percent.38

To implement the change to how historical depreciation rates are applied to develop the BPU revenue requirement, a new column was added to the detailed tables on Table 36 (Worksheet P) which contain the depreciation rate in effect in each year of the calculation. Each year’s depreciation expense is then calculated using the depreciation rate in effect for that year. This ensures that net plant correctly reflects the depreciation expense that has been recognized in past years. To simplify and centralize the inputs for the BPU depreciation rate, SPS is also including a new section in Table 36 that lists the BPU depreciation rate in effect for historic years.39

B. Direct Assignment of Regulatory Commission Expenses Related to Administration of the Xcel Energy Tariff and the Template

Under the current Template, SPS’s Total ATRR includes a subset of SPS’s costs booked

to Account No. 928 (regulatory commission expenses). The recovered costs are the Account No. 928 expenses that are directly related to SPS’s provision of transmission service pursuant to the Xcel Energy Tariff, including the Template (“Transmission Regulatory Expenses”). For example, Transmission Regulatory Expenses include the costs SPS incurs to respond to an FPA Section 206 complaint challenging SPS’s Template. It also includes the costs incurred to prepare filings to revise the Template, such as this filing.40

SPS is subject to cost-based regulation by the PUCT, NMPRC and the Commission. In its retail rate cases, SPS’s Transmission Regulatory Expenses are excluded from SPS’s retail electric rates. Because SPS’s wholesale transmission customers pay only their load ratio share of SPS’s Zonal ATRR, SPS recovers only about 39 percent of its Transmission Regulatory

(Dec. 14, 2015); Southwestern Public Service Co., Docket No. ER15-949-003 (Jan. 29, 2016) (delegated letter order). Because the Template and Protocols did not specify the general and intangible plant depreciation rates to be used to calculate transmission rates, SPS incorporated the general and intangible plant depreciation rates established in the global settlement in Docket Nos. ER15-949-000, et al. when calculating transmission service rates effective January 1, 2015.

37 Freitas Direct Testimony at 18. 38 Freitas Direct Testimony at 19. 39 Freitas Direct Testimony at 18-19. 40 Freitas Direct Testimony at 20.

Honorable Kimberly D. Bose November 27, 2018 Page 13 Expenses in Zone 11 network service rates. The same is true to the portion of SPS’s BPU revenue requirement allocated to Zone 11. Therefore, although regulatory matters related to service to SPS’s wholesale transmission customers cause 100 percent of SPS’s Transmission Regulatory Expenses, SPS recovers only a portion of those costs from its wholesale transmission service customers.41

SPS’s Transmission Regulatory Expenses also are collected through the portion of SPS’s BPU revenue requirement allocated to SPP’s Region-wide Base Plan Charge and that applies to SPP Tariff customers outside of Zone 11. Currently, 39.41 percent of SPS’s BPU revenue requirement is charged to customers outside Zone 11 through the SPP Base Plan Region-wide Charge.42

Taking both the Zonal ATRR and the BPU revenue requirement into account, SPS is currently under-recovering its Transmission Regulatory Expenses by approximately 46 percent. The remaining costs are allocated to the SPS retail portion of total network loads by the Template, but are not recovered in retail rates, and thus they are currently borne by Xcel Energy shareholders.43

In contrast, the SPS production formula rates include a mechanism to recover SPS’s FERC production-related regulatory commission expenses to SPS’s wholesale requirements customers.44 In this filing, SPS proposes to include a similar mechanism in the Template for its Transmission Regulatory Expenses.

To more accurately track cost causation, the Revised Template will recover SPS’s incremental Transmission Regulatory Expenses from SPS’s wholesale transmission customers. Specifically, the Revised Template applies a new gross-up factor (“Regulatory Commission Expense Factor” or “RC Factor”) to the Transmission Regulatory Expenses to arrive at the amount of expenses to include in the transmission revenue requirement.45 The gross-up factor is calculated using SPS’s total transmission network load, the wholesale network load, and the percent of the BPU revenue requirement that is charged back to Zone 11. When applied to the Transmission Regulatory Expenses, the gross up factor will increase the amount included in the Zonal ATRR so that the resulting amount recovered from the wholesale transmission service customers is nearly the full amount of Transmission Regulatory Expenses.46

41 Freitas Direct Testimony at 20-21. 42 Freitas Direct Testimony at 22. 43 Freitas Direct Testimony at 22. 44 Freitas Direct Testimony at 26. See, e.g., Replacement Power Sales Agreement between Central Valley

Electric Cooperative, Inc. and Southwestern Public Service Co., Table 27 note c. (“Regulatory commission expenses related to Full Requirements proceedings will be direct assigned.”) The other production formula rate templates contain the same or similar language regarding direct assignment of regulatory commission expenses. Regulatory commission expenses associated with SPS’s administration of its wholesale requirements sales contracts are also excluded from retail rates by the PUCT and NMPRC.

45 Freitas Direct Testimony at 22-23. 46 Freitas Direct Testimony at 23.


To calculate and apply the new RC Factor, SPS is revising Tables 4, 5, 9, 10, 18, and 28 of the Template. These changes are described in the Freitas Direct Testimony.47 Exhibit No. SPS-0006 to the Freitas Direct Testimony provides an illustrative calculation showing how use of SPS’s proposed gross-up factor would allow SPS to nearly recover the full amount of incremental regulatory commission expenses from wholesale transmission customers both inside Zone 11 and through the BPU revenue requirement. To provide transparency, Worksheet H, Table 28 identifies the Transmission Regulatory Expenses to be recovered. Pursuant to the Protocols, the materials provided at customer meetings will identify and explain these costs.48

Exhibit No. SPS-0006 shows that the Revised Template assumes $49,602 in costs to be recovered in 2019 Estimated Rates.49 The Revised Template results in just and reasonable rates because it adheres to the Commission’s long-standing cost causation policy,50 allows SPS to recover those costs consistent with that policy, and is consistent with the SPS production formula rate templates.

C. Correcting the Allocation of Transmission-Specific ADIT

Under the current Template, SPS’s transmission-specific costs, including transmission-specific gross plant, accumulated depreciation, and depreciation expense, are allocated using the transmission plant (“TP”) allocator. The TP allocator recognizes that less than 100 percent of SPS’s transmission costs are recovered through SPS’s ATRR. This is because two types of transmission facility costs are excluded from the ATRR: (i) the costs associated with radial transmission facilities, and (ii) the costs associated with transmission facilities that serve a production function (such as generation step up transformers). For 2019, the estimated TP allocator is 95.389 percent.51

As explained in the Freitas Direct Testimony, ADIT is currently allocated into four categories in the Template based on whether it is: (i) not applicable to the transmission function; (ii) allocated based on plant; (iii) allocated based on labor; or (iv) transmission specific.52 The current Template does not use the TP allocator to allocate SPS’s transmission-specific ADIT

47 Freitas Direct Testimony at 24-25. 48 Freitas Direct Testimony at 26. 49 SPS would recover 2019 actual incremental regulatory commission expenses through the 2019 True-up

calculated in 2020 and reflected in Estimated Rates in 2021. 50 See Midwest Independent Transmission System Operator, Inc., 139 FERC ¶ 61253, at P 45 (2012) (stating

the Commission's cost causation policy is “that costs are borne by those who cause them”), on clarification and reh’g, 150 FERC ¶ 61,035 (2015); ISO New England, 115 FERC ¶ 61,145, at P 13 (2006) (stating “[u]nder cost causation principles, costs are allocated to the parties who cause the incurrence of such costs”); Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004) (stating cost causation requires that “approved rates reflect to some degree costs actually caused by the customer who must pay them”) (quoting KN Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992)).

51 Freitas Direct Testimony at 27. 52 Freitas Direct Testimony at 27. ADIT that is not applicable to transmission is excluded from the

transmission formula rate, and there are allocators for the ADIT based on plant or labor. Freitas Direct Testimony at 27.

Honorable Kimberly D. Bose November 27, 2018 Page 15 (“Transmission-Specific ADIT”). Instead, the current Template directly assigns 100 percent of SPS’s Transmission-Specific ADIT to the transmission function. This direct assignment of Transmission-Specific ADIT is not an accurate way to allocate this cost because it ignores the exclusion of certain transmission-facility costs from the ATRR. The current Template therefore over-allocates Transmission-Specific ADIT to SPS’s transmission function and does not allow SPS to fully recover its costs.53

In this filing, SPS is revising the Template so that SPS’s Transmission-Specific ADIT is allocated using the TP allocator. In the Revised Template, SPS has modified Tables 22, 23 and 24 of Worksheet E to change: (i) a line to include the transmission plant allocator; (ii) the column header of column E to remove the word “100%”; and (iii) the allocation factor in column E from “100%” to the appropriate transmission plant allocator calculated in the supporting calculations section on Tables 5 and 10.54

The Revised Template results in just and reasonable rates because it ensures consistency with the allocation of other transmission-specific amounts in the Template and corrects for the assignment of ADIT to transmission service customers even when that ADIT is related to radial lines and transmission serving generation.

D. Revisions to Address Return (or Recovery) of Excess (or Deficient) ADIT

On December 22, 2017, President Trump signed the Tax Cuts and Jobs Act of 2017 into law. Section 13001 of the TCJA reduces the federal corporate income tax rate from a maximum of 35 percent under the graduated rate structure, to a flat 21 percent rate.55 The change to the federal corporate income tax rate became effective January 1, 2018.

The reduction in the federal corporate income tax rate resulted in SPS having “excess” ADIT balances. These “excess” ADIT balances represent the amount of ADIT that SPS has on its books that exceed the ADIT balance that would be on SPS’s books if the federal corporate income tax rate had been set at the new, lower rate the entire time SPS was collecting these funds in rates.

53 Freitas Direct Testimony at 27-28. 54 Freitas Direct Testimony at 28-29. 55 Tax Cuts and Jobs Act, Pub. L. No. 115-97, § 13001(a), 131 Stat. 2096 (2017); 26 U.S.C. § 11(b).


Mr. Freitas explains the impacts of the TCJA on SPS.56 The Revised Template addresses the TCJA’s impact on the calculation of rate base by adding lines to reflect the inclusion of Account Nos. 182.3 and 254 to account for excess ADIT associated with non-plant items. The Revised Template addresses the TCJA’s impact on the calculation of tax expense by adding a calculation that amortizes excess ADIT in the deferred tax expense, which is reflected in two new rows, one for plant-related excess ADIT and the other for non-plant related excess ADIT.57

Ms. Ostrom explains and supports SPS’s proposal for the flow-back of plant-related excess ADIT to customers using the Average Rate Assumption Method (“ARAM”). Specifically, SPS proposes to return both “protected” and “unprotected” plant-related excess ADIT to customers using ARAM and explains in detail how ARAM is calculated based on the in service date of the subject assets. Ms. Ostrom explains that approximately 92 percent of SPS’s total plant-related excess ADIT is “protected.” Ms. Ostrom supports the return of “unprotected” plant-related excess ADIT to customers using ARAM because doing so is consistent with SPS’s historical practice of normalizing all plant-related deferred taxes to effectively share the current tax benefits with all future customers that also will be served by the assets. Ms. Ostrom calculates the amount of deferred income tax expense associated with SPS’s transmission plant-related excess ADIT balance to be $4.7 million in 2018 on a total company basis.58

Mr. Freitas explains SPS’s proposed treatment associated with the flow-back of non-plant related excess ADIT and supports a five-year amortization period.59 A 5-year amortization period is reasonable because it ensures inter-generational equities and has been implemented in Texas and New Mexico. Mr. Freitas then explains the Template changes made to reflect the impact of the TCJA.60

SPS’s ADIT-related changes to the Template are consistent with the preliminary guidance provided by the Commission in the recent ADIT NOPR.61 In the ADIT NOPR, the Commission proposed to require public utilities with transmission formula rates to incorporate a new permanent worksheet into their transmission formula rates that will annually track information related to excess or deficient ADIT under Section 35.24 of the Commission’s regulations.62 The Commission also proposed that these ADIT worksheets include certain minimum ADIT-related information. 63

56 Freitas Direct Testimony at 29-31. 57 Freitas Direct Testimony at 38-39. 58 Ostrom Direct Testimony at 16-20. 59 Freitas Direct Testimony at 34-35. All non-plant-related excess ADIT is “unprotected” excess ADIT. 60 Freitas Direct Testimony at 35-40. 61 Public Utility Transmission Rate Changes to Address Accumulated Deferred Income Taxes, Notice of

Proposed Rulemaking, 165 FERC ¶ 61,117 (2018) (“ADIT NOPR”). 62 ADIT NOPR at P 46. 63 ADIT NOPR at P 47.


Although the ADIT NOPR is a proposed rule and not binding, SPS’s Revised Template includes the ADIT-related information described in the proposed rule. In this filing, SPS is adding two new ADIT-related worksheets as Tables 21B and 21C of the Template. This filing also revises Tables 3, 4, 8, 9, 19, 21A, 22, 23, and 24. The Revised Template:

1. Measures SPS’s ADIT balances before and after the TCJA’s effective date of January 1, 2018 to show how SPS has accounted for the effect of the TCJA on SPS’s excess or deficient ADIT balances. See Table 19, rows 20 and 64, and Table 21B.

2. Accounts for excess or deficient amounts in Account Nos. 182.3 and 254. See Table 21B.

3. Provides the necessary details to determine whether excess or deficient ADIT is protected or unprotected. See Table 19, rows 21-22 and 65-66, and Table 21B.

4. Shows the accounts to which the excess or deficient ADIT amounts are amortized. See Table 21C.

5. Provides the necessary detail to determine the amortization period of the excess or deficient ADIT being returned or recovered through SPS’s rates. See Table 21C.64

In the ADIT NOPR, the Commission also proposes to require that transmission formula rates be designed to ensure rate base neutrality, which would require a formula rate mechanism to deduct excess ADIT from rate base or add deficient ADIT to rate base.65 With respect to excess ADIT, this would require that unamortized excess ADIT balances are “treated as an offset to (i.e., a deduction from) rate base until those balances are flowed back” to customers.66 SPS’s current Template already ensures rate base neutrality because it includes excess ADIT balances in rate base.67

Finally, the ADIT NOPR includes a proposal to require that a public utility’s transmission formula rate include a mechanism that decreases the utility’s income tax allowance to account for any amortized excess ADIT and increases the utility’s income tax allowance to account for any amortized deficient ADIT.68 In this filing, SPS is revising the Template to satisfy this requirement. Applying the proposed changes to the 2018 true-up results in the amortization of excess ADIT beginning January 1, 2018, which benefits SPS’s wholesale

64 Freitas Direct Testimony at 42-43. 65 ADIT NOPR at P 2. 66 ADIT NOPR at P 21. 67 Freitas Direct Testimony at 32, 40. 68 ADIT NOPR at P 3.

Honorable Kimberly D. Bose November 27, 2018 Page 18 transmission customers.69 Under the Revised Template, SPS will amortize its excess ADIT balances concurrently with the flow-back of these amounts in rates.

SPS’s Revised Template will result in just and reasonable rates because it flows back to wholesale transmission service customers, effective January 1, 2018, the excess ADIT balances resulting from the TCJA, complies with the ADIT NOPR’s proposed requirements for transmission formula rates, and is otherwise consistent with Commission precedent.70

E. Ministerial Change to Re-label a Row on Table 4 of the Template

Table 4 of the Template is a summary table that displays all of SPS’s expenses. Starting at Row 121, Table 4 lists four categories of “Taxes Other Than Income” taxes. Row 127 is labeled “Other – Texas Use.” As Mr. Freitas explains, Row 127 displays more than just the amount of SPS’s Texas use taxes. It also displays other taxes, including the amount of SPS’s Oklahoma business franchise tax. These other taxes have always been included in Row 127.71 In this filing, SPS is re-labelling Row 127 as “Other Taxes” to clarify that this row includes more than just SPS’s Texas use tax.

F. Companion Revisions to SPP Tariff

In addition to being included in the Xcel Energy Tariff, the Template is incorporated into the SPP Tariff as Addendum 5 to Attachment H. Under the SPP Tariff, as provided in Section II(1) of Attachment H, SPS’s Zonal ATRR for Zone 11 is calculated using the formula rate as specified in Attachment O – SPS of the Xcel Energy OATT. Upon Commission acceptance of the Revised Template, XES and SPS will work with SPP to submit a companion filing to modify the SPP Tariff to reflect the Revised Template in Attachment H to the SPP Tariff, effective February 1, 2019.

IV. INFORMATION RELATING TO THE EFFECT OF THE RATE CHANGE

SPS estimates that three of the changes to the Template will impact SPS’s revenues and the Estimated Rates paid by SPS’s wholesale transmission customers in 2019: the Updated Depreciation Rates; the revised allocation of ADIT; and the flow-back of excess ADIT. SPS estimates that the two remaining Template changes—the new RC allocation factor for Transmission Regulatory Expenses and the ministerial change to relabel Table 4—will not impact SPS’s revenues or the 2019 Estimated Rates paid by SPS’s wholesale transmission customers. The ministerial change to Table 4 does not affect the costs included in the 2019

69 Freitas Direct Testimony at 40-41. 70 See Midcontinent Independent System Operator, Inc., 163 FERC ¶ 61,163 (2018) (accepting similar

revisions filed by Ameren Services Company on behalf of its utility operating company affiliates), reh’g granted for further consideration, Docket No. ER17-2323-002 (Aug. 1, 2018) (delegated order); see also Midcontinent Independent System Operator, Inc., 164 FERC ¶ 61,113 (2018) (accepting comparable revisions by the Entergy Operating Companies to allow amortization of excess/deficient deferred taxes).

71 Freitas Direct Testimony at 43-44. In the current Template, on Row 127, the “data source” is shown as Worksheet J and page 263.i of SPS’s FERC Form 1. This includes taxes other than the Texas use tax.

Honorable Kimberly D. Bose November 27, 2018 Page 19 Estimated Rates, and the Transmission Regulatory Expense change affects only $50,000 in estimated total costs, with actuals to be reflected in the 2019 true-up. The Revised Template’s estimated impacts are shown in Exhibit No. SPS-0005 (Estimated Revenue Impact of Filing) and are summarized in Table 2:

Table 2 Estimated Annual Customer Impact

Using 2018 Estimated ATRR and Rates

Impact of Zone 11 Network

Transmission Rate Change

Impact of Schedule 11

Rate Change to Zone 11 Rates Total

Golden Spread Elect Cooperative $1,036,698 $1,246,564 $2,283,262 City of Brownfield $18,501 $22,247 $40,748 Central Valley Co-op. $145,269 $174,676 $319,945 Farmers Co-op. $75,338 $90,589 $165,928 City of Floydada $4,594 $5,524 $10,117 Lea County Co-op $239,613 $288,120 $527,733 Lubbock Power & Light $618,295 $743,461 $1,361,755 Roosevelt Cty. Co-op $31,571 $37,963 $69,534 Tri-County Elect. Co-op $73,816 $88,759 $162,575 City of Tulia $7,811 $9,393 $17,204 Total Zone 11 Wholesale $2,251,506 $2,707,925 $4,958,800 Impact to Other SPP Rate Zones via SPP Schedule 11 $4,469,518

As explained in the Ostrom Direct Testimony, the 2018 annual transmission plant

depreciation expense based on existing depreciation rates is $56.9 million and the annual transmission depreciation expense based on the Updated Depreciation Rates is $75.5 million (total company). The resulting difference is a $18.6 million dollar increase in the annual expense based on June 30, 2018 plant balances at the SPS total company level.72

In Docket No. ER18-2319-000, SPS filed to eliminate the Template’s use of “two-step

averaging” in calculating ADIT balances.73 For purposes of evaluating the impact of the Template changes proposed in this filing, Mr. Freitas included this change in both the current Template and the Revised Template. Mr. Freitas first used the current Template to calculate the impact on the 2019 Projected Rates for customers in Zone 11, the SPS rate zone. In his second calculation, Mr. Freitas used the Revised Template to calculate revised 2019 Projected Rates.

72 Ostrom Direct Testimony at 10. 73 See Revisions to Calculation of ADIT Balances in Transmission Formula Rates, Public Service Co. of

Colorado, Docket No. ER18-2319-000 (Aug. 27, 2018). The Commission has not yet acted on SPS’s proposed revisions to the Template.

Honorable Kimberly D. Bose November 27, 2018 Page 20 Using the most recent available billing determinants (September 2017 – August 2018), Mr. Freitas calculated the annual impact to SPS’s Zone 11 transmission service customers using the recalculated network transmission rate.74

V. OTHER FILING REQUIREMENTS

None of the costs proposed to be recovered in the Revised Template have been alleged or judged in any administrative or judicial proceeding to be illegal, duplicative, or unnecessary costs that are demonstrably the product of discriminatory employment practices.75

VI. REQUESTED EFFECTIVE DATE

SPS respectfully requests that the Commission allow the Revised Template to become effective February 1, 2019, sixty-six (66) days after filing, without suspension or hearing. Under the Protocols, this effective date will allow SPS to use the Updated Depreciation Rates in the 2019 Annual Update to establish new Estimated Rates effective February 1, 2019. Then, in the 2019 Annual True-up, calculated in June 2020, the Revised Template would be used to derive the 2019 actual charges and true-up, with the true-up recovered (or refunded) Estimated Rates for 2021, giving effect to the Revised Template back to February 1, 2019, plus interest back to that date.

SPS’s requested February 1, 2019 effective date should be granted without suspension or hearing. The modifications reflected in the Revised Template and their impact on SPS’s revenues and on the rates paid by SPS’s wholesale transmission customers are fully supported by the testimony and associated exhibits, including the updated Depreciation Study, included as part of this filing.76 To the extent the Commission chooses to suspend the effectiveness of the Revised Template, it should do so for a nominal, one-day suspension period. In West Texas Utilities Co.,77 the Commission explained that a nominal suspension period is justified in cases where no more than ten percent of the proposed increase appears to be excessive. Here, a nominal suspension is warranted because the overall rate impact of SPS’s filing is an increase of roughly 5.54 percent for each network transmission service customer in Zone 11. (See Exhibit No. SPS-0005.) No portion of the proposed increase is excessive, much less 10 percent of it.

For example, the largest component of SPS’s proposed rate increase is caused by the Updated Depreciation Rates. Nearly thirty years have passed since SPS established the currently effective 1989 Depreciation Rates. As explained in the Watson Direct Testimony, significant increases in the costs of removal, increased labor costs, negligible asset salvage value, and the necessity of proactively replacing aging infrastructure have all contributed to the transition from

74 Freitas Direct Testimony at 45-47. 75 18 C.F.R. 35.13(b)(7) (2018). 76 See Exhibit No SPS-0012 (Depreciation Study), which is attached to the Watson Direct Testimony. 77 West Texas Utilities Co., 18 FERC ¶ 61,189, at 61,375 (1982), which states that a “utility’s increased rates

will be suspended for only one day instead of the five month maximum in those cases where our preliminary analysis indicates that no more than ten percent of the increase appears to be excessive.”

Honorable Kimberly D. Bose November 27, 2018 Page 21 positive net salvage values to more negative net salvage values.78 These values are more accurate because they reflect SPS’s thirty years of actual experience with these assets and reflect current market conditions. Therefore, the Updated Depreciation Rates improve the accuracy of SPS’s rates and no portion of this rate increase is excessive. The flow-back of excess ADIT accurately reflects the impact of the TCJA on SPS’s revenue requirements, and benefits transmission customers. Finally, a nominal one-day suspension period for the effectiveness of the Revised Template is consistent with recent Commission action addressing modifications to transmission formulas in SPP.79

VII. REQUESTS FOR WAIVER

A. Request for Waiver to Adjust Estimated Transmission Rates for 2019

Consistent with the Protocols, SPS published its 2019 Estimated ATRR and Estimated Rates on October 1, 2018, and held the Customer Meeting required by the Protocols on October 11, 2018. The Protocols are silent on the issue of adjusting Estimated Rates based on Commission-approved changes to the inputs to the Template. To the extent necessary, SPS requests waiver of the Protocols to allow SPS to revise the 2019 SPS ATRR so rates charged under the SPP Tariff may be adjusted effective on the February 1, 2019 effective date.

SPS’s request satisfies the Commission’s criteria for granting such waivers because: (i) SPS has acted in good faith; (ii) the waiver is of limited scope, because it represents a one-time “out-of-cycle” adjustment to the 2019 estimated ATRR and rates that would be based on a Commission-approved change to inputs to the Template; (iii) the waiver addresses a concrete problem, because it avoids a large true-up adjustment for 2019, to be calculated in 2020 and billed in rates in 2021 (with interest) under the normal true-up schedule; and (iv) the waiver does not have undesirable consequences, such as harming third parties, because the rate change would have occurred, calculated effective February 1, 2019, in any event, and customers can ensure the accuracy of the adjusted rates during the normal true-up and customer review process.80

B. Request for Waiver to Calculate the 2018 True-Up Adjustment to Reflect TCJA Effective Date

Although SPS proposes that the excess ADIT flow-back and other Template revisions be effective February 1, 2019, to the extent necessary, SPS requests waiver so it may calculate the 2018 rate year true-up to reflect the proposed excess ADIT revisions, so the flow-back of excess ADIT can begin effective January 1, 2018. Good cause exists to grant this waiver. Permitting

78 See Watson Testimony at 17-20. 79 See e.g., Southwest Power Pool, Inc., 165 FERC ¶ 61,066, at P 38 (2018) (accepting proposed tariff

revisions to add an ATRR to Zone 11 to the SPP Tariff associated with GridLiance High Plains LLC’s facilities – with a 2019 estimate rate impact of $9.5 million to Zone 11 – and suspending their effectiveness for only a nominal one-day period).

80 See EDP Renewables North America LLC, 161 FERC ¶ 61,086, at P 6 (2017) (listing the Commission’s four criteria for granting tariff waivers); see also Southwest Power Pool, Inc., 153 FERC ¶ 61,339, at PP 17-18 (2015).

Honorable Kimberly D. Bose November 27, 2018 Page 22 the calculation as requested will allow the flow-back of excess ADIT to commence as of the effective date of the TCJA consistent with the Commission guidance.81

C. Requests for Waiver to Provide Cost-of-Service Statements SPS respectfully requests that the Commission recognize that SPS has endeavored to

comply fully with the Commission’s filing requirements set forth in Part 35 of the Commission’s regulations. In the event that the Commission, upon review of the filing, should find that SPS has misinterpreted or failed to respond in some detail to such filing requirements, SPS requests that the Commission waive any failure to comply strictly with such filing requirements in recognition of SPS’s good faith attempt at compliance.

To the extent necessary, SPS respectfully requests waiver of any requirement to submit cost-of-service statements. Specifically, SPS requests waiver of the following sections of the Commission’s regulations: Sections 35.13(d)(1)-(2) (Period I and II data for Statements AA through BM), Section 35.13(d)(5) (workpapers related to Period I and II data), and Section 35.13(h) (cost-of-service statements).82 Good cause exists to grant these waivers. Detailed statements of SPS’s cost of service are not needed because the currently effective Templates already calculate the rates for service on a formulaic basis and are trued-up each year to SPS’s actual costs. The Commission has routinely granted such waiver requests in similar proceedings where a party has proposed to implement or modify a formula rate construct83 and where a party has proposed to modify its depreciation rates.84

81 Inquiry Regarding the Effect of the Tax Cuts and Jobs Act on Commission-Jurisdictional Rates, FERC Stats. & Regs. ¶ 35,582 at PP 4, 16 (2018). See also Midcontinent Independent System Operator, 163 FERC ¶ 61,163 (accepting ADIT transmission formula rate revisions filed by Ameren Services Company to be effective January 1 and June 1, 2018, but allowing Ameren to apply the revisions to the calculation of the 2017 true-up); but see Midcontinent Independent System Operator, Inc., 157 FERC ¶ 61,250 (2016) (rejecting proposal to calculate 2016 transmission formula rate true-up using formula rate revisions accepted effective January 1, 2017 as a violation of the filed rate doctrine), order denying reh’g, 161 FERC ¶ 61,020 (2017).

82 See 18 C.F.R. § 35.13(d)(1)(2), (d)(5), (h) (2018). 83 Duke Energy Progress, Inc., 149 FERC ¶ 61,220, at P 77 (2014) (granting waiver of Period I and II data,

consistent with “prior approval of formula rates”); Public Service Co. of New Mexico, 142 FERC ¶ 61,168, at P 29 (2013) (granting waiver of Period I and II data), reh’g denied, 143 FERC ¶ 61,227 (2013); Southern California Edison Co., 136 FERC ¶ 61,074, at P 29 (2011); Xcel Energy Servs. Inc., 122 FERC ¶ 61,098, at P 75 (2008) (granting waiver of Period I and II data), on reh’g, 125 FERC ¶ 61,092 (2008); American Electric Power Service Corp., 120 FERC ¶ 61,205, at P 41 (2007) (granting waiver of Period I and II data), reh’g denied, 121 FERC 61,245 (2007); Commonwealth Edison Co., 119 FERC ¶ 61,238, at PP 92-94 (2007) (granting waiver of Period I and II data and cost-of-service statements), reh’g granted in part, 122 FERC ¶ 61,037 (2008), reh’g granted in part, 124 FERC ¶ 61,231 (2008).

84 See Westar Energy Inc., 131 FERC ¶ 61,183 at P 20 (2010) (finding proposed depreciation rates to be reasonably and adequately supported by the depreciation study and granting waiver of the requirements of Section 35.13 of the Commission’s regulations), reh’g denied, 134 FERC ¶ 61,176 (2011).


In addition, specific support for SPS’s revisions to the Template is contained in the testimony, supporting exhibits, and other materials included with this filing. This includes Exhibits included with the Freitas Direct Testimony.

VII. CORRESPONDENCE AND COMMUNICATIONS

The following persons are authorized to receive notices and communications with respect to this filing:

William A. Grant* Regional Vice President – Rates and Regulatory Affairs Southwestern Public Service Company 790 Buchanan Street - 7 Amarillo, TX 79101 (806) 378-2928 (phone) [email protected] James P. Johnson* Assistant General Counsel Xcel Energy Services Inc. 414 Nicollet Mall, 401-8 Minneapolis, MN 55401 (612) 215-4592 (phone) [email protected]

Wesley Berger* Manager, Rate Cases Southwestern Public Service Company 790 Buchanan Street - 7 Amarillo, TX 79101 (806) 378-2891 (phone) [email protected] Kenneth B. Driver* David Martin Connelly JONES DAY 51 Louisiana Ave., N.W. Washington, D.C. 20001 (202) 879-3939 (phone) [email protected]

SPS requests that the individuals identified above with an asterisk be placed on the Commission’s official service list in this proceeding. SPS respectfully requests waiver of Section 385.203(b)(3) of the Commission’s regulations to permit the designation of more than two persons upon whom service is to be made in this proceeding.85

VIII. SERVICE AND POSTING

SPS will serve a copy or notice of this filing on the state regulatory commissions with jurisdiction over SPS and on each network transmission service customer in Zone 11. SPS will also serve electronic notice of this filing on all interested parties in SPP through use of the SPP FERC filings email exploder. A courtesy copy or notice will be served on the Director, Division of Tariffs and Market Development (Central). A copy of the filing is also available for public inspection in the offices of SPS in Amarillo, Texas.

85 18 C.F.R. § 385.203(b)(3) (2018).

Honorable Kimberly D. Bose November 27, 2018 Page 24 IX. CONCLUSION

For the reasons stated above, SPS respectfully requests that the Commission accept the revised e-Tariff records, to be effective February 1, 2019. SPS further requests the Commission grant all of the waivers requested herein.

Respectfully submitted,

/s/ James P. Johnson James P. Johnson Assistant General Counsel Xcel Energy Services Inc. 414 Nicollet Mall – 401 - 8 Minneapolis, MN 55401 Phone: (612) 215-4592 Email: [email protected] Counsel for Xcel Energy Services Inc., on behalf of Public Service Company of Colorado and Southwestern Public Service Company

cc: SPS State Commissions SPS Zone 11 Network Transmission Service Customers SPP FERC Filings email exploder list Director, Division of Tariffs and Development (Central)

Attachment 1 (ATTESTATION)

Attachment 2(Certificte of Service)

CERTIFICATE OF SERVICE

I hereby certify that I have this day electronically served a notice of the enclosed filing on

the state commissions with jurisdiction over SPS and on affected transmission service customers.

Dated at Minneapolis, Minnesota this 27th day of November, 2018.

s/ Tracee J. Holte Tracee J. Holte Xcel Energy/Responsible by Nature Senior Transmission Business Analyst 414 Nicollet Mall – 6th Floor Minneapolis, MN 55401 (612) 330-6206 [email protected]

mailto:[email protected]

Exhibit No. SPS-0001 (ATT O-SPS FORMULA RATE - CLEAN)

Xcel Energy Operating Companies FERC FPA Electric Tariff Third Revised Volume No. 1

Att O-SPS Formula Rate, Revenue Rqmt, Projected, Table 2

Version 0.3.0 Page 1 of 1 Proposed Effective Date: 2/1/2019 Approved Effective Date: Rate Formula Template Table 2

**PROJECTED** Utilizing Projected Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY (1) (2) (3) (4) (5) Line Transmission No. Amount

28 PROJECTED REVENUE REQUIREMENT (w/o incentives) (ln 141) $ - 29 REVENUE CREDITS (Note A) Total Allocator

30 Account No. 454 (Worksheet B) - DA 1.00000 $ - 31 Account No. 456.1 (Worksheet B) - DA 1.00000 - 31.1 Account No. 421.1 (or other applicable acct) (Worksheet B) - DA 1.00000

31.2 Account No. 456.0 (Worksheet B) - DA 1.00000

32 Total Revenue Credits $ - 33 NET REVENUE REQUIREMENT (w/o incentives) (ln 28 less ln 32) $ - 34 NET PLANT CARRYING CHARGE (w/o incentives) (Note B) 35 Annual Rate (ln 33 / ln 62 x 100) 0.00% 36 Monthly Rate (ln 35 / 12) 0.00% 37 GROSS PLANT CARRYING CHARGE (w/o incentives) (Note B) 38 Annual Rate (ln 33 / ln 48 x 100) 0.00% 39 NET PLANT CARRYING CHARGE, W/O DEPRECIATION (w/o incentives) (Note B) 40 Annual Rate ( (ln 33 - ln 114 ) / ln 62 x 100) 0.00% 40.1 BPU Depreciation Rate (ln 114 / ln 48 ) 0.00% 41 NET PLANT CARRYING CHARGE, W/O DEPRECIATION, INCOME TAXES AND RETURN (Note B) 42 Annual Rate ( (ln 33 - ln 114 - ln 138 - ln 139) / ln 62 x 100) 0.00% 43 ADDITIONAL REVENUE REQUIREMENT (w/incentives) (Note C - Worksheet R) $ - 44 Projected SPP Base Plan Upgrades Revenue Requirement (WsP BPU Summary col (c) total and Note I) $ - 44a SPP Base Plan Upgrades Revenue Requirement Prior Year True-up Adjustment (Input) $ - 44b SPP Base Plan Upgrades Revenue Requirement Interest on Prior Year True-up Adjustment (Input) $ -

44c SPP Base Plan Upgrades Revenue Requirement (Amount Provided to SPP for Next Billing Period)(sum lines 44, 44a ,and 44b) $ - 45 PROJECTED REVENUE REQUIREMENT (ln 33 + ln 43 - ln 44c) $ -


Att O-SPS Formula Rate, Rate Base, Projected, Table 3


**PROJECTED** Utilizing Projected Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY Data Sources Total RATE BASE CALCULATION (See "General Notes") Total Allocator Transmission Line (1) (2) (3) (4) (5) No.

46 GROSS PLANT IN SERVICE 47 Production (WsD.1 , Ln 6)

- NA

48 Transmission (WsD.1 , Ln 11) -

TP 0.00000 -

49 Distribution (WsD.1 , Ln 16) -

NA

50 General Plant (WsD.1 , Ln 21) -

W/S 0.00000 -

51 Intangible Plant (WsD.1 , Ln 23) -

W/S 0.00000 -

52 TOTAL GROSS PLANT (sum lns 47 to 51) -

GP= 0.00000 -

53 ACCUMULATED DEPRECIATION 54 Production (WsD.1 , Ln 39)

- NA


TP 0.00000 -


NA


W/S 0.00000 -


W/S 0.00000 -

59 TOTAL ACCUMULATED DEPRECIATION (sum lns 54 to 58) -

-

60 NET PLANT IN SERVICE 61 Production (ln 47 - ln 54)

- NA

62 Transmission (ln 48 - ln 55) -

-

63 Distribution (ln 49 - ln 56) -

NA

64 General Plant (ln 50 - ln 57) -

-

65 Intangible Plant (ln 51 - ln 58) -

-

66 TOTAL NET PLANT IN SERVICE (sum lns 61 to 65) -

NP= 0.00000 -

67 ADJUSTMENTS TO RATE BASE (Note D) 68 Account No. 281 (enter negative) 273.8.k (Worksheet E)

- NA

69 Account No. 282 (enter negative) 275.2.k (Worksheet E) -

DA -


DA -

71 Account No. 190 234.8.c (Worksheet E) -

DA -

72 Account No. 255 (enter negative) 267.8.h DA -

72.1 Account No. 254 Excess ADIT (Worksheet E) - DA -



Version 0.1.0 Page 2 of 2 Proposed Effective Date: 2/1/2019 Approved Effective Date: 72.2 Account No. 182.3 Deficient ADIT (Worksheet E) - DA

- 73 Account No. 107 (WsQ , Ln 15, Col C)

- TP 0.00000

- 74 Net Pre-Funded AFUDC on CWIP included (Note E) (Worksheet Q, ln 30) - TP 0.00000

- in Rate Base (enter negative) 75 Unamortized Balance of Abandoned Incentive Plant (Note E) (Worksheet E)

- TP 0.00000

- 76 Unamortized Balance of Extraordinary Property Loss (Note E) (Worksheet E)

- TP 0.00000

-

77 TOTAL ADJUSTMENTS (sum lns 68 to 76) -

-

78 LAND HELD FOR FUTURE USE (Note F) (WsD , Ln 84, Col d)

- TP 0.00000

- 79 WORKING CAPITAL 80 CWC (Note G) 81 Materials & Supplies - Transmission (WsF , Ln 71, Col d)

- TP 0.00000

- 82 Materials & Supplies - Other (WsF , Ln 72, Col d)

- GP 0.00000

- 83 Prepayments (Account 165) Plant Related (WsF , Ln 12, Col d)

- GP 0.00000

- 84 Prepayments (Account 165) Labor Related (WsF , Ln 18, Col d)

- W/S 0.00000

- 85 Prepayments (Account 165) Transmission Related (WsF , Ln 23, Col d)

- TP 0.00000

- 86 Prepayments (Account 165) Other Not Allocated (WsF , Ln 31, Col d)

- NA 0.00000

-

87 TOTAL WORKING CAPITAL (sum lns 80 to 86) -

-

88 BALANCE OF NETWORK CREDITS (enter negative) (Note H)

- TP 0.00000

-

89 RATE BASE (sum lns 66, 77, 78, 87, 88) -

-


Att O-SPS Formula Rate, Expenses, Projected, Table 4


**PROJECTED** Utilizing Projected Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY EXPENSE, TAXES, RETURN & REVENUE Data Sources Total REQUIREMENTS CALCULATION (See "General Notes") Total Allocator Transmission Line (1) (2) (3) (4) (5) No.

90 OPERATION & MAINTENANCE EXPENSE 91 Transmission (WsG , Ln 34, Col c)

-

92 Less Total Account 561 (WsG , Ln 36, Col c) -

93 Add Back Account 561.6 (WsG , Ln 37, Col c) -



96 Transmission O&M Expense Adjustment (WsG , Ln 40, Col c) -

97 Transmission Subtotal (ln 91 - ln 92 + ln 93 + ln 94 - ln 95 + ln 96 ) -

TP 0.00000 -

98 Administrative and General (WsG , Ln 63, Col c)

-

99 Less: Acc. 928, Reg. Com. Exp. (WsG , Ln 53, Col c) -

100 Acct. 930.1, Gen. Advert. Exp. (WsG , Ln 55, Col c) -

101 Acct. 930.2, Miscellaneous Gen. Exp. (WsG , Ln 56, Col c) -

102 Acc. 924, Property Insurance (WsG , Ln 50, Col c) -

103 Balance of A & G (ln 98 - sum ln 99 to ln 102) - W/S 0.00000 -

104 Plus: Acct. 924, Property Insurance (ln 102) - GP 0.00000 -

105 Acct. 928 - Transmission Specific (Note K) (WsH ln 21, col D) - DA 1.00000 -

106 Acct. 928 - Transmission Allocated (Note K) (WsH ln 21, col E) - TP 0.00000 -

106.1 Acct. 928 - SPS Wholesale Specific (Note K) (WsH ln 12, col F) - RC 0.00000 -

107 Acct. 930.2 - Transmission Specific (Note K) (WsH ln 33, col D) - TP 0.00000 -

108 Acct. 930.2 - Transmission Allocated (Note K) (WsH ln 33, col E) - W/S 0.00000 -

109 Transmission Safety and Siting Advertising (Note K) (WsH ln 46, col B) - TP 0.00000 -

110 -

111 A & G Subtotal (sum lns 103 to 109 less ln 110) -

-

112 TOTAL O & M EXPENSE (ln 97 + ln 111 )

-

- 113 DEPRECIATION AND AMORTIZATION EXPENSE 114 Transmission (WsI, Ln 5, Col d) - TP 0.00000

- 115 Plus: Pre-Funded AFUDC Amortization (Note E) (Worksheet Q, ln 31) - TP 0.00000

-



Version 0.1.0 Page 2 of 2 Proposed Effective Date: 2/1/2019 Approved Effective Date: 116 Plus: Recovery of Abandoned Incentive Plant (Note E) (Worksheet E) - TP 0.00000

- 117 Plus: Recovery of Extraordinary Property Loss (Note E) (Worksheet E) - TP 0.00000

- 118 General (WsI, Ln 9, Col d) - W/S 0.00000

- 119 Intangible (WsI, Ln 11, Col d) - W/S 0.00000

-

120 TOTAL DEPRECIATION AND AMORTIZATION (sum lns 114 to 119) -

-

121 TAXES OTHER THAN INCOME (Note L) 122 Labor Related 123 Payroll (Worksheet J) 263.i - W/S 0.00000

- 124 Plant Related 125 Property (Worksheet J) 263.i - GP 0.00000

- 126 Franchise & Gross Receipts (Worksheet J) 263.i - NA

- 127 Other Tax (Worksheet J) 263.i - GP 0.00000

-

128 TOTAL OTHER TAXES (sum lns 123 to 127) -

-

129 INCOME TAXES (Note M) 130 T=1 - {[(1 - SIT) * (1 - FIT)] / (1 - SIT * FIT * p)} = 0.00% 131 CIT=(T/1-T) * (1-(WCLTD/R)) = 0.00% 132 where WCLTD=(ln 160) and R= (ln 163) 133 and FIT, SIT & p are as given in Note M. 134 1 / (1 - T) = (from ln 130)

-

135 Amortized Investment Tax Credit (enter negative) (Worksheet J) 266.8.f -

135.1 (Excess)/Deficient ADIT Amortization - Plant (Note P) (Worksheet D.4)

-

135.2 (Excess)/Deficient ADIT Amortization - Non-Plant

(Note P) (Worksheet D.4) -

136 Income Tax Calculation (ln 131 * ln 139)

-

- 137 ITC adjustment (ln 134 * ln 135) - NP 0.00000

- 137.1 (Excess)/Deficient ADIT Amortization - Plant (ln 134 * ln 135.1)

- DA 0.00000

- 137.2 (Excess)/Deficient ADIT Amortization - Non-

Plant (ln 134 * ln 135.2)

- DA 0.00000

- 138 TOTAL INCOME TAXES (sum lns 136 to 137.2)

-

- 139 RETURN (Rate Base * Rate of Return) (ln 89 * ln 163)

-

- 140 INTEREST ON NETWORK CREDITS (Note H) - TP 0.00000

-

141 REVENUE REQUIREMENT (sum lns 112, 120, 128, 138, 139, 140) -

-


Att O-SPS Formula Rate, Cap Struc, Allocations, Projected, Table 5


**PROJECTED** Utilizing Projected Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY SUPPORTING CALCULATIONS Line (1) (2) (3) (4) (5) No.

142 TRANSMISSION PLANT INCLUDED IN OATT Transmission Rate (Note N) 143 Total transmission plant (ln 48)

- 144 Less Generator Step-up facilities (WsD.1 , Ln 145)

- 145 Less Radial Line facilities (Worksheet O)

-

146 Transmission plant included in OATT Trans Rate (ln 143 - ln 144 - ln 145) -

147 Percent of transmission plant in OATT Trans Rate (ln 146 / ln 143) TP= 0.00000 148 WAGES & SALARY ALLOCATOR (W/S) (Note O) 149 Production (WsG , Ln 69, Col e)

- NA

- 150 Transmission (WsG , Ln 70, Col e)

- TP 0.00000

- 151 Regional Market (WsG , Ln 71, Col e)

- NA

- 152 Distribution (WsG , Ln 72, Col e)

- NA

- 153 Other (WsG , Ln 73, Col e)

- NA

-

154 Total (sum lns 149 to 153) -

-

155 W/S Allocator W/S= 0.00000 155.1 REGULATORY COMMISSION EXPENSE FACTOR

(RC)

155.2 Transmission Network Load (WsC , Ln 14, Col f) - 155.3 Wholesale Transmission Network Load (WsC , Ln 42, Col c) - 155.4 Percent of BPU Rev Req charged to SPS Zone Input - 155.5 Wholesale Load Ratio Share (Ln 155.3/Ln 155.2) - 155.6 RC Factor 1/(Ln 155.3/Ln 155.2)*(1-(Ln 155.4*Ln 155.5)) RC= - 156 RETURN (R) $

157 Long Term Interest (Worksheet K, Ln 51, Col d) -

158 Preferred Dividends (Worksheet K, Ln 56, Col d) -

159 $ % Cost Weighted

160 Long Term Debt (Worksheet K, Ln 17, Col o) - 0.00% 0.0000 0.0000 161 Preferred Stock (Worksheet K, Ln 5, Col o) - 0.00% 0.0000 0.0000 162 Common Stock (Worksheet K, Ln 9, Col o) - 0.00% 0.1050 0.0000


R 0.0000


Att O-SPS Formula Rate, Notes, Projected, Table 6


**PROJECTED** Utilizing Projected Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY General Notes: a) References to data from FERC Form 1 are indicated as: page#.line#.col.# Note Letter

A The revenues credited shall include amounts received directly from the SPP for service under this tariff reflecting SPS's integrated transmission facilities. Revenues associated with FERC annual charges, gross receipts taxes, ancillary services or other facilities revenues shall be excluded from the definition of transmission facilities under this tariff shall not be included as revenue credits. Revenue from coincident peak loads included in the DIVISOR are also not included as revenue credits unless this revenue is offset by a corresponding expense. See Worksheet B for details. B The annual and monthly net and gross plant carrying charges on page 2 are to be used to compute the revenue requirement for directly assigned facilities,any Base Plan Upgrades, distribution facilities, and radial lines. C This additional revenue requirement is determined using a net plant carrying charge (fixed carrying charge or FCR) approach. Worksheet R shows the calculation of the additional revenue requirements for each project receiving incentive rate treatment, as accepted by FERC by a separate docket. These individual additional revenue requirements shall be summed, for the then current year, and included here. D Reflects the transmission related portion of balances in Accounts 281, 282, 283, 190, and 255 as adjusted by any amounts in contra accounts identified as regulatory assets or liabilities related to FASB 106, 109, 133,158 or FASB Interpretation No. 48. Balance of Account 255 is reduced by prior flow throughs and completely excluded if the utility chose to utilize amortization of tax credits against taxable income as discussed in Note M. The calculation of ADIT for both the true-up and the annual projection will be performed in accordance with IRS regulation Section 1.167(l)-1(h)(6 The Annual True-Up for a given year will use the same methodology that was used to project that year’s rates. (Except for ADIT Proration which is

described on Table 21A of the template.) E Includes any incentive Construction Work in Progress (CWIP), any related Allowance for Funds Used During Construction (AFUDC), any unamortized balances related to the recovery of abandoned incentive plant costs, any extraordinary property losses and any related depreciation and amortization expense amounts. Formula amounts for all of the foregoing items will remain at $0 until approved by FERC under a separate docket. F Includes only transmission related or functionally booked as transmission land held for future use. G Cash Working Capital will be set at and remain $0 until such time as SPS files and receives FERC approval for a lead/lag study. H Equal to the balance of Network Facilities Upgrades Credits, net of accumulated depreciation, due transmission customers that made lump-sum payments towards the construction of Network Transmission Facilities consistent with Paragraph 657 of Order 2003-A. Excludes interest since interest is added to the revenue requirement on line 140. I The base plan upgrade revenue requirement will be updated annually in the Annual Update. The BPU revenue requirement will be a projected amount with a true-up to actual adjustment. The updated revenue requirement will be provided to the SPP no later than November 15 for billings effective January 1. J (Reserved for future use) K Includes all Regulatory Commission expense itemized in FERC Form 1 at 351.h. Show in Worksheet H how these expense items are assigned to transmission. FERC Assessment Fees, General Advertising, and Industry Association Dues and Research and Developments costs recorded in 930.2 shall not be assigned to transmission. A & G expenses shall Include specific transmission safety-related advertising and transmission siting advertising costs. The annual PBOP expense amount will be based on the PBOP expense amount reported in SPS’s most recent annual actuarial valuation report as of the date of SPS’s Annual Update. SPS will provide a copy of that actuarial report as part of its Annual Update and its Annual Informational Filing to the

Commission. NERC fees recorded in Acct. 928, Regulatory Commission Expenses, or in Acct. 165, Prepayments, shall be excluded from the formula. L Includes only FICA, unemployment, highway, property and other assessments charged in the current year. Gross receipts tax, taxes related to income, retail and non-transmission related taxes are excluded. M The currently effective income tax rate, where FIT is the Federal income tax rate; SIT is the State income tax rate, and p = "the percentage of federal income tax deductible for state income taxes". If the utility is taxed in more than one state, it must attach a work paper showing the name of each state and how the blended or composite SIT was developed. Furthermore, a utility that elected to utilize amortization of tax credits against taxable income, rather than book tax credits to Account No. 255 and reduce rate base, must reduce its income tax expense by the amount of the Amortized Investment Tax Credit (Form 1, 266.8.f) (ln 135) multiplied by (1/1-T) . If the applicable tax rates are zero enter 0. Inputs Required: FIT = 0.00% SIT= (Worksheet L) 0.00% (State Income Tax Rate or Composite SIT) p = 0.00% (percent of FIT deductible for state purposes) N Removes the dollars of plant booked to transmission plant that is excluded from the Tariff because it does not meet the Tariff's definition of Transmission Facilities, or is booked to transmission (e.g. step-up transformers) that is included in the development of OATT ancillary service rates, or is otherwise not eligible to be recovered under this Tariff. O Enter dollar amounts. Includes service company labor. Does not include contract labor. P Includes the amortization of any excess/deficient deferred income taxes resulting from changes to income tax laws, income tax rates (including changes

in apportionment) and other actions taken by a taxing authority. Excess and deficient deferred income taxes will reduce or increase tax expense by the amount of the excess or deficiency multiplied by (1/(1-T)).


Att O-SPS Formula Rate, Revenue Rqmt, Actual, Table 7


**ACTUAL** Utilizing FERC Form 1 Actual Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY (1) (2) (3) (4) (5) Line Transmission No. Amount

164 REVENUE REQUIREMENT (w/o incentives) (ln 277) $ - 165 REVENUE CREDITS (Note A) Total Allocator

166 Account No. 454 (Worksheet B) - DA 1.00000 $ - 167 Account No. 456.1 (Worksheet B) - DA 1.00000 - 167.1 Account No. 421.1 (or other applicable acct) (Worksheet B) - DA 1.00000 - 167.2 Account No. 456.0 (Worksheet B) - DA 1.00000 -

168 Total Revenue Credits $ -

169 NET REVENUE REQUIREMENT (w/o incentives) (ln 164 less ln 168) $ - 170 NET PLANT CARRYING CHARGE (w/o incentives) (Note B) 171 Annual Rate (ln 169 / ln 198 x 100) 0.00% 172 Monthly Rate (ln 171 / 12) 0.00% 173 GROSS PLANT CARRYING CHARGE (w/o incentives) (Note B) 174 Annual Rate (ln 169 / ln 184 x 100) 0.00% 175 NET PLANT CARRYING CHARGE, W/O DEPRECIATION (w/o incentives) (Note B) 176 Annual Rate ( (ln 169 - ln 250 ) / ln 198 x 100) 0.00% 176.1 BPU Depreciation Rate (ln 250 / ln 184) 0.00% 177 NET PLANT CARRYING CHARGE, W/O DEPRECIATION, INCOME TAXES AND RETURN (Note B) 178 Annual Rate ( (ln 169 - ln 250 - ln 274 - ln 275) / ln 198 x 100) 0.00% 179 ADDITIONAL REVENUE REQUIREMENT (w/incentives) (Note C - Worksheet R) $ - 180 LESS SPP Base Plan Upgrades Revenue Requirement (WsP BPU Summary col (d) total and Note I) $ - 181 ACTUAL REVENUE REQUIREMENT (ln 169 + ln 179 - ln 180) $ -


Att O-SPS Formula Rate, Rate Base, Actual, Table 8


**ACTUAL** Utilizing FERC Form 1 Actual Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY Data Sources Total RATE BASE CALCULATION (See "General Notes") Total Allocator Transmission Line (1) (2) (3) (4) (5) No.

182 GROSS PLANT IN SERVICE 183 Production (WsD.1 , Ln 78) - NA 184 Transmission (WsD.1 , Ln 83) - TP 0.00000

- 185 Distribution (WsD.1 , Ln 88) - NA 186 General Plant (WsD.1 , Ln 93) - W/S 0.00000

- 187 Intangible Plant (WsD.1 , Ln 95) - W/S 0.00000

-

188 TOTAL GROSS PLANT (sum lns 183 to 187) - GP= 0.00000 -

189 ACCUMULATED DEPRECIATION 190 Production (WsD.1 , Ln 110) - NA 191 Transmission (WsD.1 , Ln 115) - TP 0.00000



-

195 TOTAL ACCUMULATED DEPRECIATION (sum lns 190 to 194) - -

196 NET PLANT IN SERVICE 197 Production (ln 183 - ln 190) - NA 198 Transmission (ln 184 - ln 191) -

- 199 Distribution (ln 185 - ln 192) - NA 200 General Plant (ln 186 - ln 193) -

- 201 Intangible Plant (ln 187 - ln 194) -

-

202 TOTAL NET PLANT IN SERVICE (sum lns 197 to 201) - NP= 0.00000 -

203 ADJUSTMENTS TO RATE BASE (Note D) 204 Account No. 281 (enter negative) 273.8.k (Worksheet E) - NA 205 Account No. 282 (enter negative) 275.2.k (Worksheet E) - DA

- 206 Account No. 283 (enter negative) 277.9.k (Worksheet E) - DA

- 207 Account No. 190 234.8.c (Worksheet E) - DA

- 208 Account No. 255 (enter negative) 267.8.h DA

- 208.1 Account No. 254 Excess ADIT (Worksheet E) - DA

- 208.2 Account No. 182.3 Deficient ADIT (Worksheet E) - DA

- 209 Account No. 107 (WsQ , Ln 46, Col C) - TP 0.00000

- 210 Net Pre-Funded AFUDC on CWIP included in Rate Base (Note E) (Worksheet Q, ln 61) - TP 0.00000

- (enter negative)



Version 0.1.0 Page 2 of 2 Proposed Effective Date: 2/1/2019 Approved Effective Date: 211 Unamortized Balance of Abandoned Incentive Plant (Note E) (Worksheet E) - TP 0.00000

- 212 Unamortized Balance of Extraordinary Property Loss (Note E) (Worksheet E) -

-

213 TOTAL ADJUSTMENTS (sum lns 204 to 212) - -

214 LAND HELD FOR FUTURE USE (Note F) (WsD , Ln 84, Col h) - TP 0.00000

- 215 WORKING CAPITAL 216 CWC (Note G)

- 217 Materials & Supplies - Transmission (WsF , Ln 79, Col d) - TP 0.00000

- 218 Materials & Supplies - Other (WsF , Ln 80, Col d) - GP 0.00000

- 219 Prepayments (Account 165) Plant Related (WsF , Ln 42, Col d) - GP 0.00000

- 220 Prepayments (Account 165) Labor Related (WsF , Ln 48, Col d) - W/S 0.00000

- 221 Prepayments (Account 165) Transmission Related (WsF , Ln 53, Col d) - TP 0.00000

- 222 Prepayments (Account 165) Other Not Allocated (WsF , Ln 61, Col d) - NA 0.00000

-

223 TOTAL WORKING CAPITAL (sum lns 216 to 222) - -

224 BALANCE OF NETWORK CREDITS (enter negative) (Note H) - TP 0.00000

-

225 RATE BASE (sum lns 202, 213, 214, 223, 224) - -


Att O-SPS Formula Rate, Expenses, Actual, Table 9


**ACTUAL** Utilizing FERC Form 1 Actual Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY EXPENSE, TAXES, RETURN & REVENUE Data Sources Total REQUIREMENTS CALCULATION (See "General Notes") Total Allocator Transmission Line (1) (2) (3) (4) (5) No.

226 OPERATION & MAINTENANCE EXPENSE 227 Transmission (WsG , Ln 34, Col e) - 228 Less Total Account 561 (WsG , Ln 36, Col e) - 229 Add Back Account 561.6 (WsG , Ln 37, Col e) - 230 Add Back Account 561.7 (WsG , Ln 38, Col e) - 231 Less Total Account 565 (WsG , Ln 39, Col e) - 232 Transmission O&M Expense Adjustment (WsG , Ln 40, Col e) -

233 Transmission Subtotal (ln 227 - ln 228 + ln 229 + ln 230 - ln 231 + ln 232 ) - TP 0.00000 -

234 Administrative and General (WsG , Ln 63, Col e) - 235 Less: Acc. 928, Reg. Com. Exp. (WsG , Ln 53, Col e) - 236 Acct. 930.1, Gen. Advert. Exp. (WsG , Ln 55, Col e) - 237 Acct. 930.2, Miscellaneous Gen. Exp. (WsG , Ln 56, Col e) - 238 Acc. 924, Property Insurance (WsG , Ln 50, Col e) -



241 Acct. 928 - Transmission Specific (Note K) (WsH , Ln 21, Col H) - DA 1.00000 -

242 Acct. 928 - Transmission Allocated (Note K) (WsH , Ln 21, Col I) - TP 0.00000 -

242.1 Acct. 928 - SPS Wholesale Specific (Note K) (WsH , Ln 12, Col K) - RC 0.00000 -

243 Acct. 930.2 - Transmission Specific (Note K) (WsH , Ln 33, Col H) - TP 0.00000 -

244 Acct. 930.2 - Transmission Allocated (Note K) (WsH , Ln 33, Col I) - W/S 0.00000 -

245 Transmission Safety and Siting Advertising (Note K) (WsH , Ln 46, Col C) - TP 0.00000 -

246 -

247 A & G Subtotal (sum lns 239 to 246) - -

248 TOTAL O & M EXPENSE (ln 233 + ln 247 ) -



- 252 Plus: Recovery of Abandoned Incentive Plant (Note E) (Worksheet E) - TP 0.00000

- 253 Plus: Recovery of Extraordinary Property

Loss (Note E) (Worksheet E) - TP 0.00000



-

256 TOTAL DEPRECIATION AND AMORTIZATION (sum lns 250 to 255) - -



Version 0.1.0 Page 2 of 2 Proposed Effective Date: 2/1/2019 Approved Effective Date: 257 TAXES OTHER THAN INCOME (Note L)

258 Labor Related 259 Payroll (Worksheet J) 263.i - W/S 0.00000



- 263 Other Tax (Worksheet J) 263.i - GP 0.00000

-

264 TOTAL OTHER TAXES (sum lns 259 to 263) - -

265 INCOME TAXES (Note M) 266 T=1 - {[(1 - SIT) * (1 - FIT)] / (1 - SIT * FIT * p)} = 0.00% 267 CIT=(T/1-T) * (1-(WCLTD/R)) = 0.00% 268 where WCLTD=(ln 296) and R= (ln 299) 269 and FIT, SIT & p are as given in Note M. 270 1 / (1 - T) = (from ln 266) - 271 Amortized Investment Tax Credit (266.8.f) (Worksheet J) 266.8.f - (enter negative) 271.1 (Excess)/Deficient ADIT Amortization - Plant (Note P) (Worksheet D.4)

-



272 Income Tax Calculation (ln 267 * ln 275) - -

273 ITC adjustment (ln 270 * ln 271) - NP 0.00000 -

273.1 (Excess)/Deficient ADIT Amortization - Plant (ln 270 * ln 271.1) -

DA 0.00000 -


(ln 270 * ln 271.2) -

DA 0.00000 -

274 TOTAL INCOME TAXES (sum lns 272 to 273.2) -

- 275 RETURN (Rate Base * Rate of Return) (ln 225 * ln 299) -


-

277 REVENUE REQUIREMENT (sum lns 248, 256, 264, 274, 275, 276) - -


Att O-SPS Formula Rate, Cap Struc, Allocations, Actual, Table 10


**ACTUAL** Utilizing FERC Form 1 Actual Data

For the Billing Period 01/01/yy to 12/31/yy

SOUTHWESTERN PUBLIC SERVICE COMPANY

SUPPORTING CALCULATIONS

Line (1) (2) (3) (4) (5)

No.

278 TRANSMISSION PLANT INCLUDED IN OATT Transmission Rate (Note N)

279 Total transmission plant (ln 184) -

280 Less Generator Step-up facilities (WsD.1 , Ln 147) -

281 Less Radial Line facilities (Worksheet O) -

281a Plus Radial Line facilities true-up (Worksheet M) -

282 Transmission plant included in OATT Trans Rate (ln 279 - ln 280 - ln 281-281a) -

283 Percent of transmission plant in OATT Trans Rate (ln 282 / ln 279) TP= 0.00000

284 WAGES & SALARY ALLOCATOR (W/S) (Note O)

285 Production (WsG , Ln 69, Col i) -

NA -

286 Transmission (WsG , Ln 70, Col i) -

TP 0.00000 -

287 Regional Market (WsG , Ln 71, Col i) -

NA -

288 Distribution (WsG , Ln 72, Col i) -

NA -

289 Other (WsG , Ln 73, Col i) -

NA -


-

291 W/S Allocator W/S= 0.00000

291.1 REGULATORY COMMISSION EXPENSE FACTOR (RC)

291.2 Transmission Network Load (WsC , Ln 28, Col f) -

291.3 Wholesale Transmission Network Load (WsC , Ln 42, Col d) -

291.4 Percent of BPU Rev Req charged to SPS Zone Input -

291.5 Wholesale Load Ratio Share (Ln 291.3/Ln 291.2) -

291.6 RC Factor 1/(Ln 291.3/Ln 291.2)*(1-(Ln 291.4*Ln 291.5)) RC= -

292 RETURN (R) $

293 Long Term Interest (Worksheet K, Ln 51, Col h) -

294 Preferred Dividends (Worksheet K, Ln 56, Col h) -


296 Long Term Debt (Worksheet K, Ln 36, Col o) -

0.00% 0.0000 0.0000

297 Preferred Stock (Worksheet K, Ln 23, Col o) -

0.00% 0.0000 0.0000



Version 0.1.0 Page 2 of 2 Proposed Effective Date: 2/1/2019 Approved Effective Date: 298 Common Stock (Worksheet K, Ln 27, Col o)

- 0.00% 0.1050 0.0000


R 0.0000


Att O-SPS Formula Rate, Notes, Actual, Table 11

Version 0.3.0 Page 1 of 1 Proposed Effective Date: 2/1/2019 Approved Effective Date:

Rate Formula Template Table 11 **ACTUAL** Utilizing FERC Form 1 Actual Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY General Notes: a) References to data from FERC Form 1 are indicated as: page#.line#.col.# Note Letter

A The revenues credited shall include amounts received directly from the SPP for service under this tariff reflecting SPS's integrated transmission facilities. Revenues associated with FERC annual charges, gross receipts taxes, ancillary services or other facilities revenues shall be excluded from the definition of transmission facilities under this tariff shall not be included as revenue credits. Revenue from coincident peak loads included in the DIVISOR are also not included as revenue credits unless this revenue is offset by a corresponding expense. See Worksheet B for details. B The annual and monthly net and gross plant carrying charges on page 7 are to be used to compute the revenue requirement for directly assigned facilities, any Base Plan Upgrades, distribution facilities, and radial lines. C This additional revenue requirement is determined using a net plant carrying charge (fixed carrying charge or FCR) approach. Worksheet R shows the calculation of the additional revenue requirements for each project receiving incentive rate treatment, as accepted by FERC by a separate docket. These individual additional revenue requirements shall be summed, for the then current year, and included here. D Reflects the transmission related portion of balances in Accounts 281, 282, 283, 190, and 255 as adjusted by any amounts in contra accounts identified as regulatory assets or liabilities related to FASB 106, 109, 133,158 or FASB Interpretation No. 48. Balance of Account 255 is reduced by prior flow throughs and completely excluded if the utility chose to utilize amortization of tax credits against taxable income as discussed in Note M.

The calculation of ADIT for both the true-up and the annual projection will be performed in accordance with IRS regulation Section 1.167(l)-1(h)(6). The Annual True-Up for a given year will use the same methodology that was used to project that year’s rates. (Except for ADIT Proration which is described on Table 21A of the template.)

E Includes any incentive Construction Work in Progress (CWIP), any related Allowance for Funds Used During Construction (AFUDC), any unamortized balances related to the recovery of abandoned incentive plant costs, any extraordinary property losses and any related depreciation and amortization expense amounts. Formula amounts for all of the foregoing items will remain at $0 until approved by FERC under a separate docket. F Includes only transmission related or functionally booked as transmission land held for future use. G Cash Working Capital will be set at and remain $0 until such time as SPS files and receives FERC approval for a lead/lag study. H Equal to the balance of Network Facilities Upgrades Credits, net of accumulated depreciation, due transmission customers that made lump-sum payments towards the construction of Network Transmission Facilities consistent with Paragraph 657 of Order 2003-A. Excludes interest since interest is added to the revenue requirement on line 276. I The base plan upgrade revenue requirement will be updated annually in the Annual Update. The BPU revenue requirement will be a projected amount with a true-up to actual adjustment. The updated revenue requirement will be provided to the SPP no later than November 15 for billings effective January 1. J (Reserved for future use) K Includes all Regulatory Commission expense itemized in FERC Form 1 at 351.h. Show in Worksheet H how these expense items are assigned to transmission. FERC Assessment Fees, General Advertising, and Industry Association Dues and Research and Developments costs recorded in 930.2 shall not be assigned to transmission. A & G expenses shall Include specific transmission safety-related advertising and transmission siting advertising costs. The annual PBOP expense amount will be based on the PBOP expense amount reported in SPS’s most recent annual actuarial valuation report as of the date of SPS’s Annual Update. SPS will provide a copy of that actuarial report as part of its Annual Update and its Annual Informational Filing to the

Commission. NERC fees recorded in Acct. 928, Regulatory Commission Expenses, or in Acct. 165, Prepayments, shall be excluded from the formula. L Includes only FICA, unemployment, highway, property and other assessments charged in the current year. Gross receipts tax, taxes related to income, retail and non-transmission related taxes are excluded. M The currently effective income tax rate, where FIT is the Federal income tax rate; SIT is the State income tax rate, and p = "the percentage of federal income tax deductible for state income taxes". If the utility is taxed in more than one state, it must attach a work paper showing the name of each state and how the blended or composite SIT was developed. Furthermore, a utility that elected to utilize amortization of tax credits against taxable income, rather than book tax credits to Account No. 255 and reduce rate base, must reduce its income tax expense by the amount of the Amortized Investment Tax Credit (Form 1, 266.8.f) (ln 271) multiplied by (1/1-T) . If the applicable tax rates are zero enter 0. Inputs Required: FIT = 0.00% SIT= (Worksheet L) 0.00% (State Income Tax Rate or Composite SIT) p = 0.00% (percent of FIT deductible for state purposes) N Removes the dollars of plant booked to transmission plant that is excluded from the Tariff because it does not meet the Tariff's definition of Transmission Facilities, or is booked to transmission (e.g. step-up transformers) that is included in the development of OATT ancillary service rates,or is otherwise not eligible to be recovered under this Tariff. O Enter dollar amounts. Includes service company labor. Does not include contract labor. P Includes the amortization of any excess/deficient deferred income taxes resulting from changes to income tax laws, income tax rates (including changes



Att O-SPS Formula Rate, Wksht C, Divisor, Table 18

Version 0.1.0 Page 1 of 2 Proposed Effective Date: 2/1/2019 Approved Effective Date: Southwestern Public Service Company Worksheet C

Worksheet C - Divisor Table 18 I. Transmission Network Load (mW) Projected for Billing Year = 20yy

Line No. Month Network Load1 Plus: Intertie Demand2 TO's Transmission Network Load

1 0

2 0

3 0

4 0

5 0

6 0

7 0

8 0

9 0

10 0

11 0

12 0

13 Total 0 0 0

14 12-CP 0 0 0

II. Transmission Network Load (mW) Actual for Billing Year = 20yy

Line No. Month, Day and Year1 Hour Ending1 Network Load1 Plus: Intertie Demand2 TO's Transmission Network Load

15 0

16 0

17 0

18 0

19 0

20 0

21 0

22 0

23 0

24 0

25 0

26 0

27 Total 0 0 0

28 12-CP 0 0 0

III. Notes 1 These are the dates, hour ending and loads at the time of the transmission peak, as reported in FERC Form 1, page 400. 2 Reserved capacity associated with SPS-Public Service Company of Colorado Intertie. IV. Firm Network Service for Others (mW) for Billing Year = 20yy

Line No. Month Projected

Wholesale Load

Actual Wholesale Load3

29 January

30 February

31 March

32 April

33 May

34 June

35 July

36 August

37 September

38 October



Version 0.1.0 Page 2 of 2 Proposed Effective Date: 2/1/2019 Approved Effective Date: 39 November

40 December

41 Total

42 12 Month Average

V. Notes 3 These are the Wholesale Loads by month, as reported in FERC Form 1, page 400.


Att O-SPS Formula Rate, Wksht D, Average ADIT, Table 19

Version 0.1.0 Page 1 of 2 Proposed Effective Date: 2/1/2019 Approved Effective Date: Southwestern Public Service Company Worksheet D

Worksheet D Average Rate Base Table 19 Inputs for Average Rate Base Calculations Year = 20yy Year = 20yy Line (a) (b) (c) (d) (e) (f) (g) (h) No. Projected Projected Projected References for Actual Actual Actual Beg of Year End of Year Average Beg of Year End of Year Average Balance Balance Balance Actual Data Balance Balance Balance 1 Deferred Taxes - Account 281 2 0 0 3 0 0 4 0 0 5 0 0 6 0 0 7 0 0

8 Total Account 281 0 0 0 FF1, p273 (acct not currently used) 0 0 0

9 10 Deferred Taxes - Account 282 11 12 0 0 13 0 0 14 0 0 15 0 0 16 0 0 17 0 0 18 0 0 19 0 0 20 Excess ADIT 0 0 21 FAS 109 Plant Excess ADIT –

Protected 0 0

22 FAS 109 Plant Excess ADIT – Unprotected

0 0

23 Total Account 282 0 0 0 FF1, p 275, ln 9, col k 0 0 0

24 25 Deferred Taxes - Account 283 26 0 0 27 0 0 28 0 0 29 0 0 30 0 0 31 0 0 32 0 0 33 0 0 34 0 0 35 0 0


37 38 Deferred Taxes - Account 190 39 0 0 40 0 0 41 0 0 42 0 0 43 0 0 44 0 0 45 0 0 46 0 0 47 0 0 48 0 0 49 0 0 50 0 0 51 0 0 52 0 0 53 0 0 54 0 0



Version 0.1.0 Page 2 of 2 Proposed Effective Date: 2/1/2019 Approved Effective Date: 55 0 0

56 0 0 57 0 0 58 0 0 59 0 0 60 0 0 61 0 0 62 0 0 63 0 0 64 Deficient ADIT 0 0 65 FAS 109 Plant Deficient ADIT –

Protected 0 0

66 FAS 109 Plant Deficient ADIT – Unprotected

0 0

67 Total Account 190 0 0 0 FF1, p 234, ln 18, col c 0 0 0

68

69 Total Deferred Taxes 0 0

70 71 Unamortized Balance of Abandoned Incentive Plant 72 (See Formula Template Note E found on pages 6 and 11.) 73 0 0 74 0 0

75 Total Abandoned Incentive Plant 0 0 0 Company Records 0 0 0

76 77 Unamortized Balance of Extraordinary Property Loss (Note E) 78 (See Formula Template Note E found on pages 6 and 11.) 79 0 0 80 0 0

81 Total Extraordinary Property Loss 0 0 0 Company Records 0 0 0

82 83

84 Land Held for Future Use 0 FF1, p 214 0


Att O-SPS Formula Rate, Wksht D.2, ADIT Prorate Factor, Table 21A


Southwestern Public Service Company WsD.2 ADIT Proration Factor

Accumulated Deferred Income Taxes Proration Factor Table 21A

Rate Year=

Line No.

1 Account 282 – Liberalized Depreciation-Transmission

2 Days in Period Averaging with Proration - Projected

Averaging Preserving Projected Proration – True-up (See Note 6)

3 A B C D E F G H I J K L M N

4

Month Days in the Month

Number of Days

Remaining in Year After

Month’s Accrual of Deferred

Taxes

Total Days

in Futur

e Portion of Test Perio

d

Proration Amount (C / D)

Projected Monthly Activity

Prorated Projected Monthly Activity (E x F)

Prorated Projected Balance

(Cumulative Sum of G)

Actual

Monthly Activity

Difference between projected and actual

activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly

activity are either both increases

or decreases (See Note

2)


activity when

actual and projected



3)

When projected activity is

an increase while actual activity is a decrease or

projected activity is a decrease

while actual activity is

an increase (See Note

4)

Balance reflecting proration

or averaging (See Note 5)

5

6 December 31st balance Prorated Items

7 January

8 February

9 March

10 April

11 May

12 June

13 July

14 August

15 September

16 October

17 November

18 December

19 Total

20

21



Version 0.2.0 Page 2 of 12 Proposed Effective Date: 2/1/2019 Approved Effective Date: 22

23

24 Ending Balance of Prorated items (Line 18, & Col H) (Line 18, & Col N)

25 Non-prorated Average Balance From WsD Avg Rate Base From WsD Avg Rate Base

26 Proration Adjustment (Line 24 minus Line 25) (Line 24 minus Line 25)

27

28

29 Account 282 – Liberalized Depreciation-General and Intangible




32


Number of Days

Remaining in Year

After Month’s Accrual

of Deferred

Taxes

Total Days in Future Portion of Test Period






Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



33


35 January

36 February

37 March

38 April

39 May

40 June

41 July

42 August

43 September

44 October

45 November

46 December

47 Total

48




50

51




55

56

57 Account 283 – Liberalized Depreciation-Software




60


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



61


63 January

64 February

65 March

66 April

67 May

68 June

69 July

70 August

71 September

72 October

73 November

74 December

75 Total




77

78

79




83

84

85 Account 190 – Basis Difference-Transmission




88


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



89


91 January

92 February

93 March

94 April

95 May

96 June

97 July

98 August

99 September

100 October

101 November

102 December



Version 0.2.0 Page 5 of 12 Proposed Effective Date: 2/1/2019 Approved Effective Date: 103 Total

104

105

106

107




111

112

113 Account 190 – Basis Difference-General and Intangible




116


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



117


119 January

120 February

121 March

122 April

123 May

124 June

125 July

126 August

127 September

128 October

129 November



Version 0.2.0 Page 6 of 12 Proposed Effective Date: 2/1/2019 Approved Effective Date: 130 December

131 Total

132

133

134

135




139

140

141 Account 190 – Basis Difference-CIAC Transmission




144


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



145


147 January

148 February

149 March

150 April

151 May

152 June

153 July

154 August

155 September

156 October

157 November



Version 0.2.0 Page 7 of 12 Proposed Effective Date: 2/1/2019 Approved Effective Date: 158 December

159 Total

160

161

162

163




167

168

169 Account 190 – Basis Difference-CIAC General




172


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



173


175 January

176 February

177 March

178 April

179 May

180 June

181 July

182 August

183 September

184 October



Version 0.2.0 Page 8 of 12 Proposed Effective Date: 2/1/2019 Approved Effective Date: 185 November

186 December

187 Total

188

189

190

191




195

196

197 Account 190 – Federal Only NOL-Transmission




200


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



201


203 January

204 February

205 March

206 April

207 May

208 June

209 July

210 August

211 September



Version 0.2.0 Page 9 of 12 Proposed Effective Date: 2/1/2019 Approved Effective Date: 212 October

213 November

214 December

215 Total

216

217

218

219




223

224

225 Account 190 – Federal Only NOL-General




228


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



229


231 January

232 February

233 March

234 April

235 May

236 June

237 July

238 August



Version 0.2.0 Page 10 of 12 Proposed Effective Date: 2/1/2019 Approved Effective Date: 239 September

240 October

241 November

242 December

243 Total

244

245

246

247




251

252

253

254

255 Account 182 – Excess ADIT Federal Only NOL - Transmission




258


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



259


261 January

262 February

263 March

264 April

265 May



Version 0.2.0 Page 11 of 12 Proposed Effective Date: 2/1/2019 Approved Effective Date: 266 June

267 July

268 August

269 September

270 October

271 November

272 December

273 Total

274

275

276

277


279 Non-prorated Average Balance From WsD.3 Excess ADIT From WsD.3 Excess ADIT


281

282

283 Account 182 – Excess ADIT Federal Only NOL - General




286


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



287


289 January

290 February

291 March

292 April

293 May

294 June



Version 0.2.0 Page 12 of 12 Proposed Effective Date: 2/1/2019 Approved Effective Date: 295 July

296 August

297 September

298 October

299 November

300 December

301 Total

302

303

304

305




Notes: 1) Column J is the difference between projected monthly and actual monthly activity (Column I minus Column F). Specifically, if projected and actual

activity are both positive, a negative in Column J represents over-projection (amount of projected activity that did not occur) and a positive in Column J

represents under-projection (excess of actual activity over projected activity). If projected and actual activity are both negative, a negative in Column J

represents under-projection (excess of actual activity over projected activity) and a positive in Column J represents over-projection (amount of projected

activity that did not occur).

2) Column K preserves proration when actual monthly and projected monthly activity are either both increases or decreases. Specifically, if Column J

is over-projected, enter Column G x [Column I/Column F]. If Column J is under-projected, enter the amount from Column G and complete Column L). In other

situations, enter zero.

3) Column L applies when (1) Column J is under-projected AND (2) actual monthly and projected monthly activity are either both increases or

decreases. Enter the amount from Column J. In other situations, enter zero.

4) Column M applies when (1) projected monthly activity is an increase while actual monthly activity is a decrease OR (2) projected monthly activity is

a decrease while actual monthly activity is an increase. Enter actual monthly activity (Col I). In other situations, enter zero.

5) Column N is computed by adding the prorated monthly activity, if any, from Column K to 50 percent of the portion of monthly activity, if any, from

Column L or M to the balance at the end of the prior month. The activity in columns L and M is multiplied by 50 percent to reflect averaging of rate base to the

extent that the proration requirement has not been applied to a portion of the monthly activity.

6) The methodology to remove double averaging from the true-up ADIT Proration calculation is effective June 27, 2018.


Att O-SPS Formula Rate, Wksht D.3, Excess ADIT-Table 21B


Southwestern Public Service Company

Worksheet D.3 Non-Plant Excess ADIT

Inputs for Average Rate Base Calculations

Year = 20yy

Year = 20yy

Line (a)

(b) (c) (d) (e) (f) (g) (h) (i) (j)

No.

Projected Projected Projected

Avg.

References Actual Actual Actual Avg.

Beg of Year

End of Year Balance ADIT for

Beg of Year

End of Year Balance ADIT

Balance Balance (b+c)/2 Amortization

Actual Data Balance Balance (f+g)/2 Amortization

1 Excess Deferred Taxes - Assets Account 254 (note 1)

2 3

4 5 6 7 8 9 10 11

12

-

- 13 Excess ADIT Liabilities Subject to Proration

Excess ADIT Liabilities Subject to Proration

14

-

- 15

-

-

16 Total Account 254

0 0 - 0 0 0 0 0

17 18 Acct 254 Gross Up

Worksheet D.3 Table 21B




19

20 Total Acct 254 Grossed Up

0 0

FF1, p 278, Footnote 0 0

21

22 Excess Deferred Taxes - Assets Account 182.3 (Note 2)

23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50




Note 1: All Excess ADIT Balances recorded in FERC Account 254 are unprotected Note 2: The Deficient ADIT balance associated with prior Net Operating Loss deferred tax assets are protected. The other Deficient ADIT items in FERC Account 182.3 are unprotected.

51

-

- 52

-

-

53 Excess ADIT Assets Subject to Proration

Excess ADIT Assets Subject to Proration

54 55 56

57

-

- 58

-

-

59

-

- 60

-

-

61 Total Account 182.3

0 0 0 0

0 0 0 0

62 63 Acct 182.3 Gross Up

64

65 Total Acct 182.3 Grossed Up

0 0



Att O-SPS Formula Rate, Wksht D.4 - Excess-Deficnt ADIT Amort-Table 21C



Worksheet D.4

Worksheet D.4 - (Excess)/Deficient ADIT Amortization

Table 21C

Plant Excess ADIT Amortization, Projected for Billing Year = 20yy

(a) (b) (c) (d) (e) (f) (g) (h)

Retail, Production

Total Included Remaining

& Other

Transmission Plant Labor

in Income Tax Expense Amortization

Identification Total (Note

1) Related Related Relate

d Relate

d (d)+(e)+(f) Period (Note

2)

Subtotal

Transmission Allocator [ TP, GP or W/S ]



Version 0.0.0 Page 2 of 5 Proposed Effective Date: 2/1/2019 Approved Effective Date: Total



Non-Plant Excess ADIT Amortization, Projected for Billing Year = 20yy

(a) (b) (c) (d) (e) (f) (g) (h)

Retail, Production


& Other





d Relate


2)




Subtotal


Total



Plant Excess ADIT Amortization, Actual for Billing Year = 20yy

(a) (b) (c) (d) (e) (f) (g) (h)

Retail, Production


& Other





d Relate


2)




Subtotal


Total



Non-Plant Excess ADIT Amortization, Actual for Billing Year = 20yy

(a) (b) (c) (d) (e) (f) (g) (h)

Retail, Production


& Other Transmission

Plant Labor



1) Related Related

Related

Related (d)+(e)+(f)

Period (Note 2)




Subtotal


Total

Note 1: Excess and Deficient ADIT is amortized to FERC Accounts 410.1 and 411.1

Note 2: The amortization of Excess and Deficient ADIT balances began January 1, 2018


Att O-SPS Formula Rate, Wksht E, Accts 281 282 283, Proj, Table 22

Version 0.2.0 Page 1 of 3 Proposed Effective Date: 2/1/2019 Approved Effective Date: Southwestern Public Service Company Worksheet E

Worksheet E - Rate Base Adjustments Table 22 ADIT Account 281 Projected for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

281 -

281 -

281 -

281 -

281 -

Subtotal - Form 1, p273 Projected -

-

-

-

-

Less FASB 109 Above if not separately removed


Total -

-

-

-

-

Transmission Allocator [ TP, GP or W/S ] 0.0000% 0.0000% 0.0000% 0.0000%

Total 0 0 0 0 0

ADIT Account 282 Projected for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

282 -

282 -

282 -

282 -

282 -

282 FAS 109 Plant Excess ADIT – Protected -

282 FAS 109 Plant Excess ADIT – Unprotected -


-

-

-

-



Proration Adjustment – Transmission (from WsD.2)

Proration Adjustment – General & Intangible (from WsD.2)

Total -

-

-

-

-


Total 0 0 0 0 0





283 -

283 -

283 -

283 -

283 -

283 -

283 -

283 -

283 -

283 -

283 -


-

-

-

-



Proration Adjustment – Software (from WsD.2)

Total -

-

-

-

-


Total 0 0 0 0 0


254 -

254 -

254 -

254 -

254 -




-

254 -

Excess ADIT Liabilities Subject to Proration -

-

-

-

-

-

-

-

-

Subtotal - Projected -

-

-

-

-


Total -

-

-

-

-


Total 0 0 0 0 0


Att O-SPS Formula Rate, Wksht E, Acct 190, Proj, Table 23


Worksheet E - Rate Base Adjustments Table 23 ADIT Account 190 Projected for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -


190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 FAS 109 Plant Deficient ADIT - Protected

-

190 FAS 109 Plant Deficient ADIT - Unprotected



Version 0.2.0 Page 2 of 3 Proposed Effective Date: 2/1/2019 Approved Effective Date: Subtotal - Form 1, p234 Projected

- -

-

-

-





Proration Adjustment – Transmission NOL (from wsD.2)

Proration Adjustment – General NOL (from WsD.2)

Total -

-

-

-

-


Total 0 0 0 0 0

ADIT Account 182.3 Projected for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -

Excess ADIT Assets Subject to Proration -

-

-

-

-

-

-

-

-


-

-

-

-

Proration Adjustment – Transmission NOL (from WsD.2)


Total - - - - -


Total 0 0 0 0 0




Unamortized Balance of Abandoned Incentive Plant Projected for Billing Year = 20yy (A) (B) (C) (D) (E) Average Unamortized Unamortized Current Year Balance Balance Amortization End of Acc. No. Identification from WsD Expense Current Year

-

-

-

-

Total -

-

-

Unamortized Balance of Extraordinary Property Loss Projected for Billing Year = 20yy (A) (B) (C) (D) (E) Average Unamortized Unamortized Current Year Balance Balance Amortization End of Acc. No. Identification from WsD Expense Current Year

-

-

-

-

Total -

-

-


Att O-SPS Formula Rate, Wksht E, ADIT, Actual, Table 24


Worksheet E - Rate Base Adjustments Table 24 ADIT Account 281 Actual for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

281 -

281 -

281 -

Subtotal - Form 1, p273 -

-

-

-

-



Total -

-

-

-

-


Total 0 0 0 0 0

ADIT Account 282 Actual for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

282 -

282 -

282 -



-


-

-

-

-





Total -

-

-

-

-


Total 0 0 0 0 0

ADIT Account 283 Actual for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production 0 0 Total Included Avg Balance & Other Transmission Plant Labor in Ratebase



Version 0.2.0 Page 2 of 4 Proposed Effective Date: 2/1/2019 Approved Effective Date: Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

283 -

283 -

283 -

283 -


-

-

-

-




Total -

-

-

-

-


Total 0 0 0 0 0


254 -

254 -

254 -

254 -

254 -

254 -

254 -


-

-

-

-

-

-

-

-

Subtotal - Actual -

-

-

-

-


Total -

-

-

-

-


Total 0 0 0 0 0





190 -

190 -

190 -

190 -

190 FAS 109 Plant Deficient ADIT – Protected -



-

-

-

-







Total -

-

-

-

-


Total 0 0 0 0 0

ADIT Account 182.3 Actual for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -


-

-

-

-



Version 0.2.0 Page 4 of 4 Proposed Effective Date: 2/1/2019 Approved Effective Date: -

-

-

-

Subtotal - Actual -

-

-

-

-



Total - - - - -

Transmission Allocator [ TP, GP or W/S ] 0.0000% 0.0000% 0.0000% 0.0000% 0

Total 0 0 0 0 0


Att O-SPS Formula Rate, Wksht H, Misc Expenses, Table 28


11 12 13 Acct 930.2 Projected for Billing Year = 20yy Acct 930.2 Actual for Billing Year = 20yy 14 15 16 17 18 19 20 21 Total 930.2

- -

-

-

- -

-

-

22 23 24 Transmission Safety & Siting Advertising (Other

Than in Acct 930.1) Projected for Year = 20yy Actual Transmission Safety & Siting for Year = 20yy

25 26 27 28 29 30 Total Transmission Safety & Siting Adv.

- -

Southwestern Public Service Company Worksheet H Worksheet H - Miscellaneous Expenses Table 28 Projected Actual Line No. 1 Acct 928 Projected for Billing Year = 20yy Acct 928 Actual for Billing Year = 20yy 2 (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) 3 100% 100% 100% 100% 4 Non- Transmission Transmission SPS Wholesale Non- Transmission Transmission SPS Wholesale 5 Description Expense Transmission Specific Allocated Specific Expense Transmission Specific Allocated Specific Explanation 6 7 8 9 10 Total 928

- -

-

- - -

-

-

-

-


Att O-SPS Formula Rate, Wksht P, Base Plan Upgrade, Table 36


Southwestern Public Service Company Worksheet P

Worksheet P - Revenue Requirement for Base Plan Upgrades, Service Upgrades, Sponsored Upgrades and Generator

Table 36

I. Determine the Revenue Requirement for Base Plan Upgrades

Line

No.

1 SUMMARY OF

BPU UPGRADES

2 (a) (b) (c) (d) (e) (f) (g) (h)

3 Investmen

t

4 Year Project Description

Projected Revenue

Requirement

Actual Revenue

Requirement

SPP Base Plan True-up

Amount

20yy SPP Base Plan True-up Amount

20yy SPP Base Plan True-up

Amount Int.

20yy Projected Revenue

Req.

5 Section A Base Plan Facilities in Service Project 1

-

-

-


-

-

-


-

-

-

8 -

-

-

9 -

-

-

10 -

-

-

11 -

-

-

12

13

14

15 Total Revenue Requirement and True-up Amount -

-

-

16 A. Base Plan facilities. In Service

17 i. Project 1, Projected (Describe)

18 The calculated Rev. Req. from TO's and Other Zones shown below are only valid for

Investment Year

19 matching Projected Year. Values prior and subsequent to the Projected Year will change

as Attachment O is updated.

20 These changes will not result in a refund or additional charge related to years prior to the

Projected Year.

21

Projected Details

22 Beginning Investment

Projected Year (Input) 20yy




23 Service Year (yyyy) Projected Year FCR w/o

incentives, less depreciation 0.00%

24 Billing Month (1-12) (From ARR – Projected Data, line

40 col (5))

25 Depreciation Rate

26 CIAC (Yes or No)

27 Investmen

t

Beginni

ng

Addition/

(Ret) Plant Investment

Depreciation Ending Revenue

28 Year Balance Amount Balance Depreciation

Rate Expense Balance

Requirement

29 -

-

-

-

-

-

-

30 -

-

-

-

-

-

-

31 -

-

-

-

-

-

-

32 -

-

-

-

-

-

-

33 -

-

-

-

-

-

-

34 -

-

-

-

-

-

-

35 -

-

-

-

-

-

-

36 -

-

-

-

-

-

-

37 -

-

-

-

-

-

-

38 -

-

-

-

-

-

-

39 -

-

-

-

-

-

-

40 -

-

-

-

-

-

-

41 -

-

-

-

-

-

-

42 -

-

-

-

-

-

-

43 -

-

-

-

-

-

-

44 -

-

-

-

-

-

-

45 -

-

-

-

-

-

-

46 -

-

-

-

-

-

-

47 -

-

-

-

-

-

-

48 -

-

-

-

-

-

-

49 -

-

-

-

-

-

-

50 -

-

-

-

-

-

-

51 -

-

-

-

-

-

-

52 -

-

-

-

-

-

-

53 -

-

-

-

-

-

-

54 -

-

-

-

-

-

-

55 -

-

-

-

-

-

-




56 -

-

-

-

-

-

-

57 -

-

-

-

-

-

-

58 -

-

-

-

-

-

-

59 -

-

-

-

-

-

-

60 …. …. ….. …..

….. ….. ….

61

62 i. Project 1, Actual (Describe)


Investment Year

64 matching True-up Year. Values prior and subsequent to the True-up Year will change as

Attachment O is updated.


True-up Year.

66

True-up Year Actual Details


True-up Year (Actual Year Used for Revenue Requirement - Input) 20yy

68 Service Year (yyyy) True-up Year (Actual FCR w/o incentives, less

depreciation) 0.00%

69 Billing Month (1-12) (From ARR-Actual Data, line 176

col (5))


71 CIAC (Yes or No)

72 Investmen

t

Beginni

ng Addition/(Ret) Plant Investment




Requirement

74 -

-

-

-

-

-

-

75 -

-

-

-

-

-

-

76 -

-

-

-

-

-

-

77 -

-

-

-

-

-

-

78 -

-

-

-

-

-

-

79 -

-

-

-

-

-

-

80 -

-

-

-

-

-

-

81 -

-

-

-

-

-

-

82 -

-

-

-

-

-

-

83 -

-

-

-

-

-

-

84 -

-

-

-

-

-

-

85 -

-

-

-

-

-

-

86 -

-

-

-

-

-

-

87 -



Version 0.1.0 Page 4 of 8 Proposed Effective Date: 2/1/2019 Approved Effective Date: - - - - - -

88 -

-

-

-

-

-

-

89 -

-

-

-

-

-

-

90 -

-

-

-

-

-

-

91 -

-

-

-

-

-

-

92 -

-

-

-

-

-

-

93 -

-

-

-

-

-

-

94 -

-

-

-

-

-

-

95 -

-

-

-

-

-

-

96 -

-

-

-

-

-

-

97 -

-

-

-

-

-

-

98 -

-

-

-

-

-

-

99 -

-

-

-

-

-

- 100 -

-

-

-

-

-

-

101 -

-

-

-

-

-

-

102 -

-

-

-

-

-

-

103 -

-

-

-

-

-

-

104 -

-

-

-

-

-

-

105 …. …. ….. …..

….. ….. ….

106

107

A. Base Plan facilities. In Service

108

i. Project 2, Projected (Describe)

109

The calculated Rev. Req. from TO's and Other Zones shown below are only valid for Investment Year

110

matching Projected Year. Values prior and subsequent to the Projected Year will change as Attachment O is updated.

111

These changes will not result in a refund or additional charge related to years prior to the Projected Year.

112

Projected Details

113

Beginning Investment


114 Service Year (yyyy)

Projected Year FCR w/o incentives, less depreciation 0.00%

115 Billing Month (1-12)

(From ARR – Projected Data, line 40 col (5))


11 CIAC (Yes or No)




118

Investment

Beginning

Addition/(Ret) Plant Investment


119 Year Balance Amount Balance

Depreciation Rate Expense Balance Requirement

120 - - - -

- - -

121 - - - -

- - -

122 - - - -

- - -

123 - - - -

- - -

124 - - - -

- - -

125 - - - -

- - -

126 - - - -

- - -

127 - - - -

- - -

128 - - - -

- - -

129 - - - -

- - -

130 - - - -

- - -

131 - - - -

- - -

132 - - - -

- - -

133 - - - -

- - -

134 - - - -

- - -

135 - - - -

- - -

136 - - - -

- - -

137 - - - -

- - -

138 - - - -

- - -

139 - - - -

- - -

140 - - - -

- - -

141 - - - -

- - -

142 - - - -

- - -

143 - - - -

- - -

144 - - - -

- - -

145 - - - -

- - -

146 - - - -

- - -

147 - - - -

- - -

148 - - - -

- - -

149 - - - -

- - -




0 - - - -

- - - 151 …. …. ….. …..

….. ….. ….

152

153

i. Project 2, Actual (Describe)

154


155

matching True-up Year. Values prior and subsequent to the True-up Year will change as Attachment O is updated.

156

These changes will not result in a refund or additional charge related to years prior to the True-up Year.

157


158



159 Service Year

True-up Year (Actual FCR w/o incentives, less depreciation) 0.00%

160 Billing Month

(From ARR-Actual Data, line 176 col (5))


162 CIAC (Yes or No)

163

Investment

Beginning





165 - - - -

- - -

166 - - - -

- - -

167 - - - -

- - -

168 - - - -

- - -

169 - - - -

- - -

170 - - - -

- - -

171 - - - -

- - -

172 - - - -

- - -

173 - - - -

- - -

174 - - - -

- - -

175 - - - -

- - -

176 - - - -

- - -

178 - - - -

- - -

180 - - - -

- - -

181 - - - -

- - -

182 - - - -

- - -

18 - - - - - - -




184 - - - -

- - -

185 - - - -

- - -

186 - - - -

- - -

187 - - - -

- - -

188 - - - -

- - -

189 - - - -

- - -

190 - - - -

- - -

191 - - - -

- - -

192 - - - -

- - -

193 - - - -

- - -

194 - - - -

- - -

195 - - - -

- - -

196 …. …. ….. …..

….. ….. ….

197

II. Determine the Revenue Requirement for Service Upgrades, Sponsored Upgrades and Generator Interconnection Facilities

Line

No.

1

SUMMARY OF SERVICE, SPONSORED AND

GENERATOR INTERCONNECTION

UPGRADES

2 (a) (b) (c) (d) (e)

3 Investment Projected Revenue Actual Revenue SPP Base Plan

4 Year Project Description Requirement Requirement True-up Amount

5 - - -

6 - - -

7 - - -

8 - - -

9 - - -

10 - - -

11 - - -

12

13




14

15 Total Revenue Requirement and True-up Amount - - -

Worksheet P - Revenue Requirement for Base Plan Upgrades, Service Upgrades, Sponsored Upgrades and Generator Interconnection Facilities.

III. Depreciation Rates

Year Projected Worksheet P Depr Rate

Actual Worksheet P Depr Rate

20yy

20yy

20yy

20yy

20yy

20yy

20yy

Projected Ref. Table 2, Line 40.1, col(5) Actual Ref. Table 7, Line 176.1 col(5)

20yy

20yy

20yy

20yy

20yy

20yy

20yy

20yy

20yy

20yy


Att O-SPS Formula Rate, Depreciation and Amortization Rates, Table 45


Southwestern Public Service Company Table 45

Transmission Formula Rate Template Worksheet S

Twelve Months Ended December 31, 20YY Depreciation and Amortization Rates

Depreciation/

Amortization

Rate

FERC Account Name (%)

Electric Intangible

303.40 Electric Intangible Software 3 Yr 33.33





Electric Transmission 350.2 Land Rights 1.30

352 Structures & Improvements 1.80

353 Station Equipment 2.29

354 Towers & Fixtures 1.64

355 Poles & Fixtures 3.61

356 OH Conductors & Devices 2.97

357 UG Conduit 1.95

358 UG Conductors & Devices 3.16

359 Roads & Trails 1.56

Electric General 389 General Land Rights 2.12

390 Structures and Improvements 2.36

391 Office, Furniture and Equipment 4.00

391.4 Computer Hardware 20.00

392.1 Transportation Equipment - Autos 9.10

392.2 Transportation Equipment - Light Trucks 9.30

392.3 Transportation Equipment - Trailers 6.07

392.4 Transportation Equipment - Heavy Trucks 7.83

393 Stores Equipment 2.86

394 Tools Shop Equipment 2.86

395 Laboratory Equipment 4.00

396 Power Operated Equipment 4.74

397 Communications Equipment 6.93

397.3 Communications Equipment - EMS 6.93

398 Miscellaneous Equipment 4.17




Notes:

The Depreciation Rates were approved in Docket ER19-XXX (Transmission) and Docket ER15-949 (General and Intangible) and will not change absent a 205 or 206 filing.

Exhibit No. SPS -0002 (ATT O-SPS FORMULA RATE - MARKED)


Att O-SPS Formula Rate, Revenue Rqmt, Projected, Table 2

Version 0.2.0 0.3.0 Proposed Effective Date: 1/1/2019 2/1/2019 Page 1 of 1 Rate Formula Template Table 2

**PROJECTED** Utilizing Projected Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY (1) (2) (3) (4) (5) Line Transmission No. Amount

28 PROJECTED REVENUE REQUIREMENT (w/o incentives) (ln 141) $ - 29 REVENUE CREDITS (Note A) Total Allocator

30 Account No. 454 (Worksheet B) - DA 1.00000 $ - 31 Account No. 456.1 (Worksheet B) - DA 1.00000 - 31.1 Account No. 421.1 (or other applicable acct) (Worksheet B) - DA 1.00000

31.2 Account No. 456.0 (Worksheet B) - DA 1.00000

32 Total Revenue Credits $ - 33 NET REVENUE REQUIREMENT (w/o incentives) (ln 28 less ln 32) $ - 34 NET PLANT CARRYING CHARGE (w/o incentives) (Note B) 35 Annual Rate (ln 33 / ln 62 x 100) 0.00% 36 Monthly Rate (ln 35 / 12) 0.00% 37 GROSS PLANT CARRYING CHARGE (w/o incentives) (Note B) 38 Annual Rate (ln 33 / ln 48 x 100) 0.00% 39 NET PLANT CARRYING CHARGE, W/O DEPRECIATION (w/o incentives) (Note B) 40 Annual Rate ( (ln 33 - ln 114 ) / ln 62 x 100) 0.00% 40.1 BPU Depreciation Rate (ln 114 / ln 48 ) 0.00% 41 NET PLANT CARRYING CHARGE, W/O DEPRECIATION, INCOME TAXES AND RETURN (Note B) 42 Annual Rate ( (ln 33 - ln 114 - ln 138 - ln 139) / ln 62 x 100) 0.00% 43 ADDITIONAL REVENUE REQUIREMENT (w/incentives) (Note C - Worksheet R) $ - 44 Projected SPP Base Plan Upgrades Revenue Requirement (WsP BPU Summary col (c) total and Note I) $ - 44a SPP Base Plan Upgrades Revenue Requirement Prior Year True-up Adjustment (Input) $ - 44b SPP Base Plan Upgrades Revenue Requirement Interest on Prior Year True-up Adjustment (Input) $ -

44c SPP Base Plan Upgrades Revenue Requirement (Amount Provided to SPP for Next Billing Period)(sum lines 44, 44a ,and 44b) $ - 45 PROJECTED REVENUE REQUIREMENT (ln 33 + ln 43 - ln 44c) $ -




**PROJECTED** Utilizing Projected Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY Data Sources Total RATE BASE CALCULATION (See "General Notes") Total Allocator Transmission Line (1) (2) (3) (4) (5) No.

46 GROSS PLANT IN SERVICE 47 Production (WsD.1 , Ln 6)

- NA


TP 0.00000 -


NA


W/S 0.00000 -


W/S 0.00000 -

52 TOTAL GROSS PLANT (sum lns 47 to 51) -

GP= 0.00000 -

53 ACCUMULATED DEPRECIATION 54 Production (WsD.1 , Ln 39)

- NA


TP 0.00000 -


NA


W/S 0.00000 -


W/S 0.00000 -

59 TOTAL ACCUMULATED DEPRECIATION (sum lns 54 to 58) -

-

60 NET PLANT IN SERVICE 61 Production (ln 47 - ln 54)

- NA

62 Transmission (ln 48 - ln 55) -

-

63 Distribution (ln 49 - ln 56) -

NA

64 General Plant (ln 50 - ln 57) -

-

65 Intangible Plant (ln 51 - ln 58) -

-

66 TOTAL NET PLANT IN SERVICE (sum lns 61 to 65) -

NP= 0.00000 -

67 ADJUSTMENTS TO RATE BASE (Note D) 68 Account No. 281 (enter negative) 273.8.k (Worksheet E)

- NA


DA -


DA -

71 Account No. 190 234.8.c (Worksheet E) -

DA -

72 Account No. 255 (enter negative) 267.8.h DA -

72.1 Account No. 254 Excess ADIT (Worksheet E) - DA -



Version 0.0.0 0.1.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 2 of 2 72.2 Account No. 182.3 Deficient ADIT (Worksheet E) - DA

- 73 Account No. 107 (WsQ , Ln 15, Col C)

- TP 0.00000

- 74 Net Pre-Funded AFUDC on CWIP included (Note E) (Worksheet Q, ln 30) - TP 0.00000

- in Rate Base (enter negative) 75 Unamortized Balance of Abandoned Incentive Plant (Note E) (Worksheet E)

- TP 0.00000

- 76 Unamortized Balance of Extraordinary Property Loss (Note E) (Worksheet E)

- TP 0.00000

-

77 TOTAL ADJUSTMENTS (sum lns 68 to 76) -

-

78 LAND HELD FOR FUTURE USE (Note F) (WsD , Ln 84, Col d)

- TP 0.00000

- 79 WORKING CAPITAL 80 CWC (Note G) 81 Materials & Supplies - Transmission (WsF , Ln 71, Col d)

- TP 0.00000

- 82 Materials & Supplies - Other (WsF , Ln 72, Col d)

- GP 0.00000

- 83 Prepayments (Account 165) Plant Related (WsF , Ln 12, Col d)

- GP 0.00000

- 84 Prepayments (Account 165) Labor Related (WsF , Ln 18, Col d)

- W/S 0.00000

- 85 Prepayments (Account 165) Transmission Related (WsF , Ln 23, Col d)

- TP 0.00000

- 86 Prepayments (Account 165) Other Not Allocated (WsF , Ln 31, Col d)

- NA 0.00000

-

87 TOTAL WORKING CAPITAL (sum lns 80 to 86) -

-

88 BALANCE OF NETWORK CREDITS (enter negative) (Note H)

- TP 0.00000

-

89 RATE BASE (sum lns 66, 77, 78, 87, 88) -

-




**PROJECTED** Utilizing Projected Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY EXPENSE, TAXES, RETURN & REVENUE Data Sources Total REQUIREMENTS CALCULATION (See "General Notes") Total Allocator Transmission Line (1) (2) (3) (4) (5) No.

90 OPERATION & MAINTENANCE EXPENSE 91 Transmission (WsG , Ln 34, Col c)

-





96 Transmission O&M Expense Adjustment (WsG , Ln 40, Col c) -

97 Transmission Subtotal (ln 91 - ln 92 + ln 93 + ln 94 - ln 95 + ln 96 ) -

TP 0.00000 -

98 Administrative and General (WsG , Ln 63, Col c)

-

99 Less: Acc. 928, Reg. Com. Exp. (WsG , Ln 53, Col c) -

100 Acct. 930.1, Gen. Advert. Exp. (WsG , Ln 55, Col c) -

101 Acct. 930.2, Miscellaneous Gen. Exp. (WsG , Ln 56, Col c) -

102 Acc. 924, Property Insurance (WsG , Ln 50, Col c) -



105 Acct. 928 - Transmission Specific (Note K) (WsH ln 21, col D) - DA 1.00000 -

106 Acct. 928 - Transmission Allocated (Note K) (WsH ln 21, col E) - TP 0.00000 -

106.1 Acct. 928 - SPS Wholesale Specific (Note K) (WsH ln 12, col F) - RC 0.00000 -

107 Acct. 930.2 - Transmission Specific (Note K) (WsH ln 33, col D) - TP 0.00000 -

108 Acct. 930.2 - Transmission Allocated (Note K) (WsH ln 33, col E) - W/S 0.00000 -

109 Transmission Safety and Siting Advertising (Note K) (WsH ln 46, col B) - TP 0.00000 -

110 -

111 A & G Subtotal (sum lns 103 to 109 less ln 110) -

-

112 TOTAL O & M EXPENSE (ln 97 + ln 111 )

-



-



Version 0.0.0 0.1.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 2 of 2 116 Plus: Recovery of Abandoned Incentive Plant (Note E) (Worksheet E) - TP 0.00000

- 117 Plus: Recovery of Extraordinary Property Loss (Note E) (Worksheet E) - TP 0.00000



-

120 TOTAL DEPRECIATION AND AMORTIZATION (sum lns 114 to 119) -

-

121 TAXES OTHER THAN INCOME (Note L) 122 Labor Related 123 Payroll (Worksheet J) 263.i - W/S 0.00000



- 127 Other Tax- Texas Use (Worksheet J) 263.i - GP 0.00000

-

128 TOTAL OTHER TAXES (sum lns 123 to 127) -

-

129 INCOME TAXES (Note M) 130 T=1 - {[(1 - SIT) * (1 - FIT)] / (1 - SIT * FIT * p)} = 0.00% 131 CIT=(T/1-T) * (1-(WCLTD/R)) = 0.00% 132 where WCLTD=(ln 160) and R= (ln 163) 133 and FIT, SIT & p are as given in Note M. 134 1 / (1 - T) = (from ln 130)

-

135 Amortized Investment Tax Credit (enter negative) (Worksheet J) 266.8.f -

135.1 (Excess)/Deficient ADIT Amortization - Plant (Note P) (Worksheet D.4)

-



136 Income Tax Calculation (ln 131 * ln 139)

-

- 137 ITC adjustment (ln 134 * ln 135) - NP 0.00000

- 137.1 (Excess)/Deficient ADIT Amortization - Plant (ln 134 * ln 135.1)

- DA 0.00000

- 137.2 (Excess)/Deficient ADIT Amortization - Non-

Plant (ln 134 * ln 135.2)

- DA 0.00000

- 138 TOTAL INCOME TAXES (sum lns 136 to 137.2)

-

- 139 RETURN (Rate Base * Rate of Return) (ln 89 * ln 163)

-


-

141 REVENUE REQUIREMENT (sum lns 112, 120, 128, 138, 139, 140) -

-


Att O-SPS Formula Rate, Cap Struc, Allocations, Projected, Table 5


**PROJECTED** Utilizing Projected Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY SUPPORTING CALCULATIONS Line (1) (2) (3) (4) (5) No.

142 TRANSMISSION PLANT INCLUDED IN OATT Transmission Rate (Note N) 143 Total transmission plant (ln 48)

- 144 Less Generator Step-up facilities (WsD.1 , Ln 145)

- 145 Less Radial Line facilities (Worksheet O)

-

146 Transmission plant included in OATT Trans Rate (ln 143 - ln 144 - ln 145) -

147 Percent of transmission plant in OATT Trans Rate (ln 146 / ln 143) TP= 0.00000 148 WAGES & SALARY ALLOCATOR (W/S) (Note O) 149 Production (WsG , Ln 69, Col e)

- NA

- 150 Transmission (WsG , Ln 70, Col e)

- TP 0.00000

- 151 Regional Market (WsG , Ln 71, Col e)

- NA

- 152 Distribution (WsG , Ln 72, Col e)

- NA

- 153 Other (WsG , Ln 73, Col e)

- NA

-


-

155 W/S Allocator W/S= 0.00000 155.1 REGULATORY COMMISSION EXPENSE FACTOR

(RC)

155.2 Transmission Network Load (WsC , Ln 14, Col f) - 155.3 Wholesale Transmission Network Load (WsC , Ln 42, Col c) - 155.4 Percent of BPU Rev Req charged to SPS Zone Input - 155.5 Wholesale Load Ratio Share (Ln 155.3/Ln 155.2) - 155.6 RC Factor 1/(Ln 155.3/Ln 155.2)*(1-(Ln 155.4*Ln 155.5)) RC= - 156 RETURN (R) $

157 Long Term Interest (Worksheet K, Ln 51, Col d) -

158 Preferred Dividends (Worksheet K, Ln 56, Col d) -


160 Long Term Debt (Worksheet K, Ln 17, Col o) - 0.00% 0.0000 0.0000 161 Preferred Stock (Worksheet K, Ln 5, Col o) - 0.00% 0.0000 0.0000 162 Common Stock (Worksheet K, Ln 9, Col o) - 0.00% 0.1050 0.0000


R 0.0000


Att O-SPS Formula Rate, Notes, Projected, Table 6


**PROJECTED** Utilizing Projected Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY General Notes: a) References to data from FERC Form 1 are indicated as: page#.line#.col.# Note Letter

A The revenues credited shall include amounts received directly from the SPP for service under this tariff reflecting SPS's integrated transmission facilities. Revenues associated with FERC annual charges, gross receipts taxes, ancillary services or other facilities revenues shall be excluded from the definition of transmission facilities under this tariff shall not be included as revenue credits. Revenue from coincident peak loads included in the DIVISOR are also not included as revenue credits unless this revenue is offset by a corresponding expense. See Worksheet B for details. B The annual and monthly net and gross plant carrying charges on page 2 are to be used to compute the revenue requirement for directly assigned facilities,any Base Plan Upgrades, distribution facilities, and radial lines. C This additional revenue requirement is determined using a net plant carrying charge (fixed carrying charge or FCR) approach. Worksheet R shows the calculation of the additional revenue requirements for each project receiving incentive rate treatment, as accepted by FERC by a separate docket. These individual additional revenue requirements shall be summed, for the then current year, and included here. D Reflects the transmission related portion of balances in Accounts 281, 282, 283, 190, and 255 as adjusted by any amounts in contra accounts identified as regulatory assets or liabilities related to FASB 106, 109, 133,158 or FASB Interpretation No. 48. Balance of Account 255 is reduced by prior flow throughs and completely excluded if the utility chose to utilize amortization of tax credits against taxable income as discussed in Note M. The calculation of ADIT for both the true-up and the annual projection will be performed in accordance with IRS regulation Section 1.167(l)-1(h)(6 The Annual True-Up for a given year will use the same methodology that was used to project that year’s rates. (Except for ADIT Proration which is

described on Table 21A of the template.) E Includes any incentive Construction Work in Progress (CWIP), any related Allowance for Funds Used During Construction (AFUDC), any unamortized balances related to the recovery of abandoned incentive plant costs, any extraordinary property losses and any related depreciation and amortization expense amounts. Formula amounts for all of the foregoing items will remain at $0 until approved by FERC under a separate docket. F Includes only transmission related or functionally booked as transmission land held for future use. G Cash Working Capital will be set at and remain $0 until such time as SPS files and receives FERC approval for a lead/lag study. H Equal to the balance of Network Facilities Upgrades Credits, net of accumulated depreciation, due transmission customers that made lump-sum payments towards the construction of Network Transmission Facilities consistent with Paragraph 657 of Order 2003-A. Excludes interest since interest is added to the revenue requirement on line 140. I The base plan upgrade revenue requirement will be updated annually in the Annual Update. The BPU revenue requirement will be a projected amount with a true-up to actual adjustment. The updated revenue requirement will be provided to the SPP no later than November 15 for billings effective January 1. J (Reserved for future use) K Includes all Regulatory Commission expense itemized in FERC Form 1 at 351.h. Show in Worksheet H how these expense items are assigned to transmission. FERC Assessment Fees, General Advertising, and Industry Association Dues and Research and Developments costs recorded in 930.2 shall not be assigned to transmission. A & G expenses shall Include specific transmission safety-related advertising and transmission siting advertising costs. The annual PBOP expense amount will be based on the PBOP expense amount reported in SPS’s most recent annual actuarial valuation report as of the date of SPS’s Annual Update. SPS will provide a copy of that actuarial report as part of its Annual Update and its Annual Informational Filing to the

Commission. NERC fees recorded in Acct. 928, Regulatory Commission Expenses, or in Acct. 165, Prepayments, shall be excluded from the formula. L Includes only FICA, unemployment, highway, property and other assessments charged in the current year. Gross receipts tax, taxes related to income, retail and non-transmission related taxes are excluded. M The currently effective income tax rate, where FIT is the Federal income tax rate; SIT is the State income tax rate, and p = "the percentage of federal income tax deductible for state income taxes". If the utility is taxed in more than one state, it must attach a work paper showing the name of each state and how the blended or composite SIT was developed. Furthermore, a utility that elected to utilize amortization of tax credits against taxable income, rather than book tax credits to Account No. 255 and reduce rate base, must reduce its income tax expense by the amount of the Amortized Investment Tax Credit (Form 1, 266.8.f) (ln 135) multiplied by (1/1-T) . If the applicable tax rates are zero enter 0. Inputs Required: FIT = 0.00% SIT= (Worksheet L) 0.00% (State Income Tax Rate or Composite SIT) p = 0.00% (percent of FIT deductible for state purposes) N Removes the dollars of plant booked to transmission plant that is excluded from the Tariff because it does not meet the Tariff's definition of Transmission Facilities, or is booked to transmission (e.g. step-up transformers) that is included in the development of OATT ancillary service rates, or is otherwise not eligible to be recovered under this Tariff. O Enter dollar amounts. Includes service company labor. Does not include contract labor. P Includes the amortization of any excess/deficient deferred income taxes resulting from changes to income tax laws, income tax rates (including changes



Att O-SPS Formula Rate, Revenue Rqmt, Actual, Table 7


**ACTUAL** Utilizing FERC Form 1 Actual Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY (1) (2) (3) (4) (5) Line Transmission No. Amount

164 REVENUE REQUIREMENT (w/o incentives) (ln 277) $ - 165 REVENUE CREDITS (Note A) Total Allocator

166 Account No. 454 (Worksheet B) - DA 1.00000 $ - 167 Account No. 456.1 (Worksheet B) - DA 1.00000 - 167.1 Account No. 421.1 (or other applicable acct) (Worksheet B) - DA 1.00000 - 167.2 Account No. 456.0 (Worksheet B) - DA 1.00000 -

168 Total Revenue Credits $ -

169 NET REVENUE REQUIREMENT (w/o incentives) (ln 164 less ln 168) $ - 170 NET PLANT CARRYING CHARGE (w/o incentives) (Note B) 171 Annual Rate (ln 169 / ln 198 x 100) 0.00% 172 Monthly Rate (ln 171 / 12) 0.00% 173 GROSS PLANT CARRYING CHARGE (w/o incentives) (Note B) 174 Annual Rate (ln 169 / ln 184 x 100) 0.00% 175 NET PLANT CARRYING CHARGE, W/O DEPRECIATION (w/o incentives) (Note B) 176 Annual Rate ( (ln 169 - ln 250 ) / ln 198 x 100) 0.00% 176.1 BPU Depreciation Rate (ln 250 / ln 184) 0.00% 177 NET PLANT CARRYING CHARGE, W/O DEPRECIATION, INCOME TAXES AND RETURN (Note B) 178 Annual Rate ( (ln 169 - ln 250 - ln 274 - ln 275) / ln 198 x 100) 0.00% 179 ADDITIONAL REVENUE REQUIREMENT (w/incentives) (Note C - Worksheet R) $ - 180 LESS SPP Base Plan Upgrades Revenue Requirement (WsP BPU Summary col (d) total and Note I) $ - 181 ACTUAL REVENUE REQUIREMENT (ln 169 + ln 179 - ln 180) $ -




**ACTUAL** Utilizing FERC Form 1 Actual Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY Data Sources Total RATE BASE CALCULATION (See "General Notes") Total Allocator Transmission Line (1) (2) (3) (4) (5) No.

182 GROSS PLANT IN SERVICE 183 Production (WsD.1 , Ln 78) - NA 184 Transmission (WsD.1 , Ln 83) - TP 0.00000



-

188 TOTAL GROSS PLANT (sum lns 183 to 187) - GP= 0.00000 -

189 ACCUMULATED DEPRECIATION 190 Production (WsD.1 , Ln 110) - NA 191 Transmission (WsD.1 , Ln 115) - TP 0.00000



-

195 TOTAL ACCUMULATED DEPRECIATION (sum lns 190 to 194) - -

196 NET PLANT IN SERVICE 197 Production (ln 183 - ln 190) - NA 198 Transmission (ln 184 - ln 191) -

- 199 Distribution (ln 185 - ln 192) - NA 200 General Plant (ln 186 - ln 193) -

- 201 Intangible Plant (ln 187 - ln 194) -

-

202 TOTAL NET PLANT IN SERVICE (sum lns 197 to 201) - NP= 0.00000 -

203 ADJUSTMENTS TO RATE BASE (Note D) 204 Account No. 281 (enter negative) 273.8.k (Worksheet E) - NA 205 Account No. 282 (enter negative) 275.2.k (Worksheet E) - DA

- 206 Account No. 283 (enter negative) 277.9.k (Worksheet E) - DA

- 207 Account No. 190 234.8.c (Worksheet E) - DA

- 208 Account No. 255 (enter negative) 267.8.h DA

- 208.1 Account No. 254 Excess ADIT (Worksheet E) - DA

- 208.2 Account No. 182.3 Deficient ADIT (Worksheet E) - DA

- 209 Account No. 107 (WsQ , Ln 46, Col C) - TP 0.00000

- 210 Net Pre-Funded AFUDC on CWIP included in Rate Base (Note E) (Worksheet Q, ln 61) - TP 0.00000

- (enter negative)



Version 0.0.0 0.1.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 2 of 2 211 Unamortized Balance of Abandoned Incentive Plant (Note E) (Worksheet E) - TP 0.00000

- 212 Unamortized Balance of Extraordinary Property Loss (Note E) (Worksheet E) -

-

213 TOTAL ADJUSTMENTS (sum lns 204 to 212) - -

214 LAND HELD FOR FUTURE USE (Note F) (WsD , Ln 84, Col h) - TP 0.00000

- 215 WORKING CAPITAL 216 CWC (Note G)

- 217 Materials & Supplies - Transmission (WsF , Ln 79, Col d) - TP 0.00000

- 218 Materials & Supplies - Other (WsF , Ln 80, Col d) - GP 0.00000

- 219 Prepayments (Account 165) Plant Related (WsF , Ln 42, Col d) - GP 0.00000

- 220 Prepayments (Account 165) Labor Related (WsF , Ln 48, Col d) - W/S 0.00000

- 221 Prepayments (Account 165) Transmission Related (WsF , Ln 53, Col d) - TP 0.00000

- 222 Prepayments (Account 165) Other Not Allocated (WsF , Ln 61, Col d) - NA 0.00000

-

223 TOTAL WORKING CAPITAL (sum lns 216 to 222) - -

224 BALANCE OF NETWORK CREDITS (enter negative) (Note H) - TP 0.00000

-

225 RATE BASE (sum lns 202, 213, 214, 223, 224) - -




**ACTUAL** Utilizing FERC Form 1 Actual Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY EXPENSE, TAXES, RETURN & REVENUE Data Sources Total REQUIREMENTS CALCULATION (See "General Notes") Total Allocator Transmission Line (1) (2) (3) (4) (5) No.

226 OPERATION & MAINTENANCE EXPENSE 227 Transmission (WsG , Ln 34, Col e) - 228 Less Total Account 561 (WsG , Ln 36, Col e) - 229 Add Back Account 561.6 (WsG , Ln 37, Col e) - 230 Add Back Account 561.7 (WsG , Ln 38, Col e) - 231 Less Total Account 565 (WsG , Ln 39, Col e) - 232 Transmission O&M Expense Adjustment (WsG , Ln 40, Col e) -

233 Transmission Subtotal (ln 227 - ln 228 + ln 229 + ln 230 - ln 231 + ln 232 ) - TP 0.00000 -

234 Administrative and General (WsG , Ln 63, Col e) - 235 Less: Acc. 928, Reg. Com. Exp. (WsG , Ln 53, Col e) - 236 Acct. 930.1, Gen. Advert. Exp. (WsG , Ln 55, Col e) - 237 Acct. 930.2, Miscellaneous Gen. Exp. (WsG , Ln 56, Col e) - 238 Acc. 924, Property Insurance (WsG , Ln 50, Col e) -



241 Acct. 928 - Transmission Specific (Note K) (WsH , Ln 21, Col H) - DA 1.00000 -

242 Acct. 928 - Transmission Allocated (Note K) (WsH , Ln 21, Col I) - TP 0.00000 -

242.1 Acct. 928 - SPS Wholesale Specific (Note K) (WsH , Ln 12, Col K) - RC 0.00000 -

243 Acct. 930.2 - Transmission Specific (Note K) (WsH , Ln 33, Col H) - TP 0.00000 -

244 Acct. 930.2 - Transmission Allocated (Note K) (WsH , Ln 33, Col I) - W/S 0.00000 -

245 Transmission Safety and Siting Advertising (Note K) (WsH , Ln 46, Col C) - TP 0.00000 -

246 -

247 A & G Subtotal (sum lns 239 to 246) - -

248 TOTAL O & M EXPENSE (ln 233 + ln 247 ) -



- 252 Plus: Recovery of Abandoned Incentive Plant (Note E) (Worksheet E) - TP 0.00000

- 253 Plus: Recovery of Extraordinary Property

Loss (Note E) (Worksheet E) - TP 0.00000



-

256 TOTAL DEPRECIATION AND AMORTIZATION (sum lns 250 to 255) - -



Version 0.0.0 0.1.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 2 of 2 257 TAXES OTHER THAN INCOME (Note L)

258 Labor Related 259 Payroll (Worksheet J) 263.i - W/S 0.00000



- 263 Other Tax- Texas Use (Worksheet J) 263.i - GP 0.00000

-

264 TOTAL OTHER TAXES (sum lns 259 to 263) - -

265 INCOME TAXES (Note M) 266 T=1 - {[(1 - SIT) * (1 - FIT)] / (1 - SIT * FIT * p)} = 0.00% 267 CIT=(T/1-T) * (1-(WCLTD/R)) = 0.00% 268 where WCLTD=(ln 296) and R= (ln 299) 269 and FIT, SIT & p are as given in Note M. 270 1 / (1 - T) = (from ln 266) - 271 Amortized Investment Tax Credit (266.8.f) (Worksheet J) 266.8.f - (enter negative) 271.1 (Excess)/Deficient ADIT Amortization - Plant (Note P) (Worksheet D.4)

-



272 Income Tax Calculation (ln 267 * ln 275) - -

273 ITC adjustment (ln 270 * ln 271) - NP 0.00000 -

273.1 (Excess)/Deficient ADIT Amortization - Plant (ln 270 * ln 271.1) -

DA 0.00000 -


(ln 270 * ln 271.2) -

DA 0.00000 -

274 TOTAL INCOME TAXES (sum lns 272 to 273.2) -

- 275 RETURN (Rate Base * Rate of Return) (ln 225 * ln 299) -


-

277 REVENUE REQUIREMENT (sum lns 248, 256, 264, 274, 275, 276) - -




**ACTUAL** Utilizing FERC Form 1 Actual Data

For the Billing Period 01/01/yy to 12/31/yy


SUPPORTING CALCULATIONS

Line (1) (2) (3) (4) (5)

No.

278 TRANSMISSION PLANT INCLUDED IN OATT Transmission Rate (Note N)

279 Total transmission plant (ln 184) -

280 Less Generator Step-up facilities (WsD.1 , Ln 147) -

281 Less Radial Line facilities (Worksheet O) -

281a Plus Radial Line facilities true-up (Worksheet M) -

282 Transmission plant included in OATT Trans Rate (ln 279 - ln 280 - ln 281-281a) -

283 Percent of transmission plant in OATT Trans Rate (ln 282 / ln 279) TP= 0.00000

284 WAGES & SALARY ALLOCATOR (W/S) (Note O)

285 Production (WsG , Ln 69, Col i) -

NA -

286 Transmission (WsG , Ln 70, Col i) -

TP 0.00000 -

287 Regional Market (WsG , Ln 71, Col i) -

NA -

288 Distribution (WsG , Ln 72, Col i) -

NA -

289 Other (WsG , Ln 73, Col i) -

NA -


-

291 W/S Allocator W/S= 0.00000

291.1 REGULATORY COMMISSION EXPENSE FACTOR (RC)

291.2 Transmission Network Load (WsC , Ln 28, Col f) -

291.3 Wholesale Transmission Network Load (WsC , Ln 42, Col d) -

291.4 Percent of BPU Rev Req charged to SPS Zone Input -

291.5 Wholesale Load Ratio Share (Ln 291.3/Ln 291.2) -

291.6 RC Factor 1/(Ln 291.3/Ln 291.2)*(1-(Ln 291.4*Ln 291.5)) RC= -

292 RETURN (R) $

293 Long Term Interest (Worksheet K, Ln 51, Col h) -

294 Preferred Dividends (Worksheet K, Ln 56, Col h) -


296 Long Term Debt (Worksheet K, Ln 36, Col o) -

0.00% 0.0000 0.0000

297 Preferred Stock (Worksheet K, Ln 23, Col o) -

0.00% 0.0000 0.0000



Version 0.0.0 0.1.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 2 of 2 298 Common Stock (Worksheet K, Ln 27, Col o)

- 0.00% 0.1050 0.0000


R 0.0000


Att O-SPS Formula Rate, Notes, Actual, Table 11

Version 0.2.0 0.3.0 Proposed Effective Date: 1/1/2019 2/1/2019 Page 1 of 1

Rate Formula Template Table 11 **ACTUAL** Utilizing FERC Form 1 Actual Data For the Billing Period 01/01/yy to 12/31/yy SOUTHWESTERN PUBLIC SERVICE COMPANY General Notes: a) References to data from FERC Form 1 are indicated as: page#.line#.col.# Note Letter

A The revenues credited shall include amounts received directly from the SPP for service under this tariff reflecting SPS's integrated transmission facilities. Revenues associated with FERC annual charges, gross receipts taxes, ancillary services or other facilities revenues shall be excluded from the definition of transmission facilities under this tariff shall not be included as revenue credits. Revenue from coincident peak loads included in the DIVISOR are also not included as revenue credits unless this revenue is offset by a corresponding expense. See Worksheet B for details. B The annual and monthly net and gross plant carrying charges on page 7 are to be used to compute the revenue requirement for directly assigned facilities, any Base Plan Upgrades, distribution facilities, and radial lines. C This additional revenue requirement is determined using a net plant carrying charge (fixed carrying charge or FCR) approach. Worksheet R shows the calculation of the additional revenue requirements for each project receiving incentive rate treatment, as accepted by FERC by a separate docket. These individual additional revenue requirements shall be summed, for the then current year, and included here. D Reflects the transmission related portion of balances in Accounts 281, 282, 283, 190, and 255 as adjusted by any amounts in contra accounts identified as regulatory assets or liabilities related to FASB 106, 109, 133,158 or FASB Interpretation No. 48. Balance of Account 255 is reduced by prior flow throughs and completely excluded if the utility chose to utilize amortization of tax credits against taxable income as discussed in Note M.

The calculation of ADIT for both the true-up and the annual projection will be performed in accordance with IRS regulation Section 1.167(l)-1(h)(6). The Annual True-Up for a given year will use the same methodology that was used to project that year’s rates. (Except for ADIT Proration which is described on Table 21A of the template.)

E Includes any incentive Construction Work in Progress (CWIP), any related Allowance for Funds Used During Construction (AFUDC), any unamortized balances related to the recovery of abandoned incentive plant costs, any extraordinary property losses and any related depreciation and amortization expense amounts. Formula amounts for all of the foregoing items will remain at $0 until approved by FERC under a separate docket. F Includes only transmission related or functionally booked as transmission land held for future use. G Cash Working Capital will be set at and remain $0 until such time as SPS files and receives FERC approval for a lead/lag study. H Equal to the balance of Network Facilities Upgrades Credits, net of accumulated depreciation, due transmission customers that made lump-sum payments towards the construction of Network Transmission Facilities consistent with Paragraph 657 of Order 2003-A. Excludes interest since interest is added to the revenue requirement on line 276. I The base plan upgrade revenue requirement will be updated annually in the Annual Update. The BPU revenue requirement will be a projected amount with a true-up to actual adjustment. The updated revenue requirement will be provided to the SPP no later than November 15 for billings effective January 1. J (Reserved for future use) K Includes all Regulatory Commission expense itemized in FERC Form 1 at 351.h. Show in Worksheet H how these expense items are assigned to transmission. FERC Assessment Fees, General Advertising, and Industry Association Dues and Research and Developments costs recorded in 930.2 shall not be assigned to transmission. A & G expenses shall Include specific transmission safety-related advertising and transmission siting advertising costs. The annual PBOP expense amount will be based on the PBOP expense amount reported in SPS’s most recent annual actuarial valuation report as of the date of SPS’s Annual Update. SPS will provide a copy of that actuarial report as part of its Annual Update and its Annual Informational Filing to the

Commission. NERC fees recorded in Acct. 928, Regulatory Commission Expenses, or in Acct. 165, Prepayments, shall be excluded from the formula. L Includes only FICA, unemployment, highway, property and other assessments charged in the current year. Gross receipts tax, taxes related to income, retail and non-transmission related taxes are excluded. M The currently effective income tax rate, where FIT is the Federal income tax rate; SIT is the State income tax rate, and p = "the percentage of federal income tax deductible for state income taxes". If the utility is taxed in more than one state, it must attach a work paper showing the name of each state and how the blended or composite SIT was developed. Furthermore, a utility that elected to utilize amortization of tax credits against taxable income, rather than book tax credits to Account No. 255 and reduce rate base, must reduce its income tax expense by the amount of the Amortized Investment Tax Credit (Form 1, 266.8.f) (ln 271) multiplied by (1/1-T) . If the applicable tax rates are zero enter 0. Inputs Required: FIT = 0.00% SIT= (Worksheet L) 0.00% (State Income Tax Rate or Composite SIT) p = 0.00% (percent of FIT deductible for state purposes) N Removes the dollars of plant booked to transmission plant that is excluded from the Tariff because it does not meet the Tariff's definition of Transmission Facilities, or is booked to transmission (e.g. step-up transformers) that is included in the development of OATT ancillary service rates,or is otherwise not eligible to be recovered under this Tariff. O Enter dollar amounts. Includes service company labor. Does not include contract labor. P Includes the amortization of any excess/deficient deferred income taxes resulting from changes to income tax laws, income tax rates (including changes




Version 0.0.0 0.1.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 1 of 2 Southwestern Public Service Company Worksheet C

Worksheet C - Divisor Table 18 I. Transmission Network Load (mW) Projected for Billing Year = 20yy

Line No. Month Network Load1 Plus: Intertie Demand2 TO's Transmission Network Load

1 0

2 0

3 0

4 0

5 0

6 0

7 0

8 0

9 0

10 0

11 0

12 0

13 Total 0 0 0

14 12-CP 0 0 0

II. Transmission Network Load (mW) Actual for Billing Year = 20yy

Line No. Month, Day and Year1 Hour Ending1 Network Load1 Plus: Intertie Demand2 TO's Transmission Network Load

15 0

16 0

17 0

18 0

19 0

20 0

21 0

22 0

23 0

24 0

25 0

26 0

27 Total 0 0 0

28 12-CP 0 0 0

III. Notes 1 These are the dates, hour ending and loads at the time of the transmission peak, as reported in FERC Form 1, page 400. 2 Reserved capacity associated with SPS-Public Service Company of Colorado Intertie. IV. Firm Network Service for Others (mW) for Billing Year = 20yy

Line No. Month Projected

Wholesale Load

Actual Wholesale Load3

29 January

30 February

31 March

32 April

33 May

34 June

35 July

36 August

37 September

38 October



Version 0.0.0 0.1.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 2 of 2 39 November

40 December

41 Total

42 12 Month Average

V. Notes 3 These are the Wholesale Loads by month, as reported in FERC Form 1, page 400.



Version 0.0.0 0.1.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 1 of 2 Southwestern Public Service Company Worksheet D

Worksheet D Average Rate Base Table 19 Inputs for Average Rate Base Calculations Year = 20yy Year = 20yy Line (a) (b) (c) (d) (e) (f) (g) (h) No. Projected Projected Projected References for Actual Actual Actual Beg of Year End of Year Average Beg of Year End of Year Average Balance Balance Balance Actual Data Balance Balance Balance 1 Deferred Taxes - Account 281 2 0 0 3 0 0 4 0 0 5 0 0 6 0 0 7 0 0

8 Total Account 281 0 0 0 FF1, p273 (acct not currently used) 0 0 0

9 10 Deferred Taxes - Account 282 11 12 0 0 13 0 0 14 0 0 15 0 0 16 0 0 17 0 0 18 0 0 19 0 0 20 Excess ADIT 0 0 21 FAS 109 Plant Excess ADIT –

Protected 0 0


0 0


24 25 Deferred Taxes - Account 283 26 0 0 27 0 0 28 0 0 29 0 0 30 0 0 31 0 0 32 0 0 33 0 0 34 0 0 35 0 0


37 38 Deferred Taxes - Account 190 39 0 0 40 0 0 41 0 0 42 0 0 43 0 0 44 0 0 45 0 0 46 0 0 47 0 0 48 0 0 49 0 0 50 0 0 51 0 0 52 0 0 53 0 0 54 0 0



Version 0.0.0 0.1.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 2 of 2 55 0 0

56 0 0 57 0 0 58 0 0 59 0 0 60 0 0 61 0 0 62 0 0 63 0 0 64 Deficient ADIT 0 0 65 FAS 109 Plant Deficient ADIT –

Protected 0 0


0 0

67 Total Account 190 0 0 0 FF1, p 234, ln 18, col c 0 0 0

68

69 Total Deferred Taxes 0 0

70 71 Unamortized Balance of Abandoned Incentive Plant 72 (See Formula Template Note E found on pages 6 and 11.) 73 0 0 74 0 0

75 Total Abandoned Incentive Plant 0 0 0 Company Records 0 0 0

76 77 Unamortized Balance of Extraordinary Property Loss (Note E) 78 (See Formula Template Note E found on pages 6 and 11.) 79 0 0 80 0 0

81 Total Extraordinary Property Loss 0 0 0 Company Records 0 0 0

82 83

84 Land Held for Future Use 0 FF1, p 214 0




Southwestern Public Service Company WsD.2 ADIT Proration Factor

Accumulated Deferred Income Taxes Proration Factor Table 21A

Rate Year=

Line No.

1 Account 282 – Liberalized Depreciation-Transmission




4


Number of Days

Remaining in Year After

Month’s Accrual of Deferred

Taxes

Total Days

in Futur

e Portion of Test Perio

d






Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



5


7 January

8 February

9 March

10 April

11 May

12 June

13 July

14 August

15 September

16 October

17 November

18 December

19 Total

20

21



Version 0.1.0 0.2.0 Proposed Effective Date: 1/1/2019 2/1/2019 Page 2 of 12 22

23




27

28

29 Account 282 – Liberalized Depreciation-General and Intangible




32


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



33


35 January

36 February

37 March

38 April

39 May

40 June

41 July

42 August

43 September

44 October

45 November

46 December

47 Total

48




50

51




55

56

57 Account 283 – Liberalized Depreciation-Software




60


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



61


63 January

64 February

65 March

66 April

67 May

68 June

69 July

70 August

71 September

72 October

73 November

74 December

75 Total




77

78

79




83

84

85 Account 190 – Basis Difference-Transmission




88


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



89


91 January

92 February

93 March

94 April

95 May

96 June

97 July

98 August

99 September

100 October

101 November

102 December



Version 0.1.0 0.2.0 Proposed Effective Date: 1/1/2019 2/1/2019 Page 5 of 12 103 Total

104

105

106

107




111

112

113 Account 190 – Basis Difference-General and Intangible




116


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



117


119 January

120 February

121 March

122 April

123 May

124 June

125 July

126 August

127 September

128 October

129 November



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131 Total

132

133

134

135




139

140

141 Account 190 – Basis Difference-CIAC Transmission




144


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



145


147 January

148 February

149 March

150 April

151 May

152 June

153 July

154 August

155 September

156 October

157 November



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159 Total

160

161

162

163




167

168

169 Account 190 – Basis Difference-CIAC General




172


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



173


175 January

176 February

177 March

178 April

179 May

180 June

181 July

182 August

183 September

184 October



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186 December

187 Total

188

189

190

191




195

196

197 Account 190 – Federal Only NOL-Transmission




200


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



201


203 January

204 February

205 March

206 April

207 May

208 June

209 July

210 August

211 September



Version 0.1.0 0.2.0 Proposed Effective Date: 1/1/2019 2/1/2019 Page 9 of 12 212 October

213 November

214 December

215 Total

216

217

218

219




223

224

225 Account 190 – Federal Only NOL-General




228


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



229


231 January

232 February

233 March

234 April

235 May

236 June

237 July

238 August



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240 October

241 November

242 December

243 Total

244

245

246

247




251

252

253

254

255 Account 182 – Excess ADIT Federal Only NOL - Transmission




258


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



259


261 January

262 February

263 March

264 April

265 May



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267 July

268 August

269 September

270 October

271 November

272 December

273 Total

274

275

276

277




281

282

283 Account 182 – Excess ADIT Federal Only NOL - General




286


Number of Days

Remaining in Year


of Deferred

Taxes







Actual

Monthly Activity


activity (See Note

1)

Preserve proration

when actual

monthly and

projected monthly



2)


activity when




3)






4)



287


289 January

290 February

291 March

292 April

293 May

294 June



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296 August

297 September

298 October

299 November

300 December

301 Total

302

303

304

305




Notes: 1) Column J is the difference between projected monthly and actual monthly activity (Column I minus Column F). Specifically, if projected and actual

activity are both positive, a negative in Column J represents over-projection (amount of projected activity that did not occur) and a positive in Column J

represents under-projection (excess of actual activity over projected activity). If projected and actual activity are both negative, a negative in Column J

represents under-projection (excess of actual activity over projected activity) and a positive in Column J represents over-projection (amount of projected

activity that did not occur).

2) Column K preserves proration when actual monthly and projected monthly activity are either both increases or decreases. Specifically, if Column J

is over-projected, enter Column G x [Column I/Column F]. If Column J is under-projected, enter the amount from Column G and complete Column L). In other

situations, enter zero.

3) Column L applies when (1) Column J is under-projected AND (2) actual monthly and projected monthly activity are either both increases or

decreases. Enter the amount from Column J. In other situations, enter zero.

4) Column M applies when (1) projected monthly activity is an increase while actual monthly activity is a decrease OR (2) projected monthly activity is

a decrease while actual monthly activity is an increase. Enter actual monthly activity (Col I). In other situations, enter zero.

5) Column N is computed by adding the prorated monthly activity, if any, from Column K to 50 percent of the portion of monthly activity, if any, from

Column L or M to the balance at the end of the prior month. The activity in columns L and M is multiplied by 50 percent to reflect averaging of rate base to the

extent that the proration requirement has not been applied to a portion of the monthly activity.

6) The methodology to remove double averaging from the true-up ADIT Proration calculation is effective June 27, 2018.



Version 0.0.0 Proposed Effective Date: 2/1/2019 Page 1 of 3


Worksheet D.3 Non-Plant Excess ADIT

Inputs for Average Rate Base Calculations

Year = 20yy

Year = 20yy

Line (a)

(b) (c) (d) (e) (f) (g) (h) (i) (j)

No.

Projected Projected Projected

Avg.

References Actual Actual Actual Avg.

Beg of Year

End of Year Balance ADIT for

Beg of Year

End of Year Balance ADIT

Balance Balance (b+c)/2 Amortization

Actual Data Balance Balance (f+g)/2 Amortization

1 Excess Deferred Taxes - Assets Account 254 (note 1)

2 3

4 5 6 7 8 9 10 11

12

-

- 13 Excess ADIT Liabilities Subject to Proration

Excess ADIT Liabilities Subject to Proration

14

-

- 15

-

-

16 Total Account 254

0 0 - 0 0 0 0 0

17 18 Acct 254 Gross Up

Worksheet D.3 Table 21B




19

20 Total Acct 254 Grossed Up

0 0


21

22 Excess Deferred Taxes - Assets Account 182.3 (Note 2)

23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50




Note 1: All Excess ADIT Balances recorded in FERC Account 254 are unprotected Note 2: The Deficient ADIT balance associated with prior Net Operating Loss deferred tax assets are protected. The other Deficient ADIT items in FERC Account 182.3 are unprotected.

51

-

- 52

-

-

53 Excess ADIT Assets Subject to Proration

Excess ADIT Assets Subject to Proration

54 55 56

57

-

- 58

-

-

59

-

- 60

-

-

61 Total Account 182.3

0 0 0 0

0 0 0 0

62 63 Acct 182.3 Gross Up

64

65 Total Acct 182.3 Grossed Up

0 0






Worksheet D.4


Table 21C

Plant Excess ADIT Amortization, Projected for Billing Year = 20yy

(a) (b) (c) (d) (e) (f) (g) (h)

Retail, Production


& Other





d Relate


2)

Subtotal




Version 0.0.0 Proposed Effective Date: 2/1/2019 Page 2 of 5 Total



Non-Plant Excess ADIT Amortization, Projected for Billing Year = 20yy

(a) (b) (c) (d) (e) (f) (g) (h)

Retail, Production


& Other





d Relate


2)




Subtotal


Total



Plant Excess ADIT Amortization, Actual for Billing Year = 20yy

(a) (b) (c) (d) (e) (f) (g) (h)

Retail, Production


& Other





d Relate


2)




Subtotal


Total



Non-Plant Excess ADIT Amortization, Actual for Billing Year = 20yy

(a) (b) (c) (d) (e) (f) (g) (h)

Retail, Production


& Other Transmission

Plant Labor



1) Related Related

Related

Related (d)+(e)+(f)

Period (Note 2)




Subtotal


Total

Note 1: Excess and Deficient ADIT is amortized to FERC Accounts 410.1 and 411.1

Note 2: The amortization of Excess and Deficient ADIT balances began January 1, 2018



Version 0.1.0 0.2.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 1 of 3 Southwestern Public Service Company Worksheet E

Worksheet E - Rate Base Adjustments Table 22 ADIT Account 281 Projected for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production 100% Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

281 -

281 -

281 -

281 -

281 -


-

-

-

-



Total -

-

-

-

-


Total 0 0 0 0 0

ADIT Account 282 Projected for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production 100% Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

282 -

282 -

282 -

282 -

282 -


282 FAS 109 Plant Excess ADIT – Unprotected -


-

-

-

-





Total -

-

-

-

-


Total 0 0 0 0 0





283 -

283 -

283 -

283 -

283 -

283 -

283 -

283 -

283 -

283 -

283 -


-

-

-

-




Total -

-

-

-

-


Total 0 0 0 0 0


254 -

254 -

254 -

254 -

254 -




-

254 -


-

-

-

-

-

-

-

-


-

-

-

-


Total -

-

-

-

-


Total 0 0 0 0 0




Worksheet E - Rate Base Adjustments Table 23 ADIT Account 190 Projected for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production 100% Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -


190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 -

190 FAS 109 Plant Deficient ADIT - PUnprotected

-

190 FAS 109 Plant Deficient ADIT - Unprotected



Version 0.1.0 0.2.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 2 of 3 Subtotal - Form 1, p234 Projected

- -

-

-

-





Proration Adjustment – Transmission NOL (from wsD.2)


Total -

-

-

-

-


Total 0 0 0 0 0

ADIT Account 182.3 Projected for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -


-

-

-

-

-

-

-

-


-

-

-

-



Total - - - - -


Total 0 0 0 0 0




Unamortized Balance of Abandoned Incentive Plant Projected for Billing Year = 20yy (A) (B) (C) (D) (E) Average Unamortized Unamortized Current Year Balance Balance Amortization End of Acc. No. Identification from WsD Expense Current Year

-

-

-

-

Total -

-

-

Unamortized Balance of Extraordinary Property Loss Projected for Billing Year = 20yy (A) (B) (C) (D) (E) Average Unamortized Unamortized Current Year Balance Balance Amortization End of Acc. No. Identification from WsD Expense Current Year

-

-

-

-

Total -

-

-




Worksheet E - Rate Base Adjustments Table 24 ADIT Account 281 Actual for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production 100% Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

281 -

281 -

281 -


-

-

-

-



Total -

-

-

-

-


Total 0 0 0 0 0

ADIT Account 282 Actual for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production 100% Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

282 -

282 -

282 -



-


-

-

-

-





Total -

-

-

-

-


Total 0 0 0 0 0

ADIT Account 283 Actual for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production 100% 0 0 Total Included Avg Balance & Other Transmission Plant Labor in Ratebase



Version 0.1.0 0.2.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 2 of 4 Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

283 -

283 -

283 -

283 -


-

-

-

-




Total -

-

-

-

-


Total 0 0 0 0 0


254 -

254 -

254 -

254 -

254 -

254 -

254 -


-

-

-

-

-

-

-

-

Subtotal - Actual -

-

-

-

-


Total -

-

-

-

-


Total 0 0 0 0 0




ADIT Account 190 Actual for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production 100% Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

190 -

190 -

190 -

190 -

190 FAS 109 Plant Deficient ADIT – PUnprotected

-



-

-

-

-







Total -

-

-

-

-


Total 0 0 0 0 0

ADIT Account 182.3 Actual for Billing Year = 20yy (A) (B) (C) (D) (E) (F) (G) (H) (I) Retail, Production Total Included Avg Balance & Other Transmission Plant Labor in Ratebase Acc. No. Identification from WsD Related Related Related Related (E)+(F)+(G) Description

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -

182.3 -


-

-

-

-



Version 0.1.0 0.2.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 4 of 4 -

-

-

-

Subtotal - Actual -

-

-

-

-



Total - - - - -

Transmission Allocator [ TP, GP or W/S ] 0.0000% 0.0000% 0.0000% 0.0000% 0

Total 0 0 0 0 0


Att O-SPS Formula Rate, Wksht H, Misc Expenses, Table 28


11 12 13 Acct 930.2 Projected for Billing Year = 20yy Acct 930.2 Actual for Billing Year = 20yy 14 (A) (B) (C) (D) (E) (F) (G) (H) (I) 15 16 17 18 19 20 21 212 Total 930.2

- -

-

-

- -

-

-

22 23 24 Transmission Safety & Siting Advertising (Other

Than in Acct 930.1) Projected for Year = 20yy Actual Transmission Safety & Siting for Year = 20yy

25 in Acct 930.1) Projected for Year = 20yy Actual Transmission Safety & Siting for Year = 20yy 26 27 (A) (B) (C) (E) (F) 28 Description Expense Expense 29 30 31 32 3327 3428 3529 3630 Total Transmission Safety & Siting Adv.

- -

Southwestern Public Service Company Worksheet H Worksheet H - Miscellaneous Expenses Table 28 Projected Actual Line No. 1 Acct 928 Projected for Billing Year = 20yy Acct 928 Actual for Billing Year = 20yy 2 (Aa) (Bb) (Cc) (Dd) (Ee) (f) (gF) (hG) (iH) (jI) (k) (l) 3 100% 100% 100% 100% 4 Non- Transmission Transmission SPS Wholesale Non- Transmission Transmission SPS Wholesale 5 Description Expense Transmission Specific Allocated Specific Expense Transmission Specific Allocated Specific Explanation 6 7 8 9 10 Total 928

- -

-

- - -

-

-

-

-




Southwestern Public Service Company Worksheet P

Worksheet P - Revenue Requirement for Base Plan Upgrades, Service Upgrades, Sponsored Upgrades and Generator

Table 36

I.

Determine the Revenue Requirement for Base Plan Upgrades, Service Upgrades, Sponsored Upgrades and

Generator Interconnection Facilities.

Line

No.

1

SUMMARY OF BPU UPGRADES ALL SECTIONS

2 (a) (b) (c) (d) (e) (f) (g) (h)

3 Investmen

t

4 Year Project Description

Projected Revenue

Requirement

Actual Revenue

Requirement

SPP Base Plan True-up

Amount

20yy SPP Base Plan True-up Amount

20yy SPP Base Plan True-up

Amount Int.

20yy Projected Revenue

Req.


-

-

-


-

-

-


-

-

-

8 Section B Base Plan Facilities in Service CWIP Project 1

-

-

-

9 Section C Service Upgrades Project 1 -

-

-

10 Section D Sponsored Upgrades Project 1 -

-

-

11 Section E Generator Interconnect Upgrades Project 1

-

-

-

12

13

14

15 Total Revenue Requirement and True-up Amount -

-

-

16 A. Base Plan facilities. In Service

17 i. Project 1, Projected (Describe)


Investment Year

19 matching Projected Year. Values prior and subsequent to the Projected Year will change

as Attachment O is updated.


Projected Year.

21

Projected Details






23 Service Year (yyyy) Projected Year FCR w/o

incentives, less depreciation 0.00%

24 Billing Month (1-12) (From ARR – Projected Data, line

40 col (5))


26 CIAC (Yes or No)

27 Investmen

t

Beginni

ng

Addition/

(Ret) Plant Investment




Requirement

29 -

-

-

-

-

-

-

30 -

-

-

-

-

-

-

31 -

-

-

-

-

-

-

32 -

-

-

-

-

-

-

33 -

-

-

-

-

-

-

34 -

-

-

-

-

-

-

35 -

-

-

-

-

-

-

36 -

-

-

-

-

-

-

37 -

-

-

-

-

-

-

38 -

-

-

-

-

-

-

39 -

-

-

-

-

-

-

40 -

-

-

-

-

-

-

41 -

-

-

-

-

-

-

42 -

-

-

-

-

-

-

43 -

-

-

-

-

-

-

44 -

-

-

-

-

-

-

45 -

-

-

-

-

-

-

46 -

-

-

-

-

-

-

47 -

-

-

-

-

-

-

48 -

-

-

-

-

-

-

49 -

-

-

-

-

-

-

50 -

-

-

-

-

-

-

51 -

-

-

-

-

-

-

52 -

-

-

-

-

-

-

53 -

-

-

-

-

-

-

54 -

-

-

-

-

-

-




55 -

-

-

-

-

-

-

56 -

-

-

-

-

-

-

57 -

-

-

-

-

-

-

58 -

-

-

-

-

-

-

59 -

-

-

-

-

-

-

60 …. …. ….. …..

….. ….. ….

61

62 i. Project 1, Actual (Describe)


Investment Year

64 matching True-up Year. Values prior and subsequent to the True-up Year will change as

Attachment O is updated.


True-up Year.

66




68 Service Year (yyyy) True-up Year (Actual FCR w/o incentives, less

depreciation) 0.00%

69 Billing Month (1-12) (From ARR-Actual Data, line 176

col (5))


71 CIAC (Yes or No)

72 Investmen

t

Beginni

ng Addition/(Ret) Plant Investment




Requirement

74 -

-

-

-

-

-

-

75 -

-

-

-

-

-

-

76 -

-

-

-

-

-

-

77 -

-

-

-

-

-

-

78 -

-

-

-

-

-

-

79 -

-

-

-

-

-

-

80 -

-

-

-

-

-

-

81 -

-

-

-

-

-

-

82 -

-

-

-

-

-

-

83 -

-

-

-

-

-

-

84 -

-

-

-

-

-

-

85 -

-

-

-

-

-

-

86 -



Version 0.0.0 0.1.0 Proposed Effective Date: 4/16/2016 2/1/2019 Page 4 of 8 - - - - - -

87 -

-

-

-

-

-

-

88 -

-

-

-

-

-

-

89 -

-

-

-

-

-

-

90 -

-

-

-

-

-

-

91 -

-

-

-

-

-

-

92 -

-

-

-

-

-

-

93 -

-

-

-

-

-

-

94 -

-

-

-

-

-

-

95 -

-

-

-

-

-

-

96 -

-

-

-

-

-

-

97 -

-

-

-

-

-

-

98 -

-

-

-

-

-

-

99 -

-

-

-

-

-

- 100 -

-

-

-

-

-

-

101 -

-

-

-

-

-

-

102 -

-

-

-

-

-

-

103 -

-

-

-

-

-

-

104 -

-

-

-

-

-

-

105 …. …. ….. …..

….. ….. ….

106

107

A. Base Plan facilities. In Service

108

i. Project 2, Projected (Describe)

109


110

matching Projected Year. Values prior and subsequent to the Projected Year will change as Attachment O is updated.

111

These changes will not result in a refund or additional charge related to years prior to the Projected Year.

112

Projected Details

113



114 Service Year (yyyy)

Projected Year FCR w/o incentives, less depreciation 0.00%

115 Billing Month (1-12)

(From ARR – Projected Data, line 40 col (5))






118

Investment

Beginning





120 - - - -

- - -

121 - - - -

- - -

122 - - - -

- - -

123 - - - -

- - -

124 - - - -

- - -

125 - - - -

- - -

126 - - - -

- - -

127 - - - -

- - -

128 - - - -

- - -

129 - - - -

- - -

130 - - - -

- - -

131 - - - -

- - -

132 - - - -

- - -

133 - - - -

- - -

134 - - - -

- - -

135 - - - -

- - -

136 - - - -

- - -

137 - - - -

- - -

138 - - - -

- - -

139 - - - -

- - -

140 - - - -

- - -

141 - - - -

- - -

142 - - - -

- - -

143 - - - -

- - -

144 - - - -

- - -

145 - - - -

- - -

146 - - - -

- - -

147 - - - -

- - -

148 - - - -

- - -




9 - - - -

- - - 150 - - - -

- - -

151 …. …. ….. …..

….. ….. ….

152

153

i. Project 2, Actual (Describe)

154


155

matching True-up Year. Values prior and subsequent to the True-up Year will change as Attachment O is updated.

156

These changes will not result in a refund or additional charge related to years prior to the True-up Year.

157


158



159 Service Year

True-up Year (Actual FCR w/o incentives, less depreciation) 0.00%

160 Billing Month

(From ARR-Actual Data, line 176 col (5))



163

Investment

Beginning





165 - - - -

- - -

166 - - - -

- - -

167 - - - -

- - -

168 - - - -

- - -

169 - - - -

- - -

170 - - - -

- - -

171 - - - -

- - -

172 - - - -

- - -

173 - - - -

- - -

174 - - - -

- - -

175 - - - -

- - -

176 - - - -

- - -

178 - - - -

- - -

180 - - - -

- - -

181 - - - -

- - -

18 - - - - - - -




183 - - - -

- - -

184 - - - -

- - -

185 - - - -

- - -

186 - - - -

- - -

187 - - - -

- - -

188 - - - -

- - -

189 - - - -

- - -

190 - - - -

- - -

191 - - - -

- - -

192 - - - -

- - -

193 - - - -

- - -

194 - - - -

- - -

195 - - - -

- - -

196 …. …. ….. …..

….. ….. ….

197

II. Determine the Revenue Requirement for Service Upgrades, Sponsored Upgrades and Generator Interconnection Facilities

Line

No.

1

SUMMARY OF SERVICE, SPONSORED AND

GENERATOR INTERCONNECTION

UPGRADES

2 (a) (b) (c) (d) (e)

3 Investment Projected Revenue Actual Revenue SPP Base Plan

4 Year Project Description Requirement Requirement True-up Amount

5 - - -

6 - - -

7 - - -

8 - - -

9 - - -

10 - - -

11 - - -

12




13

14

15 Total Revenue Requirement and True-up Amount - - -

Worksheet P - Revenue Requirement for Base Plan Upgrades, Service Upgrades, Sponsored Upgrades and Generator Interconnection Facilities.

III. Depreciation Rates

Year Projected Worksheet P Depr Rate

Actual Worksheet P Depr Rate

20yy

20yy

20yy

20yy

20yy

20yy

20yy

Projected Ref. Table 2, Line 40.1, col(5) Actual Ref. Table 7, Line 176.1 col(5)

20yy

20yy

20yy

20yy

20yy

20yy

20yy

20yy

20yy

20yy




Southwestern Public Service Company Table 45

Transmission Formula Rate Template Worksheet S

Twelve Months Ended December 31, 20YY Depreciation and Amortization Rates

Depreciation/

Amortization

Rate

FERC Account Name (%)

Electric Intangible






Electric Transmission 350.2 Land Rights 1.30

352 Structures & Improvements 1.80

353 Station Equipment 2.29

354 Towers & Fixtures 1.64

355 Poles & Fixtures 3.61

356 OH Conductors & Devices 2.97

357 UG Conduit 1.95

358 UG Conductors & Devices 3.16

359 Roads & Trails 1.56

Electric General 389 General Land Rights 2.12

390 Structures and Improvements 2.36

391 Office, Furniture and Equipment 4.00

391.4 Computer Hardware 20.00

392.1 Transportation Equipment - Autos 9.10

392.2 Transportation Equipment - Light Trucks 9.30

392.3 Transportation Equipment - Trailers 6.07

392.4 Transportation Equipment - Heavy Trucks 7.83

393 Stores Equipment 2.86

394 Tools Shop Equipment 2.86

395 Laboratory Equipment 4.00

396 Power Operated Equipment 4.74

397 Communications Equipment 6.93

397.3 Communications Equipment - EMS 6.93

398 Miscellaneous Equipment 4.17




Notes:

The Depreciation Rates were approved in Docket ER19-XXX (Transmission) and Docket ER15-949 (General and Intangible) and will not change absent a 205 or 206 filing.

Exh. Nos. SPS-0003 – SPS-0006

Exhibit No. SPS-0003

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION Southwestern Public Service Company ) Docket No. ER19-____-000 )

DIRECT TESTIMONY OF

ARTHUR P. FREITAS

ON BEHALF OF SOUTHWESTERN PUBLIC SERVICE COMPANY

NOVEMBER 27, 2018


DIRECT TESTIMONY OF ARTHUR P. FREITAS

TABLE OF CONTENTS

I. INTRODUCTION AND EXPERIENCE .......................................................................... 1

II. PURPOSE OF TESTIMONY ............................................................................................ 4

III. OVERVIEW OF SPS’S FILING ....................................................................................... 5

A. Overview of SPS .................................................................................................... 5

B. Overview of SPS Formula Rate Template and the SPP Tariff .............................. 7

IV. TRANSMISSION DEPRECIATION RATES ................................................................ 13

A. SPS’s Transmission Depreciation-Related Changes to the Template ................. 13

B. Implementation of Transmission Depreciation-Related Template Changes ....... 17

V. WHOLESALE TRANSMISSION-RELATED REGULATORY COMMISSION EXPENSES ...................................................................................................................... 19

A. SPS’s Recovery of Wholesale Transmission-Related Regulatory Commission Expenses ......................................................................................... 19

B. Implementation of SPS’s Recovery of Wholesale Transmission-Related Regulatory Commission Expenses ...................................................................... 22

VI. ALLOCATION OF TRANSMISSION-SPECIFIC ADIT .............................................. 26

A. SPS’s Allocation of Transmission-Specific ADIT .............................................. 26

B. Implementation of SPS’s Allocation of Transmission-Specific ADIT................ 28

VII. TAX CUTS AND JOBS ACT TEMPLATE CHANGES ............................................... 29

A. The Need for Template Changes Related to the TCJA........................................ 29

B. Implementation of TCJA Changes in the Revised Template............................... 35

VIII. RE-LABELLING A ROW ON TABLE 4 ....................................................................... 43

A. Need For the Template Change ........................................................................... 43

B. Implementation of the Change to Table 4 ............................................................ 44

IX. IMPACT OF TEMPLATE CHANGES ON SPS’S WHOLESALE TRANSMISSION SERVICE CUSTOMERS ................................................................. 44

X. CONCLUSION ................................................................................................................ 47


EXHIBITS TO DIRECT TESTIMONY OF ARTHUR P. FREITAS

Exhibit No. Description

SPS – 0004 SPS – 0005

Roadmap of Changes to Formula Rate Template Transmission Customer Annual Revenue Impacts

SPS – 0006

Illustrative Calculation of Regulatory Commission Expense Recovery Under Revised Template




Summary of the Direct Testimony of Arthur P. Freitas

Mr. Freitas provides testimony in support of the filing by Southwestern Public Service Company

(“SPS” or “Company”) to revise the transmission formula rate template (“Template”) set forth in

the Attachment O-SPS to the Xcel Energy Open Access Transmission Tariff. Mr. Freitas

provides an overview of SPS; introduces SPS’s other witnesses in this proceeding (Ms. Melissa

L. Ostrom and Mr. Dane A. Watson); and explains and supports the changes to the Template that

SPS proposes to become effective February 1, 2019 (the “Revised Template”). Mr. Freitas’

testimony explains and supports the Revised Template’s revisions to transmission plant

depreciation rates, revisions to allow SPS the opportunity to fully recover certain regulatory

commission expenses incurred as a result of transmission related proceedings before the

Commission, a correction to the allocation of transmission-specific accumulated deferred income

taxes (“ADIT”), and revisions related to the calculation of ADIT to reflect the amortization of

“excess” ADIT resulting from enactment of the Tax Cuts and Jobs Act. Mr. Freitas also

describes a ministerial correction to the Template. Mr. Freitas calculates the estimated cost

impact of the Revised Template on wholesale transmission service customers in the SPS rate

zone (Zone 11) under the Southwest Power Pool, Inc. (“SPP”) Open Access Transmission Tariff

(“Tariff”) and the cost impact to regional transmission service rates under Schedule 11 to the

SPP Tariff.

Exhibit No. SPS-0003 Page 1 of 48

DIRECT TESTIMONY OF

ARTHUR P. FREITAS

I. INTRODUCTION AND EXPERIENCE

Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 1

A. My name is Arthur P. Freitas. My business address is 1800 Larimer Street, Denver, 2

Colorado 80202. 3

Q. BY WHOM ARE YOU EMPLOYED AND WHAT IS YOUR POSITION? 4

A. I am employed by Xcel Energy Services Inc. (“XES”), the centralized service company 5

subsidiary of Xcel Energy Inc. (“Xcel Energy”), as Manager of Revenue Analysis. 6

Q. PLEASE DESCRIBE XCEL ENERGY. 7

A. Xcel Energy is a public utility holding company with, among other subsidiaries, four 8

wholly owned, vertically integrated public utility operating company subsidiaries: 9

Southwestern Public Service Company (“SPS”), Northern States Power Company, a 10

Minnesota corporation (“NSPM”), Northern States Power Company, a Wisconsin 11

corporation (“NSPW”), and Public Service Company of Colorado (“PSCo”) (together, 12

the “Xcel Energy Operating Companies”). 13

Q. ON WHOSE BEHALF ARE YOU TESTIFYING? 14

A. I am testifying on behalf of SPS. 15

Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND 16

PROFESSIONAL EXPERIENCE. 17

A. I graduated from Marquette University with a Bachelor’s degree in Business 18

Administration in 1994. 19


I worked for Boston Gas Company from 1998 through 2000 as a rate analyst. In 1

2000, I began working for a consulting group, La Capra Associates, where I gained a 2

broad range of experience and expertise that encompassed utility functions from system 3

planning through retail ratemaking. I performed analyses on a range of topics, including 4

retail cost allocation and rate design, electricity market design and analysis, power market 5

forecasting, and integrated resource planning. In 2011, I joined XES as a Principal Rate 6

Analyst. I assumed my current role in July 2015. 7

I have significant experience involving the regulatory process. I have participated 8

in regulatory proceedings, on behalf of both regulated utilities and interested 9

stakeholders, in a number of states. In those proceedings, I explored various issues, 10

including cost allocation and retail rate design, integrated resource planning, resource 11

acquisition, transmission system expansion, and renewable energy policy. Over the 12

course of those regulatory proceedings, I have prepared pre-filed testimony, developed 13

and responded to discovery, and conducted analyses on issues relevant to the proceeding 14

to support the testimony of expert witnesses. 15

Q. WHAT ARE YOUR DUTIES IN YOUR CURRENT POSITION? 16

A. I provide project supervision and technical expertise for jurisdictional cost of service 17

studies, revenue requirement determinations, formula rate administration, and related 18

projects for the Xcel Energy Operating Companies, with a focus on SPS. 19


Q. HAVE YOU PREVIOUSLY SUBMITTED TESTIMONY BEFORE THE 1

FEDERAL ENERGY REGULATORY COMMISSION OR ANY OTHER 2

REGULATORY COMMISSION? 3

A. I have not previously submitted testimony before the Federal Energy Regulatory 4

Commission (“FERC” or “Commission”). However, I have submitted testimony before a 5

number of state regulatory commissions. I have submitted pre-filed testimony to the New 6

Mexico Public Regulation Commission (“NMPRC”) on SPS’s cost of service and on 7

transmission costs in Case Nos. 15-00139-UT, 15-00296-UT and 16-00269-UT, and I 8

testified before the NMPRC in Case No. 17-00255-UT. I testified before the Public 9

Utility Commission of Texas (“PUCT”) in Docket No. 43695, a rate case filed in 2014, 10

regarding expenses incurred and revenues received from the Southwest Power Pool, Inc. 11

(“SPP”) and other utilities under the SPP Open Access Transmission Tariff (“SPP 12

Tariff”). In addition, I submitted pre-filed testimony in SPS’s base rate cases before the 13

PUCT in Docket Nos. 45524 and 47527. I also submitted pre-filed testimony to the 14

PUCT in Docket Nos. 42042 and 42004 regarding transmission-related costs incurred 15

under tariffs approved by FERC. Finally, prior to being employed by XES, I testified 16

before the Massachusetts Department of Public Utilities on behalf of Blackstone Gas 17

Company, and I submitted pre-filed testimony to the New Hampshire Public Utilities 18

Commission on behalf of the Office of Consumer Advocate. 19

Q. WAS THIS TESTIMONY PREPARED BY YOU OR UNDER YOUR DIRECT 20

SUPERVISION? 21

A. Yes. 22


II. PURPOSE OF TESTIMONY

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? 1

A. The purpose of my testimony is to support SPS’s proposal to revise Attachment O-SPS to 2

the Xcel Energy Operating Companies Open Access Transmission Tariff (“Xcel Energy 3

OATT” or “Tariff”). Attachment O-SPS is a formula rate template (the “Template” or 4

“Formula Rate Template”) used to calculate the rates applicable to SPS’s wholesale 5

transmission service customers in the SPS rates zone (Zone 11) and transmission costs 6

recovered under SPP regional rates under Schedule 11 to the SPP Tariff. As part of this 7

filing, SPS is submitting a number of proposed revisions to the Template. I refer to these 8

revisions as the “Revised Template.” In my testimony: 9

• I provide an overview of SPS; 10

• I provide an overview of the filing and introduce SPS’s other witnesses, Ms. 11 Melissa L. Ostrom and Mr. Dane A. Watson; 12

• I explain and support SPS’s proposed changes to the Formula Rate Template. 13 The Revised Template reflects (a) revised transmission depreciation rates, (b) 14 revisions to allow SPS the opportunity to fully recover certain regulatory 15 commission expenses incurred as a result of transmission related proceedings 16 before the Commission, (c) a correction to the allocation of transmission-17 specific ADIT, (d) revisions related to the calculation of accumulated deferred 18 income taxes (“ADIT”) to reflect the amortization of “excess” ADIT resulting 19 from enactment of the Tax Cuts and Jobs Act (“TCJA”) in late 2017, and (e) a 20 ministerial correction to the Template; and 21

• I discuss the estimated cost impact of the Revised Template on the wholesale 22 transmission service customers in the SPS rate zone (Zone 11) under the SPP 23 Tariff and the cost impact to regional transmission service rates under 24 Schedule 11 to the SPP Tariff. 25


Q. ARE YOU SPONSORING ANY EXHIBITS? 1

A. Yes. I am sponsoring the following exhibits which are attached to my testimony: 2


SPS - 0004 Roadmap of Changes to Formula Rate Template

SPS - 0005 Transmission Customer Annual Revenue Impacts

SPS - 0006 Illustrative Calculation of Regulatory Commission Expense Recovery Under Revised Template

I am also sponsoring Exhibits SPS-0001 and SPS-0002, which are the clean and marked 3

tariff pages to the Revised Template. 4

III. OVERVIEW OF SPS’S FILING

A. Overview of SPS

Q. PLEASE DESCRIBE SPS. 5

A. Headquartered in Amarillo, Texas, SPS is a vertically integrated generation, transmission, 6

and distribution electric utility that serves approximately 390,000 retail and wholesale 7

customers in a 52,000 square-mile area of the Panhandle and the South Plains of Texas, 8

and eastern and southern New Mexico. SPS’s service area extends approximately 400 9

miles from north to south and 200 miles from east to west. SPS also owns certain 10

transmission facilities in Kansas and Oklahoma. SPS provides regulated, cost-based 11

retail services subject to the jurisdiction of the PUCT and the NMPRC. SPS also 12

provides cost-based requirements wholesale service to cooperative and municipal power 13

customers, with rates determined under production formula rate templates that are part of 14

the individual wholesale power sales agreements. 15


SPS is a member of the SPP regional transmission organization (“RTO”) and is 1

synchronously connected to the Eastern Interconnection grid. With limited exceptions, 2

all transmission services on the SPS system are provided under the SPP Tariff. SPS is 3

also connected to the Western Interconnection grid through three high-voltage direct-4

current back-to-back converters. Although SPS operates adjacent to the Electric 5

Reliability Council of Texas (“ERCOT”) grid, it has no direct interconnections with 6

ERCOT transmission owners. 7

Q. PLEASE DESCRIBE SPS’S SERVICE AREA. 8

A. The Texas retail jurisdiction is SPS’s single largest regulatory jurisdiction. SPS also 9

serves retail customers in a large portion of eastern and southeastern New Mexico. SPS’s 10

service territory in both Texas and New Mexico is primarily agricultural, with large areas 11

of oil and natural gas production. Additionally, wholesale power sales and transmission 12

services have historically been a significant business segment for SPS. SPS directly 13

serves six wholesale requirements power sales (production) customers, who in turn may 14

serve member customers, and provides wholesale Network Integration Transmission 15

Service (“Network Service”) to various wholesale transmission customers via the SPP 16

Tariff. The SPS transmission system is included in Zone 11 of the SPP Tariff. In recent 17

years, SPS has been making substantial investments in new transmission facilities to 18

respond to increased demand from the oil and gas industry and to respond to other retail 19

and wholesale customer needs. These new facilities were planned through the SPP 20

regional transmission process. 21


B. Overview of SPS Formula Rate Template and the SPP Tariff

Q. PLEASE DESCRIBE THE CURRENTLY EFFECTIVE SPS FORMULA RATE 1

TEMPLATE. 2

A. In addition to the Template’s formula rate calculations, Attachment 1 to the Template is a 3

set of Annual Formula Rate Implementation Procedures (the “Protocols”). The 4

Template, including the Protocols, is on file with the Commission as Attachment – O 5

(SPS) to the Xcel Energy OATT and as Attachment H, Addendum 5 to the SPP Tariff. 6

SPS calculates its Zonal annual transmission revenue requirement (“ATRR”), its 7

project-specific Base Plan Upgrade (“BPU”) revenue requirements, and the Scheduling, 8

System Control and Dispatch revenue requirement (for Schedule 1 services) pursuant to 9

the formulae set forth in the Template. Under the SPP Tariff, as provided in Section II(1) 10

of Attachment H, SPS’s Zonal ATRR for Zone 11 is calculated using the formula rate as 11

specified in Attachment O – SPS of the Xcel Energy OATT. SPS’s Zonal ATRR is used 12

to calculate rates for Firm and Non-Firm Point-to-Point Transmission Service provided 13

under Schedules 7 and 8 and for Network Service provided under Schedule 9 of the SPP 14

Tariff. SPS employs a forward-looking Template, whereby the ATRR is projected under 15

the Template each year using estimated costs and loads. The ATRR projections are then 16

subject to an annual true-up based on actual costs and loads when actual data becomes 17

available. SPS calculates the true-up by June of the year following the estimated Rate 18

Year, and the true-up is applied to customer bills at the beginning of the second year 19

following the estimated Rate Year. For example, the Estimated ATRR and Estimated 20

Rates for 2018 were calculated in late 2017 and will be subject to true-up in June 2019, 21

with the true-up applied to bills in 2020. The Protocols provides specifics for postings on 22


the Open Access Same-Time Information System (“OASIS”), customer meetings, 1

discovery, challenge processes, and an annual informational filing with the Commission 2

with the Estimated Rates for the upcoming Rate Year on December 1st. 3

After SPS files to revise the Template, and the Commission accepts the changes 4

(initially or finally), SPS works with SPP to similarly update Attachment H to the SPP 5

Tariff effective on the same effective date set by the Commission for the Xcel Energy 6

Tariff’s Template revisions. This sequential filing avoids the need for the Commission to 7

review two identical formula rate revisions at the same time. The revisions to 8

Attachment H to the SPP Tariff are effectively compliance changes to implement the 9

applicable Commission order addressing the Xcel Energy Tariff. 10

Q. PLEASE DESCRIBE HOW THE COST ALLOCATION METHODS IN SPP’S 11

TARIFF AFFECTS THE SPS FORMULA RATE TEMPLATE. 12

A. Under the SPP Tariff, transmission facilities fall into different categories, and different 13

cost allocation rules apply to each category. The cost allocation rule that applies to a 14

facility under the SPP Tariff is determined when the project is approved for construction 15

by SPP. As a general matter, SPS’s transmission facility costs are (1) allocated zonally to 16

Zone 11, (2) allocated to Zone 11 as part of the SPP Base Plan Zonal Charge, or (3) 17

allocated regionally as part of the SPP Base Plan Region-wide Charge. With respect to 18

Base Plan Upgrades, SPP’s cost allocation rules sometimes require that the costs of a 19

single SPS facility be split between the Zone 11 Base Plan Zonal Charge and the SPP 20

Base Plan Region-wide Charge. For example, for certain Base Plan Upgrades, 67 percent 21

of a facility’s costs are allocated zonally to Zone 11 while 33 percent of that same 22

facility’s costs are allocated regionally to SPP’s Region-wide Charge. Because the 23


Region-wide Base Plan Charge applies to all zones, Zone 11 is allocated a portion of 1

SPS’s costs that are allocated regionally through the SPP Base Plan Region-wide Charge. 2

Q. PLEASE CONTINUE. 3

A. To reflect the SPP cost allocation rules, SPS’s Template calculates three separate 4

ATRRs: (1) the Zonal ATRR, which is the Zonal Network Integration Transmission 5

Service revenue requirement for Zone 11 (SPS) under the SPP Tariff; (2) SPS’s BPU 6

revenue requirement, which includes all BPU facilities; and (3) the Scheduling, System 7

Control and Dispatch revenue requirement (for Schedule 1 services). In this filing, SPS 8

is not proposing Template changes to the calculation of the Scheduling, System Control 9

and Dispatch revenue requirement. 10

To calculate the Zonal ATRR, the Template first calculates a Total Transmission 11

Revenue Requirement (“Total ATRR”). The Total ATRR is the revenue requirement for 12

the entire SPS network transmission system regardless of whether the plant is eligible to 13

be part of the BPU revenue requirement. The Total ATRR’s rate base is calculated based 14

on SPS’s total transmission gross plant, accumulated depreciation, ADIT, and similar rate 15

base components. The return on rate base is then calculated based on the weighted 16

average cost of capital in the Template. The return on rate base is then added to other 17

transmission operating expenses such as O&M and depreciation expense to arrive at a 18

gross revenue requirement. Finally, applicable revenue credits are applied to calculate 19

the Total ATRR. 20

Next, SPS calculates the BPU revenue requirement using a Net Plant Carrying 21

Charge without Depreciation (“NPCC”). The BPU revenue requirement for each BPU 22

project is calculated on Table 36 (Worksheet P) of the Template. The NPCC is 23


calculated by taking SPS’s Total ATRR (minus depreciation expense) divided by net 1

plant. On Table 36 of the Template, each BPU project’s gross plant is multiplied by the 2

applicable depreciation rate to calculate depreciation expense. SPS’s total Company 3

BPU revenue requirement is the sum of the individual BPU project revenue requirements 4

calculated on Table 36. 5

SPS’s Zonal ATRR is calculated by subtracting SPS’s total Company BPU 6

revenue requirement from the Total ATRR. 7

Q. PLEASE DESCRIBE HOW THESE REVENUE REQUIREMENTS ARE 8

RECOVERED FROM TRANSMISSION SERVICE CUSTOMERS. 9

A. After SPS calculates the three revenue requirements in the Template, they are sent to SPP 10

for inclusion in the Revenue Requirement and Rates (“RRR”) file. SPP performs one 11

additional step to bill the BPU revenue requirement. SPS allocates the BPU revenue 12

requirements for each BPU project to (1) the Base Plan Zonal Charge for Zone 11, (2) to 13

the SPP Base Plan Region-wide Charge, or (3) splits the BPU project’s revenue 14

requirement between the SPP’s Zonal and Region-wide Base Plan Charges. The 15

information on the cost allocation for each project is published by SPP in the RRR file, 16

including the amount of each SPS BPU project that is allocated to the SPS zone. SPP 17

invoices the wholesale transmission service customers (both inside Zone 11 or regionally 18

via Schedule 11), and SPS receives the applicable wholesale Zonal, BPU and Schedule 1 19

revenues. 20

C. The Proposed Revised Template and Supporting Witnesses 21

Q. PLEASE SUMMARIZE THE CHANGES TO THE FORMULA RATE 22

TEMPLATE SPS PROPOSES IN THIS FILING. 23


A. In this proceeding, SPS is proposing a Revised Template containing the following 1

changes to the currently effective Template: 2

1. Transmission Depreciation Rates – SPS is updating its authorized depreciation 3 rates on transmission plant. The change in depreciation rates results in three 4 changes to the Template. The first change is to list the authorized 5 depreciation on a worksheet in the Template. The second change involves the 6 calculation of the BPU revenue requirement. The calculation of net plant 7 must be changed so the proposed depreciation rates are applied prospectively 8 only. The third change is to use the weighted average transmission 9 depreciation rate in the calculation of BPU depreciation expense rather than 10 using the rate for a single FERC account, as occurs today. 11

2. Recovery of Wholesale Transmission Regulatory Commission Expenses – 12 SPS is proposing changes to the Formula Rate Template to allow SPS the 13 opportunity to recover certain regulatory commission expenses incurred in 14 proceedings before the Commission, similar to the recovery currently 15 provided under SPS’s production formula rate template. 16

3. Allocation of Transmission-Specific ADIT – SPS is proposing changes to 17 correct the allocation of transmission-specific ADIT so it is allocated 18 consistently with the other transmission-specific components of the 19 transmission revenue requirement. 20

4. Tax Cuts and Jobs Act – SPS is proposing to change the Template so it 21 reflects the provisions of the TCJA, including the amortization of “Excess” 22 ADIT. 23

5. Re-labeling a Row on Table 4 – SPS is proposing a ministerial change to re-24 label one row on Table 4 to make it more accurate. 25

Q. WHAT IS THE PROPOSED EFFECTIVE DATE FOR THE REVISED 26

TEMPLATE? 27

A. SPS is requesting an effective date of February 1, 2019 for the Revised Template. In 28

addition, as discussed later in my testimony, SPS is proposing to reflect the changes 29

related to the inclusion and amortization of Excess ADIT when calculating the 2018 Rate 30

Year transmission formula rate true up in 2019. 31

Q. PLEASE INTRODUCE THE OTHER WITNESSES PROVIDING TESTIMONY 32

IN SUPPORT OF SPS’S PROPOSED TARIFF CHANGES. 33


A. In addition to my supporting testimony, SPS’s filing is also supported by the Direct 1

Testimony of Ms. Melissa L. Ostrom, Director of Capital Asset Accounting for XES, 2

Exhibit Nos. SPS-0007 to SPS-0009 (the “Ostrom Direct Testimony”), and the Direct 3

Testimony of Mr. Dane A. Watson of Alliance Consulting Group, Exhibit Nos. SPS-0010 4

to SPS-0012 (the “Watson Direct Testimony”). 5

Q. WHAT DOES MS. OSTROM ADDRESS IN HER TESTIMONY? 6

A. Ms. Ostrom supports SPS’s request for updated depreciation rates on transmission plant 7

(“Updated Depreciation Rates”). She describes and supports the process SPS used in 8

calculating the proposed depreciation rates and, using information provided by Mr. 9

Watson, sponsors the proposed transmission depreciation rates, and calculates the 10

resulting change in depreciation expense on a total SPS basis. In addition, Ms. Ostrom 11

explains the impact of the TCJA on SPS’s plant-related ADIT balances and supports 12

SPS’s calculation of the annual amortization of plant-related excess ADIT using the 13

Average Rate Assumption Method (“ARAM”). 14

Q. WHAT DOES MR. WATSON ADDRESS IN HIS TESTIMONY? 15

A. Mr. Watson presents the results of the SPS Transmission Book Depreciation Study at 16

June 30, 2018 for SPS Transmission function assets (the “Depreciation Study”) prepared 17

by Alliance Consulting Group and provides detailed support for the recommended 18

depreciation rate changes for SPS’s transmission plant based on the results of the 19

Depreciation Study. 20

Q. HAVE YOU QUANTIFIED THE IMPACT OF THE CHANGE PROPOSED IN 21

THE REVISED TEMPLATE ON SPS’S WHOLESALE TRANSMISSION 22

SERVICE CUSTOMERS? 23


A. Yes. I present the Revised Template’s annual revenue impact on SPS’s customers in 1

Exhibit SPS-0005, which is attached to my testimony. In Section IX of my testimony, I 2

explain and support my calculations of the annual customer impacts presented in Exhibit 3

SPS-0005. 4

IV. TRANSMISSION DEPRECIATION RATES

A. SPS’s Transmission Depreciation-Related Changes to the Template

Q PLEASE DESCRIBE THE TRANSMISSION DEPRECIATION-RELATED 5

CHANGES SPS IS MAKING IN THE REVISED TEMPLATE. 6

A. In this filing, SPS is making three transmission depreciation-related changes. First, SPS 7

is updating its transmission depreciation rates and is adding a new table, Table 46, in the 8

Template that lists SPS’s depreciation rates used in the Template. Second, in the BPU 9

revenue requirement calculation, SPS is proposing to use a weighted average 10

transmission depreciation rate as the depreciation rate rather than use the depreciation 11

rate for a single FERC transmission account. Third, in the BPU revenue requirement 12

calculation of net plant, which requires a depreciation expense calculation that applies to 13

past years, SPS is revising the depreciation expense calculation so that the depreciation 14

rate used in a given year’s calculation is the rate actually in effect for that year. 15

Q. WHY IS SPS PROPOSING TO UPDATE ITS DEPRECIATION RATES FOR 16

TRANSMISSION PLANT? 17

A. As discussed by Ms. Ostrom and Mr. Watson, SPS’s transmission depreciation rates were 18

last updated and approved by the Commission through a settlement in Docket Nos. EL89-19

50-000, et al. in 1990, nearly thirty years ago. The depreciation rates were based on a 20

1988 depreciation rate study. As described in more detail by Ms. Ostrom and Mr. 21


Watson, SPS is updating its depreciation rates to reflect revised service lives for 1

transmission plant (generally longer lives) and revised net salvage values (generally 2

higher negative net salvage rates). SPS’s Updated Depreciation Rates impact the 3

calculation of depreciation expense in SPS’s Total ATRR and result in higher 4

transmission depreciation expense to be included in transmission rates. 5

Q. IS SPS PROPOSING TO UPDATE THE DEPRECIATION RATES FOR 6

GENERAL AND INTANGIBLE PLANT? 7

A. No. SPS is proposing to change only its transmission depreciation rates. Effective 8

January 1, 2015, SPS incorporated the general and intangible plant depreciation rates 9

established in the global settlement in Docket Nos. ER15-949-000, et al. when 10

calculating transmission service rates. For purposes of calculating its transmission 11

revenue requirement, SPS will continue to use these depreciation rates for general and 12

intangible plant. 13

Q. PLEASE EXPLAIN SPS’S PROPOSAL TO USE AN AVERAGE 14

TRANSMISSION DEPRECIATION RATE TO CALCULATE THE BPU 15

REVENUE REQUIREMENT. 16

A. Currently, the depreciation rate used in the Template’s BPU revenue requirement 17

calculation is an input value using the SPS depreciation rate for FERC Account 353 – 18

Station Equipment, currently 1.8840 percent. Over the last decade, the amount of 19

transmission plant included in the BPU revenue requirement has grown so that it is now 20

the majority of all SPS transmission plant and encompasses plant in all transmission 21

FERC Accounts discussed by Ms. Ostrom. In the 2019 Template, if the approximately 22

$3.0 billion of total transmission plant, the BPU projects accounted for approximately 23


$1.8 billion. The types of projects that make up the BPU revenue requirement now range 1

from large 345 kV transmission lines down to 115 kV lines and substations. For these 2

reasons, the SPS depreciation rate for FERC Account 353 is no longer representative of 3

SPS’s actual transmission depreciation expenses for BPU projects. To address this, SPS 4

is proposing to use a weighted average transmission depreciation rate as the BPU 5

depreciation rate. 6

Q. WHY IS THE USE OF AN AVERAGE TRANSMISSION DEPRECIATION RATE 7

BETTER THAN THE CURRENT PRACTICE OF USING THE DEPRECIATION 8

RATE FOR ONE FERC ACCOUNT TO CALCULATE THE BPU REVENUE 9

REQUIREMENT? 10

A. The Template includes only a single cell to identify the depreciation rate to be used to 11

calculate the BPU revenue requirement. SPS initially used the rate for FERC Account 12

353. The current depreciation rate for FERC Account 353 is lower than the average 13

transmission depreciation rate, which means that an inaccurate and lower amount of 14

depreciation expense is being recovered through the BPU revenue requirement. An 15

average depreciation rate calculation provides a more accurate measure of SPS’s actual 16

transmission depreciation expense applicable to SPS’s BPU transmission plant as a 17

whole. 18

In addition, the use of an average depreciation rate in the BPU revenue 19

requirement calculation is consistent with the rest of the BPU revenue requirement 20

calculation. The BPU revenue requirement calculation uses the NPCC times each 21

project’s net plant balance. Depreciation expense is then added to arrive at the annual 22

revenue requirement. This NPCC calculation is used for all components of the revenue 23


requirement other than depreciation expense. The NPCC is SPS’s Total ATRR minus 1

depreciation expense divided by total transmission net plant. The NPCC is therefore a 2

weighted average of all transmission costs other than depreciation expense. Using a 3

weighted average depreciation rate brings SPS’s depreciation expense calculation into 4

alignment with the rest of the BPU revenue requirement calculation. 5

Q. HOW DO THE PROPOSED CHANGES TO THE BPU REVENUE 6

REQUIREMENT CALCULATION AFFECT THE 2019 ESTIMATED ATRR? 7

A. For the 2019 Rate Year, the average depreciation rate percentage is higher than SPS’s 8

FERC Account 353 depreciation rate. The proposed depreciation rate for FERC Account 9

353 recommended by Ms. Ostrom is 2.2913 percent and the average transmission 10

depreciation rate is 2.5399 percent. Because the weighted average depreciation rate is a 11

more accurate measure of SPS’s actual depreciation expense for the facilities whose costs 12

go into SPS’s BPU revenue requirement, the BPU revenue requirement will be more 13

accurate. SPS will recover a more accurate amount of depreciation expense through the 14

SPP Base Plan Region-wide Charge. Because SPS’s Zonal ATRR equals SPS’s Total 15

ATRR minus its BPU revenue requirement, this will also make SPS’s Zonal ATRR more 16

accurate. 17

Q. PLEASE EXPLAIN THE NEED FOR TEMPLATE REVISIONS RELATED TO 18

THE USE OF HISTORICAL DEPRECIATION RATES IN THE BPU REVENUE 19

REQUIREMENT CALCULATION. 20

A. Currently, the Template calculates a BPU revenue requirement for each BPU project, 21

which is each project’s net plant balance multiplied by the NPCC. The NPCC excluding 22

depreciation expense is calculated on Tables 2 and 7 of the Formula Rate Template. To 23


calculate each project’s net plant balance, the current Template takes a gross plant 1

balance minus accumulated depreciation expense. This accumulated depreciation 2

expense is the sum of the annual depreciation expense amounts from the project’s first 3

year to the current year. Currently, the Template applies the currently effective 4

depreciation rate to calculate both the current year’s annual transmission depreciation 5

expense and the annual depreciation expense for prior years. SPS is proposing to revise 6

its transmission depreciation rates in this filing. Absent SPS’ proposed change to the 7

Template, the Template would prospectively calculate historical depreciation expenses 8

for each BPU project as if the new depreciation rates had been in effect since the project 9

was placed in service, which would result in an incorrect calculation of historical 10

depreciation expense. In this filing, SPS is changing the BPU depreciation expense 11

calculation so that the depreciation rate used in a given year’s calculation is the rate 12

actually in effect for that year. 13

B. Implementation of Transmission Depreciation-Related Template Changes

Q. PLEASE DESCRIBE THE REVISED DEPRECIATION RATES INCLUDED IN 14

THE REVISED TEMPLATE. 15

A. SPS is proposing three changes to the Formula Rate Template with respect to the 16

proposed depreciation rates. First, SPS is proposing a new table in the Template, Table 17

46, that lists the Commission-approved transmission plant and general and intangible 18

plant depreciation rates. In the electronic version of the Template, this is Worksheet S, 19

which is a new worksheet. This change is intended to make it more convenient and 20

transparent for parties to understand the depreciation rates used to calculate the 21

transmission revenue requirement. 22


Second, SPS is also proposing to use an average transmission depreciation rate as 1

the depreciation rate in the BPU revenue requirement calculation rather than the 2

depreciation rate for one transmission FERC Account, presented on Tables 2, 7, and 36. 3

Finally, SPS is proposing to change the calculation of the BPU revenue 4

requirement, presented on Table 36, Worksheet P. The calculation of net plant is being 5

changed so the proposed depreciation rates are applied only prospectively. 6

Q. PLEASE DESCRIBE THE CHANGES NEEDED TO LIST SPS’S 7

DEPRECIATION RATES IN THE TEMPLATE. 8

A. In this filing, SPS is amending the Template to add Table 45, a new table that lists the 9

currently effective depreciation rates that SPS applies in the calculation of depreciation 10

expense. With respect to SPS’s transmission plant depreciation rates, Table 45 (which is 11

Worksheet S in the electronic formula rate Template file) lists the Updated Depreciation 12

Rates. With respect to SPS’s general and intangible plant depreciation rates, which SPS 13

is not changing in this filing, Table 45 lists the depreciation rates that SPS currently 14

applies in the Template’s calculation of depreciation expense. 15

Q. PLEASE DESCRIBE THE TEMPLATE CHANGES NEEDED TO IMPLEMENT 16

THE CHANGES TO THE BPU REVENUE REQUIREMENT. 17

A. First, to implement the change to an average depreciation rate, SPS has added a new line 18

to Tables 2 and 7 which calculates the average transmission depreciation rate that will be 19

used in the BPU Revenue Requirement (“BPU depreciation rate”). The average 20

transmission depreciation rate is simply total transmission depreciation expense divided 21

by total transmission plant. The average depreciation rate then flows onto the new 22


depreciation rate section of Table 36 that I described previously. The average 1

depreciation rate for 2019 is 2.5399 percent. 2

Second, to implement the change to how historical depreciation rates are applied 3

to develop the BPU revenue requirement, a new column was added to the detailed tables 4

on Table 36 (Worksheet P) which contain the depreciation rate in effect in each year of 5

the calculation. Each year’s depreciation expense is then calculated using the 6

depreciation rate in effect for that year. This ensures that net plant correctly reflects the 7

depreciation expense that has been recognized in past years. To simplify and centralize 8

the inputs for the BPU depreciation rate, SPS is also including a new section in Table 36 9

which lists the BPU depreciation rate in effect for historic years. 10

V. WHOLESALE TRANSMISSION-RELATED REGULATORY COMMISSION EXPENSES

A. SPS’s Recovery of Wholesale Transmission-Related Regulatory Commission Expenses

Q. PLEASE DESCRIBE SPS’S WHOLESALE TRANSMISSION-RELATED 11

REGULATORY COMMISSION EXPENSES. 12

A. SPS incurs FERC regulatory commission costs related to the administration of its Tariff, 13

including the Template. However, as discussed below, under the current Template, SPS 14

recovers only a portion of those expenses from its wholesale transmission service 15

customers and the remaining costs are borne by Xcel Energy shareholders, because SPS 16

is not allowed to recover these regulatory commission expenses from SPS’s retail 17

customers in state rate case proceedings. To correctly align cost recovery with cost 18

causation, SPS is revising the Template to ensure that incremental FERC regulatory 19


commission costs that relate to administration of the SPS Tariff, including the Template, 1

are recovered from wholesale transmission service customers. 2

Q. WHAT REGULATORY COMMISSION EXPENSES DOES SPS PROPOSE TO 3

RECOVER? 4

A. SPS incurs incremental costs for certain proceedings before the Commission. SPS’s 5

Total ATRR calculated by the current Template includes a subset of SPS’s costs booked 6

to FERC Account 928 (regulatory commission expenses). Specifically, the Total ATRR 7

includes 100 percent of SPS’s FERC Account 928 expenses that are directly related to 8

SPS’s provision of transmission service pursuant to the Xcel Energy Tariff, including the 9

Template (“Transmission Regulatory Expenses”). These include, for example, costs to 10

respond to challenges of SPS’s transmission service rates, modifications to the Xcel 11

Energy OATT or the Template, or the costs to prepare filings to revise the Formula Rate 12

Template, such as this filing. These costs may include the costs of outside legal counsel 13

or consultants as well as travel expenses to attend meetings or hearings at the 14

Commission. These costs are incurred as a direct result of the administration of the Xcel 15

Energy OATT, including the administration of the Template. 16

Q. PLEASE EXPLAIN WHY SPS DOES NOT PRESENTLY FULLY RECOVER 17

THESE REGULATORY ADMINISTRATION COSTS FROM CUSTOMERS. 18

A. SPS’s Transmission Regulatory Expenses are directly assigned to the jurisdiction that is 19

the subject of the regulatory proceeding. Therefore, SPS’s Total ATRR includes no 20

retail-related regulatory expenses. Similarly, the Public Utilities Commission of Texas 21

(“PUCT”) and New Mexico Public Regulatory Commission (“NMPRC”) exclude 22

wholesale transmission related regulatory expenses from retail rates, requiring that SPS 23


directly assign those to wholesale customers. Under the Template, however, SPS’s 1

wholesale transmission network customers pay their load ratio share of SPS Zonal 2

ATRR. SPS’s wholesale transmission customers account for roughly 39 percent of SPS’s 3

network load. Therefore, although regulatory matters related to service to SPS’s 4

wholesale transmission customers cause 100 percent of SPS’s incremental wholesale 5

transmission-related regulatory expenses, and SPS’s Zonal ATRR includes 100 percent 6

of the wholesale transmission-related regulatory expenses, SPS recovers only a portion of 7

those costs from wholesale transmission service customers. The remainder of these costs 8

are allocated to the SPS retail portion of total network loads but not recovered in retail 9

rates, and thus are currently borne by Xcel Energy shareholders. This results in SPS 10

under-recovering its wholesale transmission-related regulatory commission expenses. 11

Q. PLEASE EXPLAIN IN MORE DETAIL HOW SPS CURRENTLY RECOVERS 12

REGULATORY COMMISSION EXPENSES UNDER THE TEMPLATE. 13

A. First, SPS currently includes Transmission Regulatory Expenses in its Template on Table 14

28 (Worksheet H). Transmission Regulatory Expenses are included in the Total ATRR 15

and are recovered from the wholesale transmission customers based on the wholesale 16

transmission customers’ load ratio share of SPS’s total transmission load. Second, as I 17

discussed earlier, after the Total ATRR is calculated a NPCC is applied to BPU projects. 18

Therefore, a weighted average of Transmission Regulatory Expenses is included in the 19

BPU revenue requirement and the SPS Zonal ATRR (Total ATRR minus the BPU 20

revenue requirement). This means that SPS collects Transmission Regulatory Expenses 21

under both Schedules 9 and 11 of the SPP Tariff. Schedule 9 contains the SPS Zonal 22

ATRR. So, SPS collects the wholesale transmission customers load ratio share of the 23


SPS Zonal ATRR under Schedule 9 (approximately 39 percent). Schedule 11 contains 1

the SPS BPU Revenue Requirement. 2

As I discussed earlier, cost allocation varies for each BPU project under the SPP 3

Tariff depending on the voltage level and purpose of the project. Summing up the dollars 4

allocated to SPP Zone 11 (SPS) for each BPU project and dividing that by the total BPU 5

revenue requirement results in the percentage of SPS’s BPU revenue requirement that is 6

allocated to Zone 11. I performed this exercise for SPS’s current BPU projects to 7

calculate the percentage allocated to Zone 11, which is 60.59 percent. Only a portion of 8

the cost allocated to Zone 11 is actually collected from SPS’s wholesale transmission 9

customers (currently, approximately 39 percent). Finally, SPS collects all of the 10

Transmission Regulatory Expenses included in the BPU revenue requirement that is 11

allocated for recovery from SPP Tariff customers outside of Zone 11 through the SPP 12

Base Plan Region-wide Charge (currently 39.41 percent). 13

For example, assume SPS incurred $50,000 of Transmission Regulatory 14

Expenses. My SPS Exhibit No. 6 illustrates SPS’s current level of recovery using all of 15

the facts I have just described. In this example, SPS under-recovers its Transmission 16

Regulatory Expenses by $23,212. This represents an under-recovery of 46.42 percent. 17

B. Implementation of SPS’s Recovery of Wholesale Transmission-Related Regulatory Commission Expenses

Q. PLEASE DESCRIBE HOW THE REVISED TEMPLATE ALLOWS SPS THE 18

OPPORTUNITY TO RECOVER ITS WHOLESALE TRANSMISSION-19

RELATED REGULATORY COMMISSION EXPENSES. 20

A. The Revised Template includes a calculation of a “gross up factor” to be applied to 21

certain incremental regulatory commission expenses associated with the administration of 22


SPS OATT, including the Template. The gross up factor is calculated using SPS’s total 1

transmission network load, the wholesale network load, and the percent of the BPU 2

revenue requirement that is charged back to the SPS zone. When applied to the 3

transmission related regulatory commission expenses, the gross up factor will increase 4

the amount included in the revenue requirement so the resulting amount recovered from 5

the wholesale transmission service customers is nearly equal to the full amount of 6

wholesale related regulatory commission expenses. 7

Q. PLEASE PROVIDE THE CALCULATION OF THE GROSS UP FACTOR AND 8

EXPLAIN THE DETAILED COMPONENTS. 9

A. Mathematically, the gross up factor proposed by SPS is calculated as follows: 10

Factor = RC costs * (SPS/WH) * (1 – WH/SPS *ZBPU), where 11

RC costs = SPS’s Regulatory Commission expenses, 12

SPS = SPS Zone’s total calendar year 12-CP, 13

WH = SPS’s wholesale network customers’ calendar year 12-CP, and 14

ZBPU = SPS Zone’s allocation of SPS BPU Revenue Requirement 15

Conceptually, the first term in the gross up calculation, SPS/WH, takes into account that 16

SPS does not collect any FERC regulatory commission expenses from its retail 17

customers. The second term, (1-WH/SPS * ZBPU), adjusts the gross up factor down by 18

the amount of SPS’s BPU Revenue Requirement allocated to the SPS Zone. This factor 19

ensures all wholesale collections by SPS are recognized so that SPS cannot over-recover 20

its Regulatory Commission Expenses. In my illustrative example of $50,000 of 21

Transmission Regulatory Expenses, which is included as Exhibit No. SPS-0006 to my 22

testimony, the new gross-up factor would allow SPS to recover nearly the full amount 23


from wholesale transmission customers both inside Zone 11 and through the BPU 1

revenue requirement. 2

Q. PLEASE DESCRIBE THE TEMPLATE CHANGES NEEDED TO IMPLEMENT 3

A MORE ACCURATE RECOVERY OF WHOLESALE TRANSMISSION 4

REGULATORY COMMISSION EXPENSES. 5

A. SPS is proposing changes to Tables 4, 5, 9, 10, 18, and 28. Tables 4 and 5 are on the tab 6

labeled “ARR-Projected Data” in the native electronic formula rate template file. Table 4 7

contains the calculation of the expenses that are included in the projected revenue 8

requirement. Row 106.1 (“Acct 928 – SPS Wholesale Specific”) has been inserted. This 9

row is populated with the Transmission Regulatory Expenses identified on Table 28. The 10

costs in row 106.1 are then multiplied by the Regulatory Commission Expense Factor 11

(“RC factor”) which is calculated on Table 5 to arrive at the amount of Transmission 12

Regulatory Expenses included in the transmission revenue requirement. 13

Table 5 is the supporting calculations for the projected revenue requirement 14

where the various allocators in the formula rate template are calculated. Six rows were 15

inserted (155.1 through 155.6) where the RC factor is calculated. The RC factor uses the 16

transmission network load and the wholesale transmission network load from Table 18 as 17

well as the percent of the SPS BPU revenue requirement allocated to the SPS zone. This 18

percent is calculated from the information on the cost allocation for each BPU project 19

that is published by SPP in the RRR file and is then input into the Revised Template. 20

Tables 9 and 10 are the companion tables to Tables 4 and 5 but for the actual 21

revenue requirement calculation. Tables 9 and 10 are on the tab labeled “ARR-Actual 22

Data” in the native electronic formula rate template file. The changes on those tables are 23


the same as the changes to Tables 4 and 5 except that they are populated with actual data 1

rather than projected data. 2

Table 18 (Worksheet C) is the table that contains the transmission network load 3

information. This table was changed by adding a new section that contains the projected 4

and actual wholesale transmission network load as well as an accompanying footnote 5

indicating the source of the load data. The wholesale network load is presented on a 6

monthly basis which is then used to calculate a total and 12 month average load amount. 7

This is consistent with the existing presentation of total network load. 8

Table 28 (Worksheet H) is the table for miscellaneous expenses. This table 9

assigns the expenses in FERC Account 928 to non-transmission, transmission specific, or 10

transmission allocated. The change to this table involved adding two new columns for 11

SPS’s wholesale transmission-specific expenses. One column is for projected expenses 12

(column f) and the other column is for actual expenses (column k). SPS wholesale 13

transmission-specific expenses are expense related to the administration of the 14

transmission formula rate for which SPS does not currently have the opportunity to fully 15

recover. 16

Q. DO THE 2019 ESTIMATED ATRR AND RATES INCLUDE ANY SPECIFIC 17

INCREMENTAL REGULATORY COMMISSION EXPENSES THAT WOULD 18

BE SUBJECT TO THE PROPOSED GROSS-UP FACTOR? 19

A. Yes. The 2019 Estimated Rates SPS posted on October 1, 2018 did not include any 20

expenses that are subject to the proposed gross up. However, as part of the changes 21

included in the Revised Template, SPS has included $50,000 of expenses that are subject 22


to the gross-up. The $50,000 is an estimated amount of costs SPS expects to incur in 1

2019 from OATT related proceedings before the Commission, including this docket. 2

Q. WOULD TRANSMISSION SERVICE CUSTOMERS BE ABLE TO REVIEW 3

THE SPECIFIC REGULATORY COSTS RECOVERED? 4

A. Yes. Worksheet H, Table 28 would identify the actual Wholesale Specific costs to be 5

recovered, and SPS would identify and explain the costs in the materials provided for the 6

customer meetings pursuant to the Protocols. 7

Q. ARE YOU AWARE OF ANY SIMILAR REGULATORY EXPENSE RECOVERY 8

MECHANISMS AUTHORIZED BY THE COMMISSION? 9

A. Yes. The SPS production formula rates include a similar mechanism to recover 10

incremental regulatory commission expense related to administration of SPS’s cost-based 11

production formula rates. 12

VI. ALLOCATION OF TRANSMISSION-SPECIFIC ADIT

A. SPS’s Allocation of Transmission-Specific ADIT

Q. WHAT IS ADIT? 13

A. ADIT or Accumulated Deferred Income Taxes is the cumulative amount of taxes that 14

SPS will need to pay to the Internal Revenue Service (“IRS”) at some point in the future. 15

ADIT is primarily a result of differences between depreciation expense for tax purposes 16

and depreciation expense for book purposes. For ratemaking purposes, ADIT is included 17

in rate base and it is typically a reduction to rate base. 18

Q. PLEASE DESCRIBE THE ALLOCATION OF TRANSMISSION-SPECIFIC 19

ADIT CURRENTLY USED IN THE FORMULA RATE TEMPLATE. 20


A. In the current Template, total ADIT is grouped into four categories based on whether it 1

is: (1) not applicable to the transmission function, (2) allocated based on plant (“GP 2

allocator”), (3) allocated based on labor (Wages and Salaries (“W/S”) allocator), or (4) 3

transmission-specific. ADIT that is not applicable to the transmission function is 4

excluded from the Template. ADIT that is allocated based on plant is allocated using the 5

gross plant allocator calculated within the Template. ADIT that is allocated on labor is 6

allocated using the wages and salaries allocator also calculated within the formula rate 7

template. The transmission-specific ADIT is direct assigned 100 percent to the 8

transmission function in the formula rate template, as shown on Tables 22, 23, and 24, 9

Worksheet E. 10

Because the Template directly assigns transmission-specific ADIT, the current 11

Template allocates transmission-specific ADIT in an inaccurate way. Directly assigning 12

100 percent of the transmission-specific ADIT is inconsistent with the manner in which 13

other transmission-specific components of the revenue requirement are allocated. For 14

example, transmission-specific gross plant, accumulated depreciation, and depreciation 15

expense are all allocated to the transmission revenue requirement using the transmission 16

plant allocator (“TP allocator”). For 2019, the estimated TP allocator is 95.389 percent. 17

The transmission plant allocator is used to allocate costs to the transmission revenue 18

requirement because the transmission revenue requirement excludes costs associated with 19

radial transmission lines and transmission plant serving production (such as generation 20

step up transformers). The costs associated with radial lines are excluded from the 21

ATRR. Similarly, the costs of SPS’s transmission plant that serves the SPS production 22

function also are excluded from the ATRR. 23


Because the costs of some transmission assets (radial lines and transmission 1

serving production) are excluded from the SPS transmission revenue requirement, 2

directly assigning 100 percent of the transmission-specific ADIT to the transmission 3

revenue requirement results in too much ADIT being included in transmission rate base 4

(i.e., reducing rate base). The end result is that the transmission revenue requirement is 5

under-collecting SPS’s cost of providing network transmission service. 6

Q. HOW DOES SPS PROPOSE TO CORRECT THIS INCONSISTENCY? 7

A. SPS proposes to modify the Template to use the Transmission Plant allocator to allocate 8

transmission-specific ADIT in the formula rate template. This is consistent with the 9

allocation of the other transmission-specific components of the revenue requirement 10

calculation. The portion of transmission-specific ADIT related to radial lines and 11

transmission serving production would thus be excluded. 12

B. Implementation of SPS’s Allocation of Transmission-Specific ADIT

Q. PLEASE DISCUSS THE CHANGES TO THE TEMPLATE TO CORRECT THE 13

ALLOCATION OF TRANSMISSION-SPECIFIC ADIT. 14

A. The allocation of ADIT occurs on Tables 22, 23 and 24. In the native electronic formula 15

rate template these tables are located on Worksheet E. On each of the tables, there is a 16

line titled “Transmission Allocator [GP or W/S]” which contains the allocation factors for 17

the different categories of ADIT, Transmission-specific, plant related, or labor related. 18

The changes to these tables involve changing the title of the line to include the TP 19

allocator, changing the column header of column E to remove the “100%” value in the 20

header, and changing the allocation factor in column E from 100 percent to the 21

appropriate TP allocation factor calculated in the supporting calculations section on 22


Tables 5 and 10. For 2019 the estimated TP allocator is 95.389 percent. The tables on 1

Worksheet E that allocate the projected ADIT reference the projected TP allocator from 2

Table 5 and the actual ADIT allocation tables reference the actual TP allocator from 3

Table 10. 4

VII. TAX CUTS AND JOBS ACT TEMPLATE CHANGES

A. The Need for Template Changes Related to the TCJA

Q. PLEASE DESCRIBE THE RELATIONSHIP BETWEEN THE TAX CUTS AND 5

JOBS ACT AND THE FORMULA RATE TEMPLATE. 6

A. The TCJA is the most comprehensive revision of the United States Tax Code since 1986 7

and it affects regulated utilities in important ways. However, only one change to the 8

Template is needed to fully reflect the impacts of the TCJA. As explained below, this is 9

because the current Formula Rate Template already allows SPS to reflect some of the 10

TCJA’s effects. SPS has already reflected the TCJA’s effect on the ADIT balances in 11

rate base in the 2018 transmission rates. The change will address the TCJA’s effect on 12

income tax expense. In this filing SPS is proposing new worksheets in the Revised 13

Template to detail the ADIT balances included in rate base. The remaining TCJA 14

changes do not directly affect SPS’s transmission business and therefore they require no 15

changes to the Template. 16

Q. PLEASE DESCRIBE THE TAX CUTS AND JOBS ACT AND HOW IT AFFECTS 17

SPS. 18

A. The TCJA affects regulated utilities, including SPS, in several important ways: 19

(1) Corporate Tax Rate. The TCJA set the federal corporate income tax rate 20 applicable to utilities and other C corporations at a flat 21 percent rate 21 beginning on January 1, 2018, whereas under prior law a utility’s taxable 22 income was subject to a graduated tax rate that topped out at 35 percent. 23


Customers will see an immediate benefit from the lower tax rate through a 1 lower provision for income taxes reflected in revenue requirements. 2

(2) End of Bonus Depreciation. Utilities are no longer eligible to use bonus 3 depreciation for assets placed into service after December 31, 2017, but 4 instead must use Modified Accelerated Cost Recovery System 5 depreciation rates for those assets. Although the TCJA provides for 100 6 percent expensing of “qualified property” placed in service after 7 December 31, 2017 and before January 1, 2023, “qualified property” is 8 now defined to exclude public utility property. 9

(3) Net Operating Loss (“NOL”) Deductions. The NOL deduction is limited 10 to 80 percent of taxable income for losses arising in tax years beginning 11 after December 31, 2017. 12

(4) Interest Expense Deductibility. The TCJA allows utilities to continue 13 deducting all interest expense, whereas companies in other industries may 14 not be able to deduct all of the interest expense they incur. 15

(5) Manufacturing Deduction. The deduction formerly available for certain 16 manufacturing activities under section 199 of the Internal Revenue Code 17 (“IRC”) was eliminated effective January 1, 2018. 18

(6) Meals and Entertainment Expense. The deductibility of meals and 19 entertainment expense was modified effective January 1, 2018. 20

(7) Executive Compensation. The deductibility of executive compensation 21 expense was modified effective January 1, 2018. 22

(8) Effect on ADIT Balances. This is explained in detail in my testimony 23 below. 24

Q. OF THE TCJA IMPACTS YOU LISTED, WHICH ONES ARE ALREADY 25

INCORPORATED IN THE TRANSMISSION FORMULA TEMPLATE? 26

A. No change to the Formula Rate Template is needed to reflect the effect of the following 27

TCJA changes listed above: (1) corporate tax rate; (2) end of bonus depreciation; (3) 28

NOL deductions, (4) interest expense deductibility, (5) meals and entertainment expense; 29

and (6) executive compensation. The effects of these TCJA changes already flow 30

through the Formula Rate Template. For example, the federal corporate income tax rate 31

“cell” in the Template is a blank cell that requires SPS to calculate its ATRR using the 32


currently effective tax rate. As such, transmission service rates for 2018 will reflect this 1

change without any change to the Template. 2

Q. IS THERE A TCJA IMPACT THAT HAS NO EFFECT SPS’S TRANSMISSION 3

COSTS AND THEREFORE NO CHANGE TO THE TEMPLATE IS REQUIRED 4

TO ADDRESS IT? 5

A. Yes. Because it has no effect on SPS’s transmission costs, the repeal of the 6

manufacturing deduction has no impact on the Template. 7

Q. WHAT IS “EXCESS” AND “DEFICIENT” ADIT? 8

A. For ADIT amounts in FERC Account 190, the difference between the balance in the 9

general ledger and the revalued balance reflecting the TCJA is a regulatory asset that will 10

be recovered from customers. These amounts are “deficient” ADIT. For ADIT amounts 11

in FERC Accounts 282 and 283, the difference between the balance in the general ledger 12

and the revalued balance is a regulatory liability that will be refunded to customers. 13

These amounts are “excess” ADIT. In the context of my testimony, I use the term Excess 14

ADIT to refer to both the excess amounts to be refunded to customers as well as the 15

deficient amounts to be recovered from customers because for SPS the net is a regulatory 16

liability that will be refunded over time. 17

Q. HOW DID THE TCJA AFFECT ADIT BALANCES? 18

A. The reduction in the federal corporate income tax rate gives rise to Excess ADIT because 19

the deferred income tax expense collected in prior years’ rates was based on a 35 percent 20

income tax rate, but utilities will pay the deferred taxes to the Internal Revenue Service at 21

a 21 percent rate. 22


Q. DOES THE CURRENT FORMULA RATE TEMPLATE FLOW THROUGH 1

SOME OF THE EXCESS ADIT CREATED BY THE TCJA? 2

A. Yes. SPS’s currently effective Template provides for the inclusion of Excess ADIT 3

balances in rate base. Footnote D on Tables 6, and 11 allows SPS to include contra 4

accounts to FERC Account 282, 283 and 190, provided the contra balances are identified 5

as regulatory liabilities or assets and are related to FASB 106, 109, 133, 158, or FASB 6

Interpretation No. 48. After enactment of the TCJA, SPS was required to revalue its 7

ADIT balances at the lower 21 percent federal corporate income tax rate, and the 8

difference between the ADIT balances on SPS’s books and the revalued ADIT balances 9

was Excess ADIT that SPS booked in accordance with FASB-109. 10

Q. WHAT CHANGES TO THE FORMULA RATE TEMPLATE ARE NECESSARY 11

TO ADDRESS THOSE ADIT BALANCES? 12

A. The Excess ADIT should be returned to customers over varying periods of time, 13

depending on the type of the underlying asset or liability. To address these ADIT 14

balances, changes must be made to both the calculation of rate base as well as the 15

calculation of income tax expense. Income tax expense is referred to as income tax 16

allowance in the Commission’s ADIT-related notice of proposed rulemaking which I 17

discuss later in my testimony. Until the Excess ADIT is amortized, customers will 18

continue to receive the benefit of a rate base reduction for the Excess ADIT. 19

Q. WHY ARE CHANGES TO THE CALCULATION OF RATE BASE USUALLY 20

NECESSARY? 21

A. When the TCJA was passed and the corporate income tax rate was reduced to 21 percent, 22

SPS and other utilities were required to recalculate their ADIT balances under FASB-23


109. The ADIT balances represent tax expense amounts SPS will pay to the U.S. 1

government at some point in the future. Because the tax rate went down, SPS’s future tax 2

liability also went down. The difference between the ADIT balance calculated using the 3

35 percent federal income tax rate and the restated balance at the lower 21 percent 4

income tax rate is recorded as Excess ADIT. Because SPS’s transmission rates had been 5

calculated assuming a higher future tax liability (in other words a higher ADIT balance), 6

these Excess ADIT amounts need to be refunded to SPS’s customers over time. Until the 7

amounts are refunded, the un-refunded Excess ADIT balance needs to remain as a credit 8

to rate base. 9

Q. PLEASE EXPLAIN THE RATE BASE-RELATED CHANGES TO THE 10

TEMPLATE. 11

A. The Excess ADIT will be returned to customers over various periods of time depending 12

on the type of Excess ADIT. The Excess ADIT balances associated with SPS’s plant in 13

service are recorded in FERC Accounts 190, 282 and 283. These accounts are already 14

included in the Template so no changes are necessary to include plant-related Excess 15

ADIT. However, the Excess ADIT associated with non-plant items are recorded in 16

FERC Accounts 182.3 and 254. These accounts are not currently included in the 17

Template. Prior to the revaluation after TCJA, the Excess ADIT balances in FERC 18

Accounts 182.3 and 254 were part of ADIT recorded in FERC Accounts 190 and 283. 19

To properly reflect the treatment of non-plant related Excess ADIT, the balances 20

recorded in FERC Accounts 182.3 and 254 need to be included in rate base. Any other 21

items recorded in these accounts are not included in rate base unless specifically 22

approved by the Commission. 23


Q. PLEASE EXPLAIN THE INCOME TAX EXPENSE-RELATED CHANGES TO 1

THE TEMPLATE. 2

A. SPS proposes that Excess ADIT amounts be returned to customers over various time 3

periods, depending on the type of Excess ADIT. The amortization of Excess ADIT is 4

included in deferred tax expense, which is not a component of the calculation of the 5

transmission revenue requirement in the current Template. 6

Q. PLEASE EXPLAIN THE TYPES OF EXCESS ADIT AND HOW THE 7

AMORTIZATION OF EACH TYPE OF EXCESS ADIT IS CALCULATED. 8

A. Excess ADIT falls into two types depending on whether or not it is subject to IRS 9

normalization rules. Excess ADIT that is subject to normalization is referred to as 10

“protected” and Excess ADIT that is not subject to normalization is referred to as 11

“unprotected.” Protected Excess ADIT is required to be amortized using ARAM by the 12

IRS normalization rules, which amortizes the Excess ADIT balance over the average 13

remaining life of the underlying assets. The Net Operating Loss or NOL Carryforward 14

deferred tax asset is a protected asset because the NOL was generated as a result of SPS 15

claiming bonus depreciation. There is no specified amortization period for unprotected 16

ADIT balances. 17

SPS’s plant-related Excess ADIT is made up of both protected and unprotected 18

Excess ADIT. The protected Excess ADIT will be amortized over the underlying assets’ 19

remaining life using ARAM. As discussed in the Ostrom Direct Testimony, plant-related 20

unprotected Excess ADIT will also be amortized using ARAM over the remaining life of 21

the assets to which the Excess ADIT relates. SPS’s non-plant Excess ADIT is all 22

unprotected and SPS is proposing to amortize the non-plant Excess ADIT over 5 years. 23


Q. PLEASE EXPLAIN WHY A 5-YEAR AMORTIZATION PERIOD FOR NON-1

PLANT EXCESS ADIT IS REASONABLE 2

A. ADIT accumulates and then reverses over the life of the underlying asset or liability that 3

generated the ADIT. The underlying assets and liabilities that gave rise to the non-plant 4

ADIT have varying lives. Some are very short term in nature and have lives that are only 5

a year or two in length. Other assets and liabilities have a longer remaining life, such as 6

those that are related to retirement obligations. SPS’s proposal to use a 5-year 7

amortization period takes into account inter-generational equity issues by providing a 8

balance between SPS’s current customers and its future customers. 9

Q. HAS SPS PROPOSED A 5-YEAR AMORTIZATION PERIOD FOR NON-PLANT 10

EXCESS ADIT IN ANY OF ITS OTHER JURISDICTIONS? 11

A. Yes. In SPS’s recently concluded rate cases in Texas (PUCT Docket No. 47527) and 12

New Mexico (NMPRC Case No. 17-00255-UT), SPS proposed a 5-year amortization 13

period for non-plant Excess ADIT. The PUCT rate case was resolved through a 14

settlement agreement that authorizes SPS to use the 5-year amortization period for non-15

plant Excess ADIT, although parties remain free to raise the issue in SPS’s future PUCT 16

rate cases. In New Mexico, the NMPRC issued a final order authorizing SPS to use the 17

5-year amortization period for non-plant Excess ADIT. 18

B. Implementation of TCJA Changes in the Revised Template

Q. PLEASE SUMMARIZE THE TEMPLATE CHANGES RELATED TO EXCESS 19

ADIT. 20

A. SPS is proposing to change the Formula Rate Template to include the amortization of 21

plant and non-plant Excess ADIT using the amortization periods I described above. As 22


noted, the Net Operating Loss or NOL Carryforward deferred tax asset is a protected 1

asset. SPS will amortize the NOL over 44 years, which is the average remaining life of 2

all of SPS’s plant. SPS currently functionalizes the NOL Carryforward ADIT balance in 3

the Formula Rate Template. The NOL Carryforward Excess ADIT will be functionalized 4

in the same manner. 5

Q. PLEASE DISCUSS THE SPECIFIC CHANGES RELATED TO THE TCJA. 6

A. The changes related to the TCJA are extensive and impact Tables 3, 4, 8, 9, 19, 21A, 22, 7

23, and 24. In addition, two new Worksheets were created and are included on Tables 8

21B and 21C. In the native electronic formula rate template file: Tables 3 and 4 are on 9

the “ARR-Projected Data” tab; Tables 8 and 9 are on the “ARR-Actual Data” tab; Table 10

19 is on the “WsD Avg Rate Base” tab; Table 21A is on the “WsD.2 ADIT Proration 11

Factor” tab; and Tables 22, 23, and 24 are on the “WsE Rate Base Adj” tab. The two 12

new tables were put on new tabs in the native electronic file. Table 21B is on tab 13

“WsD.3 Non-plant Excess ADIT” and Table 21C is on tab “WsD.4 Excess ADIT 14

Amort.” The changes to the Formula Rate Template include changes to both the 15

calculation of rate base and to the calculation of income tax expense. Furthermore, as 16

discussed below, SPS’s Template changes also incorporate the guidance the Commission 17

provided in its ADIT-related notice of proposed rulemaking (“NOPR”) issued on 18

November 15, 2018 in Docket No. RM19-5-000. 19

Q. PLEASE DESCRIBE THE CHANGES TO THE CALCULATION OF RATE 20

BASE SPS IS PROPOSING. 21

A. The Template changes related to rate base are intended to bring clarity and transparency 22

to the Template. SPS’s current Template provides for the inclusion of Excess ADIT 23


balances in the calculation of rate base. However, the current Template does not 1

distinguish ordinary ADIT amounts from the Excess ADIT amounts. The changes to the 2

calculation of rate base make clear the amount of ADIT being included in rate base and 3

the amount of Excess ADIT being included in rate base and whether the Excess ADIT is 4

protected or unprotected. 5

To implement this, new lines were added to Table 19 and a new table, Table 21B, 6

was created. The new lines on Table 19 provide SPS’s plant-related Excess ADIT 7

balances, further broken down by whether the ADIT is protected or unprotected. Table 8

21B presents the beginning and ending balance of non-plant related Excess ADIT. Plant-9

related Excess ADIT is included with plant ADIT in the FERC Form 1 so it is already 10

included in the formula rate template on Table 19. Non-plant Excess ADIT is recorded in 11

either FERC Account 182.3 or FERC Account 254, depending on whether the Excess 12

ADIT is related to a deferred tax asset or a deferred tax liability. Table 21B also presents 13

the annual amortization of the non-plant Excess ADIT. Tables 22, 23, and 24 then 14

reference the Excess ADIT average balance calculated on Table 21B. 15

Tables 22, 23, and 24 (Worksheet E) were changed to include new sections to 16

categorize and allocate the non-plant Excess ADIT. These new sections function in the 17

same manner as the existing sections on Worksheet E. The new sections also contain a 18

line for a proration adjustment because the Excess ADIT related to the NOL is protected 19

and therefore must be prorated. The proration is calculated on Table 21A. 20

Table 21A (Worksheet D.2) was changed to add two new sections which calculate 21

the proration adjustment for the transmission-specific and general plant NOL Excess 22

ADIT. The new sections function in the same manner as the existing sections on Table 23


21A. The proration adjustment is then included in the total amount of adjustments to rate 1

base calculated on Worksheet E and included in the calculation of rate base on Tables 3, 2

and 8. 3

Table 3 (ARR-Projected Data) was changed to add two new lines in the 4

Adjustments to Rate Base section of the rate base calculation. Line 72.1 includes the 5

Excess ADIT recorded in FERC Account 254. Line 72.2 includes the Excess ADIT 6

recorded in FERC Account 182.3. Because these amounts are coming from Worksheet E 7

already allocated, the balances are included in transmission rate base without further 8

allocation, which is consistent with the treatment of the other ADIT balances calculated 9

on Worksheet E. 10

Table 8 (ARR-Actual Data) was changed in the same manner as Table 3, except 11

that it references the actual data calculated on Worksheet E. 12

Q. PLEASE DESCRIBE THE CHANGES TO THE TEMPLATE THAT AFFECT 13

THE CALCULATION OF INCOME TAX EXPENSE? 14

A. SPS proposes changes to Tables 4 and 9, as well as adding a new table (Table 21C). 15

Table 21C (Worksheet D.4) presents and allocates the amortization of both plant 16

and non-plant Excess ADIT. This new table functions in the same fashion as Worksheet 17

E. The plant-related Excess ADIT amortization is input in the top section of the table 18

which then allocates the Excess ADIT based on whether it is not transmission-related, 19

transmission-specific, plant-related, or labor-related. Similarly, the non-plant Excess 20

ADIT amortization is categorized and allocated in the same manner. Rather than the 21

amounts being input, they are referenced from Table 21B. Once the Excess ADIT 22


amortizations are allocated, they are included in the calculation of income tax expense on 1

Tables 4 and 9. 2

Table 4 (ARR-Projected Data) was changed by inserting four lines to include the 3

Excess ADIT Amortization. Lines 135.1 and 135.2 reference the allocated Excess ADIT 4

Amortization calculated on Table 21C for plant (Line 135.1) and non-plant (Line 135.2). 5

Lines 137.1 and 137.2 then apply the income tax gross up factor calculated on an existing 6

line (Line 130) to gross up the amortizations to a revenue basis. Finally, the sum on Line 7

138 was adjusted to include the two new lines 137.1 and 137.2 in the total income tax 8

expense amount. 9

The Template changes being proposed are for transparency so that the non-plant 10

Excess ADIT balances in FERC Accounts 182.3 and 254 are expressly listed in the 11

Revised Template. 12

Q. WHAT IS THE RELATIONSHIP BETWEEN SPS’S PROPOSED TCJA-13

RELATED TEMPLATE CHANGES AND THE TRUE-UP PROCESS UNDER 14

THE PROTOCOLS? 15

A. As I stated previously, SPS’s currently effective Template provides for the inclusion of 16

Excess ADIT balances in rate base. Therefore, SPS included the Excess ADIT balances 17

associated with the TCJA in its 2017 true-up (calculated in June 2018 back to January 1, 18

2017) and will continue to include these balances in upcoming true ups, including the 19

2018 true up. Because the Excess ADIT balances will be included in the true-up rates, 20

SPS proposes to start the Excess ADIT amortization period on January 1, 2018, when the 21

Excess ADIT balances first appeared. 22


In Docket No. ER18-1521-000, SPS received a waiver of the Protocols so SPP 1

could revise its 2018 transmission service rates in 2018 to reflect the 21 percent corporate 2

tax rate, rather than wait for the 2018 true-up in 2019. SPS requested and received a 3

January 1, 2018 effective date for the waiver. The Revised Template and true-up 4

proposal ensures that transmission service customers also receive the Excess ADIT 5

benefits of the TCJA from the date it became effective (January 1, 2018). 6

Q. PLEASE DESCRIBE HOW THE PROPOSED TEMPLATE CHANGES 7

INCORPORATE THE GUIDANCE THE COMMISSION PROVIDED IN ITS 8

RECENT ADIT-RELATED NOPR. 9

A. In the ADIT NOPR, the Commission provided preliminary TCJA-related guidance to 10

public utilities with transmission formula rates with respect to three topics: (1) ensuring 11

rate base neutrality; (2) return/recovery of excess/deficient ADIT and; (3) support for 12

excess/deficient ADIT calculation and amortization. 13

Regarding rate base neutrality, the Commission explained that Excess ADIT 14

balances must be included as reduction to rate base until the Excess ADIT has been 15

refunded to customers. As I described above, SPS’s current Template includes Excess 16

ADIT in rate base. 17

Regarding the return or recovery of excess or deficient ADIT, the Commission 18

proposed that public utilities be required to reflect the full value of Excess ADIT in rates 19

and that the amortization of Excess ADIT should occur concurrent with when the 20

amortization is included in rates. SPS’s proposal satisfies this guidance because the 21

Revised Template uses the TCJA changes both prospectively and for the 2018 true-up. 22

By using the proposed TCJA changes in the 2018 true-up, SPS will be including the 23


amortization of Excess ADIT starting January 1, 2018, to the benefit of SPS’s wholesale 1

transmission customers. 2

Finally, the Commission proposed to require public utilities with transmission 3

formula rates to incorporate a new permanent worksheet into their transmission formula 4

rates that will annually track information related to excess or deficient ADIT under 5

Section 35.24 of the Commission’s regulations. The Commission also proposed that 6

these ADIT worksheets include certain minimum ADIT-related information addressing: 7

1. How the ADIT accounts were re-measured and the excess or deficient 8

ADIT contained therein; 9

2. The accounting of any excess or deficient ADIT in Accounts 182.3 and 10

254; 11

3. Whether the excess or deficient ADIT is protected or unprotected; 12

4. The accounts to which the excess or deficient ADIT are amortized; and 13

5. The amortization period of the excess or deficient ADIT being returned or 14

recovered through rates. 15

The ADIT NOPR states that the Commission is not defining the form of the new 16

worksheet (or worksheets), only the information it must contain. The Commission will 17

evaluate each utility’s proposed worksheet on an individual basis. SPS is using more 18

than one worksheet in the interests of clarity and organization of the information. 19

Q. PLEASE DESCRIBE HOW THE PROPOSED TEMPLATE CHANGES 20

INCLUDE INFORMATION THAT SATISFY THE NOPR’S PROPOSED 21

REQUIREMENTS. 22


A. Although the ADIT NOPR is not binding, SPS’s Revised Template includes the ADIT-1

related information described in the NOPR on the following worksheets: 2

1. For plant-related Excess ADIT, SPS’s current Template presents the 3

Excess ADIT balances without need for modifications on Table 19. 4

Currently, Table 19 is largely a freeform input worksheet that allows SPS 5

to input itemized ADIT balances. To clearly show that SPS will present 6

Excess ADIT balances as described in the NOPR, SPS has inserted new 7

lines on Table 19 that detail SPS’s plant-related Excess ADIT balances, 8

further breaking down those balances to show whether they are protected 9

or unprotected. 10

2. SPS’s non-plant-related Excess ADIT balances are detailed on Table 21B, 11

which is a new table. This table presents the Excess ADIT balances in 12

Accounts 182.3 and 254, which is where non-plant Excess ADIT is 13

recorded. 14

3. The protected and unprotected Excess ADIT balances are shown on Table 15

19 for plant-related Excess ADIT and on Table 21B for non-plant-related 16

Excess ADIT. 17

4. The accounts to which Excess ADIT is amortized are noted in footnotes 18

on Table 21C. Table 21C is a new table that presents the annual Excess 19

ADIT amortization amounts included in income tax expense for both 20

plant-related and non-plant-related Excess ADIT. Currently, Excess 21

ADIT is amortized into Accounts 410.1 and 411.1, which are deferred tax 22

expense accounts. SPS does not expect any accounting changes that 23


would change those accounts, which is why it is proposing a footnote. 1

SPS will amortize its Excess ADIT balances concurrently with the flow-2

back of these amounts in rates. 3

5. For both plant-related and non-plant-related Excess ADIT, Table 21C 4

presents the amortization method and the date the amortization start date. 5

VIII. RE-LABELLING A ROW ON TABLE 4

A. Need For the Template Change

Q. PLEASE DESCRIBE THE CHANGE TO THE LABEL OF THE OTHER TAXES 6

ITEM ON THE REVENUE REQUIREMENT SUMMARY TABLES. 7

A. On Table 4, the other taxes section of the revenue requirement summary tables contains 8

an item labeled “Other – Texas Use” which is being changed to “Other Taxes”. 9

Q. PLEASE EXPLAIN WHY THIS LABEL IS BEING CHANGED? 10

A. The label is being changed to better describe the costs associated with that line item. The 11

Texas use tax is included in that line, but there are other costs that are also included in the 12

revenue requirement calculation. This change is intended to denote that the revenue 13

requirement contains other taxes besides the Texas use tax. 14

Q. IN ADDITION TO THE TO THE TEXAS USE TAX, WHAT ARE THE OTHER 15

COSTS ON TABLE 4 THAT ARE INCLUDED IN THE REVENUE 16

REQUIREMENT? 17

A. The other costs on Table 4 are items such as miscellaneous taxes and a business franchise 18

tax for the state of Oklahoma. SPS owns transmission assets in Oklahoma and pays a 19

business franchise tax, which is why this cost is included in the revenue requirement. 20


Q. HAVE THESE COSTS PREVIOUSLY BEEN INCLUDED IN SPS’S REVENUE 1

REQUIREMENT? 2

A. Yes. In the formula rate template, the line labeled “Other – Texas Use” references a 3

subtotal line on Worksheet J (Table 30) which itemizes the various other taxes and 4

categorizes them as to whether they are in the revenue requirement or excluded from it. 5

The change in the label is simply intended to indicate that there are other taxes besides 6

the Texas use tax that are included in the revenue requirement. The change is for clarity 7

only. 8

B. Implementation of the Change to Table 4

Q. PLEASE DESCRIBE THE REVISED TEMPLATE’S CHANGE TO TABLE 4. 9

A. The label on Table 4, line 127 and Table 9, line 263 have been changed from “Other – 10

Texas Use” to “Other Tax”. 11

IX. IMPACT OF TEMPLATE CHANGES ON SPS’S WHOLESALE TRANSMISSION SERVICE CUSTOMERS

Q. HAVE YOU CALCULATED THE IMPACT OF THE TEMPLATE CHANGES 12

ON CUSTOMERS? 13

A. Yes. Using the 2019 projected rates posted on OASIS by SPS on October 1, 2018, I have 14

quantified the impact of SPS’s proposed changes on SPS’s wholesale transmission 15

customers’ Schedule 9 network transmission charges. I have also estimated the impact of 16

SPS’s proposed Template changes will have on the charges to Zone 11 wholesale 17

transmission customers for SPS’s regionally allocated Base Plan Upgrade transmission 18

projects. 19

Q. WHAT IS THE DOLLAR IMPACT ON SPS’S WHOLESALE TRANSMISSION 20

CUSTOMERS? 21


A. The proposed Template changes result in an estimated increase in transmission charges to 1

SPS’s wholesale transmission network customers in Zone 11 of $4.96 million, and 2

increased transmission charges to SPP Tariff customers outside Zone 11 of $4.47 million. 3

Table 1 summarizes the annual impact to each type of SPS wholesale customer. 4

Table 1 Estimated Annual Customer Impact

Using 2019 Estimated ATRR and Rates

Impact of Zone 11 Network

Transmission Rate Change

Impact of Schedule 11

Rate Change to Zone 11 Rates Total

Golden Spread Elect Cooperative

$1,036,698

$1,246,564

$2,283,262

City of Brownfield $ 18,501

$ 22,247

$ 40,748

Central Valley Co-op. $ 145,269

$ 174,676

$ 319,945

Farmers Co-op. $ 75,338

$ 90,589

$ 165,928

City of Floydada $ 4,594

$ 5,524

$ 10,117

Lea County Co-op $ 239,613

$ 288,120

$ 527,733

Lubbock Power & Light $ 618,295

$ 743,461

$1,361,755

Roosevelt Cty. Co-op $ 31,571

$ 37,963

$ 69,534

Tri-County Elect. Co-op $ 73,816

$ 88,759

$ 162,575

City of Tulia $ 7,811

$ 9,393

$ 17,204

Total Zone 11 Wholesale $2,251,506

$2,707,295

$4,958,800

Impact to Other SPP Rate Zones via SPP Schedule 11 $4,469,518

Q. PLEASE DESCRIBE HOW YOU CALCULATED THE ANNUAL CUSTOMER 5

IMPACTS. 6

A. In Docket No. ER18-2319-000, SPS has filed to eliminate the double averaging 7

associated with ADIT proration. These changes are currently pending before the 8


Commission. In preparing SPS’s 2019 Estimated Rates, which will go into effect 1

January 1, 2019, SPS incorporated the changes to eliminate ADIT double averaging. To 2

quantify the impact of the Revised Template, I started with the same Template used to 3

calculate SPS’s 2019 Estimate Rates and then revised the Template to include the 4

changes SPS has proposed in this docket. I then recalculated the Schedule 9 network 5

transmission rate. Using the most recent available billing determinants (September 2017 6

– August 2018) as a proxy for 2019 billing determinants, I calculated the annual impact 7

to SPS’s Zone 11 transmission service customers using the recalculated network 8

transmission rate. 9

I also calculated the annual bill impact related to the change in the BPU revenue 10

requirement that is charged to SPS’s wholesale transmission network customers in Zone 11

11. Again, I started this calculation with the 2019 estimated BPU revenue requirement. I 12

then incorporated the Template changes proposed in this docket and calculated the 13

change in the BPU revenue requirement. Because the BPU revenue requirement is 14

charged to all network transmission loads in the SPP, I calculated the share that would be 15

charged to SPS’s Zone 11 wholesale customers. To perform this calculation, I used the 16

RRR file SPP uses to bill the transmission revenue requirement to the users of the 17

transmission system. I used the currently effective RRR file published by SPP for service 18

on or after June 1, 2018. Using the information in the RRR file, I calculated the 19

aggregate share of all of SPS’s BPU project revenue requirements that are allocated to the 20

SPS zone (60.59 percent). Using this percentage, I calculated the amount of the change 21

in the total BPU revenue requirement that would be allocated to Zone 11. Finally, I 22

calculated each wholesale transmission customer’s share of the SPS total zonal load using 23


the same billing determinant data used in the calculation of the Schedule 9 network bill 1

impact. Using each customer’s zonal load ratio share, I estimated the amount of the SPS 2

zone change in BPU revenue requirement allocated to each wholesale transmission 3

customer. I added the network transmission and BPU annual impacts to determine the 4

total annual impacts to each SPS Zone 11 transmission customer. 5

Q. WHAT IS THE OVERALL RATE INCREASE TO THE ZONE 11 NETWORK 6

CUSTOMERS ON A PERCENTAGE BASIS? 7

A. Using the Zone 11 network customers’ and SPS total system loads for the 12-month 8

period of September 2017 through August 2018, the network customers’ total charges 9

under the 2019 Estimated Rates are $89.4 million. As shown in Exhibit No. SPS-0005, 10

the network customers’ increase resulting from the Revised Template is $4.96 million, an 11

increase of 5.54 percent. 12

Q. WHAT IS THE OVERALL RATE INCREASE TO SPP TARIFF CUSTOMERS 13

OUTSIDE ZONE 11? 14

A. For SPP customers located outside Zone 11, the total estimated impact is an increase of 15

$4.47 million, an increase of 6.44 percent. 16

X. CONCLUSION

Q. PLEASE SUMMARIZE YOUR RECOMMENDATIONS. 17

A. I recommend that the Commission approve SPS’s proposed revisions to SPS’s Formula 18

Rate Template discussed in my testimony, effective on February 1, 2019. Each of these 19

changes is just and reasonable because it improves the accuracy of how the Template 20

measures and allocates SPS’s transmission cost of service. 21


Q. DOES THIS CONCLUDE YOUR PRE-FILED DIRECT TESTIMONY? 1

A. Yes. 2

Exhibit No. SPS-0004 (Road Map)

Southwestern Public Service Company Exhibit No. SPS-0004Roadmap to Transmission Formula Rate Template Changes Page 1 of 1November 27, 2018 Filing

Line # Topic Description Formula Table and Line #1 Depreciation Rates SPS is updating its depreciation rates on transmission plant. SPS has updated the template to

include a depreciation and amortization table to show these current rates.45 (WsS), New Table2 (ARR-Proj), Line 40.17 (ARR-Act), Line 176.136 (WsP), Heading, Section titles, added columns (f), (g) and (h), added Section II, added Section III - Depreciation Rates and added Depreciation Rate column to section A, project tables

2 Regulatory Commission Expenses SPS is improving the recovery of regulatory commission expenses in order to provide better matching of expenses to customer incurred in the administration of Attachment O-SPS.

4 (ARR-Proj), Line 106.15 (ARR-Proj), Lines 155.1-155.69 (ARR-Act), Line 242.110 (ARR-Act), Lines 291.1-291.618 (WsC), Section IV Lines 29-42 and Section V Note 328 (WsH), Relabeled heading columns and added SPS Wholesale Specific columns

3 ADIT Balance Allocation Correction SPS is correcting the allocation of transmission specific ADIT balances in rate base from 100% to using the formula template calculated transmission plant allocator consistent with the current allocation of gross plant and accumulated reserve for depreciation.

22 (WsE), Removed 100% from column (E), added TP for Transmission Allocator23 (WsE), Removed 100% from column (E), added TP for Transmission Allocator24( WsE), Removed 100% from column (E), added TP for Transmission Allocator

4 TCJA Impacts SPS is incorporating changes in the formula rate to provide customers with the benefits of the Tax Cuts and Jobs Act (TCJA), specifically to include the amortization of excess ADIT.

3 (ARR-Proj) Lines 72.1, 72.24 (ARR-Proj) Lines 135.1, 135.2, 137.1, 137.2, 1386 (ARR-Proj) Footnote P8 (ARR-Act) Lines 208.1, 208.29 (ARR-Act) Lines 271.1, 271.2, 273.1, 273.2, 27411 (ARR-Act) Footnote P19 (WsD), Line 20-23 and Line 64-6721A (WsD.2) Lines 251-30821B (WsD.3 non-plant excess ADIT), New Table21C (WsD.4 Excess ADIT Amort), New Table22 (WsE) Added FERC Account 254 - Projected 23 (WsE) Added FERC Account 182.3 - Projected , Added FAS 109 Plant Deficient ADIT Protected and Unprotected to existing FERC Account 190 - Projected24 (WsE) Added FERC Account 254 - Actual, Added FERC Account 182.3 - Actual, Added FAS 109 Plant Deficient ADIT Protected and Unprotected to existing FERC Account 190 - Actual

5 (Ministerial Change) Label Change - Other Taxes The other taxes section of the revenue requirement summary tables contain an item labeled “Other–Texas Use” which is being changed to “Other Taxes” to better respresent the dollars included on that line.

4 (ARR-Proj), Line 1279 (ARR-Act), Line 263

Exhibit No. SPS-0005 (Trans Annual Revenue Impacts)

Southwestern Public Service Company Exhibit No. SPS-0005Total Annual Transmission Revenue Impact Page 1 of 1

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

CustomerAnnual 12-CP Demand (MW)

SPS Zone Load Ratio Share

Current Schedule 9

Charges

Current Schedule 11

Charges

Total Current Transmission

Charges

Proposed Schedule 9

Charges

Proposed Schedule 11

Charges

Total Proposed Transmission

ChargesIncrease

($)Increase

(%)Annual Transmission Revenue Requirement 176,199,429$ 187,540,883$

Golden Spread Electric Cooperative 11,157 18.14% 21,830,716$ 19,366,468$ 41,197,184$ 22,867,414$ 20,613,032$ 43,480,446$ 2,283,262$ 5.54%Brownfield, City of 199 0.32% 389,600 345,622 735,221 408,101 367,868 775,969 40,748 5.54%Central Valley Electric Cooperative 1,563 2.54% 3,059,057 2,713,751 5,772,808 3,204,325 2,888,427 6,092,753 319,945 5.54%Farmers Electric Cooperative 811 1.32% 1,586,466 1,407,386 2,993,851 1,661,804 1,497,975 3,159,779 165,928 5.54%Floydada, City of 49 0.08% 96,733 85,814 182,547 101,327 91,337 192,664 10,117 5.54%Lea County 2,579 4.19% 5,045,757 4,476,192 9,521,949 5,285,370 4,764,312 10,049,682 527,733 5.54%Lubbock Power & Light 6,654 10.82% 13,020,007 11,550,311 24,570,318 13,638,302 12,293,771 25,932,073 1,361,755 5.54%Roosevelt County Electric Cooperative 340 0.55% 664,829 589,783 1,254,612 696,401 627,746 1,324,146 69,534 5.54%Tri-County Electric Cooperative 794 1.29% 1,554,408 1,378,947 2,933,355 1,628,224 1,467,706 3,095,930 162,575 5.54%Tulia, City of 84 0.14% 164,494 145,926 310,419 172,305 155,318 327,624 17,204 5.54%Total Wholesale 24,231 39.40% 47,412,066$ 42,060,199$ 89,472,265$ 49,663,572$ 44,767,494$ 94,431,066$ 4,958,800$ 5.54%

SPS Retail 37,275 60.60% 72,934,145$ 64,701,349$ 137,635,494$ 76,397,644$ 68,865,990$ 145,263,634$ 7,628,140$ 5.54%

Total SPS Zone 11 61,507 100% 120,346,211$ 106,761,549$ 227,107,760$ 126,061,216$ 113,633,484$ 239,694,700$ 12,586,940$ 5.54%

Total Outside SPS Zone 11 -$ 69,437,881$ 69,437,881$ -$ 73,907,399$ 73,907,399$ 4,469,518$ 6.44%

Exhibit No. SPS-0006 (Recovery FERC Reg Costs - Example)

Exhibit No. SPS-0006Page 1 of 1

Assumptions

Regulatory Weighted Adjusted Regulatory WeightedCosts Allocation Costs Allocation

Sch 9 ATRR 130,000,000$ 20,313$ 48,310$ Sch 11 ATRR 190,000,000$ 29,688$ 48,310$ Total SPS ATRR 320,000,000$ 50,000$ 50,000$ 96,620$ 96,620$

Schedule 11 RR allocated to SPS zone 60.59%

Allocation and Recovery

CustomerAnnual 12-CP Demand (MW)

SPS Zone Load Ratio

Share Sch 9 Sch 11 Total Sch 9 Sch 11 Total

SPS NITS 24,231 39.40% 8,002$ 7,087$ 15,089$ (1) 19,032$ 11,532$ 30,564$ (1)

SPS Retail 37,275 60.60% 12,310$ 10,901$ 23,212$ (2) 29,277$ 17,740$ 47,017$ (2)

Total SPS Zone 61,507 100% 20,313$ 17,988$ 38,301$ 48,310$ 29,272$ 77,581$

Schedule 11 Recovery Outside SPS Zone 11,699$ 11,699$ (3) 19,038$ 19,038$ (3)

Actual Collections ((1) + (3)) 26,788$ Actual Collections ((1) + (3)) 49,602$

Under Collection (23,212)$ Under Collection (398)$

Current Allocation Proposed Recovery

Current Proposed

Illustration Showing SPS Recovery of FERC Regulatory Costs




FEDERAL ENERGY REGULATORY COMMISSION

Southwestern Public Service Company ) Docket No. ER19-____-000 )

DIRECT TESTIMONY OF

MELISSA L. OSTROM


NOVEMBER 27, 2018


DIRECT TESTIMONY OF MELISSA L. OSTROM

TABLE OF CONTENTS

I. INTRODUCTION AND EXPERIENCE ............................................................................1

II. PURPOSE OF TESTIMONY ..............................................................................................4

III. DEPRECIATION RATE MODIFICATIONS ....................................................................5

A. Overview of the Depreciation Study ........................................................................5

B. Transmission Plant Depreciation Rates ...................................................................9

C. Reserve Reallocation .............................................................................................12

IV. EFFECT OF 2017 TAX CUTS AND JOBS ACT ............................................................14

A. Accumulated Deferred Income Taxes – Plant Assets ............................................14

B. Company Proposal .................................................................................................16

V. CONCLUSION ..................................................................................................................21


EXHIBITS TO DIRECT TESTIMONY OF MELISSA L. OSTROM


SPS-0008

Comparison of current and proposed transmission depreciation rates by plant account

SPS-0009 Deferred tax expense calculation examples




Summary of the Direct Testimony of Melissa L. Ostrom

Ms. Ostrom’s Direct Testimony on behalf of Southwestern Public Service Company

(“SPS” or “Company”) supports the changes SPS is making to the depreciation rates to be used

in SPS’s transmission formula rates. Ms. Ostrom explains that the changes to the transmission

depreciation rates are supported by the “Southwestern Public Service Company – FERC Book

Depreciation Accrual Rate Study at June 30, 2018” (“Depreciation Study”) sponsored by

Company witness Mr. Dane A. Watson of the Alliance Consulting Group. Ms. Ostrom testifies

that these depreciation rate changes will result in an overall increase in depreciation expense

charged to transmission service customers.

Ms. Ostrom explains that Mr. Watson performed a depreciation reserve reallocation

within applicable functional classes of the Company’s plant assets in developing the

recommended depreciation rates as part of the Depreciation Study.

Ms. Ostrom notes that SPS’s current transmission depreciation rates have not been

updated for nearly thirty years, since the settlement of Docket Nos. EL89-50-000, et al. Ms.

Ostrom recommends that the Commission approve the Company’s revised depreciation rates to

become effective as of February 1, 2019. In recommending approval of the proposed

depreciation rates, Ms. Ostrom further recommends that the Commission expressly approve the

depreciation reserve reallocation performed as part of the Depreciation Study.


Ms. Ostrom also addresses the effects of the 2017 Tax Cuts and Jobs Act (“TCJA”) as it

relates to the plant assets. In particular, Ms. Ostrom explains that the Company’s plant-related

accumulated deferred income tax (“ADIT”) must be recalculated to reflect the reduced federal

corporate income tax from 35 percent to 21 percent under the TCJA, creating “excess” ADIT,

and then amortized over the average life of existing plant assets under the Average Rate

Assumption Method to return the plant-related excess deferred tax liability to customers. Ms.

Ostrom also discusses the adjustments necessary to incorporate these impacts into the SPS

annual transmission revenue requirement.

.


DIRECT TESTIMONY OF MELISSA L. OSTROM



A. My name is Melissa L. Ostrom. My business address is 414 Nicollet Mall, 401-3rd Floor, 2

Minneapolis, Minnesota, 55401. 3


A. I am employed by Xcel Energy Services Inc. (“Xcel Energy Services” or “XES”), a 5

wholly-owned subsidiary of Xcel Energy Inc. (“Xcel Energy”), as Director, Capital Asset 6

Accounting. Xcel Energy Services is the centralized service company for the Xcel 7

Energy holding company system, and provides various corporate services to the 8

subsidiaries of Xcel Energy. 9

Q. PLEASE DESCRIBE XCEL ENERGY. 10

A. Xcel Energy is a public utility holding company with, among other subsidiaries, four 11

wholly-owned, vertically integrated public utility operating company subsidiaries: 12

Southwestern Public Service Company (“SPS” or the “Company”), Northern States 13

Power Company, a Minnesota corporation, Northern States Power Company, a 14

Wisconsin corporation, and Public Service Company of Colorado (“PSCo”) (together, the 15

“Xcel Energy Operating Companies”). 16


A. I am testifying on behalf of SPS. 18




A. I obtained a Bachelor of Business Administration degree with an Accounting Major from 1

the University of Wisconsin – Madison in May 2006. In May 2007, I also received a 2

Master of Accountancy degree from the University of Wisconsin – Madison. 3

I began my professional career with Deloitte & Touche, LLP in 2007 as an Audit 4

& Assurance Associate. In 2009, I was promoted to Audit & Assurance Senior. In 2010, 5

I began working for XES as a Senior Accounting Analyst in the Sarbanes-Oxley 6

Management Office, Corporate Accounting, and External Reporting departments. I held 7

that position until 2012, when I was promoted to Manager of Budgeting and Forecasting 8

for Energy Supply Finance. In 2013, I began serving as Manager, Capital Asset 9

Accounting. I held that position until 2016, when I assumed my current position. 10


A. As Director of Capital Asset Accounting, I am responsible for and oversee the overall 12

capital asset accounting policies, the day-to-day maintenance of accounting and tax 13

records for capital assets, and the related reporting and regulatory requirements for Xcel 14

Energy and its subsidiaries, including SPS. Specifically, my duties include: 15

• establishing corporate capitalization policies for the development, 16 enhancement, and maintenance of the Corporate Continuing Property Record 17 process for all of the plant assets of Xcel Energy and its subsidiaries; 18

• managing the capital investment cost recovery process, which includes the 19 development of detailed actuarial analyses, regulatory filings with the various 20 state rate regulatory commissions and the Federal Energy Regulatory 21 Commission (“FERC” or “Commission”), and expert testimony to support 22 recovery levels in rate proceedings; 23

• overseeing the development of corporate income tax deductions related to 24 accelerated income tax depreciation expenses and providing for the 25 computation and support of deferred income taxes, which normalize the 26 impact of these accelerated deductions for ratemaking and book accounting 27 purposes; 28


• assisting with the plant asset-related ratemaking process, which supports the 1 rate filings for all of the Xcel Energy Operating Companies’ retail and 2 wholesale jurisdictions; 3

• overseeing capital asset reporting and information processing necessary to 4 disseminate capital asset information as required by various state regulatory 5 authorities, the Commission, and the U.S. Securities and Exchange 6 Commission, as well as meeting all internal information requirements 7 necessary to sustain efficient and effective business operations; and directing 8 the nuclear plant decommissioning funding process for NSPM, which includes 9 developing detailed engineering cost studies combined with a complete 10 financial and economic analysis to develop detailed regulatory filings to 11 establish the ratepayer funding levels necessary to accumulate the total future 12 decommissioning cost requirement. 13

Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THIS COMMISSION OR 14

BEFORE OTHER REGULATORY AGENCIES? 15

A. Yes. I submitted pre-filed testimony to the Public Utility Commission of Texas 16

(“PUCT”) in Docket Nos. 45524 and 47527, SPS’s 2016 and 2017 Texas retail base rate 17

cases. I also submitted pre-filed testimony to the PUCT on SPS’s behalf in Docket Nos. 18

44671 and 46877, which dealt with the sale of certain transmission facilities to Sharyland 19

Utilities in 2015 and an application for approval of a transmission cost recovery factor, 20

respectively. I also submitted pre-filed testimony to the New Mexico Public Regulation 21

Commission (“NMPRC”) on behalf of SPS in Case No. 17-00255-UT. In addition, I 22

have submitted pre-filed testimony to the Colorado Public Utilities Commission on 23

behalf of PSCo in Proceeding No. 17AL-0363G. Finally, I submitted pre-filed testimony 24

to the Commission regarding (1) proposed changes to the remaining lives of SPS’s Tolk 25

Unit 1 and Tolk Unit 2 generating stations, and (2) the depreciation reserve reallocation 26

associated with the retirement of the Carlsbad Generating Station, filed in Docket No. 27

ER18-228-000. As I understand, Docket No. ER18-228-000 remains pending before the 28

Commission in settlement judge procedures. 29




A. The purpose of my testimony is (1) to support SPS’s changes to the currently effective 2

transmission depreciation rates used for the depreciation expense calculation in the 3

Attachment O-SPS transmission formula rate template (“Template”), and (2) to support 4

the calculation of the impacts of the 2017 Tax Cuts and Job Act (“TCJA”) on the revenue 5

requirement for the transmission plant assets. I am providing the accounting support and 6

justification for the Company’s adoption of the proposed revised depreciation rates for 7

transmission utility plant.1 As the Company’s accounting witness, I am attesting to the 8

reasonableness of the Company’s proposals in this proceeding and their consistency with 9

sound depreciation practices. I provide an explanation of the amortization of the plant-10

related excess deferred taxes to the revenue requirement through the use of the Average 11

Rate Assumption Method (“ARAM”). My testimony covers the following: 12

• I support Commission approval of the proposed depreciation rates for 13

transmission plant accounts being proposed by the Company for approval in this 14

case, as supported by the Book Depreciation Accrual Rate Study at June 30, 2018 15

(“Depreciation Study”), performed by Alliance Consulting Group (“Alliance”) 16

and sponsored by Company witness Mr. Dane A. Watson, including the 17

depreciation reserve reallocation performed by Mr. Watson as part of that study. 18

1 For ease of reference, the term “depreciation rates” is used in this proceeding to refer to the Company’s depreciation and amortization of all electric utility and common utility plant accounts. It should be noted, however, that certain of the Company’s intangible plant accounts are amortized, and not depreciated through the use of approved depreciation rates. Thus, in many contexts, the term “depreciation rates” also includes the amortization periods applicable to accounts that are amortized, and not depreciated. This filing does not affect SPS’s intangible plant accounts.


• I also provide the estimated impact of SPS’s proposed transmission depreciation 1

rate changes on depreciation expense at the Company level. 2

• I explain how SPS proposes to “unwind” the excess deferred taxes created by 3

enactment of the TCJA through ARAM amortization for both “protected” and 4

“unprotected” plant assets. 5

Q. HAVE YOU PREPARED ANY EXHIBITS IN SUPPORT OF YOUR 6

TESTIMONY IN THIS PROCEEDING? 7

A. Yes. I am sponsoring the following exhibits, which were prepared under my direct 8

supervision: 9


SPS-0008

Comparison of current and proposed depreciation rates by plant account;

SPS-0009 Deferred tax expense calculation examples.

III. DEPRECIATION RATE MODIFICATIONS

A. Overview of the Depreciation Study

Q. PLEASE DESCRIBE SPS’S TRANSMISSION ASSETS. 10

A. SPS owns transmission facilities in the panhandle and south plains regions of Texas, in 11

eastern and southern New Mexico, and in Kansas and Oklahoma. SPS’s transmission 12

assets at December 31, 2017 include: 8,516 conductor miles of 345 kV transmission lines 13

with supporting structures; 9,608 conductor miles of 230 kV transmission lines with 14

supporting structures; 13,555 conductor miles of 115 kV transmission line with 15

supporting structures; 24,795 conductor miles of less than 115 kV line; and 454 16


transmission and distribution substations. SPS’s total transmission plant as of June 30, 1

2018 was $2.9 billion. 2

Q. WHY IS SPS REVISING ITS TRANSMISSION DEPRECIATION RATES? 3

A. The transmission depreciation rates currently used in SPS’s Template were established by 4

a settlement approved by the Commission in Southwestern Public Service Company, 5

Letter Order, Docket Nos. EL89-50-000, et al. (issued October 10, 1990). The 6

depreciation rates approved in that settlement were based on a 1988 depreciation study 7

filed by the Company. After 1990, the Company periodically revised its retail 8

depreciation rates in general rate case or other filings to the PUCT or NMPRC, but did 9

not modify the depreciation rates used to calculate wholesale transmission, production or 10

ancillary services rates on file with the Commission. 11

Due to the passage of time since the current rates were established, SPS decided 12

to reevaluate its wholesale depreciation rates. In 2014, SPS evaluated the need to update 13

the depreciation rates for wholesale production and transmission. A production and 14

general plant study was filed with the Commission on January 30, 2015 in Docket No. 15

ER15-949-000, and the new depreciation rates for production and general and 16

amortization rates for intangible plant were accepted for use in SPS’s production formula 17

rates effective January 1, 2015. As part of a “global settlement” agreement resolving that 18

proceeding and others, SPS agreed not to file changes to transmission depreciation rates 19

until at least November 1, 2016. 20

In 2018, SPS requested that Alliance perform a new transmission depreciation 21

study, which indicates updates to the transmission depreciation rates are necessary. As 22

described in the Direct Testimony of Mr. Dane A. Watson (“Watson Direct Testimony”) 23


and in the Depreciation Study, the remaining lives and salvage rates for several 1

transmission plant accounts need updating. 2

Attached to my testimony as Exhibit No. SPS-0008 is a comparison of current and 3

proposed transmission plant depreciation rates by plant account. The Depreciation Study 4

supports an increase in the depreciation rates for SPS’s transmission plant assets to be 5

incorporated in the Template. SPS is not proposing to change the depreciation rates for 6

general plant or amortization rates for intangible plant used in Attachment O-SPS, which 7

were updated in Docket No. ER15-949-000. 8

Q. WHO PERFORMED THE DEPRECIATION STUDY? 9

A. The Depreciation Study was performed by Alliance at the Company’s direction and 10

supervision. Alliance personnel have over 80 years of combined experience in 11

conducting depreciation studies, as well as many years of utility experience managing 12

and studying utility assets. SPS witness Dane A. Watson, a partner of Alliance, presents 13

the Depreciation Study. Alliance also prepared the production and general plant 14

depreciation study filed in Docket No. ER15-949-000, and has prepared studies 15

supporting SPS’s depreciation rate filings to the PUCT and NMPRC. Alliance is thus 16

very familiar with both the SPS system and Xcel Energy’s depreciation practices. 17

Q. PLEASE DESCRIBE THE DEPRECIATION STUDY. 18

A. The Depreciation Study analyzes annual transmission depreciation rates based on SPS’s 19

depreciable plant in service as of June 30, 2018. The depreciation rates are based on 20

average remaining life calculations and net salvage rates. The Depreciation Study 21

follows the Commission’s long-standing precedent for determining the average 22

remaining life depreciation rate based on the Average Life Group and straight-line 23


depreciation. In this way, all customers are charged for their appropriate share of the 1

capital expended for their benefit. The Depreciation Study fully supports the Company’s 2

proposed changes to its current transmission plant depreciation rates. 3

Q. WHAT DEFINITION OF DEPRECIATION WAS USED IN PREPARING THE 4

DEPRECIATION STUDY AND THIS TESTIMONY? 5

A. The term “depreciation,” as I use it and as it was used in preparing the Depreciation 6

Study, is an accounting method that spreads the cost of assets, less net salvage (if any), 7

over the estimated useful life of the assets in a systematic and rational manner. 8

Depreciation expense is systematically allocated to accounting periods over the life of the 9

assets. The amount allocated to any year does not necessarily represent the loss or 10

decrease in value that will occur during that year. Thus, depreciation is considered an 11

expense or cost, rather than a loss or decrease in value. SPS accrues depreciation based 12

on the original cost of all property included in each depreciable plant account. On 13

retirement, the full cost of depreciable property, less any net salvage amount (positive or 14

negative), is charged to the depreciation reserve. 15

Q. WHAT RECOMMENDATIONS ARE YOU MAKING REGARDING SPS’S 16

TRANSMISSION DEPRECIATION RATES? 17

A. I recommend that the Commission: 18

• Approve SPS’s proposed depreciation rates for transmission plant reflected in Exhibit 19

No. SPS-0008, as supported by the Depreciation Study, and authorize them to go into 20

effect beginning February 1, 2019; and 21

• Approve SPS’s proposed reserve reallocation for transmission plant accounts 22

performed as part of the Depreciation Study. 23


Q. DO THE METHODOLOGIES USED BY ALLIANCE IN DEVELOPING THE 1

DEPRECIATION STUDY AND THE REVISED DEPRECIATION RATES 2

PERMIT SPS TO SYSTEMATICALLY AND RATIONALLY ALLOCATE THE 3

COSTS OF SPS’S PROPERTY OVER ITS USEFUL LIFE? 4

A. Yes. 5

B. Transmission Plant Depreciation Rates

Q. WHAT TRANSMISSION PROPERTY IS INCLUDED IN THE DEPRECIATION 6

STUDY? 7

A. The Depreciation Study includes all the transmission assets in FERC Account No. 350.2, 8

Land Rights, through Account No. 359, Roads and Trails. Although the Company does 9

not have an approved rate for Account No. 350.2, Land Rights, the Company has 10

historically amortized Land Rights property over 50 years. Also, new to the Depreciation 11

Study is Account No. 359, Roads and Trails. The Company has been utilizing the Docket 12

Nos. EL89-50-000, et al., depreciation rate for Account No. 352, Structures and 13

Improvements, as the basis for depreciating the current plant balance in Account No. 359, 14

Roads and Trails. In this filing, the Company proposes an average service life, retirement 15

curve, and net salvage rate for both Account No. 350.2, Land Rights, and Account No. 16

359, Roads and Trails, based on the Depreciation Study. 17

The following table lists the FERC Accounts included in the Depreciation Study: 18

Table 1: FERC Transmission Accounts 19 FERC

Account Account Description

350.2 Land Rights 352 Structures and Improvements 353 Station Equipment 354 Towers and Fixtures 355 Poles and Fixtures


356 Overhead Conductors and Devices 357 Underground Conduit 358 Underground Conductors and Devices 359 Roads and Trails

Q. PLEASE DESCRIBE THE RESULTS OF THE DEPRECIATION STUDY FOR 1

TRANSMISSION PLANT. 2

A. The results of the analysis conducted in the Depreciation Study result in an overall 3

increase to SPS’s depreciation expense for transmission plant. Exhibit No. SPS-0008 4

compares the proposed depreciation rates to the current depreciation rates. The 2018 5

annual transmission plant depreciation expense based on the current depreciation rates is 6

$56.9 million. The annual depreciation expense based on the revised depreciation rates is 7

$75.5 million, or an estimated $18.6 million increase in annual expense based on June 30, 8

2018 plant balances at the SPS total company level. 9

Q. WHAT ARE THE PRIMARY DRIVERS OF THE INCREASE IN 10

DEPRECIATION EXPENSE? 11

A. The increase is predominantly the result of revised negative net salvage rates for several 12

transmission plant accounts due to increases in the cost of demolition and removal of 13

transmission assets over time. For example, SPS proposes to change approved net 14

salvage percentages for Account Nos. 353, 355, and 356 from zero, positive 5 and 15

positive 5 percent, respectively, to negative 20, negative 35, and negative 30 percent, 16

respectively. The detailed reasons for this are discussed further in the Watson Direct 17

Testimony. The impact of these three changes results in an annual increase in 18

depreciation expense of $17.2 million on a Company basis. While Mr. Watson’s 19

Depreciation Study concludes that a negative 60 percent net salvage value would be 20

appropriate for Account No. 355, SPS proposes to use a more conservative negative 35 21


percent at FERC until the Depreciation Study results can be reviewed and approved by 1

the PUCT. This change will align the net salvage rates with those approved and effective 2

in SPS’s Texas retail jurisdiction. This is addressed in the Watson Direct Testimony and 3

the Depreciation Study. Table 2 below compares the net salvage rates with approved 4

Texas and New Mexico retail and proposed FERC. 5

Table 2: Comparison of Net Salvage Rates between Jurisdictions 6

Docket Docket12-00350-UT 43695 (2014)

FERC Account Description

NMApproved

TXApproved Note

FERCProposed

350.2 LAND RIGHTS 0.00% 0.00% 0.00%352 STRUCTURES AND IMPROVEMENTS -20.00% -10.00% -10.00%353 STATION EQUIPMENT -19.00% -20.00% -20.00%354 TOWERS AND FIXTURES -5.00% -5.00% -5.00%355 POLES AND FIXTURES -60.00% -35.00% (A) -35.00%356 OVERHEAD CONDUCTORS AND DEVICES -30.00% -30.00% -30.00%357 UNDERGROUND CONDUIT 0.00% 0.00% 0.00%358 UNDERGROUND CONDUCTORS AND DEVICES 0.00% 0.00% 0.00%359 ROADS AND TRAILS 0.00% 0.00% 0.00%

(A) SPS proposed a -60% net salvage rate in TX Docket No. 43695; however, the PUC ordered SPS to use a -35% net salvage rate

This impact is somewhat mitigated by SPS’s proposals to increase the depreciable lives 7

of several transmission plant accounts, causing an annual decrease in depreciation 8

expense of $2.1 million. The remaining variance is driven by a reserve deficiency 9

resulting from a higher theoretical reserve2 compared to the reallocated book reserve. 10

The reserve deficiency is increasing annual depreciation expense by $3.5 million on a 11

Company basis. Consistent with Commission precedent, the depreciation expense is 12

2 The theoretical depreciation reserve balance is a calculated balance of what the reserve would be if the life and salvage estimates proposed had always been applied. Where the theoretical balance is greater than the actual balance a reserve deficiency exists.


increased over the average remaining life to compensate for the reserve deficit. Further 1

discussion surrounding reserve reallocation and theoretical reserve can be found in the 2

next section of my testimony. 3

Q. DOES SPS PLAN TO FILE THE DEPRECIATION STUDY IN ANY OTHER 4

JURISDICTION? 5

A. Yes. SPS will file with the PUCT and NMPRC in 2019 for approval of the remaining 6

lives and negative salvage rates for transmission plant included in the Depreciation Study 7

for purposes of developing retail rates. 8

Q. DOES SPS ANTICIPATE A FUTURE REVISION TO THE WHOLESALE 9

TRANSMISSION DEPRECIATION RATE FOR ACCOUNT NO. 355 IF THE SPS 10

STATE COMMISSIONS ADOPT THE STUDY RECOMMENDATIONS? 11

A. Yes. SPS anticipates that it would file to change the wholesale transmission depreciation 12

rates if the Depreciation Study results are adopted in the SPS retail jurisdictions. As I 13

understand, this change would require a future filing to the Commission, where the 14

affected customers could intervene and comment. 15

C. Reserve Reallocation

Q. WHAT IS RESERVE REALLOCATION? 16

A. Reserve reallocation can be thought of as a true-up mechanism for the depreciation 17

reserve. The actual reserve within a functional property class is reallocated between 18

accounts. In this manner, the reserve for each account is adjusted so that it is closer to its 19

theoretical reserve. The theoretical reserve is calculated based on current assumptions for 20

the assets regarding the average age, average service lives, survival curve, and net 21

salvage percentages or amounts as if they had been used throughout the life of the 22


property group. Comparing the reallocated book reserve with the theoretical reserve 1

based on proposed parameters from the Depreciation Study indicates a reserve deficit. 2

As previously summarized, the impact due to the reserve deficiency is a $3.5 million 3

increase to annual depreciation expense. This is aligned with how the “Commission has 4

addressed any alleged excess or deficiency in depreciation reserves through adjustment of 5

depreciation rates that eliminate such excess or deficiency over the remaining life of a 6

utility’s plant.”3 7

Q. IS REALLOCATING THE DEPRECIATION RESERVE AMONG PLANT 8

ACCOUNTS AN ACCEPTED PRACTICE IN DEPRECIATION ACCOUNTING? 9

A. Yes. As explained in the Watson Direct Testimony, the practice of reserve reallocation 10

has been endorsed by the National Association of Regulatory Utility Commissioners in 11

its publication, "Public Utility Depreciation Practices," where appropriate to realign the 12

depreciation reserve positions of the accounts to better match the life characteristics of 13

the assets. 14

Q. HAS THE COMMISSION PREVIOUSLY ALLOWED FOR THE 15

REALLOCATION OF THE COMPANY’S DEPRECIATION RESERVE IN 16

SETTING DEPRECIATION RATES FOR THE COMPANY’S PLANT ASSETS? 17

A. Yes. The theoretical reserve calculation and the reallocation of reserve calculation are 18

the same type of calculations used in developing the electric production and general 19

depreciation rates included in the settlement approved by the Commission in Docket No. 20

ER15-949-000. In addition, the Company proposed (and my direct testimony supported) 21

a reserve allocation within electric generation accounts associated with the retirement of 22

3 See Florida Power Corp., et al., 134 FERC ¶ 61,145 at P 10 n. 44 (2011).


the SPS Carlsbad Generating Station in Docket No. ER18-228-000. As I understand, the 1

latter filing is pending final Commission action. 2

IV. EFFECT OF 2017 TAX CUTS AND JOBS ACT

Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY? 3

A. In this section of my testimony, I explain the effects that certain provisions of the TCJA 4

will have on the deferred taxes associated with the Company’s plant assets and thus on 5

the revenue requirement calculations in this proceeding. I also explain how generally 6

accepted accounting principles (“GAAP”) direct the determination of the effect of the 7

TCJA on plant assets. 8

Q. PLEASE PROVIDE A SUMMARY OF THE TCJA AND ITS EFFECT ON THE 9

DEFERRED TAXES ASSOCIATED WITH PLANT ASSETS OF A REGULATED 10

ENTITY. 11

A. The primary provision of the TCJA that will affect the SPS transmission revenue 12

requirement calculation related to plant assets in this proceeding is the reduction of the 13

federal corporate income tax rate from 35 percent to 21 percent effective January 1, 2018. 14

The reduction in the federal corporate income tax rate affects the calculation of revenue 15

requirements by reducing the amount of current taxes calculated, reducing the gross up 16

factor, increasing the deferred tax calculated due to the flow-back of excess accumulated 17

deferred income taxes (“ADIT”), and lowering the ADIT net liability over time. 18

A. Accumulated Deferred Income Taxes – Plant Assets

Q. WHAT ARE DEFERRED TAXES? 19

A. At a high level, deferred taxes are a mechanism that tracks the temporary timing 20

differences between tax depreciation and deductions versus book depreciation. The 21


effect of this mechanism is to share the faster tax depreciation or deductions with all 1

customers throughout the life of the asset, such that the customers benefiting from the 2

asset in its first year of operation get the same tax benefit as the customers benefiting 3

from the asset in its last year of operation. This is referred to as normalization of the tax 4

benefits. The Internal Revenue Service (“IRS”) requires utilities to normalize the tax 5

benefits in order to use accelerated tax depreciation methods. Because of this IRS 6

requirement, the FERC approved normalization of the plant deferred taxes used in 7

ratemaking in Order No. 144.4 The calculation of deferred taxes in its simplest form is 8

the difference between tax depreciation and book depreciation, times the current tax rate. 9

Q. ARE THERE PLANT AND NON-PLANT DEFERRED TAXES? 10

A. Yes. My testimony addresses the ADIT related to plant assets, which are either 11

“protected” and “unprotected” plant assets. Company witness Mr. Freitas addresses the 12

ADIT related to non-plant assets, all of which are “unprotected” assets. 13

Q. HAS THE TCJA REDUCTION IN THE FEDERAL CORPORATE INCOME TAX 14

RATE AFFECTED DEFERRED TAX BALANCES? 15

A. Yes, from a financial reporting perspective, but not from a ratemaking perspective. All 16

ADIT asset and liability balances existing at December 31, 2017 were recalculated at the 17

21 percent federal corporate income tax rate for purposes of financial reporting under 18

GAAP. 19

The difference between the net ADIT liability at the former 35 percent federal 20

income tax rate and net ADIT liability at the lower 21 percent federal income tax rate 21

4 Tax Normalization for Certain Items Reflecting Timing Differences in the Recognition of Expenses or Revenues for Ratemaking and Income Tax Purposes, Order No. 144, FERC Stats. & Regs. ¶ 30,254 (1981), order on reh’g, Order No. 144-A, FERC Stats. & Regs. ¶ 30,340 (1982).


created a net regulatory liability,5 referred to as “excess” ADIT. For ratemaking 1

purposes, the regulatory liability created for plant-related excess ADIT is presented as 2

part of the total net ADIT liability balance when calculating rate base. This assures that 3

the rate base is not immediately increased with a tax rate change. Plant excess ADIT for 4

SPS totals $230.7 million as of December 31, 2017 for transmission, general, and 5

intangible assets on a total Company basis. 6

In addition, for deferred income tax expense arising after the TCJA enactment 7

date (i.e., additions to ADIT in 2018 and afterward), the deferred tax expense will be 8

determined using the lower 21 percent federal corporate income tax rate, resulting in a 9

lower ADIT balance than would have existed prior to the tax rate change. 10

B. Company Proposal

Q. HOW IS THE COMPANY PROPOSING TO RETURN THIS EXCESS ADIT TO 11

CUSTOMERS? 12

A. The plant excess ADIT balance for both “protected” and “unprotected” plant is returned 13

to customers using ARAM. The TCJA provides that plant excess ADIT cannot be used 14

to reduce the cost of service more rapidly than the rate at which the timing differences 15

reverse over the life of the related property. Because the federal corporate tax rate 16

change is a tax benefit, and because the tax benefits of accelerated depreciation methods 17

are shared by all customers benefiting from the asset through deferred taxes, the tax rate 18

benefit is provided to all customers through the use of ARAM. The return of the plant 19

excess ADIT to customers through ARAM effectively increases the deferred taxes by this 20

ARAM amount, also known as ARAM amortization, or the flow-back of excess ADIT. 21

5 The net of ADIT assets and ADIT liabilities is referred to as the “ADIT net liability.”


Therefore, when the income taxes are calculated for revenue requirements, current and 1

deferred taxes do not equal one another and the net of the current and deferred taxes 2

create a reduction to revenue requirements equal to this ARAM amortization. 3

Q. PLEASE EXPLAIN IN MORE DETAIL HOW ARAM IS CALCULATED. 4

A. Plant ADIT net liability balances arise primarily due to accelerated timing of tax 5

depreciation as compared to book depreciation. When tax depreciation is greater than 6

book depreciation, the ADIT liability balance is increasing, or “setting up.” When tax 7

depreciation is less than book depreciation, typically later in an asset’s life, the ADIT 8

liability balance for that asset is getting smaller, or “unwinding.” ARAM is a method 9

that calculates an average tax rate from all the tax rates used up to the point when the 10

ADIT balance begins unwinding, and uses this average tax rate to unwind the ADIT to 11

zero. 12

For transmission assets that were in-service prior to the January 1, 2018 effective 13

date of the new TCJA federal tax rate but for which the ADIT has not yet begun 14

unwinding, annual deferred tax expense will be calculated at the current rate, and the 15

accumulated deferred balance will continue increasing. When the deferred tax balance 16

stops increasing and starts decreasing, the annual deferred tax calculation will switch 17

from using the current tax rate to using the average of the tax rates applied up to this 18

point, which ensures that the vintage deferred record will unwind to zero over the 19

remaining life. 20

For assets that were in-service before January 1, 2018 and for which the ADIT 21

has already begun unwinding (meaning book depreciation is greater than tax 22

depreciation), the annual deferred tax expense calculations will never use the new federal 23


tax rate of 21 percent. Instead, the assets will use an average of the composite tax rates 1

based on the historical 35 percent federal rate to unwind their accumulated deferred 2

balances. 3

Finally, for assets that are placed in-service after January 1, 2018, the deferred 4

taxes will be calculated entirely at the new federal tax rate going forward. These assets 5

have no excess ADIT, and thus no excess to flow back to customers. 6

Two examples have been provided in Exhibit No. SPS-0009 to show the deferred 7

tax expense calculation for: (1) an asset whose ADIT liability was still growing at the 8

time of a tax rate change; and (2) an asset whose ADIT liability was already unwinding at 9

the time of the tax rate change. 10

Q. IS SPS REQUIRED TO USE ARAM TO RETURN THE PLANT EXCESS ADIT 11

BALANCE TO CUSTOMERS? 12

A. The TCJA contains an alternative method for certain taxpayers that may be used if the 13

taxpayer’s books and underlying records do not contain vintage account data necessary to 14

apply ARAM.6 Since SPS maintains its utility property records with adequate vintage 15

account data to use ARAM, SPS is required to use ARAM for “protected” plant-related 16

excess ADIT. All plant-related excess ADIT should be returned using ARAM regardless 17

whether the IRS categorizes the excess as “protected” or “unprotected,” which would 18

return the excess ADIT over the average remaining lives of the assets. 19

6 If the books and records of public utilities and interstate pipelines do not contain the vintage data necessary to apply ARAM, they are required to use an alternative method, e.g., the Reverse South Georgia Method.


Q. WHAT IS MEANT BY THE TERMS “PROTECTED” AND “UNPROTECTED” 1

AND EXPLAIN HOW THESE CONCEPTS RELATE TO PLANT-RELATED 2

EXCESS ADIT. 3

A. There are generally two categories of excess ADIT — protected (IRS normalization rules 4

apply) and unprotected (IRS does not demand normalization).7 In turn, either protected 5

or unprotected excess ADIT can relate to plant-related or non-plant-related excess ADIT. 6

Most of SPS’s excess ADIT (approximately 92 percent) relates to accelerated 7

depreciation on plant, which is “protected” by normalization rules under IRS regulations 8

and other guidance. That excess ADIT must be returned to customers using ARAM. 9

The remainder of the plant excess ADIT balances, which comprises a minimal 10

amount of SPS’s plant-related excess ADIT balance, is related to other tax deductions 11

and timing differences, such as tax repairs deductions or contributions in aid of 12

construction, and is not “protected” by IRS normalization requirements (thus, it is 13

referred to as “unprotected”). The split between protected and unprotected excess ADIT 14

for the transmission, general, and intangible assets is provided below in Table 3. 15

Table 3: Protected and Unprotected Plant Excess ADIT 16

Excess ADITPercentage

of Total

Protected $211,335,933 91.6%Unprotected 19,332,743 8.4%

Total $230,668,676 100.0%

Q. WHY IS IT APPROPRIATE TO USE ARAM TO RETURN ALL PLANT-17

RELATED EXCESS ADIT TO CUSTOMERS? 18

7 Section 1.167(l)-1(h)(6) of the IRS Regulations sets forth further normalization requirements with respect to public utility property.


A. SPS recommends this approach because it is consistent with SPS’s historical practice of 1

normalizing all plant-related deferred taxes to effectively share the current tax benefits 2

with all future customers that also will be served by the assets. Because the change in tax 3

rate created a tax benefit in the form of excess deferred taxes, under the ARAM these 4

excess deferred taxes are used to reduce the cost of service no more rapidly than the rate 5

at which the timing differences reverse over the life of the related property. Returning 6

excess deferred taxes in this manner normalizes the timing difference between book and 7

tax accounting and ensures tax benefits are shared with all customers who benefit from 8

the asset, rather than giving all the tax benefits to customers in the early phases of the 9

asset’s life and no benefit to customers in the later years of the asset’s life. In fact, 10

because transmission plant lives are long, customers in the later years of service life 11

would be denied a portion of this tax benefit if the Commission were to use a method 12

other than ARAM, which is tied to the assets’ lives, for unprotected plant. Stated another 13

way, any small financial benefit to customers today would not be meaningful, whereas 14

the added complexity of a timing mismatch and the harm to future customers support 15

continuing use of the ARAM. Thus, it is important to treat unprotected balances for all 16

plant-related items in a reasonable and consistent manner that ensures the costs are spread 17

equitably across the average remaining useful life of the plant. 18

Q. WHAT IS THE CALCULATED ARAM AMORTIZATION FOR 2018? 19

A. The deferred income tax expense associated with ARAM on the excess deferred income 20

21 tax balance related to transmission assets, including general and intangible assets, is

calculated to be $4.7 million in 2018 for SPS on a total Company basis. 22


V. CONCLUSION


A. I recommend that the Commission: 2

• Approve SPS’s proposed depreciation rates for transmission plant reflected in Exhibit3

No. SPS-0008, as supported by the Depreciation Study, and authorize them to go into4

effect beginning February 1, 2019;5

• Approve SPS’s proposed reserve reallocation for transmission plant accounts6

performed as part of the Depreciation Study; and7

• Approve SPS’s use of ARAM amortization of excess ADIT for both protected and8

unprotected plant-related assets.9


A. Yes. 11

Exhibit No. SPS-0008 (Comparison of Trans Depr Rates)


Proposed Difference

FERC Account DescriptionDepreciation

Rate NoteDepreciation

Rate Depreciation Rate

350.2 LAND RIGHTS 2.0000% (B) 1.2883% -0.7117%352 STRUCTURES AND IMPROVEMENTS 2.0140% (A) 1.7847% -0.2293%353 STATION EQUIPMENT 1.8840% (A) 2.2737% 0.3897%354 TOWERS AND FIXTURES 1.2510% (A) 1.5994% 0.3484%355 POLES AND FIXTURES 2.0050% (A) 3.0161% 1.0111%356 OVERHEAD CONDUCTORS AND DEVICES 1.9740% (A) 2.9388% 0.9648%357 UNDERGROUND CONDUIT 1.2420% (A) 1.8509% 0.6089%358 UNDERGROUND CONDUCTORS AND DEVICES 1.7270% (A) 3.0132% 1.2862%359 ROADS AND TRAILS 2.0140% (C) 1.5590% -0.4550%

(A) Depreciation rates from Docket No. EL89-50-000 settlement. (B) SPS amortizes land and water rights over 50 years(C) SPS is currently using approved FERC Account 352 depreciation rates for FERC Account 359

Southwestern Public Service Company - FERCComparison of Depreciation Rates

Current

Exhibit No. SPS-0009 (Deferred Tax Exp Calc Examples)


Average Rate Assumption Method (ARAM)

Change in Tax Rate - Before ADIT Set Up is Complete

Plant Asset = $100

Year Tax

Depreciation Book

Depreciation Timing Difference Tax Rate

Deferred Expense

ADIT

(A) (B) (A)-(B)= (C) (D) (C )*(D)= (E)1 40 10 30 35% 11 11 2 30 10 20 21% (1) 4 15 3 15 10 5 21% 1 16 4 10 10 - 21% - 16 5 5 10 (5) 29% (2) (1) 14 6 - 10 (10) 29% (2) (3) 11 7 - 10 (10) 29% (2) (3) 9 8 - 10 (10) 29% (2) (3) 6 9 - 10 (10) 29% (2) (3) 3

10 - 10 (10) 29% (2) (3) -

100 100 - -

(1) Tax rate change from 35% to 21% occurs in Year 2 of asset's life

Change in Tax Rate - After ADIT Set Up is Complete

Plant Asset = $100

Year Tax

Depreciation Book

Depreciation Timing Difference Tax Rate

Deferred Expense

ADIT

(A) (B) (A)-(B)= (C) (D) (C )*(D)= (E)1 40 10 30 35% 11 11 2 30 10 20 35% 7 18 3 15 10 5 35% 2 19 4 10 10 - 21% (1) - 19 5 5 10 (5) 35% (2) (2) 18 6 - 10 (10) 35% (4) 14 7 - 10 (10) 35% (4) 11 8 - 10 (10) 35% (4) 7 9 - 10 (10) 35% (4) 4

10 - 10 (10) 35% (4) -

100 100 - -

(2) Average rate is used to unwind deferred tax liability over remaining life of asset. This is an average of the 35% and 21% rates used to calculated deferred tax expense for the years when tax depreciation was greater than book depreciation

(2) Average rate is used to unwind deferred tax liability over remaining life of asset, which is 35% since the tax rate change occured after the ADIT balance had finished setting up.

(1) Tax rate change from 35% to 21% occurs in Year 4 of asset's life

Southwestern Public Service Company - FERCDeferred Tax Expense Calculation Examples




FEDERAL ENERGY REGULATORY COMMISSION

Southwestern Public Service Company ) Docket No. ER19-____-000 )

DIRECT TESTIMONY OF

DANE A. WATSON


NOVEMBER 27, 2018


DIRECT TESTIMONY OF DANE A. WATSON

TABLE OF CONTENTS

I. INTRODUCTION AND EXPERIENCE ............................................................................1

II. PURPOSE OF TESTIMONY ..............................................................................................3

III. DEPRECIATION RATE UPDATE ....................................................................................5

IV. SPS BOOK DEPRECIATION STUDY ..............................................................................8

A. Summary of the SPS Study .............................................................................................8

B. Overview of Depreciation Study Method .....................................................................12

C. Life of Transmission Assets ..........................................................................................13

D. Net Salvage of Transmission Assets .............................................................................17

E. Reserve Reallocation .....................................................................................................17

V. CONCLUSION ........................................................................................................................25


EXHIBITS TO DIRECT TESTIMONY OF DANE A. WATSON


SPS – 0011

Dane A. Watson – List of Regulatory Appearances

SPS – 0012

Southwestern Public Service Company Book Depreciation Accrual Rate Study at June 30, 2018




Summary of the Direct Testimony of Dane A. Watson

Mr. Watson’s Direct Testimony on behalf of Southwestern Public Service Company

(“SPS”) supports the changes to the depreciation rates included in the Transmission function.

Mr. Watson explains that the changes to the SPS transmission depreciation rates from the

currently effective Transmission function depreciation rates established in the settlement in

Docket Nos. EL89-50-000, et al., are supported by a Southwestern Public Service Company

Transmission Accrual Rate Study at June 30, 2018.


DIRECT TESTIMONY OF

DANE A. WATSON



A. My name is Dane A. Watson. My business address is 101 E. Park Blvd., Suite 220, 2

Plano, Texas 75074. 3


A. I am a Partner of Alliance Consulting Group. Alliance Consulting Group provides 5

consulting and expert services to the utility industry. 6


A. I am filing testimony on behalf of Southwestern Public Service Company, a New Mexico 8

corporation (“SPS” or “Company”) and a wholly owned electric utility subsidiary of Xcel 9

Energy Inc. 10



A. I hold a Bachelor of Science degree in Electrical Engineering from the University of 13

Arkansas at Fayetteville and a Master's Degree in Business Administration from 14

Amberton University. 15

Since graduation from college in 1985, I have worked in the area of depreciation 16

and valuation. I founded Alliance Consulting Group in 2004 and am responsible for 17

conducting depreciation, valuation, and certain accounting-related studies for clients in 18

various industries. My duties related to depreciation studies include the assembly and 19


analysis of historical and simulated data, conducting field reviews, determining service 1

life and net salvage estimates, calculating annual depreciation, presenting recommended 2

depreciation rates to utility management for its consideration, and supporting such rates 3

before regulatory bodies. 4

My prior employment from 1985 to 2004 was with Texas Utilities Electric 5

Company and successor companies (“TXU”). During my tenure with TXU, I was 6

responsible for, among other things, conducting valuation and depreciation studies for the 7

domestic TXU companies. During that time, I served as Manager of Property 8

Accounting Services and Records Management in addition to my depreciation 9

responsibilities. 10

I have twice been Chair of the Edison Electric Institute (“EEI”) Property 11

Accounting and Valuation Committee and have been Chairman of EEI’s Depreciation 12

and Economic Issues Subcommittee. I am a Registered Professional Engineer in the 13

State of Texas and a Certified Depreciation Professional. I am a Senior Member of the 14

Institute of Electrical and Electronics Engineers (“IEEE”) and served for several years as 15

an officer of the Executive Board of the Dallas Section of IEEE as well as national and 16

worldwide offices. I have served as President of the Society of Depreciation 17

Professionals (“SDP”) twice. 18


A. In my current position, I serve as Managing Partner of Alliance Consulting Group. I 20

provide depreciation and valuation services to clients in the utility industry, including 21

electric, natural gas, water and wastewater, as well as telecommunication assets. 22


Q. HAVE YOU PREVIOUSLY SUBMITTED TESTIMONY BEFORE THE 1

FEDERAL ENERGY REGULATORY COMMISSION? 2

A. Yes. I have presented testimony before the Federal Energy Regulatory Commission 3

(“FERC” or “Commission”) in fourteen different cases on behalf of various natural gas 4

and electric companies. I have conducted depreciation studies and filed testimony or 5

testified on depreciation and valuation issues in more than 170 proceedings before 6

various regulatory bodies, including several SPS proceedings before the Public Utility 7

Commission of Texas (“PUCT”) and New Mexico Public Regulation Commission 8

(“NMPRC”), respectively. I am thus very familiar with SPS’s facilities and depreciation 9

practices. A complete listing of those proceedings is listed in my Exhibit No. SPS-0011. 10

Q. WAS THIS TESTIMONY PREPARED BY YOU OR UNDER YOUR DIRECT 11

SUPERVISION? 12

A. Yes. 13



A. The purpose of my testimony is to: 15

• Discuss the recent SPS Transmission Book Depreciation Study at June 30, 2018 16 for SPS Transmission function assets (“Depreciation Study”); and 17

• Support the recommended depreciation rate changes for SPS transmission plant 18 based on the results of the Depreciation Study. 19

Q. PLEASE SUMMARIZE YOUR CONCLUSIONS REGARDING DEPRECIATION 20

RATE CHANGES FOR SPS’S TRANSMISSION ASSETS BASED ON THE 21

RESULTS OF THE DEPRECIATION STUDY. 22

A. The Depreciation Study and analysis performed under my supervision fully support 23


SPS’s proposed depreciation rates applied to June 30, 2018 depreciable plant balances for 1

SPS Transmission assets. The Depreciation Study follows the Commission’s long-2

standing precedent of a Straight-line, Average Life Group (“ALG”), Remaining Life 3

depreciation system. In this way, all customers are charged for their appropriate share of 4

the capital expended for their benefit. 5

SPS’s existing depreciation rates for Transmission assets were established by a 6

settlement in FERC Docket Nos. EL89-50-000, et al. In the years since the depreciation 7

rates were established in Docket Nos. EL89-50-000, et al., there have been significant 8

increases in the cost of removal due to changes in labor rates, environmental disposal 9

requirements, and many other factors discussed later in my testimony. Increased removal 10

costs affect negative salvage rates, and in turn the recommended depreciation rates. 11

Other factors also affect the recommended rates, however, and are discussed in detail in 12

my testimony. The Depreciation Study updates the nearly 30-year old depreciation rates 13

based on recent experience. The Depreciation Study updates life and net salvage 14

parameters for SPS’s Transmission assets. To ensure intergenerational equities, the 15

Commission should adopt the life and net salvage parameters proposed in this study. 16

Q. ARE YOU SPONSORING ANY EXHIBITS? 17

A. Yes. I am sponsoring two exhibits. Exhibit No. SPS-0011 is a listing of my appearances 18

before various regulatory bodies. Exhibit No. SPS-0012 is the Depreciation Study, titled 19

“Southwestern Public Service Company Book Depreciation Accrual Rate Study at June 20

30, 2018.” 21


III. DEPRECIATION RATE UPDATE

Q. PLEASE DESCRIBE THE DEPRECIATION ANALYSIS PHILOSOPHY 1

REFLECTED IN THE DEPRECIATION STUDY. 2

A. The objective of any sound depreciation philosophy should be the matching of expense 3

with revenue over the life of the asset. In general, the life of the asset is determined by 4

several factors including the rate of physical deterioration, obsolescence, weather, 5

maintenance, or (in some cases) the economic usefulness of an entire operating unit. The 6

function of depreciation is to recognize the cost of an asset spread over its useful life. 7

Book depreciation techniques should not accelerate or defer the recovery of an asset in 8

comparison to its appropriate useful life. 9

Q. WHAT OBJECTIVE SHOULD THE COMMISSION STRIVE TO ACHIEVE IN 10

SETTING DEPRECIATION RATES? 11

A. The objective of computing depreciation is to ensure that all customers using the assets 12

pay their reasonable share for the investment, including the cost of retirement. This 13

objective is achieved by allocating the cost or depreciable base of a group of assets over 14

the service life of those assets, on a straight-line basis, by charging a portion of the 15

consumption of the assets to each accounting period. 16

Q. IS THIS OBJECTIVE CONSISTENT WITH COMMISSION RULES AND 17

HISTORIC PRACTICE? 18

A. Yes. As evidenced by the Commission’s prior rate decisions, the Commission has a 19

long-standing practice of establishing depreciation rates using the straight-line 20

depreciation method based on the actual historic data of the utility. As stated in Public 21

Utility Depreciation Practices published by the National Association of Regulatory 22


Utility Commissioners (“NARUC”), “In utility accounting, depreciation is usually 1

combined on a straight line, group method.”1 The straight-line method of depreciation 2

operates by collecting a proportional share of the cost of the investment, including 3

removal cost, from all customers that use the asset over its useful life. 4

Q. WHAT IS THE BEST EVIDENCE THAT THE COMMISSION CAN RELY ON 5

TO ENSURE THAT THE COST OF CERTAIN ASSETS ARE RATABLY 6

RECOVERED OVER THE SERVICE LIFE OF THE ACCOUNT? 7

A. The best evidence is the actual experience of the specific group of assets being analyzed. 8

This evidence is found in the Depreciation Study based on plant investment in service at 9

June 30, 2018 shown in my Exhibit No. SPS-0012. 10

Q. WHAT IS NET SALVAGE? 11

A. As defined in the Uniform System of Accounts, net salvage means the “salvage value of 12

property retired less the cost of removal.”2 The Commission defines cost of removal as 13

“the cost of demolishing, dismantling, tearing down or otherwise removing electric plant, 14

including the cost of transportation and handling incidental thereto.”3 In the case of SPS, 15

the cost of removal for its transmission assets has risen from levels established when the 16

current depreciation rates were established in Docket Nos. EL89-50-000, et al. 17

1 National Association of Regulatory Utility Commissioners, Depreciation Subcommittee, Public

Utility Depreciation Practices 45 (1996). 2 18 C.F.R. pt. 101, Definition 19. Net salvage value (2018). 3 18 C.F.R. pt. 101, Definition 10. Cost of removal (2018).


Q. WHAT HAPPENS WHEN DEPRECIATION RATES ARE NOT ADJUSTED TO 1

REFLECT THE ACTUAL LIFE AND NET SALVAGE CHARACTERISTICS OF 2

THE ASSETS? 3

A. When depreciation rates are set at a level that does not reflect the actual life and 4

retirement characteristics of a utility’s assets, the cost of the asset will not be recovered 5

on a reasonable basis from all customers that use the asset. For example, in instances 6

where the net salvage rate for certain plant accounts is set at a level that is insufficient 7

under current conditions to recover the cost of the asset, the asset owner will not accrue a 8

reasonable level of removal cost over the useful life of the plant asset. This, in turn, 9

means that future customers will have to pay a disproportionate share of the removal 10

costs to make up for the payment deferrals. 11

Q. ARE YOUR RECOMMENDED DEPRECIATION RATES ADJUSTED TO 12

REFLECT THE MORE RECENT LIFE AND NET SALVAGE 13

CHARACTERISTICS OF THE ASSETS? 14

A. Yes. SPS is currently using depreciation life and net salvage parameters that were 15

established nearly three decades ago in the settlement of FERC Docket Nos. EL89-50-16

000, et al. My proposed depreciation rates adjust the service life and net salvage 17

estimates for SPS’s Transmission assets based on current experience and expectations. 18

Q. WHAT RATEMAKING ACTIONS ARE WARRANTED TO REFLECT THE 19

CHANGES IN LIFE AND NET SALVAGE FOR SPS’S TRANSMISSION 20

ASSETS? 21

A. The Commission should approve SPS’s proposed depreciation rates because they more 22

accurately reflect service lives and net salvage characteristics for SPS’s Transmission 23


assets. The depreciation rates proposed in my Exhibit No. SPS-0012 more accurately 1

reflect SPS’s current experience and future expectations and also allow for the recovery 2

of the appropriate level of depreciation expense. In addition, adoption of the proposed 3

depreciation rates should ensure, going forward, that SPS’s wholesale transmission 4

service customers pay a reasonable share of the investment over the remaining life of the 5

investment. This ensures that future customers are not unduly burdened by having to pay 6

a disproportionate share of any remaining investment balance for the changes of the 7

asset’s useful life and net salvage parameters. 8

IV. SPS BOOK DEPRECIATION STUDY

A. Summary of the SPS Depreciation Study

Q. HAVE YOU PREPARED A BOOK DEPRECIATION STUDY FOR SPS 9

TRANSMISSION ASSETS? 10

A. Yes. I undertook an analysis of annual depreciation for SPS’s Transmission depreciable 11

plant as of June 30, 2018. The Depreciation Study is attached to my testimony as Exhibit 12

No. SPS–0012. 13

Q. WHAT DEPRECIATION RATES ARE RECOMMENDED IN THIS 14

PROCEEDING? 15

A. The recommended depreciation rates for Transmission assets are provided in Appendices 16

A and B of the Depreciation Study. Based on updated service life and net salvage 17

estimates for Transmission plant as of June 30, 2018, I derived the appropriate 18

depreciation rates for SPS’s Transmission assets. 19


Q. WHAT DATA SOURCES DID YOU USE TO COMPUTE THE DEPRECIATION 1

RATES? 2

A. To determine the lives for the various asset groups, I used total Company plant in service 3

and historic data regarding additions, retirements, transfers and adjustments. To 4

determine the net salvage factors, I used total Company experience for gross salvage and 5

removal cost by plant account. SPS charges cost-of-service rates that are subject to the 6

jurisdiction of FERC, the PUCT and NMPRC. SPS separately accounts for accumulated 7

depreciation in each of these jurisdictions. At the FERC-jurisdictional level, SPS’s 8

accumulated depreciation accounts reflect depreciation accruals specifically approved by 9

FERC. The Company’s FERC wholesale transmission jurisdiction accumulated 10

depreciation reserves vary from those maintained by SPS at the state level (which 11

incorporate depreciation accruals approved by the PUCT and NMPRC). To compute 12

depreciation rates, I used total plant in service and the FERC-specific depreciation 13

reserves. 14

Q. WHEN DID THE LAST CHANGE IN SPS’S COMMISSION-APPROVED 15

TRANSMISSION DEPRECIATION RATES OCCUR? 16

A. SPS’s existing depreciation rates for Transmission assets were established by a July 31, 17

1990 settlement agreement approved by the Commission on October 10, 1990 in 18

Southwestern Public Service Company, Letter Order, Docket Nos. EL89-50-000, et al. In 19

that proceeding, SPS submitted a 1988 depreciation study as the basis for its proposed 20

depreciation rates, and Section IV(c) of the settlement agreement provided that 21

“Southwestern will book its applicable depreciation expense based on its 1988 22

depreciation study…”. As I understand it, the Commission order did not approve the 23


1988 depreciation study, but approved the depreciation rates as set forth in the settlement 1

agreement, which reflected the 1988 study. 2

Because nearly 30 years have passed since the current SPS wholesale 3

Transmission depreciation rates were approved, it is necessary to update the FERC 4

jurisdictional depreciation rates for SPS Transmission assets. 5

Q. WHAT ARE THE TRANSMISSION DEPRECIATION RATES SPS IS 6

PROPOSING TO PLACE INTO EFFECT ON FEBRUARY 1, 2019? 7

A. The existing versus proposed depreciation states are shown in Table 1 below. 8

TABLE 1 9 Proposed Depreciation Rates 10

Plant Account Existing Depr Rate % Proposed Depr Rate %

350.2 Land Rights 2.0000% 1.2883% 352 Structures and Improvement 2.0140% 1.7847% 353 Station Equipment 1.8840% 2.2737% 354 Towers and Fixtures 1.2510% 1.5994% 355 Poles and Fixtures 2.0050% 3.0161% 356 Overhead Conductors and Devices 1.9740% 2.9388% 357 Underground Conduit 1.2420% 1.8509% 358 Underground Conductors & Devices 1.7270% 3.0132% 359 Roads and Trails 2.0140% 1.5590%

As demonstrated by Table 1, SPS is proposing to reduce certain Transmission 11

depreciation rates, but increase most rates, based on the results of the Depreciation Study. 12

Q. PLEASE DESCRIBE THE RESULTS OF THE DEPRECIATION STUDY. 13

A. The results of the analysis conducted in the Depreciation Study, based on the service life 14

of Transmission plant and the revised net salvage rates, resulted in an increase to SPS’s 15

depreciation rates for most Transmission plant. SPS’s present depreciation rates were 16


compared to the Depreciation Study recommendations in Appendix B of Exhibit No. 1

SPS-0012. The rates proposed for Transmission assets result in an increase of 2

approximately $18.6 million in annual depreciation expenses on a system basis compared 3

to expenses under SPS’s present Docket Nos. EL89-50-000, et al., depreciation rates. 4

Q. PLEASE DESCRIBE THE MAJOR CHANGES THAT RESULTED IN THE 5

CHANGES IN DEPRECIATION RATES FOR TRANSMISSION PROPERTY. 6

A. Changes in service life, gross salvage, gross removal costs, curve selection, and 7

adjustments due to the depreciation reserve position are all factors that affect the 8

calculation of the depreciation accrual. The proposed changes in the Depreciation Study 9

analysis for Transmission assets support adjustments that both increase and decrease the 10

total accrual. However, one of the factors influenced the accrual calculation notably and 11

consistently in one direction: most of the increase in depreciation expense for 12

Transmission assets can be attributed to the effect of changes to net salvage rates. 13

In the nearly thirty years since the Docket Nos. EL89-50-000, et al., depreciation 14

rates were established, there have been significant increases in the cost of removal, but 15

there have been no commensurate increases in gross salvage value. Removal cost has 16

increased much more rapidly than gross salvage due to changes in labor rates, 17

environmental disposal requirements, and many other factors discussed in the net salvage 18

portion of this testimony. Of the nine plant accounts in Transmission, six accounts 19

exhibited more negative net salvage, two accounts retained the existing net salvage 20

estimate, and one account showed less negative net salvage. When net salvage becomes 21

increasingly negative, depreciation expense increases over previous levels. The 22


Commission should approve the net salvage parameters proposed in the Depreciation 1

Study to provide SPS straight-line asset recovery and prevent intergenerational inequities. 2

B. Overview of Depreciation Study Method

Q. WHAT DEFINITION OF DEPRECIATION WAS USED IN PREPARING THE 3

DEPRECIATION STUDY AND THIS TESTIMONY? 4

A. The term “depreciation,” as I use it and as it was used in preparing the Depreciation 5

Study, is a system of accounting that distributes the cost of assets, less net salvage (if 6

any), over the estimated useful life of the assets in a systematic and rational manner. It is 7

a process of allocation, not valuation. Depreciation expense is systematically allocated to 8

accounting periods over the life of the assets. The amount allocated to any one 9

accounting period does not necessarily represent the loss or decrease in value that will 10

occur during that particular period. Thus, depreciation is considered an expense or cost, 11

rather than a loss or decrease in value. SPS accrues depreciation based on the original 12

cost of all property included in each depreciable plant account. On retirement, the full 13

cost of depreciable property, less any net salvage amount (positive or negative), is 14

charged to the depreciation reserve. 15

Q. PLEASE DESCRIBE YOUR DEPRECIATION STUDY APPROACH. 16

A. I conducted the Depreciation Study in four phases, as described in Exhibit No. SPS-0012. 17

(See the Depreciation Study Process section on pages 12-14). The four phases are: Data 18

Collection, Analysis, Evaluation, and Calculation. I began each of the studies by 19

collecting the historical data to be used in the analysis. After the data had been 20

assembled, I performed analyses to determine the life and net salvage percentage for the 21

different property groups being studied. As part of the process for the study, I conferred 22


with SPS and Xcel Energy Services Inc. personnel responsible for the installation, 1

operation, and removal of the assets to gain their input into the operation, maintenance, 2

and salvage of the assets. The information obtained from these field personnel, combined 3

with the study results, is then evaluated to determine how the results of the historical 4

asset activity analysis, in conjunction with SPS’s expected future plans, should be 5

applied. Using all of these resources, I then calculated the depreciation rate for each 6

function. 7

Q. WHAT PROPERTY IS INCLUDED IN THE DEPRECIATION STUDY? 8

A. There is one distinct class of property in this study: Transmission Property. The 9

Transmission plant functional group consists of structures, substations, and transmission 10

lines used in the transmission of energy to the distribution system. 11

Q. WHAT DEPRECIATION METHODOLOGY DID YOU USE? 12

A. The ALG, straight-line, remaining-life depreciation system was employed to calculate 13

annual and accrued depreciation in the studies for all plant. The ALG methodology is the 14

same method used in prior studies and has been approved by this Commission in prior 15

dockets both for SPS and other companies across the United States. 16

C. Life of Transmission Assets

Q. WHAT IS THE SIGNIFICANCE OF AN ASSET’S USEFUL LIFE IN YOUR 17

DEPRECIATION STUDY? 18

A. An asset’s useful life is used to determine the remaining life over which the remaining 19

cost (original cost plus or minus net salvage, minus accumulated depreciation) can be 20

allocated to normalize the asset’s cost and spread it ratably over future periods. 21


Q. HOW DID YOU DETERMINE THE AVERAGE SERVICE LIVES FOR EACH 1

ACCOUNT? 2

A. The establishment of appropriate average service lives for each account within each 3

functional group was determined by using actuarial analysis. Actuarial analysis is the 4

preferred analysis tool when there are a sufficient number of transaction years available 5

to model an account. Graphs and tables supporting the actuarial analysis and the chosen 6

Iowa Curves (which represent the percentage of property remaining in service at various 7

age intervals) used to determine the average service lives for analyzed accounts are found 8

in the SPS Depreciation Study, Exhibit No. SPS-0012. As detailed in the study, I relied 9

on my judgment to incorporate any differences in the expected future life characteristics 10

of the assets into the selection of lives. The objective of life selection is to estimate the 11

future life characteristics of assets, not simply measure the historical life characteristics. 12

More information can be found in the life analysis section of the Depreciation Study. 13

Q. DOES YOUR DEPRECIATION STUDY REFLECT ANY CHANGES IN THE 14

USEFUL LIVES OF THE TRANSMISSION FUNCTION ASSETS FROM THE 15

LIVES EMBEDDED IN THE CURRENT DEPRECIATION RATES? 16

A. Yes. As shown in Appendix C of the Depreciation Study, six accounts have increases in 17

life and three accounts retain the same life estimate. The greatest change is an increase of 18

30 years in FERC Account 350.2. Table 2, set out below, shows the existing and 19

proposed lives for SPS’s Transmission assets, by account. 20


TABLE 2 1 Existing and Proposed Lives By Transmission Account 2

Plant Account Existing Life Proposed Life350.2 Land Rights 50 SQ 80 R4352 Structures and Improvement 50 R2 65 R4353 Station Equipment 50 R3 55 R2354 Towers and Fixtures 75 R3 75 R4355 Poles and Fixtures 45 R2.5 47 R3356 Overhead Conductors & Devices 45 R3 47 R2357 Underground Conduit 75 R3 75 R3358 Underground Conductors & Devices 45 R3 45 R3359 Roads and Trails 50 R2 65 R4

Q. HOW DO THE AVERAGE SERVICE LIVES YOU PROPOSE FOR THESE 3

ACCOUNTS COMPARE FOR LIFE PARAMETERS APPROVED BY THE 4

PUCT AND NMPRC REGULATORY BODIES? 5

A. The average service lives are similar for most of the accounts in this study as compared to 6

the approved lives in SPS’s two state jurisdictions, Texas and New Mexico. The 7

approved parameters will differ based on when each case is filed and the adjudication 8

which occurs in each jurisdiction. The parameters for Texas were most recently 9

adjudicated in PUCT Docket No. 436954 in December 2015, and the New Mexico 10

parameters were most recently adjudicated in NMPRC Docket 15-00296-UT5 in 2016. 11

Table 3, set out below, compares the Depreciation Study’s proposed average service live 12

with the service lives approved in Texas and New Mexico: 13

4 Based on data through June 2014 5 Based on data through December 2014. The NMPRC filing resulted in a stipulation agreement

that retained depreciation rates approved in a December 2011 depreciation study.


TABLE 3 1 Average Service Lives By Jurisdiction 2

Plant Account Proposed FERC Approved Texas

Approved New Mexico

350.2 Land Rights 80 80 80 352 Structures and Improvement 65 65 65 353 Station Equipment 55 57 57 354 Towers and Fixtures 75 75 75 355 Poles and Fixtures 47 53 51 356 Overhead Conductors & Devices 47 47 50 357 Underground Conduit 75 75 75 358 Underground Conductors & Devices 45 45 45 359 Roads and Trails 65 NA NA

As shown on Table 3, for Accounts 350.2, 352, 354, 357, and 358, the 3

Depreciation Study’s proposed average service lives are the same as the service lives 4

approved in Texas and New Mexico. For Accounts 353, 355, and 356, the Depreciation 5

Study’s proposed average service lives are slightly shorter than the service lives approved 6

in one or both the two retail jurisdictions. The Texas and New Mexico life parameters 7

were established based on early depreciation studies filed with the PUCT and NMPRC, 8

respectively. The Depreciation Study reflects more current information. The various 9

factors that have resulted in differences in the service lives approved in each jurisdiction 10

are discussed in the Depreciation Study. As discussed by Ms. Ostrom, SPS plans to file 11

the Depreciation Study with its retail commissions in 2019. If SPS’s proposed average 12

service lives are approved in each jurisdiction, then the slight differences seen in 13

Accounts 353, 355, and 356 will be eliminated. Account 359 did not exist at the time the 14

Texas and New Mexico studies were filed. 15


D. Net Salvage of Transmission Assets

Q. HOW DID YOU DETERMINE THE NET SALVAGE RATES USED IN YOUR 1

STUDY FOR TRANSMISSION PROPERTY? 2

A. I examined the experience realized by SPS by observing the average net salvage rates for 3

various bands (or combinations) of years. Using averages (such as the 5-year average 4

band) allows the smoothing of timing differences between when retirements, removal 5

cost, and salvage are booked. Using averages also smooths the natural variations 6

between years. By looking at successive average bands, or “rolling bands,” an analyst 7

can see trends in the data that shows the future net salvage for the account. This 8

examination, in combination with the feedback of SPS personnel related to any changes 9

in operations or maintenance that would affect the future net salvage of SPS, allowed for 10

the selection of the best estimate of future net salvage for each account. 11

Q. IS THIS A REASONABLE METHOD FOR DETERMINING NET SALVAGE 12

RATES? 13

A. Yes. This methodology is commonly employed throughout the industry and is the 14

method recommended in authoritative texts. 15

Q. DOES YOUR DEPRECIATION STUDY REFLECT ANY CHANGE IN THE NET 16

SALVAGE VALUES OF THE TRANSMISSION PROPERTY EMBEDDED IN 17

SPS’S CURRENT DEPRECIATION RATES? 18

A. Yes. As I explained earlier, the net salvage values for SPS’s Transmission property are 19

experiencing both increases in cost of removal, but gross salvage values have not 20

changed at the same rate as removal cost. Therefore, the Depreciation Study’s 21

recommended net salvage rates for these assets are more negative than the currently 22


approved rates. In the Depreciation Study, the net salvage values used in the calculation 1

of SPS’s Transmission property, along with the current net salvage values for 2

comparison, are listed in Appendix C, and a detailed computation of net salvage values is 3

included in Appendix D. Additionally, the Depreciation Study contains a detailed net 4

salvage analysis for SPS’s Transmission property, by account. 5

Q. PLEASE EXPLAIN WHY NET SALVAGE PERCENTAGES ARE BECOMING 6

MORE NEGATIVE. 7

A. Multiple factors are causing net salvage percentages to become more negative. Based on 8

my experience, and discussion with SPS personnel, these factors include: 9

• Time Value of Money. The transmission assets being retired are 40 or more years old in 10

many cases. The original cost of those assets installed so long ago was much lower than 11

the same assets being installed today. 12

• Environmental Regulations and Restrictions. The cost to remove assets from service 13

and/or demolition has increased due to increased regulation and restrictions related to 14

environmental impact, mitigation, and restoration measures. As discussed by Mr. Freitas, 15

the SPS service territory is located in the Panhandle and South Plains of Texas and 16

southern and eastern New Mexico, and covers approximately 52,000 square miles. 17

Equipment, labor, and other expenses will increase for assets located in hard-to-access 18

locations. Many construction or demolition permits require increased focus on 19

restoration of vegetation to a natural state that spans several growing seasons to restore. 20

All these requirements increase the cost of construction/demolition of transmission 21

assets. 22


• North American Electric Reliability Corporation (“NERC”) and FERC requirements. 1

SPS personnel indicated that increased regulation and requirements on operational and 2

planning standards increase the frequency of removal. The North American Electric 3

Reliability Corporation (“NERC”) may issue and the Commission then approve a 4

mandatory reliability standard that requires assets be removed before they are at the end 5

of their lives. An example is the clearance of transmission lines. As a result of a LiDAR 6

study6 conducted to satisfy NERC’s clearance standards, SPS had to remove existing 7

transmission lines and replace those lines with taller structures. 8

• Labor Costs. SPS labor costs have increased for the following reasons: (1) more NERC 9

and FERC operating requirements and standards; (2) increased regulation related to 10

operating standards that can require construction to occur in the evening or on weekends, 11

resulting in the need to pay for overtime of crews; (3) higher labor costs since the time 12

that the assets were installed, given that wages have increased for journeyman and 13

apprentices over the years; and (4) an increased demand for resources due to a general 14

shortage of licensed electrical workers, causing upwards price pressure on labor costs. 15

The increased demand for resources is the result of a limited number of qualified persons 16

available to perform the work in the face of increased construction and investment in 17

transmission facilities across the country in the last decade. The increases in capital 18

expenditures require utilities like SPS to augment their internal workforces with external 19

contract construction providers, who may come at a higher cost. 20

• Safety Requirements. The electric utility industry in general, and Xcel Energy Inc. in 21

particular, have emphasized the importance of employees complying with safe working 22

6 “LiDAR” is the acronym for “light detection and ranging.”


practices. The safety-related equipment and provisions required today have increased 1

substantially over the lives of SPS’s Transmission assets. This has increased the cost of 2

doing business. 3

• Increased Financial Controls. Over time, financial regulations have increased. SPS has 4

adopted best practices and incorporated cost and quality controls measures into the close 5

out of construction work orders. This provides more details about the costs associated 6

with demolition work compared to several years ago. Removal Work In Progress 7

(“RWIP”) varies year-by-year, but the information collected has improved since the 8

Company performed a thorough review of its accounting systems in 2007. 9

• Salvage Value. Many of the assets that are removed do not carry a high salvage value. 10

Some of the assets may be sold as scrap, but the scrap price is less than the cost of 11

installation and does not offset the assets’ removal costs. Assets that can be reused are 12

placed into inventory instead of being sold. In some cases, the assets being removed are 13

made of wood, which has no salvage value. 14

• Asset Renewal. Utilities across the nation, including SPS, are now dealing with an 15

antiquated, aging transmission infrastructure. Forty years ago, the transmission system 16

was much younger. It is now a necessity for utilities to have proactive asset renewal 17

programs to proactively replace transmission assets before they fail. The frequency of 18

projects requiring removal of existing assets has increased substantially over the last 19

decade, and will continue to increase into the future. 20


Q. PLEASE DESCRIBE HOW THE NET SALVAGE PERCENTAGES ARE 1

PROPOSED TO CHANGE FROM THE VALUES IN THE 1988 STUDY. 2

A. Table 4, set out below, shows the changes in net salvage: 3

TABLE 4 4 FERC Transmission Net Salvage Percentages 5

Existing and Proposed 6

Plant Account Existing Net Salvage %

Proposed Net Salvage %

350.2 Land Rights 0.00% 0.00% 352 Structures and Improvement -5.00% -10.00% 353 Station Equipment 0.00% -20.00% 354 Towers and Fixtures 0.00% -5.00% 355 Poles and Fixtures 5.00% -35.00% 356 Overhead Conductors & Devices 5.00% -30.00% 357 Underground Conduit 0.00% 0.00% 358 Underground Conductors & Devices 10.00% 0.00% 359 Roads and Trails -5.00% 0.00%

Q. HOW DO THE NET SALVAGE PERCENTAGES YOU PROPOSED FOR THESE 7

ACCOUNTS COMPARE FOR NET SALVAGE PERCENTAGES APPROVED BY 8

THE PUCT AND NMPRC? 9

A. For most of SPS’s Transmission accounts, the Depreciation Study’s proposed net salvage 10

percentages are similar to the net salvage percentages approved in Texas and New 11

Mexico. The approved parameters (or percentages) will differ based on when each case 12

was filed and the adjudication that occurs in each jurisdiction. In Texas, the net salvage 13

parameters were adjudicated in PUC Docket No. 43695 in December 2015. In New 14

Mexico, the net salvage parameters were adjudicated in Docket 15-00296-UT in 2016. 15


Table 5, set out below, compares the Depreciation Study’s proposed net salvage 1

percentages with the net salvage percentages approved in Texas and New Mexico: 2

TABLE 5 3 Net Salvage Percentages By Jurisdiction 4

Plant Account Proposed FERC Approved Texas

Approved New Mexico

350.2 Land Rights 0% 0% 0% 352 Structures and Improvement -10% -10% -20% 353 Station Equipment -20% -20% -19% 354 Towers and Fixtures -5% -5% -5% 355 Poles and Fixtures -35% -35% -60% 356 Overhead Conductors & Devices -30% -30% -30% 357 Underground Conduit 0% 0% 0% 358 Underground Conductors & Devices 0% 0% 0% 359 Roads and Trails 0% NA NA

For Accounts 350.2, 354, 356, 357, and 358, the Depreciation Study’s net salvage 5

percentages are the same as those approved in Texas and New Mexico. For Accounts 6

352, 353, and 355, the Depreciation Study’s net salvage percentages are the same as 7

SPS’s Texas retail jurisdiction. The Depreciation Study supports a negative 60 percent 8

negative salvage value for Account 355. However, for purposes of the current filing, the 9

Company proposes the more conservative negative 35 percent that is currently approved 10

in Texas. The various factors that have resulted in differences in the net salvage 11

percentages approved in each jurisdiction are discussed in the Depreciation Study. 12

As noted above, SPS plans to file the Depreciation Study with its retail 13

commissions in 2019. If SPS’s proposed net salvage percentages are approved in each 14

jurisdiction, then the differences seen in Accounts 352 and 353 will be eliminated. 15

However, if the Depreciation Study’s recommended negative 60 percent salvage 16


percentage for Account 355 is approved in Texas and New Mexico, the FERC 1

jurisdiction would still have a more conservative net salvage percentage for this account 2

until SPS files to change the Account 355 net salvage percentage and depreciation rate. 3

E. Reserve Reallocation

Q. WHAT IS RESERVE REALLOCATION? 4

A. Reserve reallocation is the process of re-spreading the book depreciation reserve within a 5

function based on the proposed life and net salvage characteristics among the assets in 6

each function. In the process of analyzing SPS’s depreciation reserve, I observed that the 7

depreciation reserve positions of the accounts were generally not in line with the life 8

characteristics found in the Depreciation Study’s analysis of the SPS’s assets. To allow 9

the relative reserve positions of each account within a function to mirror the life 10

characteristics of the underlying assets, I reallocated the depreciation reserves for all 11

accounts within each function. 12

Q. DOES THE REALLOCATION OF THE DEPRECIATION RESERVE CHANGE 13

THE TOTAL RESERVE? 14

A. No. The depreciation reserve represents the amounts that customers have contributed to 15

the return of the SPS investment in Transmission. The reallocation process does not 16

change the total reserve for each function; it simply reallocates the reserve between 17

accounts in the function. 18

Q. IS REALLOCATING THE DEPRECIATION RESERVE AMONG PLANT 19

ACCOUNTS AN ACCEPTED PRACTICE IN DEPRECIATION ACCOUNTING? 20

A. Yes. The practice of depreciation reserve allocation is endorsed in the 1968 publication 21

of Public Utility Depreciation Practices which explains that reallocation of the 22


depreciation reserve is appropriate “where the change in the view concerning the life of 1

property is so drastic as to indicate a serious difference between the theoretical and the 2

book reserve.”7 Additionally, the 1996 edition of the NARUC publication states that 3

“theoretical reserve studies also have been conducted for the purpose of allocating an 4

existing reserve among operating units or accounts.”8 With respect to SPS, my 5

Depreciation Study demonstrates that there have been significant changes in the life of 6

the property over the last thirty years. These changes have created a significant 7

difference between the theoretical and the book reserve in each functional group that 8

make the reallocation of the depreciation reserve appropriate in this instance. 9

Q. WHY IS IMPORTANT FOR THE DEPRECIATION RESERVE TO CONFORM 10

TO THE THEORETICAL RESERVE? 11

A. This is important because it sets the reserve at a level necessary to sustain the regulatory 12

concept of intergenerational equity among SPS’s customers, as well as set the 13

depreciation rates at the appropriate level based on current parameters and expectations. 14

Q. HAS THE COMMISSION PREVIOUSLY ALLOWED FOR THE 15

REALLOCATION OF DEPRECIATION RESERVE IN SETTING 16

DEPRECIATION RATES? 17

A. Yes. This issue has been addressed by the Company in other FERC cases, as well as its 18

state jurisdictions. I have made reserve reallocations that were accepted by the 19

Commission in Docket Nos. ER12-212-000, ER15-949-000, ER17-191-000, ER17-1664-20

7 National Association of Regulatory Utility Commissioners, Depreciation Subcommittee, Public

Utility Depreciation Practices (1968). 8 National Association of Regulatory Utility Commissioners, Depreciation Subcommittee, Public

Utility Depreciation Practices (1996).


000, and ER18-56-000. In addition, as discussed by Ms. Ostrom, the Company and also 1

proposed a production reserve reallocation in Docket No. ER18-228-000 related to the 2

Carlsbad Generating Station. 3

Q. HOW WILL THE COMPANY IMPLEMENT THE REALLOCATION OF ITS 4

DEPRECIATION RESERVE IF ITS PROPOSED RATES ARE APPROVED? 5

A. When the proposed depreciation rates are approved, SPS will reallocate the reserves on 6

its books to match the allocation performed in the Depreciation Study. 7

V. CONCLUSION


A. The Depreciation Study fully supports setting Transmission function depreciation rates 9

for SPS at the level shown in Table 1 above and in the Depreciation Study. In this way, 10

all customers are charged for their appropriate share of the capital expended by SPS for 11

their benefit. The Depreciation Study describes the extensive analysis performed and the 12

resulting rates that are now appropriate for its respective property classes. SPS’s 13

Transmission depreciation rates should be set at the recommended levels, effective 14

February 1, 2019, in order to recover SPS’s total investment in transmission property 15

over the estimated remaining life of the assets. By using the proposed depreciation rates, 16

all customers are charged for their appropriate share of the capital expended for their 17

benefit. 18


A. Yes. 20

Exhibit No. SPS-0011 (LIST OF REGULATORY

APPEARANCES)

Dane Watson Testimony Appearances Exhibit No. SPS-0011

Page 1 of 13

Asset Location Commission Docket (If Applicable Company Year Description

KentuckyKentucky Public

Service Commission

2018-00281 Atmos Kentucky 2018 Gas Depreciation Study

AlaskaRegulatory

Commission of Alaska

U-18-054 Matanuska Electric Coop 2018 Electric Generation Depreciation Study

CaliforniaCalifornia Public

Utilities Commission

A17-10-007 San Diego Gas and Electric 2018

Electric and Gas Depreciation

Study

TexasPublic Utility

Commission of Texas

48401 Texas New Mexico Power 2018

Electric Depreciation

Study

NevadaPublic Utility

Commission of Nevada

18-05031 Southwest Gas 2018 Gas Depreciation Study

TexasPublic Utility

Commission of Texas

48231 Oncor Electric Delivery 2018 Depreciation Rates

TexasPublic Utility

Commission of Texas

48371 Entergy Texas 2018Electric

Depreciation Study

KansasKansas

Corporation Commission

18-KCPE-480-RTS

Kansas City Power and Light 2018


Study

ArkansasArkansas Public

Service Commission

18-027-U Liberty Pine Bluff Water 2018

Water Depreciation

Study


Service Commission

2017-00349 Atmos KY 2018 Gas Depreciation Rates

Tennessee Tennesee Public Utility Commission 18-00017 Chattanooga Gas 2018 Gas Depreciation

Study

TexasRailroad

Commission of Texas

10679 Si Energy 2018 Gas Depreciation Study

AlaskaRegulatory


U-17-104 Anchorage Water and Wastewater 2017

Water and Waste Water

Depreciation Study

MichiganMichigan Public

Service Commission

U-18488 Michigan Gas Utilities Corporation 2017 Gas Depreciation

Study


Page 2 of 13


TexasRailroad

Commission of Texas

10669 CemterPoint South Texas 2017 Gas Depreciation

Study


Service Commission

17-061-U Empire District Electric Company 2017

Depreciation Rates for New Wind

Generation

KansasKansas


18-EPDE-184-PRE

Empire District Electric Company 2017


Generation

OklahomaOklahoma


PUD 201700471 Empire District Electric Company 2017


Generation

MissouriMissouri Public

Service Commission

EO-2018-0092 Empire District Electric Company 2017


Generation

Michigan Michigan Public Service Commission U-18457 Upper Peninsula

Power Company 2017Electric

Depreciation Study

FloridaFlorida Public

Service Commission

20170179-GU Florida City Gas 2017 Gas Depreciation Study

Michigan FERC ER18-56-000 Consumers Energy 2017Electric

Depreciation Study

MissouriMissouri Public

Service Commission

GR-2018-0013 Liberty Utilites 2017 Gas Depreciation Study

Michigan Michigan Public Service Commission U-18452 SEMCO 2017 Gas Depreciation

Study

TexasPublic Utility

Commission of Texas

47527 SPS 2017

Electric Production

Depreciation Study

MultiState FERC ER17-1664American

Transmission Company

2017Electric

Depreciation Study

AlaskaRegulatory


U-17-008Municipal Power and

Light City of Anchorage

2017Generating Unit

Depreciation Study

Mississippi Mississippi Public Service Commission 2017-UN-041 Atmos Energy 2017 Gas Depreciation

Study


Page 3 of 13


TexasPublic Utility

Commission of Texas

46957 Oncor Electric Delivery 2017


Study

OklahomaOklahoma


PUD 201700078 CenterPoint Oklahoma 2017 Gas Depreciation Study

New York FERC ER17-1010-000 New York Power Authority 2017


Study

TexasRailroad

Commission of Texas

GUD 10580 Atmos Pipeline Texas 2017 Gas Depreciation Study

TexasRailroad

Commission of Texas

GUD 10567 CenterPoint Texas 2016 Gas Depreciation Study

MultiState FERC ER17-191-000American

Transmission Company

2016Electric

Depreciation Study

New Jersey New Jersey Public Utilities Board GR16090826 Elizabethtown Natural

Gas 2016 Gas Depreciation Study

North CarolinaNorth Carolina


Docket G-9 Sub 77H Piedmont Natural Gas 2016 Gas Depreciation

Study

Michigan Michigan Public Service Commission U-18195 Consumers Energy/DTE

Electric 2016Ludington Pumped

Storage Depreciation Study

Alabama FERC ER16-2313-000 SEGCO 2016Electric

Depreciation Study

Alabama FERC ER16-2312-000 Alabama Power Company 2016


Study


Service Commission

U-18127 Consumers Energy 2016Natural Gas Depreciation

Study

MississippiMississippi Public

Service Commission

2016 UN 267 Willmut Natural Gas 2016Natural Gas Depreciation

Study

Iowa Iowa Utilities Board RPU-2016-0003 Liberty-Iowa 2016

Natural Gas Depreciation

Study


Page 4 of 13


Illinois Illinois Commerce Commission GRM #16-208 Liberty-Illinois 2016

Natural Gas Depreciation

Study

Kentucky FERC RP16-097-000 KOT 2016Natural Gas Depreciation

Study

AlaskaRegulatory


U-16-067 Alaska Electric Light and Power 2016

Generating Unit Depreciation

Study

FloridaFlorida Public

Service Commission

160170-EI Gulf Power 2016Electric

Depreciation Study

California California Public Utilities Commission A 16-07-002 California American

Water 2016


Depreciation Study

ArizonaArizona


G-01551A-16-0107 Southwest Gas 2016 Gas Depreciation

Study

TexasPublic Utility

Commission of Texas

45414 Sharyland 2016Electric

Depreciation Study

Colorado Colorado Public Utilities Commission 16A-0231E Public Service of

Colorado 2016Electric

Depreciation Study

Multi-State NE US FERC 16-453-000Northeast

Transmission Development, LLC

2015Electric

Depreciaiton Study


Service Commission

15-098-U CenterPoint Arkansas 2015Gas Depreciation Study and Cost of

Removal Study

New MexicoNew Mexico

Public Regulation Commission

15-00296-UT SPS NM 2015Electric

Depreciation Study

Atmos Energy Corporation

Tennessee Regulatory Authority

14-00146 Atmos Tennessee 2015Natural Gas Depreciation

Study



15-00261-UTPublic Service

Company of New Mexico

2015Electric

Depreciation Study

Hawaii NA NA Hawaii American Water 2015

Water/Wastewater Depreciation

Study


Page 5 of 13


KansasKansas


16-ATMG-079-RTS Atmos Kansas 2015 Gas Depreciation

Study

TexasPublic Utility

Commission of Texas

44704 Entergy Texas 2015Electric

Depreciation Study

AlaskaRegulatory


U-15-089 Fairbanks Water and Wastewater 2015


Depreciation Study

Arkansas Arkansas Public Service Commission 15-031-U Source Gas Arkansas 2015

Underground Storage Gas

Depreciation Study



15-00139-UT SPS NM 2015Electric

Depreciation Study

TexasPublic Utility

Commission of Texas

44746 Wind Energy Transmission Texas 2015


Study

Colorado Colorado Public Utilities Commission 15-AL-0299G Atmos Colorado 2015 Gas Depreciation

Study

Arkansas Arkansas Public Service Commission 15-011-U Source Gas Arkansas 2015 Gas Depreciation

Study

TexasRailroad

Commission of Texas

GUD 10432 CenterPoint- Texas Coast Division 2015 Gas Depreciation

Study

KansasKansas


15-KCPE-116-RTS

Kansas City Power and Light 2015


Study

AlaskaRegulatory


U-14-120 Alaska Electric Light and Power

2014-2015


Study

TexasPublic Utility

Commission of Texas

43950 Cross Texas Transmission 2014


Study



14-00332-UT Public Service of New Mexico 2014


Study

TexasPublic Utility

Commission of Texas

43695 Xcel Energy 2014Electric

Depreciation Study


Page 6 of 13


Multi State – SE US FERC RP15-101 Florida Gas

Transmission 2014Gas Transmission

Depreciation Study

California California Public Utilities Commission A.14-07-006 Golden State Water 2014


Depreciation Study


Service Commission

U-17653 Consumers Energy Company 2014

Electric and Common

Depreciation Study

ColoradoPublic Utilities Commission of

Colorado14AL-0660E Public Service of

Colorado 2014 Electric Depreciation Study

Wisconsin Wisconsin 05-DU-102 WE Energies 2014Electric, Gas, Steam

and Common Depreciation Studies

TexasPublic Utility

Commission of Texas

42469 Lone Star Transmission 2014


Study

NebraskaNebraska Public

Service Commission

NG-0079 Source Gas Nebraska 2014 Gas Depreciation Study

AlaskaRegulatory


U-14-055 TDX North Slope Generating 2014 Electric

Depreciation Study

AlaskaRegulatory


U-14-054 Sand Point Generating LLC 2014 Electric

Depreciation Study

AlaskaRegulatory


U-14-045 Matanuska Electric Coop 2014 Electric Generation Depreciation Study

Texas, New Mexico

Public Utility Commission of

Texas42004 Xcel Energy 2013-

2014

Electric Production,

Transmission, Distribution and

General Plant Depreciation

Study

New Jersey Board of Public Utilities GR13111137 South Jersey Gas 2013 Gas Depreciation

Study


Page 7 of 13


Various FERC RP14-247-000 Sea Robin 2013 Gas Depreciation Study

Arkansas Arkansas Public Service Commission 13-078-U Arkansas Oklahoma Gas 2013 Gas Depreciation

Study

Arkansas Arkansas Public Service Commission 13-079-U Source Gas Arkansas 2013 Gas Depreciation

Study

California California Public Utilities Commission

Proceeding No.: A.13-11-003

Southern California Edison 2013 Electric

Depreciation Study

North Carolina/South

CarolinaFERC ER13-1313 Progress Energy

Carolina2013 Electric

Depreciation Study

WisconsinPublic Service Commission of

Wisconsin4220-DU-108 Northern States Power-

Wisconsin 2013

Electric, Gas and Common


General

TexasPublic Utility

Commission of Texas

41474 Sharyland 2013Electric

Depreciation Study


Service Commission

2013-00148 Atmos Energy Corporation 2013 Gas Depreciation

Study

Minnesota Minnesota Public Utilities Commission 13-252 Allete Minnesota Power 2013 Electric

Depreciation Study

New HampshireNew Hampshire Public Service Commission

DE 13-063 Liberty Utilities 2013Electric

Distribution and General

TexasRailroad

Commission of Texas

10235 West Texas Gas 2013 Gas Depreciation Study

AlaskaRegulatory


U-12-154 Alaska Telephone Company 2012 Telecommunication

s Utility

New MexicoNew Mexico Public

Regulation Commission

12-00350-UT SPS 2012 Electric Depreciation Study

Colorado Colorado Public Utilities Commission 12AL-1269ST Public Service of

Colorado 2012 Gas and Steam Depreciation Study


Page 8 of 13


Colorado Colorado Public Utilities Commission 12AL-1268G Public Service of

Colorado 2012 Gas and Steam Depreciation Study

AlaskaRegulatory


U-12-149 Municipal Power and Light City of Anchorage 2012 Electric

Depreciation Study

Texas Texas Public Utility Commission 40824 Xcel Energy 2012 Electric

Depreciation Study

South CarolinaPublic Service Commission of South Carolina

Docket 2012-384-E

Progress Energy Carolina

2012 Electric Depreciation Study

AlaskaRegulatory


U-12-141 Interior Telephone Company 2012 Telecommunication

s Utility

Michigan Michigan Public Service Commission U-17104 Michigan Gas Utilities

Corporation 2012 Gas Depreciation Study

North CarolinaNorth Carolina


E-2 Sub 1025 Progress Energy Carolina


Texas Texas Public Utility Commission 40606 Wind Energy

Transmission Texas2012 Electric

Depreciation Study

Texas Texas Public Utility Commission 40604 Cross Texas

Transmission2012 Electric

Depreciation Study

MinnesotaMinnesota Public


12-858 Minnesota Northern States Power

2012

Electric, Gas and Common


General

TexasRailroad

Commission of Texas

10170 Atmos Mid-Tex 2012 Gas Depreciation Study

TexasRailroad

Commission of Texas

10174 Atmos West Texas 2012 Gas Depreciation Study

TexasRailroad

Commission of Texas

10182 CenterPoint Beaumont/ East Texas

2012 Gas Depreciation Study

KansasKansas


12-KCPE-764-RTS

Kansas City Power and Light



Page 9 of 13


NevadaPublic Utility

Commission of Nevada

12-04005 Southwest Gas 2012 Gas Depreciation Study

TexasRailroad

Commission of Texas

10147, 10170 Atmos Mid-Tex 2012 Gas Depreciation Study

KansasKansas


12-ATMG-564-RTS Atmos Kansas 2012 Gas Depreciation

Study

Texas Texas Public Utility Commission 40020 Lone Star Transmission 2012 Electric

Depreciation Study

Michigan Michigan Public Service Commission U-16938 Consumers Energy

Company 2011 Gas Depreciation Study

ColoradoPublic Utilities Commission of

Colorado11AL-947E Public Service of


Texas Texas Public Utility Commission 39896 Entergy Texas 2011 Electric

Depreciation Study

MultiState FERC ER12-212 American Transmission Company 2011 Electric

Depreciation Study

California California Public Utilities Commission A1011015 Southern California

Edison 2011 Electric Depreciation Study

Mississippi Mississippi Public Service Commission 2011-UN-184 Atmos Energy 2011 Gas Depreciation

Study

Michigan Michigan Public Service Commission U-16536 Consumers Energy

Company 2011 Wind Depreciation Rate Study

TexasPublic Utility

Commission of Texas

38929 Oncor 2011 Electric Depreciation Study

TexasRailroad

Commission of Texas

10038 CenterPoint South TX 2010 Gas Depreciation Study

AlaskaRegulatory


U-10-070 Inside Passage Electric Cooperative 2010 Electric

Depreciation Study

TexasPublic Utility

Commission of Texas

36633 City Public Service of San Antonio 2010 Electric

Depreciation Study


Page 10 of 13


Texas Texas Railroad Commission 10000 Atmos Pipeline Texas 2010 Gas Depreciation

Study

Multi State – SE US FERC RP10-21-000 Florida Gas Transmission 2010 Gas Depreciation

StudyMaine/ New Hampshire FERC 10-896 Granite State Gas

Transmission 2010 Gas Depreciation Study

Texas Public Utility

Commission of Texas

38480 Texas New Mexico Power 2010 Electric

Depreciation Study


Commission of Texas

38339 CenterPoint Electric 2010 Electric Depreciation Study

Texas Texas Railroad Commission 10041 Atmos Amarillo 2010 Gas Depreciation

Study

Georgia Georgia Public Service Commission 31647 Atlanta Gas Light 2010 Gas Depreciation

Study


Commission of Texas

38147 Southwestern Public Service 2010 Electric Technical

Update

AlaskaRegulatory


U-09-015 Alaska Electric Light and Power

2009-2010

Electric Depreciation Study

AlaskaRegulatory


U-10-043 Utility Services of Alaska

2009-2010

Water Depreciation Study

Michigan Michigan Public Service Commission U-16055 Consumers Energy/DTE

Energy2009-2010

Ludington Pumped Storage

Depreciation Study

Michigan Michigan Public Service Commission U-16054 Consumers Energy 2009-

2010Electric

Depreciation Study

Michigan Michigan Public Service Commission U-15963 Michigan Gas Utilities

Corporation 2009 Gas Depreciation Study

Michigan Michigan Public Service Commission U-15989 Upper Peninsula Power

Company 2009 Electric Depreciation Study

TexasRailroad

Commission of Texas

9869 Atmos Energy 2009 Shared Services Depreciation Study

Mississippi Mississippi Public Service Commission 09-UN-334 CenterPoint Energy

Mississippi 2009 Gas Depreciation Study


Page 11 of 13


TexasRailroad

Commission of Texas

9902 CenterPoint Energy Houston 2009 Gas Depreciation

Study

Colorado Colorado Public Utilities Commission 09AL-299E Public Service of


Tennessee Tennessee Regulatory Authority 11-00144 Piedmont Natural Gas 2009 Gas Depreciation

Study

Louisiana Louisiana Public Service Commission U-30689 Cleco 2008 Electric

Depreciation Study

TexasPublic Utility

Commission of Texas

35763 SPS 2008

Electric Production, Transmission,

Distribution and General Plant

Depreciation Study

Wisconsin Wisconsin 05-DU-101 WE Energies 2008Electric, Gas, Steam

and Common Depreciation Studies

North Dakota North Dakota Public Service Commission PU-07-776 Northern States Power 2008 Net Salvage

New MexicoNew Mexico Public

Regulation Commission

07-00319-UT SPS 2008 Testimony – Depreciation

Multiple StatesRailroad

Commission of Texas

9762 Atmos Energy 2007-2008

Shared Services Depreciation Study

Minnesota Minnesota Public Utilities Commission E015/D-08-422 Minnesota Power 2007-

2008Electric

Depreciation Study

TexasPublic Utility

Commission of Texas


TexasPublic Utility

Commission of Texas


Michigan Michigan Public Service Commission U-15629 Consumers Energy 2006-

2009Gas Depreciation

Study


Page 12 of 13


Colorado Colorado Public Utilities Commission 06-234-EG Public Service of


Arkansas Arkansas Public Service Commission 06-161-U CenterPoint Energy –

Arkla Gas 2006

Gas Distribution Depreciation Study and Removal Cost

Study

Texas, New MexicoPublic Utility

Commission of Texas

32766 Xcel Energy 2005-2006

Electric Production, Transmission,

Distribution and General Plant

Depreciation Study

TexasRailroad

Commission of Texas

9670/9676 Atmos Energy Corp 2005-2006

Gas Distribution Depreciation Study

TexasRailroad

Commission of Texas

9400 TXU Gas 2003-2004


TexasRailroad

Commission of Texas

9313 TXU Gas 2002 Gas Distribution Depreciation Study

TexasRailroad

Commission of Texas

9225 TXU Gas 2002 Gas Distribution Depreciation Study

TexasPublic Utility

Commission of Texas

24060 TXU 2001 Line Losses

TexasPublic Utility

Commission of Texas

23640 TXU 2001 Line Losses

TexasRailroad

Commission of Texas

9145-9148 TXU Gas 2000-2001


TexasPublic Utility

Commission of Texas

22350 TXU 2000-2001

Electric Depreciation Study,

Unbundling

TexasRailroad

Commission of Texas

8976 TXU Pipeline 1999 Pipeline Depreciation Study

TexasPublic Utility

Commission of Texas

20285 TXU 1999 Fuel Company Depreciation Study


Page 13 of 13


TexasPublic Utility

Commission of Texas

18490 TXU 1998 Transition to Competition

TexasPublic Utility

Commission of Texas

16650 TXU 1997 Customer Complaint

TexasPublic Utility

Commission of Texas

15195 TXU 1996 Mining Company Depreciaiton Study

TexasPublic Utility

Commission of Texas

12160 TXU 1993 Fuel Company Depreciation Study

TexasPublic Utility

Commission of Texas

11735 TXU 1993 Electric Depreciation Study

Exhibit No. SPS-0012 (DEPRECIATION STUDY)


Book Depreciation Accrual Rate Study

At June 30, 2018


SOUTHWESTERN PUBLIC SERVICE COMPANY-FERC TRANSMISSION DEPRECIATION RATE STUDY

AT JUNE 30, 2018

Table of Contents PURPOSE ....................................................................................................... 3

STUDY RESULTS .......................................................................................... 4

Definition .................................................................................................... 5

Basis of Depreciation Estimates .............................................................. 5

Survivor Curves ......................................................................................... 6

Actuarial Analysis ...................................................................................... 9

Judgment ................................................................................................. 10

Theoretical Depreciation Reserve .......................................................... 10

DETAILED DISCUSSION ............................................................................. 12

Depreciation Study Process ................................................................... 12

SPS Transmission Depreciation Calculation Process ......................... 14

LIFE ANALYSIS............................................................................................ 17

Transmission Accounts, FERC Accounts 350-358 ............................... 17

Salvage - Transmission Property ........................................................... 29

APPENDIX A ................................................................................................ 36

Computation of Depreciation Accrual Rates ............................................ 36

APPENDIX B ................................................................................................ 37

Comparison of Approved vs Proposed Accrual Rates ............................ 37

APPENDIX C ................................................................................................ 38

Comparison of Depreciation Parameters .................................................. 38

APPENDIX D ................................................................................................ 39

Net Salvage Analysis by Account .............................................................. 39


PURPOSE

The purpose of this study is to develop functional depreciation rates for the

depreciable Transmission a as recorded on the books of Southwestern Public Service

Company (“SPS” or “Company”) as of June 30, 2018. The depreciation rates were

designed to recover the total remaining undepreciated investment, adjusted for net

salvage, over the remaining life of SPS’s property on a straight-line basis. Non-depreciable

property was excluded from this study. SPS is engaged in the generation, transmission,

and distribution of electricity within Texas and New Mexico.

Company-wide (Texas and New Mexico), SPS provides electricity to approximately

390,000 wholesale and retail customers. Assets for SPS at December 31, 2017 include:

4,414 megawatts of generation; 8,516 conductor miles of 345 kV transmission lines with

supporting structures; 9,608 conductor miles of 230 kV transmission lines with supporting

structures; 13,555 conductor miles of 115 kV transmission line with supporting structures;

24,795 conductor miles of less than 115 kV line; and 454 transmission and distribution

substations. In addition, SPS needs associated equipment such as feeders, primary

switches, poles, conductor, line transformers, services, meters, and streetlights to serve its

approximately 390,000 customers.

General Property assets such as buildings, office furniture, transportation equipment,

and other miscellaneous property are located throughout SPS’s service territory.


STUDY RESULTS

Recommended depreciation rates for all SPS depreciable property are shown in

Appendix A. These rates translate into an annual depreciation accrual (total company) for

Transmission Plant of $75.5 million. These accruals are based on SPS's depreciable

investment as of June 30, 2018 (test year) as shown in Appendix B. The annual

depreciation expense calculated by the same method using the existing approved FERC

depreciation rates was $56.9 million for Transmission. Appendix B shows the effect of the

change in lives and curves on depreciation accrual by account. The proposed lives and

curves on which these calculations are based are shown in Appendix C. Appendix D

addresses the development of net salvage parameters for all plant accounts. Appendix E

calculates the average remaining life by account and the Company’s proposed reserve

reallocation.

This study updates depreciation rates and parameters for transmission assets that

were established in (FERC) Docket No. EL-89-50-000.


GENERAL DISCUSSION

Definition

The term "depreciation" as used in this study is considered in the accounting sense;

that is, a system of accounting that distributes the cost of assets, less net salvage (if any),

over the estimated useful life of the assets in a systematic and rational manner. It is a

process of allocation, not valuation. This expense is systematically allocated to accounting

periods over the life of the properties. The amount allocated to any one accounting period

does not necessarily represent the loss or decrease in value that will occur during that

particular period. SPS accrues depreciation on the basis of the original cost of all

depreciable property included in each functional property group. At retirement, the full cost

of depreciable property, less the net salvage value, is charged to the depreciation reserve.

Basis of Depreciation Estimates

Annual and accrued depreciation were calculated in this study by the straight-line,

broad group, remaining-life depreciation system. In this system, the annual depreciation

expense for each group is computed by dividing the original cost of the asset group less

allocated depreciation reserve less estimated net salvage by its respective average

remaining life. The resulting annual accrual amounts of all depreciable property within a

function were accumulated and the total was divided by the original cost of all functional

depreciable property to determine the depreciation rate. The calculated remaining lives

and annual depreciation accrual rates were based on attained ages of plant in service and

the estimated service life and salvage characteristics of each depreciable group. They

were computed in a direct weighting by multiplying each vintage or account balance times

its remaining life and dividing by the plant investment in service as of June 30, 2018. The

computations of the annual functional depreciation rates are shown in Appendix A.

A variety of life estimation approaches were incorporated into analyses of SPS data.

Both Simulated Plant Record (“SPR”) analysis and Actuarial Analysis are commonly used

mortality analysis techniques for electric utility property. Since SPS has vintaged

information available for its transmission assets, actuarial analysis was performed.

Placement bands were computed in the overall band with the most history available, then


other placement bands from 1968-2017 and 1993-2017 were performed which

encompassed the most recent 50 and 25 year periods respectively. Experience bands

varied depending on the amount of data. The 1968-2017 experience band was the

maximum used for Accounts 352-359. Judgment was used to a greater or lesser degree

on all accounts. Each approach used in this study is more fully described in a later section.

Survivor Curves

To fully understand depreciation projections in a regulated utility setting, one must

have a basic understanding of survivor curves. Individual assets within a group do not

normally have identical lives or investment amounts. The average life of a group can be

determined by comparing actual experience against various survivor curves. A survivor

curve represents the percentage of property remaining in service at various age intervals.

The most widely used set of representative survivor curves are the Iowa Survivor Curves

(“Iowa Curves”). The Iowa Curves are the result of an extensive investigation of life

characteristics of physical property made at Iowa State College Engineering Experiment

Station in the first half of the twentieth century. Through common usage, revalidation, and

regulatory acceptance, these curves have become a descriptive standard for the life

characteristics of industrial property. An example of an Iowa Curve is shown below.


There are four families in the Iowa Curves which are distinguished by the relation of

the age at the retirement mode (largest annual retirement frequency) and the average life.

The four families are designated as “R”— Right, “S” — Symmetric, “L” — Left, and “O” —

Origin Modal. First, for distributions with the mode age greater than the average life, an

"R" designation (i.e., Right modal) is used. The family of “R” moded curves is shown

below.


Second, an "S" designation (i.e., Symmetric modal) is used for the family whose

mode age is symmetric about the average life. Third, an "L" designation (i.e., Left modal)

is used for the family whose mode age is less than the average life. Fourth, a special case

of left modal dispersion is the "O" or origin modal curve family. Within each curve family,

numerical designations are used to describe the relative magnitude of the retirement

frequencies at the mode. A "6" indicates that the retirements are not greatly dispersed

from the mode (i.e., high mode frequency) while a "1" indicates a large dispersion about

the mode (i.e., low mode frequency). For example, a curve with an average life of 30 years

and an "L3" dispersion is a moderately dispersed, left modal curve that can be designated

as a 30 L3 Curve. An SQ, or square, survivor curve occurs where no dispersion is present

(i.e., units of common age retire simultaneously).


For Transmission accounts, a survivor curve pattern was selected based on analysis

of historical data, as well as other factors, such as general changes relevant to SPS's

operations. The blending of judgment concerning current conditions and future trends,

along with the matching of historical data, permits the depreciation analyst to make an

informed selection of an account's average life and retirement dispersion pattern. Iowa

Curves were used to depict the estimated survivor curves for each account.

Actuarial Analysis

Actuarial analysis (retirement rate method) was used in evaluating historical asset

retirement experience where vintage data was available and sufficient retirement activity

was present. In actuarial analysis, interval exposures (total property subject to retirement

at the beginning of the age interval, regardless of vintage) and age interval retirements are

calculated. The complement of the ratio of interval retirements to interval exposures

establishes a survivor ratio. The survivor ratio is the fraction of property surviving to the

end of the selected age interval, given that it has survived to the beginning of that age

interval. Survivor ratios for all of the available age intervals were chained by successive

multiplications to establish a series of survivor factors, collectively known as an observed

life table. The observed life table shows the experienced mortality characteristic of the

account and may be compared to standard mortality curves such as the Iowa Curves.

Many accounts were analyzed using this method. Placement bands were used to illustrate

the composite history over a specific era, and experience bands were used to focus on

retirement history for all vintages during a set period. Matching data in observed life tables

for each experience and placement band to an Iowa Curve requires visual examination. As

stated in Depreciation Systems by Wolf and Fitch, “the analyst must decide which points or

sections of the curve should be given the most weight. Points at the end of the curve are

often based on fewer exposures and may be given less weight than those points based on

larger samples.”1 Some analysts chose to use mathematical fitting as a tool to narrow the

population of curves using a least squares technique. Use of the least squares approach

does not imply a statistical validity, however, because the underlying data does not meet

1 W. C. Fitch and F. K. Wolf, Depreciation Systems 46 (Iowa State Press 1994).


criteria for independence between vintages and the same average price for property units

through time. Thus, Depreciation Systems cautions that “the results of mathematical fitting

should be checked visually and the final determination of best fit made by the analyst.”2

This study uses the visual matching approach to match Iowa Curves, since mathematical

fitting produces theoretically possible curve matches. Visual examination and experienced

judgment allow the depreciation professional to make the final determination as to the best

curve type.

Detailed information for each account is shown later in this study and in workpapers.

Judgment Any depreciation study requires informed judgment by the analyst conducting the

study. A knowledge of the property being studied, company policies and procedures,

general trends in technology and industry practice, and a sound basis of understanding

depreciation theory are needed to create this informed judgment. In this depreciation

study, judgment was used in areas such as survivor curve modeling and selection,

depreciation method selection, and actuarial analysis.

Where there are multiple factors, activities, actions, property characteristics,

statistical inconsistencies, property mix in accounts, or a multitude of other considerations

that affect the analysis (potentially in various directions), judgment is used to take all of

these considerations and synthesize them into a general direction or understanding of the

characteristics of the property. Individually, no one consideration in these cases may have

a substantial impact on the analysis, but overall, the collective effect of these

considerations may shed light on the use and characteristics of assets. Judgment may also

include deduction, inference, common sense, or the ability to make sensible decisions.

There is no single correct result from statistical analysis; hence, there is no answer absent

judgment.

Theoretical Depreciation Reserve

The book accumulated provision for depreciation within each function was allocated

2 Fitch and Wolf at 48.


among Transmission Property accounts through the use of the theoretical depreciation

reserve model. This study used a reserve model that relied on a prospective concept

relating future retirement and accrual patterns for property, given current life and salvage

estimates.

The theoretical reserve of a property group is developed from the estimated

remaining life of the group, the total life of the group, and estimated net salvage. The

theoretical reserve represents the portion of the group cost that would have been accrued if

current forecasts were used throughout the life of the group for future depreciation

accruals. The computation involves multiplying the vintage balances within the group by

the theoretical reserve ratio for each vintage. The straight-line remaining-life theoretical

reserve ratio (“RR”) at any given age is calculated as:

Ratio) SalvageNet-(1* Life) Service(Average

Life) Remaining (Average-1=RR


DETAILED DISCUSSION

Depreciation Study Process This depreciation study encompassed four distinct phases. The first phase involved

data collection and field interviews. The second phase was where the initial data analysis

occurred. The third phase was where the information and analysis was evaluated. After

the first three stages were complete, the fourth phase began. This phase involved the

calculation of deprecation rates and the documenting of the corresponding

recommendations.

During the Phase I data collection process, historical data was compiled from

continuing property records and general ledger systems. Data was validated for accuracy

by extracting the data and comparing it to multiple financial system sources: Projects

System (Construction ledger), Fixed Asset System (continuing property ledger), General

Ledger, and interfaces from other operating systems. Audit of this data was validated

against historical data from prior periods, historical general ledger sources, and field

personnel discussions. This data was reviewed extensively so that it could be put in the

proper format for a depreciation study. Further discussion on data review and adjustment

is found in the Salvage Consideration section of this study. Numerous discussions were

conducted with engineers and field operations personnel to obtain information that would

be helpful in formulating life and salvage recommendations in this study. One of the most

important elements in performing a proper depreciation study is to understand how a

company utilizes assets and the environment in which those assets operate.

Understanding that industry and geographical norms for mortality characteristics are

important factors in selecting life and salvage recommendations; however, care must be

used not to apply them rigorously to any particular company since no two companies would

have the same exact forces of retirement acting upon their assets. Interviews with

engineering and operations personnel are important data gathering operations that to allow

the analyst to obtain information that is helpful when evaluating the output from the life and

net salvage programs in relation to a company’s actual asset utilization and environment.

Information that was gleaned in these discussions with SPS personnel for this study is

found both in the Detailed Discussion portions of the Life Analysis and Salvage Analysis


sections and in workpapers. In addition, Alliance personnel possess a significant

understanding of the types of electric utility property the forces of retirement due to years of

day-to-day exposures, and of the operations of electric utility property.

Phase 2 is where the SPR and actuarial analysis are performed. Phase 2 and

Phase 3 (to be discussed in the next paragraph) overlap to a significant degree. The

detailed property record information is used in Phase 2 to develop observed life tables for

life analysis and SPR graphs and statistics. It is possible that an analyst would cycle back

to Phase 2 based on the evaluation process performed in Phase 3. Net salvage analysis

consists of compiling historical salvage and removal data by functional group and account

to determine values and trends in gross salvage and removal cost. This information is then

carried forward into Phase 3.

Phase 3 is the evaluation process, which synthesizes analysis, interviews, and

operational characteristics into a final selection of asset lives and net salvage parameters.

The historical analysis from Phase 2 is further enhanced by the incorporation of recent or

future changes in the characteristics or operations of assets that were revealed in Phase 1.

The preliminary results are then reviewed by the depreciation analyst and discussed with

accounting and operations personnel. Phases 2 and 3 allow the depreciation analyst to

validate the asset characteristics seen in the accounting transactions with actual company

operational experience.

Finally, Phase 4 involves calculating of accrual rates, making recommendations, and

documenting the conclusions in a final report. The calculation of accrual rates for this

study is found in Appendix A. Recommendations for the various accounts are contained

within the Detailed Discussion of this report. The depreciation study flow diagram shown

as Figure 13 documents the steps used in conducting this study. Depreciation Systems4

documents the same basic processes in performing a depreciation study, namely statistical

analysis, evaluation of statistical analysis, discussions wit management, forecast

assumptions, and document recommendations.

3 American Gas Association and Edison Electric Institute, Introduction to Depreciation for Public Utilities and Other Industries (2013). 4 Fitch and Wolf at 289.


SPS Transmission Depreciation Study Process


Transmission Calculation Process Annual depreciation expense amounts for Transmission Property Accounts were

calculated by the straight line, average life group, remaining life procedure. In a whole life representation, the annual accrual rate is computed by the following

equation,

Annual Accrual Rate = (100% - Net Salvage Percent)

Average Service Life

Use of the remaining life depreciation system adds a self-correcting mechanism,

which accounts for any differences between theoretical and book depreciation reserve over

the remaining life of the group. With the straight line, remaining life, average life group

system using Iowa Curves, composite remaining lives were calculated according to

standard broad group expectancy techniques, noted in the formula below:

Composite Remaining Life = (∑Original Cost - Theoretical Reserve)

∑Whole Life Annual Accrual

For each plant account, the difference between the surviving investment, adjusted for

estimated future net salvage, and the allocated book depreciation reserve, was divided by

the composite remaining life to yield the annual depreciation expense as noted in this

equation.

Annual Depreciation Expense = Original Cost - Book Reserve - (Original Cost * Net Salvage %)

Composite Remaining Life

Within a group, the sum of the group annual depreciation expense amounts, as a

percentage of the depreciable original cost investment summed, gives the annual

depreciation rate as shown below:

Annual Depreciation Rate = ∑Annual Depreciation Expense

∑Original Cost

These calculations are shown in Appendix A. The calculations of the theoretical


depreciation reserve values and the corresponding remaining life calculations are shown in

the workpapers for this study. Book depreciation reserves are maintained on a plant

account level basis. Theoretical reserve computations were used to reallocate

depreciation reserves by account and to compute remaining life for each account.


LIFE ANALYSIS

Transmission Accounts, FERC Accounts 350-358

FERC Account 350.2 Transmission Depreciable Land Rights (80 R4) This account consists of land rights and easements associated with Transmission

lines or Transmission substations. The account balance for this account at June 30, 2018

is $146.8 million. There is minimal retirement activity in this account, which did not

produce sufficient data for an actuarial analysis. Since the lives of many accounts in the

transmission function are lengthening, this study recommends a change to an 80 year life

and the R4 dispersion for this account. A representative curve for the proposed life and

dispersion is shown below.


FERC Account 352 Transmission Substation Structures and Improvements

(65 R4) This account includes buildings, fencing and other structures found in a transmission

substation. The account balance for this account at June 30, 2018 is $98.4 million. The

rates approved in FERC Docket No. EL-89-50-000 established a 50 year life with the R2

dispersion. Limited retirements have occurred in this account, making actuarial analysis

difficult. Although a 65-year life is on the high side of what would be expected in the

industry, a 65 year life is recommended with a change to the R4 dispersion for this

account.


FERC Account 353 Transmission Substation Equipment (55 R2) This account contains a wide variety of transmission substation equipment, from

circuit breakers to switchgear and transformers. The account balance for this account at

June 30, 2018 is $1.1 billion. The rates approved in FERC Docket No. EL-89-50-000

established a life characteristic of 50 years with the R3 dispersion. A priority is to have all

microprocessor-based relays in transmission in the future, which are expected to live no

more than 30 years. The primary reasons for replacement are: failure, testing indicating

elevated risk of failure, capacity increases (especially for circuit breakers), obsolescence,

safety hazard when assets would have catastrophic failure mode and risk is increasing,

and replacements of aging assets. Most of the new assets being installed have some form

of microprocessor controls, but typically if the controls fail, the whole asset would not

necessarily be replaced. However, at some point, the life of assets with microprocessor

controls and/or newer technology and tighter tolerances the life may start to decrease.

There are significant capacity factor increases in SPS with corresponding higher loading of

assets. This may shorten the life of assets, such as transformers, over time. However,

SPS has an excellent inspection and maintenance program related to substation

equipment. This program detects and corrects problems with large substation components

in a timely manner to keep equipment in service longer than without this program. This

program would have a tendency to reduce early failures. It appears that because of this

program, the indicated life of substation equipment has lengthened since the last study and

is longer than the expectations of many other utilities in Texas. The 55 year life with the R2

dispersion is a good match for all of the placement and experience band combinations.

This study recommends moving to a 55 R2 at this time.



FERC Account 354 Transmission Towers and Fixtures (75 R4) This account consists of Transmission towers, which are used to transmit electricity

at a voltage of 69 kV and above. The account balance for this account at June 30, 2018 is

$8.2 million. Most of the Transmission line assets are in FERC Account 355, Poles and

Fixtures, except for 25 miles (SPS has in excess of 6,900 miles of transmission line) that

are in Account 354. There are three short tower lines (one five miles in length and two in

Lubbock – 10 miles in length each). The five mile long stretch was built in the 1940s and

the 20 miles around Lubbock was built in the 1970s. There is very limited retirement data.

The rates approved in FERC Docket No. EL-89-50-000 established a life characteristic of

75 years with the R3 dispersion, which SPS personnel feel is a reasonable expectation for

the life of these assets. Judgment was used to retain the current life of 75 years but move

the dispersion to the R4.


FERC Account 355 Transmission Poles and Fixtures (47 R3) This account consists of Transmission poles and fixtures, which are used to transmit

electricity at a voltage of 69 kV and above. The account balance for this account at June

30, 2018 is $1.1 billion. The rates approved in FERC Docket No. EL-89-50-000

established a 45 year life with the R2.5 dispersion. After reviewing actuarial analysis

results, the life of transmission poles is increasing from the prior depreciation study. SPS

is beginning to use more steel poles than wood poles. A number of lines are entirely made

of steel, some with wood tangents and steel corners, and double circuit lines are now steel.

SPS has in excess of 6,900 miles of transmission line with approximately 10% - 15% of the

poles being steel. Some of the oldest steel poles are approaching 40 years of age. Some

wood pole lines are in excess of 50 years old, although many of those poles have been

replaced. SPS has issues with some lines where design and soil conditions are not

optimal. Accordingly, a change from white cedar (which lasted longer) to Douglas fir was

made. It is known that the new growth trees will not last as long as old growth trees and

60% to 65% of existing wood poles are old growth. Many older wood transmission poles of

an older design class will not take the weight of reconductoring. Most steel poles were on

foundations and now 65% of steel poles are direct buried. Arms are replaced more often

than poles. Viewing the overall bands, a 47 R3 fits all but the tail. The more recent bands

do not drop below 90 percent surviving and are not considered to reliable indicator. Based

on the actuarial analysis of the fuller placement and experience bands, as well as feedback

from SPS personnel, a 47 year life, which is an increase, and the R3 dispersion is

recommended for this account.



FERC Account 356 Transmission Overhead Conductor (47 R2) This account consists of Transmission overhead conductors, which are used to

transmit electricity at voltages of 69 kV and above. The account balance for this account at

June 30, 2018 is $436.2 million. The rates approved in FERC Docket No. EL-89-50-000

established a life of 45 years with the R3 dispersion. SPS did not use dampers in the past

and found that wires were not lasting as long without dampers because of shattering at

insulators. SPS began using dampers 25 years ago but they expect to continue seeing

residual effects of not using dampers for many years. SPS will replace the wire in many

instances when moving from single to double circuit conductor line, and more opportunities

are occurring to upgrade lines. SPS would expect a little shorter life for conductor than

poles. However, based on the actuarial analysis, the life indication is moving longer and is

consistent with our recommendation on poles of 47 years but has a slightly flatter, R2,

dispersion. Based on more recent experience bands and input from SPS personnel, this

study recommends a 47 R2 dispersion for this account.


FERC Account 357 Transmission Underground Conduit (75 R3) This account consists of underground conduit used with two underground

transmission lines in Amarillo. The account balance for this account at June 30, 2018 is

$255 thousand. There has been no retirement activity over the study period, rendering both

actuarial and SPR analysis of no aid in examining the life characteristic. The rates

approved In FERC Docket No. EL-89-50-000 established a life of 75 years with the R3

dispersion through judgment, and this selection is retained in this study. A representative

graph of the proposed curve shape is shown below.


FERC Account 358 Transmission Underground Conductor (45 R3) This account consists of underground conductor used in two underground

transmission lines in Amarillo. The account balance for this account at June 30, 2018 is

$490 thousand. The lines are low pressure, oil filled, paper wrapped 500 MCM copper

cable. The rates approved in FERC Docket No. EL-89-50-000 established a life of 45

years with the R3 dispersion. There has been no retirement activity over the study period,

rendering both actuarial and SPR analysis of no aid in examining life characteristic. This

study recommends retaining the 45 R3 dispersion for this account. A representative graph

of the proposed curve shape is shown below.


FERC Account 359 Road and Trails (65 R4) This account consists of roads and trails used in transmission operations. The

account balance for this account at June 30, 2018 is $518 thousand. This account did not

exist in the last study, and the Company used the rates and lives approved in FERC

Docket No. EL-89-50-000 of 50 years with the R2 dispersion as a proxy for this account.

There has been no retirement activity over the study period, rendering both actuarial and

SPR analysis of no aid in examining life characteristic. Generally, the life of this account is

longer than the underlying assets it is used to access. This study recommends a 65 R4

dispersion for this account. A representative graph of the proposed curve shape is shown

below.


SALVAGE ANALYSIS When a capital asset is retired, physically removed from service, and finally disposed

of, terminal retirement is said to have occurred. The residual value of a terminal retirement

is called gross salvage. Net salvage is the difference between the gross salvage (what the

asset was sold for) and the removal cost (cost to remove and dispose of the asset).

Gross salvage and cost of removal related to retirements are recorded to the general

ledger in the accumulated provision for depreciation at the time retirements occur within the

system.

Net salvage data by plant account for Transmission Property plant is shown in

Appendix D. Removal cost percentages are calculated by dividing the current cost of

removal by the original installed cost of the asset. Some plant assets can experience

significant negative removal cost percentages due to the timing of the addition versus the

retirement. For example, a Transmission asset in FERC Account 355 with a current

installed cost of $500 (2017) would have had an installed cost of $68.225 in 1970. A

removal cost of $50 for the asset calculated (incorrectly) on current installed cost would

only have a negative 10 percent removal cost ($50/$500). However, a correct removal cost

calculation would show a negative 73.29 percent removal cost for that asset ($50/$68.22).

Inflation from the time of installation of the asset until the time of its removal must be taken

into account in the calculation of the removal cost percentage because the depreciation

rate, which includes the removal cost percentage, will be applied to the original installed

cost of assets.

5 Using the Handy-Whitman Bulletin No. 187, E-4, line 36, $68.22 = $500 x 76/557.


Salvage - Transmission Property Increasing levels of removal cost are experienced in nearly all accounts in this

function. Moving averages, which smooth out yearly fluctuations between retirements and

net salvage, are used to examine data over the 1968 to 2017 period (or newer depending

on the account) and determine net salvage estimates for each account. Detailed analysis

and results by account are shown in Appendix D and individual account results are

discussed below.

The cost of retirement and removal of transmission assets has increased over time.

Company personnel have provided the following to help explain some of the pressures that

are increasing the cost to remove transmission assets from service. Many general factors

have occurred, creating changes that increase removal cost including:

• Time Value of Money

Many transmission assets have a life cycle of 40 years or more. Some of the

assets being removed were installed over 40 years ago when materials, labor

and cost of goods were cheaper.

• Environmental Regulations and Right-of-Way Access/Use Restrictions

The cost of demolition has increased due to increased regulation and

restrictions on environmental impact, mitigation and restoration measures. The

equipment, labor and other expenses will increase with hard to access locations.

Many construction or demolition permits require increased focus on restoration of

vegetation to a natural state that spans several growing seasons to restore.

Southwestern Public Service Company is experiencing ever increasing Right-

of-way (ROW) access restrictions from landowners and Bureau of Land

Management (BLM) in our New Mexico service territory. New Mexico has more

environmental regulations than Texas. In addition, our New Mexico service territory

includes significant area managed by the BLM, which includes more governmental

oversight, increasing costs both construction and removal. The western portion of

the framed Permian Basin of Texas and New Mexico is in the heart of what may be

the nation’s richest oil and gas production in the coming years. In New Mexico, the

oil field companies pay the land owners more, which also drives up our costs to


meet land owners requirements. The growth in New Mexico due to the Permian

Basin has occurred since 2013 and is expected to continue for the next 20-30 years.

Approximately 30% of our Transmission assets are located in New Mexico. For

example, an End-of-Life Replacement project in New Mexico has a projected ROW

preparation and restoration cost of approximately $350K for the removal of assets

due to strict ROW access requirements. However, an End of Life Replacement

project in Texas, which has a similar scope, has a projected ROW preparation and

restoration cost of only $52K. New Mexico ROW preparation and restoration cost

for the removal of assets is nearly six times that of Texas. This increase has been

driven by the items listed above and provides insight to future expectations that may

differ from past decades of experience.

All these requirements increase the cost of construction/demolition.

Environmental protections also affect the salvage value of material. Wood

poles that were once sold for a positive salvage value now cost the company to

dispose of the poles due to the wood protectant material (creosote).

• Change in NERC and FERC requirements

Increased regulation and requirements on operating and planning standards

increase the frequency of removal. NERC may issue a ruling that requires assets

be removed before they are fully depreciated. An example is the clearance of

transmission lines. Xcel Energy had to remove existing transmission lines and

replace with taller structures due to a LiDar study and violation in clearance

standards issued by NERC.

• Labor

1. Increase NERC and FERC Operating requirements and standards.

2. Due to increased regulation on operating standards, obtaining equipment outages

for removal and construction of assets has become more difficult requiring more

projects to be performed while the lines are still energized or forcing constructions to

occur in the evening, or on weekends that require overtime of crews. For example,

during an End of Life Replacement Project, 52 out of 261 structures had to be

addressed by contractor crews trained in hot-line work at a premium cost due to


outage constraints. The RWIP of the energized work was $190K for 52 structures

while the remaining 209 structures were completed for a total RWIP of $190K or

roughly 4 times the cost

3. Cost of labor has increased since the assets were installed. Not only have wages

increased for journey and apprentices over the years, the demand for the resources

have increased due to a shortage of licensed workers. The shortage has placed a

positive price pressure for labor costs.

In the last decade, investment in the transmission system has increased

substantially across the country. This has created a high demand for the limited

number of qualified resources available to construct the work. The increases in

capital expenditures are such that utilities now have to augment their internal

workforces with external contract construction providers, who often come at a higher

cost.

For example, a project on the 345 kV Hitchland – Potter line, replaced

structures to increase line capacity. Retirements on this project included of 54 wood

poles and 24 cross arms. The total CWIP was approximately $1.7M and the

removal cost was roughly $626K. This project was performed by SPS’s contractor.

The contractor’s estimated hourly wage is higher than SPS’s internal crew’s wage

($120/hour). Also, another likely reason why the structure removal cost for this

project was slightly higher than other projects is because the contractor had to travel

long multiple trips to replace specific structures on our ROW (higher

mobilization/equipment fees).

Another example is an arm replacement project on the 230 kV Tolk –

Yoakum line. The scope of the project was to replace 343 deteriorated arms. The

total CWIP was approximately $3.3M and the removal cost was roughly $288K. This

project was performed by SPS’s contractor. The removal cost per arm equates to

$850 per arm which is a reasonable unit cost.

• Safety Requirements

The electric utility industry, in general, and Xcel Energy in particular, have

emphasized the importance of employees complying with safe working practices.


SPS personnel indicated that the equipment and provisions required today have

increased substantially from 40 years ago. These policies have increased the cost

of doing business, but are important part of the safety culture for Xcel Energy.

• Increase Financial Controls

Over time, financial standards and regulations have increased. Xcel Energy has

adopted the best practices and incorporated cost and quality controls measures into

the close out of construction work orders. This provides greater details of costs

associated with demolition. As can be seen on the Retirements and Salvage

Analysis, retirements, salvage and removal costs vary year by year. Removal costs

have substantially increased since 2007 forward.

• Salvage Value

Many of the assets that are removed do not carry a high salvage value. Some of

the assets may be sold as scrap but it would not amount to the cost of installation or

cost offset the removal costs. Assets that can be reused are placed into inventory

instead of sold. In several cases, the assets being removed are of wood

construction, in which case there is no salvage value.

• Asset Renewal

Utilities across the nation are now dealing with an antiquated, aging transmission

infrastructure. Forty years ago the transmission system was forty years younger. It

is now a necessity for utilities to have proactive asset renewal programs to

proactively replace transmission assets before they fail. The frequency of projects

requiring removal of existing assets has increased substantially over the last

decade, and will continue to increase into the future.

FERC Account 350 Transmission Depreciable Land Rights (0 percent) The currently approved net salvage estimate for this account is zero percent.

Retirement activity has been very limited in this account. Since land rights intrinsically

have no removal costs (removal costs are attributed to the property on the land, not to the

land itself) and have no salvage value, the existing zero percent net salvage was retained.


FERC Account 352 Transmission Substation Structures and Improvements (Negative

10 percent) The currently approved net salvage estimate for this account is negative 5 percent.

In the 2017 transaction year, a moving average existed of negative 102 and negative 81

percent for the five-year and 10-year bands, respectively. However, in 2014, a negative 13

and negative 12 percent exist for the five-year and 10-year bands, respectively. Due to the

extreme swing between 2014 and 2017, even though the 2017 10-year band statistics

show a more negative net salvage, this study recommends moving toward those

indications with a conservative net salvage estimate of negative 10 percent for this account

until more information is available.

FERC Account 353 Transmission Station Equipment (Negative 20 percent) The currently approved net salvage estimate for this account is zero percent. In the

most recent period, a moving average of negative 40 percent exists for the five-year band

and a negative 33 percent exists for the 10-year band. The most recent years are fairly

consistent and more indicative of future net salvage expectations. Therefore, this study

recommends a bigger but still conservative move to a negative 20 percent for this account.

FERC Account 354 Transmission Tower and Fixtures (Negative 5 percent) The currently approved net salvage estimate for this account is zero percent. There

has been no salvage or removal recorded consistently in this account. The last retirement

and cost of removal was recorded in 2014. Given the small level of retirements and the

lack of net salvage transactional data, this study recommends reflecting a small amount of

removal cost with a negative five percent net salvage estimate for this account.

FERC Account 355 Transmission Poles and Fixtures (Negative 35 percent) The currently approved net salvage estimate for this account is positive 5 percent.

Assets in this account are impacted by many factors:

• Increased load on the system and lack of redundancy in some areas has caused

the Company to perform work under energized conditions (no outage), which is


more costly than performing the work under dead line conditions with an outage;

• Increased cost of demolition due to regulation and restrictions on environmental

impact, mitigation, and restoration measures;

• Wood assets in this account have no salvage value;

• Increased environmental protections require spending removal cost amounts to

treat wood protectant material (creosote).

In the most recent period, a moving average of negative 183 and negative 244 percent

exists for the five-year and 10-year bands, respectively. The lowest moving average in

2017 is the two year at negative 128. This account has experienced this level of negative

net salvage or more since around 2006. There is a significant level of retirements to move

strongly but still conservatively toward the indications. Based on the consistently negative

net salvage indications, this study recommends reflecting a removal cost with a negative 60

percent net salvage estimate for this account. While the data supports a negative 60

percent net salvage estimate, the Company recommended an interim step by proposing

this net salvage rate to be the negative 35 percent that is currently used in SPS’s Texas

retail jurisdiction.

FERC Account 356 Transmission Overhead Conductor (Negative 30 percent) The currently approved net salvage estimate for this account is positive 5 percent. In

the most recent period, a moving average of negative 137 and negative 115 percent exists

for the five-year and 10-year bands, respectively. Since 1991, this account has

experienced negative net salvage and is becoming more negative over time. The last five

to 15 years is a more appropriate indicator of future net salvage for this account. A

negative 32 percent in the 10 year moving average was present in 2011 and is about half

of the overall recent indications. This study conservatively recommends a negative 30

percent net salvage estimate for this account.

FERC Account 357 Transmission Underground Conduit (0 percent) The current approved net salvage estimate for this account is zero percent. There

has been only one year, 2012, with retirements recorded during the study period. While


this single year indicates cost of removal will exceed any salvage, there is not enough data

to change the existing zero percent net salvage estimate at this time and it is thus retained.

FERC Account 358 Transmission Underground Conductor and Devices (0 percent) The current approved net salvage estimate for this account is positive 10 percent.

There has been only two years, 2011 and 2012, with retirements recorded during the study

period. While these years indicate cost of removal will exceed any salvage, there is not

enough data retain the existing positive net salvage. This study recommends a change to

zero percent net salvage for this account.

FERC Account 359 Roads and Trails (0 percent) The current approved net salvage estimate for this account is negative 5 percent.

There has been no retirements recorded during the study period. There is not enough data

to retain the existing negative 5 percent net salvage. This study recommends a change to

zero percent net salvage for this account.


APPENDIX A

Computation of Depreciation Accrual Rates


Pla

ntA

lloca

ted

Ann

ual

FER

CB

alan

ceD

epr R

eser

veN

et

Net

Sal

vage

Una

ccru

edR

emai

ning

A

nnua

lA

ccru

al

Acc

ount

Des

crip

tion

06/3

0/20

1806

/30/

2018

Sal

vage

%A

mou

ntB

alan

ceLi

feA

ccru

alR

ate

350.2LAND RIGHT

S14

6,75

3,34

2.75

10,626

,392

.33

0.00

%0.00

136,12

6,95

0.42

72.00

1,89

0,58

7.82

1.28

83%

352STRU

CTURE

S AN

D IM

PROVE

MEN

TS98

,404

,057

.24

12,961

,189

.86

‐10.00

%(9,840

,405

.72)

95,283

,273

.10

54.25

1,75

6,22

4.16

1.78

47%

353STAT

ION EQUIPMEN

T1,09

7,25

0,22

6.67

126,35

9,79

0.20

‐20.00

%(219

,450

,045

.33)

1,19

0,34

0,48

1.81

47.71

24,947

,973

.13

2.27

37%

354TO

WER

S AN

D FIXTURE

S8,18

1,20

9.41

2,11

9,50

5.52

‐5.00%

(409

,060

.47)

6,47

0,76

4.37

49.45

130,84

9.61

1.59

94%

355PO

LES AN

D FIXTURE

S1,12

3,60

1,85

5.80

168,81

5,97

3.38

‐35.00

%(393

,260

,649

.53)

1,34

8,04

6,53

1.95

39.78

33,888

,922

.28

3.01

61%

356OVE

RHEA

D CO

NDU

CTORS

AND DE

VICE

S43

6,15

7,16

3.43

75,907

,571

.60

‐30.00

%(130

,847

,149

.03)

491,09

6,74

0.86

38.31

12,817

,991

.96

2.93

88%

357UNDE

RGRO

UND CO

NDU

IT25

5,07

3.38

108,03

1.52

0.00

%0.00

147,04

1.86

31.15

4,72

1.15

1.85

09%

358UNDE

RGRO

UND CO

NDU

CTORS

AND DE

VICE

S48

9,71

6.71

199,89

6.56

0.00

%0.00

289,82

0.15

19.64

14,756

.32

3.01

32%

359RO

ADS AN

D TR

AILS

517,73

6.10

17,284

.96

0.00

%0.00

500,45

1.14

62.00

8,07

1.27

1.55

90%

TOTA

L TR

ANSM

ISSION PLANT

2,91

1,61

0,38

1.49

397,11

5,63

5.92

(753

,807

,310

.09)

3,26

8,30

2,05

5.66

75,460

,097

.71

2.59

17%

Sout

hwes

tern

Pub

lic S

ervi

ce C

ompa

nyFE

RC

Com

puta

tion

of D

epre

ciat

ion

Acc

rual

Rat

esA

t Jun

e 30

, 201

8


APPENDIX B

Comparison of Approved vs Proposed Accrual Rates


Allo

cate

dA

ppro

ved

Dep

reci

atio

n P

ropo

sed

Pla

nt

Boo

k R

eser

ve T

otal

E

xpen

se

Tot

al

Pro

pose

d

FER

CB

alan

ceB

alan

ce D

epre

ciat

ion

At A

ppro

ved

D

epre

ciat

ion

Dep

reci

atio

n

A

ccou

ntD

escr

iptio

n06

/30/

2018

06/3

0/20

18R

ate

%N

otes

Rat

es R

ate

%

Exp

ense

D

iffer

ence

(1

)(2

)(3

)(4

) = (1

) x (3

)(5

)(6

) = (5

) x (1

)(7

) = (6

) - (4

)

350.

2LA

ND

RIG

HTS

146,

753,

342.

7510

,626

,392

.33

2.00

00%

(B)

2,93

5,06

6.86

1.28

83%

1,89

0,58

7.82

(1,0

44,4

79.0

3)35

2S

TRU

CTU

RE

S A

ND

IMP

RO

VE

ME

NTS

98,4

04,0

57.2

412

,961

,189

.86

2.01

40%

(A)

1,98

1,85

7.71

1.78

47%

1,75

6,22

4.16

(225

,633

.55)

353

STA

TIO

N E

QU

IPM

EN

T1,

097,

250,

226.

6712

6,35

9,79

0.20

1.

8840

%(A

)20

,672

,194

.27

2.27

37%

24,9

47,9

73.1

34,

275,

778.

8635

4TO

WE

RS

AN

D F

IXTU

RE

S8,

181,

209.

412,

119,

505.

52

1.

2510

%(A

)10

2,34

6.93

1.59

94%

130,

849.

6128

,502

.68

355

PO

LES

AN

D F

IXTU

RE

S1,

123,

601,

855.

8016

8,81

5,97

3.38

2.

0050

%(A

)22

,528

,217

.21

3.01

61%

33,8

88,9

22.2

811

,360

,705

.07

356

OV

ER

HE

AD

CO

ND

UC

TOR

S A

ND

DE

VIC

ES

436,

157,

163.

4375

,907

,571

.60

1.97

40%

(A)

8,60

9,74

2.41

2.93

88%

12,8

17,9

91.9

64,

208,

249.

5635

7U

ND

ER

GR

OU

ND

CO

ND

UIT

255,

073.

3810

8,03

1.52

1.

2420

%(A

)3,

168.

011.

8509

%4,

721.

151,

553.

1435

8U

ND

ER

GR

OU

ND

CO

ND

UC

TOR

S A

ND

DE

VIC

ES

489,

716.

7119

9,89

6.56

1.

7270

%(A

)8,

457.

413.

0132

%14

,756

.32

6,29

8.91

359

RO

AD

S A

ND

TR

AIL

S51

7,73

6.10

17,2

84.9

6

2.

0140

%(C

)10

,427

.21

1.55

90%

8,07

1.27

(2,3

55.9

3)

T

OTA

L TR

AN

SM

ISS

ION

PLA

NT

2,91

1,61

0,38

1.49

397,

115,

635.

9256

,851

,478

.01

75,4

60,0

97.7

1

18,6

08,6

19.7

0

(A) A

pproved de

preciatio

n rates from Docket N

o. EL89‐50

‐000

(B) SPS amortizes land

and

water rights over 5

0 years

(C) SPS is currently usin

g Accoun

t FER

C 35

2 de

preciatio

n rates for FER

C Accoun

t 359

Sou

thw

este

rn P

ublic

Ser

vice

Com

pany

Com

paris

on o

f File

d vs

Pro

pose

d D

epre

ciat

ion

Acc

rual

Rat

esA

t Jun

e 30

, 201

8


APPENDIX C

Comparison of Depreciation Parameters


FERC

Acco uDe

scrip

tion

Average

Life

Iowa

Curve

Net

Salvage %

Note

Average

Life

Iowa

Curve

Net

Salvage %

Average

Life

Net

Salvage %

350.2LAND RIGHT

S50

0.00

%(B)

80R4

0.00

%30

0.00

%35

2STRU

CTURE

S AN

D IM

PROVE

MEN

TS50

R2‐5.00%

(A)

65R4

‐10.00

%15

‐5.00%

353STAT

ION EQUIPMEN

T50

R30.00

%(A)

55R2

‐20.00

%5

‐20.00

%35

4TO

WER

S AN

D FIXTURE

S75

R30.00

%(A)

75R4

‐5.00%

0‐5.00%

355PO

LES AN

D FIXTURE

S45

R2.5

5.00

%(A)

47R3

‐35.00

%2

‐40.00

%35

6OVE

RHEA

D CO

NDU

CTORS

AND DE

VICE

S45

R35.00

%(A)

47R2

‐30.00

%2

‐35.00

%35

7UNDE

RGRO

UND CO

NDU

IT75

R30.00

%(A)

75R3

0.00

%0

0.00

%35

8UNDE

RGRO

UND CO

NDU

CTORS

AND DE

VICE

S45

R310

.00%

(A)

45R3

0.00

%0

‐10.00

%35

9RO

ADS AN

D TR

AILS

50R2

‐5.00%

(C)

65R4

0.00

%15

5.00

%

(A) A

ppro

ved

para

met

ers

from

Doc

ket N

o. E

L89-

50-0

00

(B) SPS amortizes land

and

water rights over 5

0 years

(C) SPS is currently usin

g Accoun

t FER

C 35

2 de

preciatio

n rates for FER

C Accoun

t 359

Southw

estern Pub

lic Service Com

pany

‐ FERC

Comparison

of D

epreciation Parameters

At Ju

ne 30, 201

8

Prop

osed

Diffe

rence

Approved


APPENDIX D

Net Salvage Analysis by Account


Tran

sact

iona

l 2-

yr

3- y

r4-

yr

5- y

r6-

yr

7- y

r8-

yr

9- y

r10

- yr

Tran

sact

ion

His

tory

Rem

oval

Net

Net

Net

Net

Net

Net

Net

Net

Net

Net

Net

Year

Ret

irem

ents

Salv

age

Cos

tSa

lvag

eSa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %19

95-

- -

- N

AN

A19

96-

- -

- N

AN

AN

A19

97-

- -

- N

AN

AN

AN

A19

98-

- -

- N

AN

AN

AN

AN

A19

99-

- -

- N

AN

AN

AN

AN

AN

A20

00-

- -

- N

AN

AN

AN

AN

AN

AN

A20

01-

- -

- N

AN

AN

AN

AN

AN

AN

AN

A20

02-

- -

- N

AN

AN

AN

AN

AN

AN

AN

AN

A20

03-

- -

- N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

04-

- -

- N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

05-

- -

- N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

06-

- -

- N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

07-

- -

- N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

08-

- -

- N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

09-

- -

- N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

1026

,242

-

5 (5

)

-0.0

2%-0

.02%

-0.0

2%-0

.02%

-0.0

2%-0

.02%

-0.0

2%-0

.02%

-0.0

2%-0

.02%

2011

11,3

87

- -

- 0.

00%

-0.0

1%-0

.01%

-0.0

1%-0

.01%

-0.0

1%-0

.01%

-0.0

1%-0

.01%

-0.0

1%20

12-

- -

- N

A0.

00%

-0.0

1%-0

.01%

-0.0

1%-0

.01%

-0.0

1%-0

.01%

-0.0

1%-0

.01%

2013

- -

- -

NA

NA

0.00

%-0

.01%

-0.0

1%-0

.01%

-0.0

1%-0

.01%

-0.0

1%-0

.01%

2014

6,65

5

- 26

1

(261

)

-3.9

2%-3

.92%

-3.9

2%-1

.45%

-0.6

0%-0

.60%

-0.6

0%-0

.60%

-0.6

0%-0

.60%

2015

- -

- -

NA

-3.9

2%-3

.92%

-3.9

2%-1

.45%

-0.6

0%-0

.60%

-0.6

0%-0

.60%

-0.6

0%20

16-

- -

- N

AN

A-3

.92%

-3.9

2%-3

.92%

-1.4

5%-0

.60%

-0.6

0%-0

.60%

-0.6

0%20

17-

- -

- N

AN

AN

A-3

.92%

-3.9

2%-3

.92%

-1.4

5%-0

.60%

-0.6

0%-0

.60%

Sout

hwes

tern

Pub

lic S

ervi

ceR

etire

men

t and

Sal

vage

Ana

lysi

sA

ccou

nt 3

50 D

epre

ciab

le U

nadj

uste

d D

ata

1995

-201

7


Tran

sact

iona

l 2-

yr

3- y

r4-

yr

5- y

r6-

yr

7- y

r8-

yr

9- y

r10

- yr

Tran

sact

ion

His

tory

Rem

oval

Net

Net

Net

Net

Net

Net

Net

Net

Net

Net

Net

Year

Ret

irem

ents

Salv

age

Cos

tSa

lvag

eSa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %19

85-

738

40

2

336

N

A19

865,

542

3,

892

5,

350

(1

,458

)

-26.

31%

-20.

25%

1987

- -

- N

A-2

6.31

%-2

0.25

%19

8814

,358

1,

109

2,

983

(1

,874

)

-13.

05%

-13.

05%

-16.

74%

-15.

06%

1989

14,1

28

3,39

5

19,9

42

(16,

547)

-117

.12%

-64.

67%

-64.

67%

-58.

42%

-57.

43%

1990

5,20

6

39 4,

790

(4

,751

)

-91.

26%

-110

.16%

-68.

78%

-68.

78%

-62.

78%

-61.

92%

1991

4,53

8

186

4,

604

(4

,418

)

-97.

36%

-94.

10%

-107

.72%

-72.

17%

-72.

17%

-66.

36%

-65.

59%

1992

7,70

8

821

6,

187

(5

,366

)

-69.

62%

-79.

90%

-83.

29%

-98.

42%

-71.

74%

-71.

74%

-66.

85%

-66.

20%

1993

2,35

3

58 4,

972

(4

,914

)

-208

.84%

-102

.18%

-100

.68%

-98.

20%

-106

.08%

-78.

42%

-78.

42%

-73.

06%

-72.

43%

1994

1,29

6

16 16

3

(147

)

-11.

34%

-138

.70%

-91.

81%

-93.

39%

-92.

87%

-102

.59%

-76.

67%

-76.

67%

-71.

60%

-71.

00%

1995

7,12

8

5,96

9

1,53

2

4,43

7

62.2

5%50

.93%

-5.7

9%-3

2.40

%-4

5.21

%-5

3.70

%-7

4.85

%-5

9.21

%-5

9.21

%-5

6.28

%19

966,

107

3,

232

10

,574

(7

,342

)

-120

.23%

-21.

95%

-21.

00%

-47.

18%

-54.

21%

-60.

93%

-65.

53%

-80.

57%

-65.

14%

-65.

14%

1997

153

-

- -

0.00

%-1

17.2

9%-2

1.70

%-2

0.78

%-4

6.76

%-5

3.88

%-6

0.62

%-6

5.24

%-8

0.32

%-6

4.98

%19

9874

- -

- 0.

00%

0.00

%-1

15.9

1%-2

1.58

%-2

0.68

%-4

6.55

%-5

3.72

%-6

0.46

%-6

5.10

%-8

0.19

%19

992,

452

-

- -

0.00

%0.

00%

0.00

%-8

3.56

%-1

8.25

%-1

7.73

%-4

0.72

%-4

8.89

%-5

5.80

%-6

0.79

%20

0040

8

- -

- 0.

00%

0.00

%0.

00%

0.00

%-7

9.85

%-1

7.80

%-1

7.32

%-3

9.89

%-4

8.17

%-5

5.09

%20

0165

5

- -

- 0.

00%

0.00

%0.

00%

0.00

%0.

00%

-74.

54%

-17.

11%

-16.

70%

-38.

62%

-47.

05%

2002

16,8

19

11,5

78

36,4

93

(24,

915)

-148

.13%

-142

.58%

-139

.33%

-122

.53%

-122

.08%

-121

.17%

-120

.95%

-82.

31%

-79.

69%

-87.

81%

2003

456

-

3,29

0

(3,2

90)

-7

22.2

5%-1

63.2

7%-1

57.3

1%-1

53.8

1%-1

35.6

7%-1

35.1

8%-1

34.2

0%-1

31.0

5%-9

0.83

%-8

7.93

%20

0416

3

- -

- 0.

00%

-531

.69%

-161

.74%

-155

.89%

-152

.45%

-134

.61%

-134

.13%

-133

.16%

-130

.27%

-90.

39%

2005

2,13

0

- 50

0

(500

)

-23.

46%

-21.

79%

-137

.89%

-146

.70%

-141

.94%

-139

.13%

-124

.35%

-123

.96%

-123

.14%

-122

.54%

2006

- -

864

(8

64)

N

A-6

4.06

%-5

9.50

%-1

69.3

5%-1

51.1

1%-1

46.2

2%-1

43.3

3%-1

28.1

0%-1

27.6

9%-1

26.8

5%20

07-

- 48

1

(481

)

NA

NA

-86.

65%

-80.

48%

-186

.85%

-153

.57%

-148

.60%

-145

.66%

-130

.18%

-129

.77%

2008

17,3

15

63 63

- 0.

00%

-2.7

8%-7

.77%

-9.4

9%-9

.41%

-25.

60%

-81.

47%

-80.

05%

-79.

19%

-74.

38%

2009

14,1

60

- 1,

278

(1

,278

)

-9.0

2%-4

.06%

-5.5

9%-8

.33%

-9.2

9%-9

.25%

-18.

74%

-61.

38%

-60.

60%

-60.

12%

2010

5,18

7

1,75

3

1,75

3

- 0.

00%

-6.6

0%-3

.49%

-4.8

0%-7

.16%

-8.0

5%-8

.02%

-16.

27%

-55.

71%

-55.

07%

2011

4,07

0

1,85

2

1,85

2

- 0.

00%

0.00

%-5

.46%

-3.1

4%-4

.32%

-6.4

4%-7

.29%

-7.2

6%-1

4.75

%-5

1.95

%20

1262

,481

-

7,02

8

(7,0

28)

-1

1.25

%-1

0.56

%-9

.80%

-9.6

7%-8

.05%

-8.5

1%-9

.35%

-9.6

4%-9

.62%

-12.

68%

2013

50,3

03

- 4,

018

(4,0

18)

-7

.99%

-9.7

9%-9

.45%

-9.0

5%-9

.05%

-8.0

3%-8

.34%

-8.9

0%-9

.10%

-9.0

9%20

1453

,701

19

0

11,8

98

(11,

708)

-21.

80%

-15.

12%

-13.

67%

-13.

34%

-12.

95%

-12.

65%

-11.

60%

-11.

83%

-12.

25%

-12.

36%

2015

36,4

58

48,0

65

312,

881

(2

64,8

16)

-7

26.3

7%-3

06.7

1%-1

99.7

3%-1

41.7

0%-1

38.9

1%-1

35.5

2%-1

27.6

1%-1

18.5

4%-1

18.7

4%-1

19.0

9%20

1623

,324

-

28,9

80

(28,

980)

-124

.25%

-491

.45%

-269

.21%

-188

.98%

-139

.90%

-137

.43%

-134

.40%

-127

.29%

-119

.04%

-119

.22%

2017

206,

151

-

66,3

19

(66,

319)

-32.

17%

-41.

53%

-135

.42%

-116

.33%

-101

.60%

-88.

54%

-87.

72%

-86.

69%

-84.

27%

-81.

19%

Sout

hwes

tern

Pub

lic S

ervi

ceR

etire

men

t and

Sal

vage

Ana

lysi

sA

ccou

nt 3

52 A

djus

ted

Dat

a19

85-2

017


Tran

sact

iona

l 2-

yr

3- y

r4-

yr

5- y

r6-

yr

7- y

r8-

yr

9- y

r10

- yr

Tran

sact

ion

His

tory

Rem

oval

Net

Net

Net

Net

Net

Net

Net

Net

Net

Net

Net

Year

Ret

irem

ents

Salv

age

Cos

tSa

lvag

eSa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %19

6886

,645

20

,289

6,

835

13

,454

15

.53%

1969

35,2

51

12,6

04

2,04

1

10,5

63

29.9

7%19

.70%

1970

47,2

39

13,4

54

3,70

5

9,74

9

20.6

4%24

.62%

19.9

6%19

7135

,333

10

,162

4,

907

5,

255

14

.87%

18.1

7%21

.70%

19.0

8%19

7213

0,73

1

8,32

6

8,66

1

(335

)

-0.2

6%2.

96%

6.88

%10

.15%

11.5

4%19

7344

,652

3,

240

1,

135

2,

105

4.

71%

1.01

%3.

33%

6.50

%9.

32%

10.7

4%19

7479

,396

9,

776

7,

986

1,

790

2.

25%

3.14

%1.

40%

3.04

%5.

50%

7.82

%9.

27%

1975

92,4

88

9,37

0

6,64

4

2,72

6

2.95

%2.

63%

3.06

%1.

81%

3.02

%4.

95%

6.85

%8.

21%

1976

100,

899

7,

274

12

,539

(5

,265

)

-5.2

2%-1

.31%

-0.2

7%0.

43%

0.23

%1.

30%

3.02

%4.

70%

6.14

%19

7713

5,95

6

25,4

23

14,3

58

11,0

65

8.14

%2.

45%

2.59

%2.

52%

2.74

%2.

07%

2.80

%4.

06%

5.36

%6.

48%

1978

71,8

21

20,2

19

11,2

84

8,93

5

12.4

4%9.

63%

4.77

%4.

35%

4.01

%4.

07%

3.20

%3.

80%

4.88

%6.

02%

1979

218,

855

41

,381

8,

555

32

,826

15

.00%

14.3

7%12

.38%

9.02

%8.

11%

7.45

%7.

28%

6.16

%6.

49%

7.19

%19

8027

,600

9,

400

1,

625

7,

775

28

.17%

16.4

7%15

.56%

13.3

4%9.

97%

8.97

%8.

23%

8.03

%6.

83%

7.13

%19

8130

6,43

4

11,8

15

14,9

07

(3,0

92)

-1

.01%

1.40

%6.

78%

7.43

%7.

56%

6.06

%5.

76%

5.49

%5.

46%

4.84

%19

8212

1,19

8

898

6,

437

(5

,539

)

-4.5

7%-2

.02%

-0.1

9%4.

74%

5.48

%5.

89%

4.75

%4.

60%

4.44

%4.

45%

1983

92,1

97

34,5

86

32,1

61

2,42

5

2.63

%-1

.46%

-1.1

9%0.

29%

4.49

%5.

17%

5.58

%4.

57%

4.44

%4.

30%

1984

326,

201

16

,915

77

,709

(6

0,79

4)

-1

8.64

%-1

3.95

%-1

1.84

%-7

.92%

-6.7

8%-2

.42%

-1.5

0%-0

.49%

-0.8

3%-0

.60%

1985

213,

440

25

,883

25

,201

68

2

0.32

%-1

1.14

%-9

.13%

-8.4

0%-6

.26%

-5.3

9%-1

.97%

-1.2

2%-0

.38%

-0.6

8%19

8643

1,52

4

16,3

50

43,8

22

(27,

472)

-6.3

7%-4

.15%

-9.0

2%-8

.01%

-7.6

6%-6

.29%

-5.6

6%-3

.06%

-2.4

5%-1

.71%

1987

361,

122

18

3,38

3

45,1

15

138,

268

38

.29%

13.9

8%11

.08%

3.80

%3.

73%

3.08

%2.

40%

2.78

%4.

05%

4.33

%19

8818

3,48

5

12,7

13

29,7

97

(17,

084)

-9.3

1%22

.25%

9.60

%7.

94%

2.22

%2.

24%

1.76

%1.

35%

1.70

%2.

98%

1989

2,63

8,93

5

1,45

2,46

2

205,

677

1,

246,

785

47.2

5%43

.57%

42.9

7%37

.08%

35.0

3%30

.82%

30.2

1%29

.24%

27.2

6%27

.26%

1990

519,

391

14

6,93

4

90,9

86

55,9

48

10.7

7%41

.25%

38.4

7%38

.45%

33.7

8%32

.13%

28.5

9%28

.09%

27.2

8%25

.61%

1991

780,

433

13

7,72

5

149,

752

(1

2,02

7)

-1

.54%

3.38

%32

.77%

30.9

0%31

.49%

28.1

7%27

.01%

24.2

8%23

.92%

23.3

1%19

9298

8,83

1

151,

810

65

,706

86

,104

8.

71%

4.19

%5.

68%

27.9

4%26

.60%

27.3

7%24

.91%

24.0

5%21

.89%

21.6

2%19

9355

0,66

8

25,2

54

123,

495

(9

8,24

1)

-1

7.84

%-0

.79%

-1.0

4%1.

12%

23.3

4%22

.28%

23.2

4%21

.26%

20.5

9%18

.76%

1994

468,

192

72

,916

53

,093

19

,823

4.

23%

-7.7

0%0.

38%

-0.1

6%1.

56%

21.8

3%20

.90%

21.8

7%20

.11%

19.5

2%19

9554

8,60

7

21,9

69

87,1

77

(65,

208)

-11.

89%

-4.4

6%-9

.16%

-2.2

5%-2

.08%

-0.3

5%18

.99%

18.2

1%19

.24%

17.7

6%19

9678

6,12

0

34,2

69

105,

493

(7

1,22

4)

-9

.06%

-10.

22%

-6.4

7%-9

.13%

-3.8

5%-3

.41%

-1.8

3%15

.96%

15.3

4%16

.40%

1997

527,

061

63

9,69

2

90,8

71

548,

821

10

4.13

%36

.37%

22.1

5%18

.55%

11.5

9%10

.86%

8.78

%8.

98%

21.9

1%21

.19%

1998

182,

513

-

7,00

2

(7,0

02)

-3

.84%

76.3

6%31

.46%

19.8

3%16

.92%

10.6

7%10

.19%

8.30

%8.

54%

21.3

2%19

9981

0,52

9

- -

- 0.

00%

-0.7

1%35

.64%

20.4

1%14

.20%

12.8

0%8.

44%

8.50

%7.

11%

7.42

%20

0072

,863

-

- -

0.00

%0.

00%

-0.6

6%34

.01%

19.7

8%13

.85%

12.5

2%8.

28%

8.37

%7.

02%

2001

177,

190

-

4,84

5

(4,8

45)

-2

.73%

-1.9

4%-0

.46%

-0.9

5%30

.33%

18.2

2%12

.90%

11.7

6%7.

81%

7.98

%20

0280

6,03

0

1,00

0,13

1

1,28

1,17

1

(281

,040

)

-34.

87%

-29.

08%

-27.

07%

-15.

32%

-14.

29%

9.93

%5.

49%

3.06

%3.

18%

0.83

%20

0326

4,55

0

- 11

,888

(1

1,88

8)

-4

.49%

-27.

36%

-23.

86%

-22.

55%

-13.

97%

-13.

17%

8.59

%4.

77%

2.58

%2.

74%

2004

6,90

4

(110

)

- (1

10)

-1

.59%

-4.4

2%-2

7.20

%-2

3.74

%-2

2.44

%-1

3.93

%-1

3.14

%8.

57%

4.75

%2.

57%

2005

1,51

3,61

9

- 19

0,07

1

(190

,071

)

-12.

56%

-12.

51%

-11.

32%

-18.

64%

-17.

63%

-17.

17%

-13.

36%

-12.

91%

1.24

%-0

.34%

2006

139,

000

-

65,9

99

(65,

999)

-47.

48%

-15.

49%

-15.

44%

-13.

93%

-20.

11%

-19.

05%

-18.

59%

-14.

61%

-14.

12%

-0.2

7%20

071,

357,

711

59

,125

30

8,59

8

(249

,473

)

-18.

37%

-21.

08%

-16.

79%

-16.

76%

-15.

77%

-19.

54%

-18.

84%

-18.

52%

-15.

61%

-15.

20%

2008

1,96

0,12

9

58,7

14

218,

448

(1

59,7

34)

-8

.15%

-12.

33%

-13.

75%

-13.

38%

-13.

37%

-12.

92%

-15.

85%

-15.

47%

-15.

29%

-13.

55%

2009

841,

086

14

4,51

4

290,

088

(1

45,5

74)

-1

7.31

%-1

0.90

%-1

3.34

%-1

4.44

%-1

3.95

%-1

3.94

%-1

3.53

%-1

6.02

%-1

5.69

%-1

5.53

%20

102,

382,

462

49

,888

55

2,62

0

(502

,732

)

-21.

10%

-20.

11%

-15.

59%

-16.

17%

-16.

82%

-16.

03%

-16.

02%

-15.

66%

-17.

33%

-17.

05%

2011

1,91

9,96

8

169,

918

69

6,61

2

(526

,695

)

-27.

43%

-23.

93%

-22.

84%

-18.

79%

-18.

72%

-19.

19%

-18.

20%

-18.

18%

-17.

84%

-19.

06%

2012

3,27

5,74

1

103,

094

75

7,35

9

(654

,265

)

-19.

97%

-22.

73%

-22.

22%

-21.

73%

-19.

16%

-19.

07%

-19.

40%

-18.

63%

-18.

62%

-18.

35%

2013

1,80

3,52

3

55,2

20

576,

841

(5

21,6

21)

-2

8.92

%-2

3.15

%-2

4.33

%-2

3.51

%-2

3.00

%-2

0.61

%-2

0.38

%-2

0.66

%-1

9.85

%-1

9.84

%20

1427

9,97

7

314,

343

19

0,08

0

124,

262

44

.38%

-19.

07%

-19.

62%

-21.

68%

-21.

54%

-21.

20%

-19.

15%

-19.

07%

-19.

35%

-18.

69%

2015

4,61

1,88

1

474,

486

5,

185,

330

(4

,710

,844

)

-1

02.1

5%-9

3.76

%-7

6.29

%-5

7.79

%-5

2.89

%-4

7.58

%-4

5.90

%-4

1.57

%-3

9.86

%-3

9.91

%20

162,

586,

292

87

,002

82

6,51

8

(739

,516

)

-28.

59%

-75.

72%

-71.

22%

-63.

00%

-51.

78%

-48.

55%

-44.

67%

-43.

37%

-39.

86%

-38.

47%

2017

10,7

05,6

74

425,

330

2,

499,

697

(2

,074

,367

)

-1

9.38

%-2

1.17

%-4

2.03

%-4

0.70

%-3

9.64

%-3

6.87

%-3

6.15

%-3

4.85

%-3

4.33

%-3

2.64

%

Sout

hwes

tern

Pub

lic S

ervi

ceR

etire

men

t and

Sal

vage

Ana

lysi

sA

ccou

nt 3

53 A

djus

ted

Dat

a19

68-2

017


Tran

sact

iona

l 2-

yr

3- y

r4-

yr

5- y

r6-

yr

7- y

r8-

yr

9- y

r10

- yr

Tran

sact

ion

His

tory

Rem

oval

Net

Net

N

et

Net

N

et

Net

N

et

Net

N

et

Net

N

et

Year

Ret

irem

ents

Salv

age

Cos

tSa

lvag

eSa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %19

8950

,440

33

,815

27,8

45

5,

970

11

.84%

1990

-

-

-

-

N

A11

.84%

1991

-

-

-

-

N

AN

A11

.84%

19

92-

-

-

-

NA

NA

NA

11.8

4%

19

93-

-

-

-

NA

NA

NA

NA

11.8

4%

19

94-

-

-

-

NA

NA

NA

NA

NA

11.8

4%

1995

-

-

-

-

N

AN

AN

AN

AN

AN

A11

.84%

1996

-

-

-

-

N

AN

AN

AN

AN

AN

AN

A11

.84%

19

97-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

11.8

4%

1998

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

A11

.84%

1999

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

00-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2001

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

02-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2003

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

04-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2005

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

06-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2007

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

08-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2009

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

10-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2011

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

12-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2013

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

1420

,154

7,

799

95

,654

(87,

855)

-435

.92%

-435

.92%

-435

.92%

-435

.92%

-435

.92%

-435

.92%

-435

.92%

NA

NA

NA

2015

-

-

-

-

N

A-4

35.9

2%-4

35.9

2%-4

35.9

2%-4

35.9

2%-4

35.9

2%-4

35.9

2%-4

35.9

2%N

AN

A20

16-

-

-

-

NA

NA

-435

.92%

-435

.92%

-435

.92%

-435

.92%

-435

.92%

-435

.92%

-435

.92%

NA

2017

-

-

-

-

NA

NA

NA

-435

.92%

-435

.92%

-435

.92%

-435

.92%

-435

.92%

-435

.92%

-435

.92%

Sout

hwes

tern

Pub

lic S

ervi

ceR

etire

men

t and

Sal

vage

Ana

lysi

sA

ccou

nt 3

54 A

djus

ted

Dat

a19

89-2

017


Tran

sact

iona

l 2-

yr

3- y

r4-

yr

5- y

r6-

yr

7- y

r8-

yr

9- y

r10

- yr

Tran

sact

ion

His

tory

Rem

oval

Net

Net

N

et

Net

N

et

Net

N

et

Net

N

et

Net

N

et

Year

Ret

irem

ents

Salv

age

Cos

tSa

lvag

eSa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %19

6823

9,40

9

70,8

33

39

,223

31,6

10

13

.20%

1969

127,

364

40

,879

8,48

5

32,3

94

25

.43%

17.4

5%

19

7021

1,94

3

28,0

10

23

,145

4,86

5

2.30

%10

.98%

11.9

0%

1971

97,8

15

18,6

36

15

,247

3,38

9

3.46

%2.

66%

9.30

%10

.68%

1972

133,

409

51

,433

20,3

64

31

,069

23.2

9%14

.90%

8.87

%12

.57%

12.7

6%

19

7384

,301

40

,263

15,9

96

24

,267

28.7

9%25

.42%

18.6

1%12

.06%

14.6

6%14

.27%

19

7455

,902

19

,460

13,0

19

6,

441

11

.52%

21.9

0%22

.58%

17.5

4%12

.00%

14.4

1%14

.11%

1975

151,

015

61

,647

25,4

93

36

,154

23.9

4%20

.59%

22.9

6%23

.06%

19.3

9%14

.46%

16.0

8%15

.46%

19

7616

8,59

1

12,6

89

7,

828

4,

861

2.

88%

12.8

3%12

.64%

15.6

0%17

.33%

15.3

7%12

.30%

13.9

2%13

.79%

19

7711

3,55

0

95,4

40

35

,535

59,9

05

52

.76%

22.9

6%23

.30%

21.9

5%22

.96%

23.0

2%20

.64%

16.8

2%17

.78%

16.9

9%19

7810

0,96

8

73,4

56

13

,135

60,3

21

59

.74%

56.0

4%32

.65%

30.1

9%28

.42%

28.4

7%27

.61%

25.0

0%20

.70%

21.1

8%19

7912

1,19

4

107,

289

31,8

49

75

,440

62.2

5%61

.11%

58.2

8%39

.76%

36.1

2%34

.18%

33.6

1%32

.13%

29.4

0%24

.76%

1980

139,

132

70

,405

21,4

83

48

,922

35.1

6%47

.77%

51.1

2%51

.51%

38.7

7%35

.95%

34.3

4%33

.84%

32.5

2%30

.09%

1981

289,

903

18

4,35

9

74

,199

110,

160

38

.00%

37.0

8%42

.62%

45.2

8%46

.39%

38.5

3%36

.50%

35.2

7%34

.83%

33.6

9%19

8228

7,51

8

33,7

48

20

,261

13,4

87

4.

69%

21.4

1%24

.08%

29.6

0%32

.85%

34.9

9%30

.56%

29.8

3%29

.11%

29.1

0%19

8328

5,09

0

382,

891

185,

184

197,

707

69

.35%

36.8

8%37

.26%

36.9

7%39

.70%

41.3

5%42

.32%

37.9

0%36

.63%

35.8

1%19

8416

4,83

3

193,

221

308,

297

(115

,076

)

-69.

81%

18.3

7%13

.03%

20.0

8%21

.88%

25.6

8%28

.15%

30.0

1%27

.28%

27.0

0%19

8513

5,86

2

100,

863

145,

791

(44,

928)

-33.

07%

-53.

21%

6.44

%5.

86%

13.8

7%16

.15%

20.0

7%22

.70%

24.7

8%22

.74%

1986

167,

695

12

7,39

7

17

5,10

3

(4

7,70

6)

-2

8.45

%-3

0.52

%-4

4.35

%-1

.33%

0.33

%8.

54%

11.0

6%14

.96%

17.6

3%19

.84%

1987

46,5

45

6,45

3

8,09

7

(1,6

44)

-3.5

3%-2

3.03

%-2

6.93

%-4

0.66

%-1

.46%

0.17

%8.

13%

10.6

1%14

.43%

17.0

6%19

8815

4,31

7

77,9

71

14

0,04

4

(6

2,07

3)

-4

0.22

%-3

1.72

%-3

0.23

%-3

1.00

%-4

0.56

%-7

.72%

-4.8

5%3.

26%

5.92

%9.

73%

1989

972,

385

15

4,00

6

49

4,59

3

(3

40,5

87)

-3

5.03

%-3

5.74

%-3

4.46

%-3

3.71

%-3

3.65

%-3

7.28

%-2

1.50

%-1

8.10

%-1

1.61

%-9

.15%

1990

430,

919

60

,191

282,

633

(222

,442

)

-51.

62%

-40.

12%

-40.

13%

-39.

07%

-38.

06%

-37.

71%

-40.

26%

-27.

01%

-23.

56%

-17.

48%

1991

298,

797

25

,477

243,

634

(218

,157

)

-73.

01%

-60.

38%

-45.

90%

-45.

42%

-44.

40%

-43.

11%

-42.

49%

-44.

39%

-32.

18%

-28.

58%

1992

308,

422

40

,447

156,

975

(116

,528

)

-37.

78%

-55.

12%

-53.

67%

-44.

65%

-44.

34%

-43.

48%

-42.

42%

-41.

91%

-43.

63%

-32.

76%

1993

179,

511

25

,059

151,

133

(126

,074

)

-70.

23%

-49.

72%

-58.

57%

-56.

11%

-46.

75%

-46.

32%

-45.

49%

-44.

37%

-43.

80%

-45.

30%

1994

69,5

97

18,3

88

13

1,09

1

(1

12,7

03)

-1

61.9

4%-9

5.85

%-6

3.73

%-6

6.97

%-6

1.83

%-5

0.30

%-4

9.65

%-4

8.78

%-4

7.48

%-4

6.77

%19

9581

2,48

0

142,

498

636,

426

(493

,928

)

-60.

79%

-68.

77%

-69.

02%

-61.

99%

-63.

96%

-61.

43%

-53.

07%

-52.

46%

-51.

76%

-50.

63%

1996

310,

919

49

,989

346,

464

(296

,476

)

-95.

35%

-70.

36%

-75.

70%

-74.

99%

-68.

16%

-68.

89%

-65.

80%

-56.

96%

-56.

23%

-55.

54%

1997

101,

146

11

,252

167,

157

(155

,904

)

-154

.14%

-109

.78%

-77.

28%

-81.

83%

-80.

42%

-73.

04%

-73.

04%

-69.

36%

-59.

78%

-58.

95%

1998

1,71

8

25

0

3,

316

(3

,066

)

-1

78.4

2%-1

54.5

4%-1

10.0

7%-7

7.42

%-8

1.96

%-8

0.53

%-7

3.14

%-7

3.12

%-6

9.44

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9.84

%19

9924

4,87

0

-

-

-

0.

00%

-1.2

4%-4

5.72

%-6

9.15

%-6

4.53

%-6

8.93

%-6

9.07

%-6

4.31

%-6

5.43

%-6

3.27

%20

0066

3

-

-

-

0.

00%

0.00

%-1

.24%

-45.

63%

-69.

08%

-64.

50%

-68.

90%

-69.

04%

-64.

29%

-65.

41%

2001

4,12

3

46

,678

64,4

19

(1

7,74

1)

-4

30.2

8%-3

70.6

9%-7

.11%

-8.2

8%-5

0.13

%-7

1.32

%-6

5.53

%-6

9.87

%-6

9.91

%-6

5.03

%20

0210

7,54

3

352,

912

898,

464

(545

,552

)

-507

.29%

-504

.44%

-501

.47%

-157

.70%

-157

.80%

-156

.99%

-132

.14%

-95.

53%

-98.

32%

-95.

57%

2003

682,

368

22

8,71

6

75

0,26

4

(5

21,5

48)

-7

6.43

%-1

35.0

9%-1

36.6

2%-1

36.5

1%-1

04.3

6%-1

04.4

8%-1

08.8

7%-1

05.9

8%-8

9.78

%-9

1.93

%20

0448

,532

2,

173

6,

120

(3

,947

)

-8

.13%

-71.

90%

-127

.74%

-129

.22%

-129

.12%

-100

.06%

-100

.19%

-104

.77%

-102

.82%

-88.

07%

2005

416,

495

2,

763

70

8,35

2

(7

05,5

89)

-1

69.4

1%-1

52.5

8%-1

07.2

9%-1

41.5

7%-1

42.5

2%-1

42.4

4%-1

19.2

6%-1

19.3

3%-1

21.5

2%-1

17.2

8%20

0694

,689

-

291,

242

(291

,242

)

-307

.58%

-195

.00%

-178

.80%

-122

.56%

-153

.22%

-154

.06%

-153

.99%

-130

.41%

-130

.46%

-131

.87%

2007

261,

747

1,

641

1,

446,

549

(1

,444

,907

)

-5

52.0

2%-4

87.0

9%-3

15.9

1%-2

97.7

2%-1

97.3

1%-2

18.0

0%-2

18.5

4%-2

18.4

5%-1

89.7

1%-1

89.7

0%20

0831

0,87

6

23,5

61

1,

316,

268

(1

,292

,708

)

-4

15.8

3%-4

78.0

8%-4

53.8

9%-3

44.5

7%-3

30.1

5%-2

34.7

5%-2

49.9

9%-2

50.3

8%-2

50.2

9%-2

22.0

7%20

0955

4,65

4

17,3

99

1,

639,

950

(1

,622

,551

)

-2

92.5

3%-3

36.8

2%-3

86.7

9%-3

80.6

5%-3

26.9

5%-3

17.7

8%-2

48.2

7%-2

59.5

2%-2

59.8

0%-2

59.7

3%20

101,

189,

152

9,

913

4,

552,

142

(4

,542

,228

)

-3

81.9

7%-3

53.5

2%-3

62.9

5%-3

84.3

2%-3

81.3

0%-3

50.0

9%-3

44.3

2%-2

92.9

5%-2

99.2

4%-2

99.3

9%20

111,

139,

611

46

,403

7,85

1,65

8

(7,8

05,2

54)

-684

.91%

-530

.22%

-484

.50%

-477

.81%

-483

.43%

-478

.74%

-446

.27%

-440

.97%

-388

.03%

-390

.70%

2012

1,37

0,07

6

40,5

13

4,

164,

490

(4

,123

,978

)

-3

01.0

0%-4

75.3

3%-4

45.3

1%-4

25.3

9%-4

24.7

4%-4

31.6

4%-4

29.2

6%-4

08.9

8%-4

05.3

7%-3

68.3

8%20

133,

956,

879

15

1,51

6

7,

235,

094

(7

,083

,578

)

-1

79.0

2%-2

10.3

9%-2

94.0

2%-3

07.6

8%-3

06.6

6%-3

10.6

4%-3

17.8

3%-3

17.7

2%-3

11.0

8%-3

09.5

0%20

142,

700,

092

25

,811

7,92

7,76

6

(7,9

01,9

55)

-292

.66%

-214

.92%

-226

.94%

-274

.61%

-285

.13%

-285

.46%

-288

.57%

-293

.77%

-293

.87%

-290

.11%

2015

1,78

1,22

2

214,

589

3,36

4,33

0

(3,1

49,7

41)

-176

.83%

-184

.37%

-182

.79%

-193

.78%

-229

.02%

-239

.68%

-241

.34%

-244

.36%

-248

.79%

-249

.09%

2016

1,05

6,00

9

29

1,19

8,63

4

(1,1

98,6

05)

-113

.50%

-153

.26%

-221

.23%

-203

.64%

-215

.92%

-260

.44%

-271

.40%

-272

.25%

-275

.42%

-280

.48%

2017

3,87

5,96

6

23,9

73

5,

129,

071

(5

,105

,098

)

-1

31.7

1%-1

27.8

1%-1

40.8

2%-1

84.3

7%-1

82.7

9%-1

93.7

8%-2

29.0

2%-2

39.6

8%-2

41.3

4%-2

44.3

6%

Sout

hwes

tern

Pub

lic S

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ted

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l 2-

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3- y

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5- y

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sact

ion

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tory

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oval

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tSa

lvag

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lv. %

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lv. %

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6823

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9

133,

617

31,1

44

10

2,47

3

44.0

5%

19

6911

0,26

6

48,1

54

6,

629

41

,525

37.6

6%42

.00%

1970

129,

484

42

,925

14,3

85

28

,540

22.0

4%29

.22%

36.5

3%

1971

76,5

32

43,2

82

14

,411

28,8

71

37

.72%

27.8

7%31

.28%

36.6

9%

19

7285

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35

,715

8,10

2

27,6

13

32

.31%

34.8

7%29

.17%

31.5

0%36

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1973

38,5

50

17,0

27

7,

698

9,

329

24

.20%

29.7

9%32

.82%

28.5

9%30

.86%

35.4

2%

1974

26,9

21

9,01

6

5,22

5

3,79

1

14.0

8%20

.04%

26.9

9%30

.60%

27.4

9%29

.89%

34.6

0%

19

7515

2,62

9

87,4

81

25

,040

62,4

41

40

.91%

36.8

9%34

.65%

33.9

9%34

.74%

31.5

1%32

.61%

35.7

3%

1976

98,4

24

3,96

0

2,07

9

1,88

1

1.91

%25

.62%

24.5

0%24

.47%

26.1

3%27

.99%

26.7

2%28

.40%

32.2

3%

1977

91,0

77

86,9

61

29

,259

57,7

02

63

.36%

31.4

4%35

.67%

34.0

9%33

.16%

33.0

1%33

.64%

31.4

9%32

.33%

34.9

5%19

7855

,439

20

,584

7,56

9

13,0

15

23

.48%

48.2

7%29

.64%

33.9

7%32

.71%

32.0

0%32

.05%

32.7

4%30

.90%

31.7

7%19

7962

,731

55

,510

17,0

13

38

,497

61.3

7%43

.59%

52.1

9%36

.11%

37.7

0%36

.40%

35.5

0%35

.05%

35.3

5%33

.24%

1980

115,

203

41

,046

12,0

89

28

,957

25.1

4%37

.91%

34.4

8%42

.59%

33.1

2%35

.19%

34.2

4%33

.64%

33.4

8%33

.89%

1981

254,

446

16

4,73

8

55

,676

109,

062

42

.86%

37.3

4%40

.82%

38.8

5%42

.71%

36.7

8%37

.54%

36.8

0%36

.26%

35.9

2%19

8253

,134

17

,462

6,37

2

11,0

90

20

.87%

39.0

6%35

.27%

38.6

4%37

.09%

40.8

7%35

.62%

36.5

4%35

.87%

35.4

0%19

8327

8,43

2

158,

131

156,

460

1,67

1

0.60

%3.

85%

20.7

9%21

.50%

24.7

8%24

.69%

28.5

6%25

.96%

27.9

2%27

.61%

1984

57,1

02

178,

339

206,

053

(27,

714)

-48.

53%

-7.7

6%-3

.85%

14.6

3%16

.23%

19.6

8%19

.92%

24.0

1%21

.97%

24.3

4%19

8599

,118

56

,520

66,0

46

(9

,526

)

-9

.61%

-23.

84%

-8.1

8%-5

.02%

11.4

0%13

.24%

16.5

2%16

.92%

20.8

8%19

.28%

1986

166,

651

12

9,99

5

13

9,70

5

(9

,710

)

-5

.83%

-7.2

4%-1

4.54

%-7

.53%

-5.2

2%8.

24%

10.1

4%13

.10%

13.6

0%17

.27%

1987

7,45

6

-

1,82

6

(1,8

26)

-24.

49%

-6.6

3%-7

.71%

-14.

77%

-7.7

4%-5

.44%

7.97

%9.

89%

12.8

4%13

.35%

1988

35,2

77

15,8

19

21

,645

(5,8

26)

-16.

52%

-17.

91%

-8.2

9%-8

.72%

-14.

93%

-8.2

2%-6

.00%

7.06

%9.

02%

11.9

2%19

891,

276,

523

47

9,26

6

29

4,60

1

18

4,66

5

14.4

7%13

.63%

13.4

2%11

.26%

9.95

%7.

92%

6.86

%7.

24%

11.3

0%11

.98%

1990

182,

779

22

3,68

4

91

,490

132,

194

72

.32%

21.7

1%20

.81%

20.5

9%17

.95%

16.4

0%14

.37%

12.5

5%12

.75%

15.9

3%19

9158

,172

13

,303

96,1

22

(8

2,81

9)

-1

42.3

7%20

.49%

15.4

2%14

.70%

14.5

1%12

.55%

11.3

4%9.

53%

8.38

%8.

68%

1992

116,

180

17

,784

60,3

89

(4

2,60

5)

-3

6.67

%-7

1.94

%1.

90%

11.7

2%11

.12%

10.9

6%9.

44%

8.47

%6.

84%

6.08

%19

9313

3,61

0

14,4

68

62

,296

(47,

828)

-35.

80%

-36.

20%

-56.

26%

-8.3

7%8.

13%

7.64

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51%

6.39

%5.

62%

4.17

%19

9440

,365

6,

965

24

,528

(17,

563)

-43.

51%

-37.

59%

-37.

22%

-54.

78%

-11.

04%

6.97

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52%

6.40

%5.

39%

4.69

%19

9522

8,42

6

85,4

03

21

5,75

0

(1

30,3

47)

-5

7.06

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5.03

%-4

8.64

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5.96

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5.68

%-2

4.88

%-0

.21%

-0.4

9%-0

.58%

-0.9

6%19

9610

7,18

5

31,8

06

15

5,22

8

(1

23,4

22)

-1

15.1

5%-7

5.61

%-7

2.17

%-6

2.63

%-5

7.81

%-6

5.00

%-3

6.04

%-5

.96%

-6.1

3%-6

.19%

1997

50,0

12

2,49

1

29,9

59

(2

7,46

7)

-5

4.92

%-9

5.99

%-7

2.93

%-7

0.14

%-6

1.94

%-5

7.60

%-6

4.32

%-3

7.07

%-7

.08%

-7.2

3%19

9820

,801

-

-

-

0.00

%-3

8.79

%-8

4.77

%-6

9.20

%-6

6.88

%-5

9.72

%-5

5.88

%-6

2.54

%-3

6.25

%-7

.01%

1999

51,0

14

-

-

-

0.

00%

0.00

%-2

2.55

%-6

5.89

%-6

1.48

%-6

0.02

%-5

4.90

%-5

2.06

%-5

8.58

%-3

4.38

%20

004,

808

-

-

-

0.

00%

0.00

%0.

00%

-21.

69%

-64.

53%

-60.

84%

-59.

45%

-54.

48%

-51.

73%

-58.

24%

2001

11,2

95

-

-

-

0.

00%

0.00

%0.

00%

0.00

%-1

9.91

%-6

1.56

%-5

9.39

%-5

8.14

%-5

3.53

%-5

0.97

%20

0293

5,76

5

185,

103

642,

281

(457

,178

)

-48.

86%

-48.

27%

-48.

03%

-45.

59%

-44.

66%

-45.

14%

-51.

49%

-52.

40%

-52.

15%

-50.

77%

2003

1,38

2,63

4

330,

971

571,

644

(240

,673

)

-17.

41%

-30.

10%

-29.

95%

-29.

89%

-29.

25%

-29.

00%

-29.

53%

-33.

11%

-35.

07%

-35.

19%

2004

162,

255

-

-

-

0.00

%-1

5.58

%-2

8.13

%-2

8.00

%-2

7.95

%-2

7.39

%-2

7.17

%-2

7.70

%-3

1.14

%-3

3.14

%20

051,

754,

197

8,

534

37

,905

(29,

370)

-1.6

7%-1

.53%

-8.1

9%-1

7.17

%-1

7.13

%-1

7.11

%-1

6.90

%-1

6.82

%-1

7.26

%-1

9.60

%20

0697

,983

30

5,25

3

6,

368

29

8,88

5

305.

04%

14.5

5%13

.38%

0.85

%-9

.89%

-9.8

6%-9

.85%

-9.7

4%-9

.69%

-10.

20%

2007

94,3

15

-

30

7,59

0

(3

07,5

90)

-3

26.1

3%-4

.53%

-1.9

6%-1

.81%

-7.9

8%-1

6.62

%-1

6.58

%-1

6.56

%-1

6.37

%-1

6.30

%20

0815

0,26

1

40,9

19

27

2,38

6

(2

31,4

67)

-1

54.0

4%-2

20.4

0%-7

0.11

%-1

2.86

%-1

1.93

%-1

4.01

%-2

1.13

%-2

1.08

%-2

1.06

%-2

0.83

%20

0954

6,43

5

3,22

0

296,

531

(293

,311

)

-53.

68%

-75.

32%

-105

.23%

-60.

01%

-21.

29%

-20.

06%

-19.

19%

-24.

60%

-24.

55%

-24.

53%

2010

824,

294

36

,174

259,

987

(223

,813

)

-27.

15%

-37.

73%

-49.

22%

-65.

39%

-44.

20%

-22.

69%

-21.

67%

-20.

50%

-24.

96%

-24.

91%

2011

1,63

3,24

3

194,

465

1,12

4,40

0

(929

,935

)

-56.

94%

-46.

95%

-48.

17%

-53.

22%

-61.

14%

-50.

42%

-33.

65%

-32.

62%

-29.

45%

-31.

85%

2012

560,

652

28

,813

R82

6,70

7

(7

97,8

94)

-1

42.3

2%-7

8.76

%-6

4.66

%-6

2.98

%-6

6.66

%-7

3.09

%-6

3.60

%-4

4.41

%-4

3.18

%-3

8.23

%20

13

3,8

00,3

07

129,

449

2,4

78,2

65

(2,3

48,8

15)

-61.

81%

-72.

16%

-68.

01%

-63.

07%

-62.

37%

-64.

21%

-67.

45%

-62.

72%

-51.

40%

-50.

53%

2014

1,33

6,26

7

7,39

3

2,84

4,42

4

(2,8

37,0

31)

-212

.31%

-100

.96%

-105

.03%

-94.

31%

-87.

53%

-85.

40%

-86.

57%

-89.

09%

-84.

82%

-71.

31%

2015

1,60

5,43

8

29,0

07

24

4,72

7

(2

15,7

19)

-1

3.44

%-1

03.7

7%-8

0.12

%-8

4.89

%-7

9.78

%-7

5.34

%-7

4.19

%-7

5.34

%-7

7.58

%-7

4.06

%20

1676

,040

-

198,

565

(198

,565

)

-261

.13%

-24.

64%

-107

.74%

-82.

14%

-86.

71%

-81.

31%

-76.

77%

-75.

56%

-76.

68%

-78.

89%

2017

1,46

3,14

0

15,2

09

5,

771,

175

(5

,755

,966

)

-3

93.4

0%-3

86.8

6%-1

96.2

2%-2

01.0

2%-1

37.1

3%-1

37.4

6%-1

24.9

1%-1

17.7

7%-1

14.8

2%-1

15.3

1%

Sout

hwes

tern

Pub

lic S

ervi

ceR

etire

men

t and

Sal

vage

Ana

lysi

sA

ccou

nt 3

56 A

djus

ted

Dat

a19

68-2

017


Tran

sact

iona

l 2-

yr

3- y

r4-

yr

5- y

r6-

yr

7- y

r8-

yr

9- y

r10

- yr

Tran

sact

ion

His

tory

Rem

oval

Net

Net

N

et

Net

N

et

Net

N

et

Net

N

et

Net

N

et

Year

Ret

irem

ents

Salv

age

Cos

tSa

lvag

eSa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %19

77-

-

-

-

NA

1978

-

-

-

-

N

AN

A

19

79-

-

-

-

NA

NA

NA

19

80-

-

-

-

NA

NA

NA

NA

1981

-

-

-

-

N

AN

AN

AN

AN

A

19

82-

-

-

-

NA

NA

NA

NA

NA

NA

19

83-

-

-

-

NA

NA

NA

NA

NA

NA

NA

1984

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

A

1985

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

A

1986

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A19

87-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

1988

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A19

89-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

1990

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A19

91-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

1992

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A19

93-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

1994

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A19

95-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

1996

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A19

97-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

1998

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A19

99-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2000

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

01-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2002

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

03-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2004

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

05-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2006

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

07-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2008

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

09-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2010

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

11-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2012

8

-

582

(582

)

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

2013

-

-

-

-

N

A-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

2014

-

-

-

-

N

AN

A-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%20

15-

-

-

-

NA

NA

NA

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%20

16-

-

-

-

NA

NA

NA

NA

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

2017

-

-

-

-

N

AN

AN

AN

AN

A-7

534.

97%

-753

4.97

%-7

534.

97%

-753

4.97

%-7

534.

97%

Sout

hwes

tern

Pub

lic S

ervi

ceR

etire

men

t and

Sal

vage

Ana

lysi

sA

ccou

nt 3

57 A

djus

ted

Dat

a19

85-2

017


Tran

sact

iona

l 2-

yr

3- y

r4-

yr

5- y

r6-

yr

7- y

r8-

yr

9- y

r10

- yr

Tran

sact

ion

His

tory

Rem

oval

Net

Net

N

et

Net

N

et

Net

N

et

Net

N

et

Net

N

et

Year

Ret

irem

ents

Salv

age

Cos

tSa

lvag

eSa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %Sa

lv. %

Salv

. %19

85-

-

-

-

NA

1986

-

-

-

-

N

AN

A

19

87-

-

-

-

NA

NA

NA

19

88-

-

-

-

NA

NA

NA

NA

1989

-

-

-

-

N

AN

AN

AN

AN

A

19

90-

-

-

-

NA

NA

NA

NA

NA

NA

19

91-

-

-

-

NA

NA

NA

NA

NA

NA

NA

1992

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

A

1993

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

A

1994

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A19

95-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

1996

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A19

97-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

1998

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A19

99-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2000

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

01-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2002

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

03-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2004

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

05-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2006

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

07-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2008

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

09-

-

-

-

NA

NA

NA

NA

NA

NA

NA

NA

NA

NA

2010

-

-

-

-

N

AN

AN

AN

AN

AN

AN

AN

AN

AN

A20

114

-

-

-

0.

00%

0.00

%0.

00%

0.00

%0.

00%

0.00

%0.

00%

0.00

%0.

00%

0.00

%20

1211

,475

-

2,84

0

(2,8

40)

-24.

75%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

2013

-

-

-

-

N

A-2

4.75

%-2

4.74

%-2

4.74

%-2

4.74

%-2

4.74

%-2

4.74

%-2

4.74

%-2

4.74

%-2

4.74

%20

14-

-

-

-

NA

NA

-24.

75%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

2015

-

-

-

-

N

AN

AN

A-2

4.75

%-2

4.74

%-2

4.74

%-2

4.74

%-2

4.74

%-2

4.74

%-2

4.74

%20

16-

-

-

-

NA

NA

NA

NA

-24.

75%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

-24.

74%

2017

-

-

-

-

N

AN

AN

AN

AN

A-2

4.75

%-2

4.74

%-2

4.74

%-2

4.74

%-2

4.74

%

Acc

ount

358

Una

djus

ted

Dat

a19

85-2

017

Sout

hwes

tern

Pub

lic S

ervi

ceR

etire

men

t and

Sal

vage

Ana

lysi

s


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