findings of fact, table of contents...oah 19-2500-33074 . mpuc e-002/gr-15-826 . state of minnesota...

OAH 19-2500-33074 MPUC E-002/GR-15-826

STATE OF MINNESOTA OFFICE OF ADMINISTRATIVE HEARINGS

FOR THE PUBLIC UTILITIES COMMISSION

In the Matter of the Application of Northern States Power Company, d/b/a Xcel Energy, for Authority to Increase Rates for Electric Service in the State of Minnesota

FINDINGS OF FACT, CONCLUSIONS OF LAW,

AND RECOMMENDATIONS

TABLE OF CONTENTS STATEMENT OF THE ISSUES ...................................................................................... 2 FINDINGS OF FACT ....................................................................................................... 4

I. Summary of the Application and Settlement .............................................. 4 II. The Parties ................................................................................................ 6 III. Procedural Background ............................................................................. 7 IV. Summary of Public Comments ................................................................ 10 V. Legal Standards ....................................................................................... 10 VI. The Settlement ........................................................................................ 12

A. Elements of the Settlement ........................................................... 13 1) Rates .................................................................................. 13 2) Sales True-Up .................................................................... 15 3) Authorized ROE ................................................................. 15 4) Capital Structure ................................................................. 16 5) Customer Protections ......................................................... 17 6) Provisional Recovery of Prairie Island Life-Cycle

Maintenance Costs and Use of Nuclear Expert .................. 17 7) Riders ................................................................................. 18 8) Interim Rate Refund ........................................................... 19 9) Deferral of 2016 Property Taxes ........................................ 19 10) Bill Pay Assistance for Customers with Medical Needs ...... 19 11) LED Street Lighting ............................................................ 20 12) Fuel Clause Adjustment ..................................................... 20

13) Other Provisions of the Settlement ..................................... 21 14) The Effect of the Settlement on Future Proceedings .......... 21 15) Comparison of Company-Proposed, DOC-Recommended,

and Settlement Revenue Requirements ............................. 22 B. Issues Resolved by the Settlement ............................................... 23

1) Overall Revenue Requirements ......................................... 26 2) Return on Equity ................................................................. 27 3) Overall Cost of Capital........................................................ 29 4) Indexed ROE Earnings Test and Sharing Mechanism ....... 31 5) Sales Forecast and True-up ............................................... 32 6) Overall Operations and Maintenance Expenses and

Use of Escalators ............................................................... 34 7) Energy Supply O&M ........................................................... 36 8) Nuclear Non-Outage O&M Expense .................................. 37 9) Prairie Island Life-Cycle Management Capital Costs ......... 38 10) Prairie Island Spent Fuel Storage Capital Costs ................ 40 11) Prairie Island Settlement Payment ..................................... 40 12) Prairie Island Reactor Coolant Pump Seals ....................... 41 13) Monticello Spent Fuel Storage Capital Costs ..................... 41 14) Monticello Cask # 16 .......................................................... 42 15) Accumulated Deferred Income Taxes (ADIT) ..................... 42 16) North Dakota Investment Tax Credit and Research and

Experimentation (R&E) Tax Credits ................................... 44 17) Minnesota R&E Tax Credits ............................................... 45 18) Protecting Americans from Tax Hikes (PATH) Act of 2015 46 19) Property Taxes and True-up ............................................... 46 20) Health and Welfare Benefits ............................................... 48 21) Annual Incentive Plan Expenses (AIP) ............................... 49 22) 401 Nicollet Mall Lease and Moving Expense .................... 49 23) Cost Allocations - Transco Costs ....................................... 50 24) Cost Allocations - Service Company Costs ........................ 50 25) Depreciation Adjusted for Approved Remaining Lives ....... 51 26) Changes to In-Service Dates – Transmission Projects ...... 51

[88507/1] ii

27) Changes to In-Service Dates – Prairie Island Fire Protection ........................................................................... 52

28) Changes to In-Service Dates - Mankato Energy Center II .. 52 29) Reclassification of Interruptible Sales to Firm ..................... 53 30) Non-Asset Based Trading .................................................. 53 31) Transmission Studies ......................................................... 54 32) Courtenay Wind Land Lease .............................................. 55 33) 2017 Capital Forecast ........................................................ 55 34) Construction Work in Progress (CWIP)/Allowance for

Funds Used During Construction (AFUDC) ........................ 56 35) Business Systems – Productivity through Technology (PTT)

Expenses ............................................................................ 58 36) Employee Expenses ........................................................... 60 37) Executive Compensation .................................................... 63 38) Revenues from Asset Based Sales .................................... 63 39) Other Revenues – Three-Year Average ............................. 64 40) Interest Rate on Interim Rate Refund ................................. 65 41) Depreciation Reserve Amortization .................................... 65 42) Wholesale Jurisdictional Allocation .................................... 67 43) Nuclear Fuel Outage Accounting ........................................ 68 44) Revenue Requirement for Fuel and Purchased Fuel ......... 70 45) MCC and EEI Dues (Lobbying) .......................................... 70 46) Rate Case Expense Amortization ....................................... 71 47) Annual Compliance Filings on Cost of Debt and

Capital Structure ................................................................. 72 48) Interest Synchronization and Cash Working Capital .......... 72 49) Length of MYRP ................................................................. 73 50) Performance Metrics .......................................................... 75 51) Riders During the MYRP .................................................... 76 52) Capital Project True-Up ...................................................... 77 53) Fuel Clause Adjustment ..................................................... 78 54) Decoupling During a MYRP ................................................ 79 55) Low-Income/Medical Needs Discount Program .................. 80 56) LED Street Lighting ............................................................ 81

[88507/1] iii

57) Billing Format Issues .......................................................... 83 58) Service Reliability (Non-Revenue Requirements) .............. 83 59) Key Performance Indicators and Incentives ....................... 84 60) Bill Documentation for Manual Bills .................................... 85

C. RETURN ON EQUITY .................................................................. 91 1) Introduction ......................................................................... 91 2) Legal Standards for Rate Case Equity Cost Analysis ......... 92 3) MARKET/RISK ANALYSES USED BY THE PARTIES ...... 93

a. Introduction .............................................................. 93 b. The Parties’ Proxy Companies ................................ 93 c. Cost of Equity Models Applied by the Parties .......... 98

i. Discounted Cash Flow Analysis ......................... 98 ii. Constant Growth DCF Analysis ......................... 99 iii. Multi-Growth or Two-Growth DCF Analysis ...... 99 iv. Capital Asset Pricing Model .............................. 99 v. Risk Premium Analysis .................................... 100

d. Xcel’s ROE Analysis .............................................. 100 e. The DOC-DER’s ROE Analysis ............................. 104 f. The OAG’s ROE Analysis ...................................... 109 g. XLI’s ROE Analysis ................................................ 114 h. Comments on ROE by the Commercial Group ...... 115 i. Comments on ROE by AARP ................................ 115 j. The OAG’s Consideration of Xcel’s and the

DOC-DER’s DCF Analyses ................................... 115 k. Flotation costs ....................................................... 116

4) ROE Conclusions and Recommendation ......................... 118 a. Application of the CAPM and Risk Premium

Analyses ................................................................ 118 b. Business Risk ........................................................ 119 c. Time Periods of Market Data Used by the Parties

in Analysis ............................................................ 120 d. Flotation Costs ....................................................... 122

5) Summary and Conclusion ................................................ 124

[88507/1] iv

D. Evaluation of the Settlement ....................................................... 124 E. Standard for Commission Review of the Settlement ................... 125 F. Reasons to Approve the Settlement ............................................ 126 G. Reasons to Reject the Settlement ............................................... 128

1) The Commission Staff’s Concerns ................................... 128 2) Criticisms of the Settlement by the OAG .......................... 130

a. Cost Detail and Support ......................................... 130 b. The Company’s Revenue Requirement ................. 131 c. The Settlement Calls for Additional Contested

Case Proceedings ................................................. 132 d. The Settlement’s ROE ........................................... 132

3) AARP’s Objections to the Settlement ............................... 135 a. The ROE in the Settlement .................................... 135 b. Profit-Sharing Mechanism ..................................... 135 c. The Four-Year Term of the Settlement .................. 136 d. Extending the Decoupling Pilot .............................. 136 e. The Settlement Does Not Resolve the Issue of the

Customer Charge .................................................. 136 f. The Commission’s Options for Settlement ............. 137

VII. Class Cost of Service Study or Studies (CCOSS) Issues ...................... 137 A. CCOSS Methodology .................................................................. 137 B. The Company’s Proposed CCOSS ............................................. 139

1) Generation Plant .............................................................. 140 2) Transmission Plant ........................................................... 142 3) Distribution Plant .............................................................. 143 4) Methods for Classifying and Allocating Distribution

System Costs ................................................................... 143 a. Minimum System ................................................... 144 b. Zero Intercept ........................................................ 146 c. Hybrid Minimum System/Zero Intercept Approach 149 d. Other Methods for Classifying and Allocating

Distribution Plant.................................................... 151 i. Basic Customer ................................................ 152 ii. Peak-and-Average ........................................... 155

[88507/1] v

iii. Customer-Related ........................................... 157 5) Comparison of Approaches to Modeling Distribution

Costs ................................................................................ 158 C. Classification of Fixed Production Plant into Capacity

vs. Energy ................................................................................... 164 D. D10S Capacity Allocator ............................................................. 164 E. D60Sub Capacity Allocator ......................................................... 168 F. Direct Assignment of Costs to Customers No Longer

Receiving Service ....................................................................... 170 G. Calculation of Loss Factors ......................................................... 171 H. Allocation of RDF Rider Costs .................................................... 173 I. Allocation of CIP Costs ............................................................... 174 J. Allocation of Solar Power Purchase Agreements (PPA) ............. 175 K. CCOSS Conclusion and Recommendation ................................. 176

VIII. Rate Design ........................................................................................... 180 A. Revenue Apportionment ............................................................. 180

1) The Company’s Position................................................... 180 2) The Department’s Position ............................................... 181 3) The Commercial Group’s Position .................................... 182 4) XLI’s and MCC’s Positions ............................................... 182 5) ECC’s Position ................................................................. 185 6) The OAG’s Position .......................................................... 185 7) Analysis ............................................................................ 188

B. Rate Design ................................................................................ 190 1) Rate Design Issues .......................................................... 191 2) The Company’s Proposed Residential and Small

Business Customer Charges ............................................ 192 3) The Department’s Position ............................................... 196 4) The OAG’s Position .......................................................... 198 5) The CEOs’ Position .......................................................... 202 6) ECC’s Position ................................................................. 204 7) The Position of Minneapolis ............................................. 205 8) SRA’s Position .................................................................. 205 9) AARP’s Position ............................................................... 205

[88507/1] vi

10) Analysis ............................................................................ 206 C. Energy Charge Credit (ECCredit) ................................................ 209 D. Interruptible Service and Discounts ............................................. 209 E. Coincident Peak Billing ............................................................... 212 F. C&I Demand Time-of-Use (TOU) Rate ....................................... 215 G. Residential TOU Rate Pilot ......................................................... 216 H. Renew-A-Source Program .......................................................... 217 I. BIS Rider ..................................................................................... 219

IX. Answers to Commission’s Questions ..................................................... 220 CONCLUSIONS OF LAW ........................................................................................... 223 RECOMMENDATION ................................................................................................. 223 NOTICE ....................................................................................................................... 224 ATTACHMENT A: SUMMARY OF PUBLIC COMMENT ............................................. 225

I. General Opposition to the Proposed Rate Increases ............................. 226 II. Recent Rate Increases .......................................................................... 229 III. Supporting Rate Increase ...................................................................... 230 IV. Critique of Xcel’s Support for Rate Increase .......................................... 230 V. Conservation .......................................................................................... 231 VI. Comments Related to Nuclear Power .................................................... 232 VII. Comments Critiquing Renewable Energy

Sources (Distributed Generation) .......................................................... 233 VIII. Conservation Efforts Resulting in Higher Rates ..................................... 233 IX. Critique of e21 Initiative ......................................................................... 233 X. Proposed 5 Year Multi Year Rate Plan and Performance Standards .... 234 XI. Red Wing Trash Incinerator ................................................................... 234 XII. High Wages for Staff .............................................................................. 235 XIII. Fuel Costs .............................................................................................. 236 XIV. Deregulation .......................................................................................... 236 XV. Requests for Changes to the Rate Case Procedure .............................. 236 XVI. Service Quality Issues ........................................................................... 237 XVII. Other Issues .......................................................................................... 238

[88507/1] vii

OAH 19-2500-33074 MPUC E-002/GR-15-826

STATE OF MINNESOTA OFFICE OF ADMINISTRATIVE HEARINGS

FOR THE PUBLIC UTILITIES COMMISSION

In the Matter of the Application of Northern States Power Company, d/b/a Xcel Energy, for Authority to Increase Rates for Electric Service in the State of Minnesota

FINDINGS OF FACT, CONCLUSIONS OF LAW,

AND RECOMMENDATIONS

The above-captioned matter is pending before Administrative Law Judge Jeffery Oxley pursuant to a Notice and Order for Hearing filed on December 22, 2015.

Public hearings were held in Saint Paul, Minneapolis, Mankato, Woodbury, Eden Prairie, Red Wing, and St. Cloud, Minnesota, between July 12 and July 27, 2016. Written public comments were received until August 10, 2016.

An evidentiary hearing was held on October 25-28, 2016, at the offices of the Public Utilities Commission in St. Paul, Minnesota.

Post-hearing initial briefs were filed by the parties on November 30, 2016. Reply briefs were filed on December 23, 2016. The record closed on December 23, 2016, with the filing of the last reply brief.

Appearances:

Eric F. Swanson, David M. Aafedt, and Joseph M. Windler, Winthrop and Weinstine, P.A.; Elizabeth M. Brama, Briggs and Morgan, P.A.; and Amanda Rome and Ryan J. Long, Assistant General Counsels with Xcel Energy Services, Inc., appeared on behalf of the Applicant Northern States Power Company (Company), doing business as Xcel Energy (Xcel, NSP, or the Applicant).

Alan R. Jenkins, Jenkins at Law, LLC, appeared on behalf of an ad hoc association of large commercial customers, including JC Penney Corporation, Inc.; Macy’s, Inc.; Sam’s West, Inc.; and Wal-Mart Stores, Inc. (Commercial Group).

James M. Strommen and Adam C. Wattenbarger, Kennedy & Graven, Chartered, appeared on behalf of the Suburban Rate Authority (SRA).

Corey Conover, Minneapolis Assistant City Attorney, appeared on behalf of the City of Minneapolis (Minneapolis).

Richard J. Savelkoul, Martin & Squires, P.A., appeared on behalf of the Minnesota Chamber of Commerce (MCC).

Hudson Kingston, attorney with the Minnesota Center for Environmental Advocacy (MCEA), and Samantha Williams, attorney with the Natural Resources Defense Council (NRDC), appeared on behalf of Fresh Energy, Sierra Club, Wind on the Wires (WOW), MCEA, and NRDC (Clean Energy Organizations or CEOs).

Andrew Moratzka, Sarah Johnson Phillips, and Emma J. Fazio, Stoel Rives, L.L.P., appeared on behalf of CHS, Inc.; Flint Hills Resources L.P.; Gerdau Ameristeel U.S. Inc.; USG Interiors, Inc.; and Unimin Corporation (XLI).

Peder A. Larson and Inga K. Schuchard, Larkin, Hoffman, Daly & Lindgren, Ltd., appeared on behalf of U.S. Energy Services, Inc., and an ad hoc group of industrial, commercial, and institutional customers (collectively ICI Group).

Pam Marshall, Executive Director, appeared on behalf of the Energy Cents Coalition (ECC).

John Coffman, Attorney at Law, appeared on behalf of AARP.

Ryan Barlow, Ian Dobson, Joseph Meyer, and Joseph Dammel, Assistant Attorneys General, appeared on behalf of the Office of the Attorney General – Antitrust and Utilities Division (OAG).

Julia E. Anderson, Linda S. Jensen, and Peter Madsen, Assistant Attorneys General, appeared on behalf of the Minnesota Department of Commerce, Division of Energy Resources (DOC-DER or Department).

Robert Harding, Jorge Alonso, Dorothy Morrissey, Clark Kaml, Genesh Krishnan, and Andrew P. Bahn, appeared as staff for the Public Utilities Commission (PUC or Commission).

STATEMENT OF THE ISSUES

1. On November 2, 2015, the Company filed a petition to increase its electric rates in Minnesota. The Company seeks authority to increase its rates for electric service through a multiyear rate plan (MYRP) under Minn. Stat. § 216B.16, subds. 1, 19 (2016). The Company proposed both a three-year and a five-year MYRP.

2. The Company’s three-year MYRP calculates its first year revenue requirement from a traditional test year (2016 Test Year) and proposes revenue requirements for plan years 2017 and 2018 based on the Company’s anticipated costs of service.1 The Company calculates its revenue requirement for the 2016 Test Year as $3,229,000,000 and projects 2016 revenues for its Minnesota jurisdiction will be $3,034,388,000, resulting in a revenue deficiency of $194,612,000. The Company requests authority to increase its rates to generate an additional $194.6 million in 2016, which is an increase 6.4 percent over its projected revenue for 2016. For 2017, the Company requests an incremental increase of

1 Exhibit (Ex.) 3 at 2 (Application filing letter). All exhibits in the record are set forth within the master exhibit list filed by the court reporter on Jan. 12, 2017. See eDocket No. 20171-128016-01.

[88507/1] 2

$52.1 million, or 1.7 percent. And for 2018, the Company requests an incremental increase of $50.4 million, or approximately 1.7 percent. 2

3. The Company’s five-year MYRP is proposed as an alternative to its three-year MYRP. Under the five-year plan, the Company would determine its cost of service based on the 2016 Test Year, set rates based on that cost of service, and increase rates by 1.8 percent in each of the four succeeding years.3

4. In the Notice and Order for Hearing filed by the Commission on December 22, 2015, the following issues were set forth:

(1) The reasonableness of the test-year revenue increase sought by the Company;

(2) The reasonableness of the rate design proposed by the Company;

(3) The reasonableness of the Company’s proposed capital structure, cost of capital, and return on equity;

(4) Whether any of the issues identified in past Commission orders, listed in the Filing Requirement Compliance Table in the Company’s November 2 filing, require further review or development;

(5) What action, if any, the Commission should take on the Company’s alternative, five-year, stand-alone rate plan, under which the Commission would set rates at the test-year cost of service for 2016 and authorize 1.8% rate increases for each of the four succeeding years;

(6) Whether all customer classes, including those previously exempted, should be included in the Company’s pilot revenue-decoupling program;

(7) The appropriate rate-recovery treatment of other states’ investment tax credits for facilities constructed outside Minnesota;

(8) Whether, in light of the following factors, the amounts authorized for cost recovery in the 2016 test year and the 2017 and 2018 plan years should be considered provisional or placeholder amounts until the Commission makes a determination on the prudence of the Life Cycle Management costs at the Prairie Island plant:

2 Ex. 31 at 3 (Chandarana Direct); Ex. 36 at 3 (Burdick Direct). 3 Ex. 31 at 69-71 (Chandarana Direct).

[88507/1] 3

a) Xcel’s pending submission of a Nuclear Scope Study in its January 29, 2016 supplemental comments in its resource plan, docket E-002/RP-15-21; and

b) The possibility that there will not be adequate time to fully investigate and determine the prudence of these costs in this rate case;

(9) Performance-based metrics and incentives to be implemented throughout the multiyear plan that begin shifting away from a regulatory system that rewards the sale of electricity and building large, capital-intensive power plants toward one that rewards Xcel for achieving a set of clearly defined performance outcomes, such as energy efficiency, reliability, community-owned distributed generation, affordability, emissions reductions, predictable rates, etc. Consideration should be made for such a new performance system to be either complementary to decoupling or a replacement.4

Based on the evidence in the record, the Administrative Law Judge makes the following:

FINDINGS OF FACT

I. Summary of the Application and Settlement

1. The Company’s petition to increase electric rates in Minnesota includes two proposals: a three-year and a five-year MYRP. The three-year MYRP consists of a traditional 2016 Test Year plus 2017 and 2018 plan years that reflect the Company’s capital forecast and escalated Operations and Maintenance (O&M) expenses.5 The Company proposes to increase rates by 6.4 percent or $194.6 million in 2016, an incremental 1.7 percent or $52.1 million in 2017, and another incremental 1.7 percent or $50.4 million in 2018.6

2. The Company’s alternative proposal to the three-year MYRP is a five-year MYRP. The five-year proposal commences with the 2016 increase of 5.4 percent increase in rates followed by four years of successive 1.8 percent increases.7

3. The impetus for the Company’s three-year and five-year MYRP proposals is its view that the traditional rate case approach of using a test year does not work well in times when investment spending is high but there is little load growth. Investment spending

4 NOTICE AND ORDER FOR HEARING at 3 (Dec. 22, 2015) (eDocket No. 201512-116721-01). 5 Ex. 3 at 2 (Application filing letter). 6 Id. 7 Ex. 31 at 74 (Chandarana Direct).

[88507/1] 4

increases the Company’s revenue requirement, and when sales are not growing there is pressure to increase rates, which leads to frequent rate case filings.8

4. In developing the MYRP proposals, the Company undertook a multi-step process of data collection and analysis. The Company developed estimates of its costs for the 2016 Test Year. The costs were in large part estimates as the Company commenced this rate case in 2015.9 To estimate its test year costs, the Company must forecast the amount of electricity that ratepayers will demand.

5. In its filings, the Company classifies various costs as either current expenses or capital investments. The Company recovers current expenses directly in the rates it charges for service. The costs of capital investments are recovered only over time through depreciation expenses. The Company’s test year capital investments are added to its rate base, which is the sum of the Company’s prior investments in plant, equipment, and other assets used in providing electric service less depreciation, upon which the Company is permitted to earn a return.10

6. The Company’s revenue requirement is the sum of its expenses (such as operating and maintenance costs, taxes, rents, overheads, and depreciation expense), plus its rate base multiplied by its authorized rate of return. Subtracting the Company’s forecasted revenue from its revenue requirement for the 2016 Test Year results in a revenue deficiency for 2016. The Company is proposing to cure the deficiency by seeking authorization to increase the rates charged to its various classes of customers: Residential, Commercial and Industrial Non-Demand, Commercial and Industrial Demand, and Street Lighting.11

7. As a primary guide to setting the rates to be charged, the Company undertakes a Class Cost of Service Study (CCOSS) to establish the costs of providing service to each class of customer. Because much of the equipment, material, and labor costs are incurred to provide service to several classes of customers rather than to one class only, assigning such costs to each customer class involves an exercise of judgment. In this proceeding, the appropriate method for allocating joint and common costs among customer classes is a subject of significant debate. Generally, the parties agree that allocating costs according to cost causation principles best serves the goals of fairness and economic efficiency, but they differ as to the most appropriate allocation methods.12

8 Ex. 36 at 5 (Burdick Direct). 9 Ex. 36 at 7-12 (Burdick Direct). 10 Ex. 63 at 27-61, Schedules 3-4 (Heuer Direct). 11 Id.; Ex. 83 (Huso Direct). 12 See, e.g., Commercial Group Initial Br. at 3 (Nov. 30, 2016) (eDocket No. 201611-126891-01); CEO Initial Br. at 11 (Nov. 30, 2016) (eDocket No. 201611-126930-02); DOC-DER Initial Br. at 51 (Nov. 30, 2016) (eDocket No. 201611-126909-01); ICI Group Initial Br. at 4-5 (Nov. 30, 2016) (eDocket No. 201611-126914-02);; MCC Initial Br. at 6, 18-19 (Nov. 30, 2016) (eDocket No. 201611-126948-01); OAG Initial Br. at 17, 48-49, 67-69 (Nov. 30, 2016) (eDocket No. 201611-126884-01); Xcel Initial Br. at 78-79 (Nov. 30, 2016) (eDocket No. 201611-126945-02); XLI Initial Br. at 1, 6-9, 12 (Nov. 30, 2016) (eDocket No. 201611-0126915-01).

[88507/1] 5

8. Subtracting the costs of serving each customer class from the forecasted sales to each class at current rates yields each class’s share of the Company’s overall revenue deficiency. Next, the Company proposes how much of each class’s revenue deficiency it intends to recover from that class, a process termed “revenue apportioning.” If one class does not cover its revenue deficiency, at least one other class must more than cover its own revenue deficiency. The final step is determining the rates to be charged to each class so as to generate the revenues apportioned to each class.13

9. The step of revenue apportionment means that the rates proposed do not necessarily result in the forecasted revenues for each class of customers exactly equaling the cost of serving that class. Other factors such as continuity with past rates, the extent to which rates are easy to understand and administer, the effect of rates on conservation, and affordability are also considered when designing appropriate rates.

10. In the course of this proceeding, the Company and many, but not all, of the parties to this proceeding reached agreement on revenue requirement issues, street lighting, and a low-income/medical needs customer assistance program. In effect, the settlement agreement proposed a four-year MYRP with cost allocation and rate design issues debated among all parties.

II. The Parties

11. Xcel is a public utility holding company with four utility subsidiaries that serve electric and natural gas customers in eight states. One of the subsidiaries is Northern States Power Company, a Minnesota corporation that serves Minnesota customers.

12. The Commercial Group is an association of large commercial operators of

retail facilities and distribution centers in Minnesota, many of which take service from Xcel.

13. The SRA is a joint powers association. Its members are suburban municipalities within the Twin Cities metropolitan area, and most are served by Xcel.

14. The City of Minneapolis has a large system of street and traffic lights, operates many large electricity-consuming municipal utilities, and has large residential and business populations.

15. The MCC represents over 2,400 businesses located throughout Minnesota. Many of its members are within Xcel’s service territory.

16. The CEOs are non-governmental advocacy organizations. They include the Sierra Club, the Natural Resources Defense Council, the Minnesota Center for Environmental Advocacy, Fresh Energy, and Wind on the Wires.

17. XLI is an ad hoc association consisting of several industrial companies that are customers of Xcel and use large amounts of electric power.

13 Ex. 84 at 1-8 (Huso Direct).

[88507/1] 6

18. The ICI Group consists of industrial, commercial, and institutional organizations that receive service from Xcel and utilize U.S. Energy Services, Inc. to manage their energy services.

19. ECC represents low- and fixed-income utility consumers throughout Minnesota.

20. The EFCA is a national advocacy group that promotes the use of distributed energy resources. The EFCA intervened as a party in this proceeding but subsequently withdrew on October 13, 2016.

21. The OAG represents the interests of residential and small business ratepayers.

22. The Department represents the interests of all ratepayers.

III. Procedural Background

23. On October 2, 2015, the Company filed its Sales Forecast Data and Attachments, and one month later, on November 2, 2015, it filed a petition to increase its electric rates in Minnesota.14

24. The Commission issued a Notice and Order for Hearing on December 22, 2015.15 The Order required the Company to file supplemental direct testimony and schedules relating to projected and actual Life-Cycle Management costs for its Prairie Island nuclear plant on or before January 29, 2016.16

25. Also on December 22, 2015, the PUC issued three orders: one established an interim rate schedule for the Company with new rates commencing on January 1, 2016;17 one set a new base cost of energy;18 and one accepted Xcel’s application to increase rates as substantially complete, suspended the Company’s proposed rates, and extended the timeline for the Commission’s final determination of rates.19

26. A prehearing conference was held on January 4, 2016, at the Public Utilities Commission office in Saint Paul. On January 11, 2016, the First Prehearing Order was issued setting forth the procedures for discovery, hearing preparation, and the dates for the evidentiary hearing.20

14 Electric Rate Case Sales Forecast Data (Oct. 2, 2015) (eDocket No. 201510-114537-02); Notice of Change in Rates and Interim Rate Petition (Nov. 2, 2015). 15 NOTICE AND ORDER FOR HEARING (Dec. 22, 2015) (eDocket No. 201512-116721-01). 16 Id. at 3. 17 ORDER SETTING INTERIM RATES (Dec. 22, 2015) (eDocket No. 201512-116720-01). 18 ORDER SETTING NEW BASE COST OF ENERGY (Dec. 22, 2015) (eDocket No. 201512-116718-02). 19 ORDER ACCEPTING FILING, EXTENDING TIMELINE, AND SUSPENDING RATES (Dec. 22, 2015) (eDocket No. 201512-116719-01). 20 FIRST PREHEARING ORDER (Jan. 11, 2016) (eDocket No. 20161-117148-02).

[88507/1] 7

27. On December 24, 2015, Carol A. Overland and No CapX 202021 filed a petition to intervene.22 The Company filed an objection to this petition, but its objection was denied as untimely. On January 22, 2016, the petition to intervene was denied for failing to demonstrate that the parties met the requirements for intervention.23

28. On January 25, 2016, Carol A. Overland and No CapX 2020 filed their second petition to intervene. The Company filed its objection to the second petition on February 1, 2016.24 On February 9, 2016, Overland’s and No CapX 2020’s second petition was denied because it did not explain how their interest in the rate case proceeding differed from the general interests of ratepayers as represented by the Department and the interests of the residential and small business ratepayers represented by the OAG.25

29. On January 29, 2016, the Company filed supplemental direct testimony.

30. On February 18, 2016, the EFCA filed its petition to intervene.26 The Company filed its objection to EFCA’s petition on February 24, 2016. On February 26, 206, the EFCA’s petition was denied without prejudice.27

31. On March 11, 2016, the EFCA filed its second petition to intervene.28 On March 18, 2016, the Company filed its second objection to EFCA’s intervention. On March 23, 2016, the EFCA was granted permission to intervene, but its participation was limited to the issues of rate design, decoupling, and performance and incentive metrics.29

32. On April 15, 2016, the Institute for Local Self-Reliance and Sunshare, LLC, filed petitions to intervene.30 On May 3, 2016, the petitions were denied with prejudice because their interests were represented by other parties to the proceeding.31

33. On May 27, 2016, the Company filed a request for mediation. The Chief Administrative Law Judge assigned Administrative Law Judge Jeanne M. Cochran as mediator.

21 No CapX 2020 is an organization represented by Ms. Overland. 22 No CapX 2020 and Overland Pet. to Intervene (Dec. 24, 2015) (eDocket No. 201512-1167630-01). 23 ORDER DENYING INTERVENTION TO OVERLAND AND NO CAPX 2020 AND GRANTING INTERVENTION TO THE COMMERCIAL GROUP, THE SUBURBAN RATE AUTHORITY, AND THE CITY OF MINNEAPOLIS (Jan. 22, 2016) (eDocket No. 20161-117574-01). 24 No CapX2020 and Overland Second Pet. to Intervene (Jan. 25, 2016) (eDocket No. 20161-117600-01). 25 ORDER DENYING INTERVENTION TO OVERLAND AND NO CAPX 2020 (Feb. 9, 2016) (eDocket No. 20162-118122-01). 26 EFCA Pet. to Intervene (Feb. 18, 2016) (eDocket No. 20162-118404-01). 27 ORDER GRANTING INTERVENTION TO CLEAN ENERGY ORGANIZATIONS, MINNESOTA CHAMBER OF COMMERCE, AND THE XCEL LARGE INDUSTRIALS, AND DENYING INTERVENTION TO ENERGY FREEDOM COALITION OF AMERICA (Feb. 26, 2016) (eDocket No. 20162-118719-01). 28 EFCA Second Pet. to Intervene (Mar. 11, 2016) (eDocket No. 20163-119086-01). 29 AMENDED ORDER GRANTING PETITIONS TO INTERVENE OF ICI GROUP, ENERGY CENTS COALITION, AND THE ENERGY FREEDOM COALITION OF AMERICA (Mar. 23, 2016) (eDocket No. 20163-119390-01). 30 Institute for Local Self-Reliance Pet. to Intervene (Apr. 15, 2016) (eDocket No. 20164-120145-01); Sunshare, L.L.C. Pet. to Intervene (Apr. 15, 2016) (eDocket No. 20164-120144-01). 31 ORDER DENYING INTERVENTION TO SUNSHARE, L.L.C. AND THE INSTITUTE FOR LOCAL SELF RELIANCE (May 3, 2016) (eDocket No. 20165-120984-01).

[88507/1] 8

34. On June 14, 2016, the intervening parties filed direct testimony.

35. Eight public hearings were held at the following locations:

July 12, 2016, Merriam Park Public Library, St. Paul

July 12, 2016, Earl Brown Heritage Center, Minneapolis

July 13, 2016, Intergovernmental Center, Mankato

July 19, 2016, Wilder Center, Minneapolis

July 19, 2016, Woodbury Central Park, Woodbury.

July 20, 2016, Eden Prairie Public Library, Eden Prairie

July 26, 2016, Lake George municipal Complex, St. Cloud

July 27, 2016, Southeast Technical College, Red Wing

36. Administrative Law Judge Cochran conducted a mediation on July 18, 19, and 22, 2016.

37. On August 2, 2016, Administrative Law Judge Cochran filed a letter announcing that a number of parties to the proceeding had reached a settlement of revenue requirement issues, street lighting, and an assistance program for low-income/medical needs persons.32

38. On August 4, 2016, a prehearing conference call was held to discuss revising the schedule for the remainder of the proceeding to allow the parties to address the terms of the settlement in rebuttal testimony.

39. On August 5, 2016, the Second Prehearing Order was issued, which contained revised dates for filing rebuttal and surrebuttal testimony, holding the hearing, and filing briefs.33

40. On August 16, 2016, Xcel filed a Stipulation of Settlement (Settlement) between the Company, the DOC-DER, XLI, the MCC, Minneapolis, the ICI Group, and ECC. The OAG, AARP, and the CEOs participated in the mediation but did not enter into the Settlement.

41. On September 23, 2016, the parties filed rebuttal testimony.

42. On October 18, 2016, the parties filed surrebuttal testimony.

32 Letter from Judge Cochran to Judge Oxley (Aug. 2, 2016) (eDocket No. 20168-123873-01). 33 AMENDED SECOND PREHEARING ORDER (Aug. 5, 2016) (eDocket No. 20168-123969-01).

[88507/1] 9

43. The evidentiary hearing was held on October 25 through 27, 2016, at the Public Utilities Commission office in Saint Paul.

44. On November 18, 2016, the Company filed the Draft Issues List and Summary of Revenue Requirements.

45. On November 30, 2016, the parties filed initial briefs.

46. On December 15, 2016, the OAG, the DOC-DER, the CEOs, and the SRA filed Responses to the Draft Issues Matrix.

47. On December 23, 2016, the parties filed reply briefs.

48. The record closed on December 23, 2016.

IV. Summary of Public Comments

49. Over 400 written public comments were received by the August 10, 2016, deadline. In addition, over 40 individuals provided oral comments at the public hearings. A full summary of the public comments is included as Attachment A to this report.

V. Legal Standards

50. The Commission must set rates that are just and reasonable:

Rates shall not be unreasonably preferential, unreasonably prejudicial, or discriminatory, but shall be sufficient, equitable, and consistent in application to a class of consumers. To the maximum reasonable extent, the commission shall set rates to encourage energy conservation and renewable energy use . . . . Any doubt as to reasonableness should be resolved in favor of the consumer.34

51. Minnesota Statutes, section 216B.16, subdivision 6 (2016), provides guidance for determining just and reasonable rates and requires the Commission to consider:

the public need for adequate, efficient, and reasonable service and to the need of the public utility for revenue sufficient to enable it to meet the cost of furnishing the service, including adequate provision for depreciation of its utility property used and useful in rendering service to the public, and to earn a fair and reasonable return upon the investment in such property.

52. The legislature has assigned the Company the burden of proof to show that its requested rates are just and reasonable.35 In contested case proceedings where the applicable substantive law does not assign a different burden or standard, Minn. R. 1400.7300, subp. 5 (2015), provides that the party proposing that a certain action be

34 Minn. Stat. § 216B.03 (2016). 35 Minn. Stat. § 216B.16, subd. 4 (2016).

[88507/1] 10

taken bears the burden of proving the facts at issue by a preponderance of the evidence. The Company accordingly has the burden of proving by a preponderance of the evidence that the increases will result in just and reasonable rates. The Minnesota Supreme Court has upheld the use of the preponderance of the evidence standard in Minnesota utility rate proceedings.36 The Court has defined the “preponderance of the evidence” standard as:

whether the evidence, even if true, justifies the conclusion sought by the petitioning utility when considered together with the Commission’s statutory duty to enforce the state’s public policy that retail consumers of utility services shall be furnished such services at reasonable rates.37

53. In setting rates, the Commission acts in both a quasi-judicial and quasi-legislative capacity. As a quasi-judicial body, the Commission makes detailed findings of fact. As a quasi-legislative body, the Commission uses its expertise and judgment to resolve issues. The Commission evaluates whether the Company’s claimed costs are appropriate and “whether the ratepayers or the shareholders should sustain the burden generated by the claimed cost . . . .”38

54. The traditional approach for utilities proposing rate increases has been for the utility to select a test year and establish its rate base, revenues, expenses, and a reasonable rate of return to demonstrate that its revenue is insufficient to meet its test year expenses plus afford the Company’s shareholders a reasonable return on their investments. From the test year costs, including a reasonable rate of return on rate base, the utility develops its revenue requirement. The utility will conduct a study of the costs of serving each class of customers. The utility proposes how to allocate its revenue requirement among the customer classes, taking into account each class’s cost of service, but also considering other goals such as conservation. The last step is the utility’s proposal for how rates should be designed to collect the appropriate revenues from each class.39 In this process, the Company must comply with Minnesota law as well as prior orders of the Commission.40

55. The Company’s revenue requirement consists of all of the expenses it incurs to provide electrical service to its Minnesota customers. These expenses include the Company’s operating expenses, depreciation on its capital assets, taxes, and a margin sufficient to allow the Company a reasonable opportunity to earn its authorized rate of return. The Company chose the 2016 calendar year as its test year in this proceeding. Because the Company filed its application to increase rates in November 2015, many of the 2016 Test Year revenues and expenses are forecasts of what the Company anticipated would occur in 2016.

36 In re Northern States Power, 416 N.W. 2d 719 (Minn. 1987). 37 Id. at 722. 38 Id. 39 Company witness Anne Heuer provided an overview of the Company’s test year revenues and expenses. See Ex. 63 (Heuer Direct). 40 See Ex. 31, AHC-1, Schedule 2 (Chandarana Direct).

[88507/1] 11

56. Minnesota Statutes, section 216B.16, subdivision 19(a) (2016), allows a utility to propose a plan to establish rates that it may charge each year for a specified number of years, not to exceed five years. The utility “shall provide a general description of the utility’s major planned investments over the plan period.”41 The utility may propose to recover its forecasted rate base “based on a formula, a budget forecast, or a fixed escalation rate, individually or in combination.”42 Similarly, the utility may propose to recover its operations and maintenance expenses “based on an electricity-related price index or other formula.”43

57. The Commission “may approve a multiyear rate plan only if it finds that the plan establishes just and reasonable rates for the utility” and “the burden of proof to demonstrate that the multiyear rate plan is just and reasonable is on the public utility proposing the plan.” The Commission may also “upon its own motion or upon the petition of any party . . . examine the reasonableness of the utility’s rates under the plan, and adjust rates as necessary.”44

VI. The Settlement

58. On August 16, 2016, the Company filed a Stipulation of Settlement together with the DOC-DER, XLI, the MCC, the Commercial Group, the SRA, Minneapolis, the ICI Group, and ECC (the Settling Parties). The OAG, AARP, the CEOs, and the EFCA did not join in the settlement. The OAG and AARP opposed the settlement terms while neither the CEOs nor the EFCA opposed it. The Settlement resolved all revenue requirement issues between the Settling Parties as well as issues related to a medical needs customer bill payment assistance program, and street lighting. Minneapolis participated in the Settlement solely to support the resolution of street lighting issues.45

59. Minnesota law encourages parties to settle issues among themselves.46 “If the applicant and all intervening parties agree to a stipulated settlement of the case or parts of the case, the settlement must be submitted to the commission” which “shall accept or reject the settlement in its entirety . . . .”47 The Commission may accept a settlement if it finds “that to do so is in the public interest and is supported by substantial evidence.”48

60. Not all intervening parties agreed to the Settlement, raising a question as to the applicability of the subsequent provisions of Minn. Stat. § 216B.16, subd. 1a (b) (2016). Because all intervening parties did not agree to the Settlement, the Administrative Law Judge finds that the appropriate standard for reviewing the Settlement is whether the rates it proposes are just and reasonable as required by Minn. Stat. § 216.03 (2016). As no other substantive law assigns the burden of proof for a non-unanimous settlement, Minn.

41 Minn. Stat. § 216B.16, subd. 19(a) (2016). 42Id., subd. 19(a)(1). 43Id., subd. 19(a)(2). 44Id., subd. 19. 45 Ex. 28 (Stipulation of Settlement). 46 Minn. Stat. § 216B.16, subd. 1a (a) (2016). 47 Id., subd. 1a (b). 48 Id.

[88507/1] 12

R. 1400.7300, subp. 5 (2015), requires that the parties proposing the Settlement have the burden of demonstrating by a preponderance of the evidence that approval of the Settlement would provide for just and reasonable rates.

61. With the exception of street lighting and the medical needs customer assistance program, the Settlement does not resolve class cost of service or rate design issues. All of the Settling Parties reserved their right to continue asserting positions on the appropriate methods for determining the class cost of service and designing rates, with the exception of street lighting rates and customer assistance issues.49

Elements of the Settlement

Rates

62. The Settlement states that the rate increases agreed to by the Settling Parties “are largely informed by the Department’s direct testimony and the LED settlement.”50 The Settling Parties agree the revenue increases in the Settlement are just, reasonable, and in the public interest. They assert that the rate increases are moderate, amounting to 6.1 percent or $184.97 million through 2019 assuming the DOC-DER’s sales forecast is correct. This is less than what the Company requested in its proposed three-year MYRP and less than half of its five-year MYRP.51

63. The overall rate increases are slightly lower, in total, than those resulting from the Department’s recommendations in the covered years. By using the Department’s overall revenue recommendation for 2016-2019 as its foundation, the Settlement establishes a cumulative rate increase over four years of 6.10 percent, slightly less than the Department’s total recommended increase over four years of 6.23 percent.52

64. One of the reasons the DOC-DER supports the Settlement is because:

[F]rom the Department’s perspective as a practical matter, the rates set forth in [the Settlement] are informed by the Department’s recommendations, which include revenue requirement adjustments that reflect the Department’s direct testimony recommended ROE of 9.06 percent.53

65. The Settlement recognizes and implements the recommendations the Department’s witnesses made in their direct testimonies. The Settlement reflects the total revenue requirement adjustments that the DOC-DER witness, Dale Lusti, presented in the second errata included with his direct testimony.54 However, there is no agreement

49 Ex. 28 at 3 (Stipulation of Settlement). 50 The “LED settlement” refers to the settlement of Street Lighting issues. 51 Ex. 32 at 5 (Chandarana Rebuttal). 52 Ex. 801 at 3 (O’Connell Rebuttal) (quoting from the Department’s response to OAG Information Request 851). 53 Id. 54 Ex. 808, DVL-9, second errata (Lusti Direct).

[88507/1] 13

among the Settling Parties as to the specific costs comprising the Settlement’s agreed-upon revenue requirement.

66. For comparison purposes, Table 1 below compares the Company’s proposed three- and five-year MYRP rate increases with the rate increases in the Settlement.

Table 155

2016 2017 2018 2019 2020 % and $ rate increase 3-year MYRP

6.4% $194.612 M

1.7% $51.4 M

1.7% $51.4 M

Cumulative56 6.4% $194.612 M

8.1% $246.7 M

9.8% $298.1 M

% rate increase 5-year MYRP57

5.4% $163.7 M

1.8% $54.6 M

1.8% $54.6 M

1.8% $54.6 M

1.8% $54.6 M

Cumulative 5.4% $163.7 M

7.2% $218.3 M

9.0% $272.9 M

10.8% $327.5M

12.6% $382.1 M

% and $ rate increase Settlement58

2.47% $74.99 M

1.97% $59.86 M

0.0% $0.00 M

1.65% $50.12 M

Cumulative 2.47% $74.99 M

4.44% $134.85 M

4.44% $134.85 M

6.1% $184.97 M

67. The Company contends that the Settlement is reasonable although the revenues the Company will receive under it are “significantly lower than both the Company’s 3-year MYRP request and 5-year MYRP settlement offer. It also results in a cumulative rate increase over the four-year period that is slightly lower than the Department’s recommendation in Direct Testimony.”59

55 Notice of Change in Rates and Interim Rate Pet. at 2 (Nov. 2, 2015) (eDocket No. 201511-115329-01). 56 Ex. 31 at 3 (Chandarana Direct) (revenue deficiency calculated assuming 10.00 return on equity). 57 Id. at 74. 58 Ex. 28, Table A (Stipulation of Settlement). 59 Ex. 37 at 2-3 (Burdick Rebuttal).

[88507/1] 14

68. The OAG’s witness, Shoa Lee, calculated that, under the Settlement, ratepayers will pay approximately $138 million more than they would have paid if the Department’s revenue requirement recommendations had been implemented.60

69. $37 million of the $138 million figure follows from the assumption that the Company’s, rather than the Department’s, sales forecast is accurate. Because the Settlement requires the sales forecast be trued-up to actual sales, it should not be included in comparing the revenue requirement derived from the Department’s direct testimony and the revenue requirement in the Settlement.61 In addition, due to the capital true-up provision in the Settlement, if the Company does not make the capital investments it has proposed, it must refund the excess. As a result, the actual increase in revenues under the Settlement could be reduced.62

70. While the Company’s revenues during the term of the Settlement will be approximately $100 million higher than if the Department’s proposed revenue requirement were adopted, the cumulative rate increase of 6.12 percent is lower than the Department’s proposed 6.23 percent increase. Rates will remain at this lower level until the Company files its next rate case.63

71. The average annual rate increase under the Settlement is less than half of the increase which the Company’s 2019 forecast indicated would be necessary.64

Sales True-Up

72. The Settlement includes a “Sales True-Up” where actual 2016 revenues are compared to the Department’s revenue forecast and the difference (positive or negative) is added to the $75 million rate increase proposed in the Settlement to set the base for rate increases.65 It also includes a schedule and outline of the mechanics for implementing the rate changes and interim rate refund.66

Authorized ROE

73. The Settlement proposes the Commission “allow Xcel Energy to represent its authorized ROE as nine and two-tenths percent (9.20%) for settlement purposes in this rate case proceeding.”67 While the ROE would play no role in setting rates, the Company could represent to financial markets and its shareholders that its authorized ROE is 9.2% and could use this figure in calculating amounts due the Company in future dockets and under various

60 Ex. 707 at 10 (Lee Rebuttal). 61 Ex. 802 at 6-7 (O’Connell Surrebuttal). 62 Evidentiary Hearing Transcript Volume (Tr. Vol.) 2 at 167 (O’Connell). 63 Ex. 801, KOC-R-1 (O’Connell Rebuttal). 64 Ex. 37 at 3 (Burdick Rebuttal). 65 Id. at 4. 66 Id. at 6. 67 Id. at 4.

[88507/1] 15

riders. However, the other Settling Parties are at liberty to “advocate for other positions and the Commission may review the ROE in each docket for setting rider rates.”68

74. Although the authorized ROE does not play a role in setting rates, the Commission is unlikely to authorize any ROE it does not find reasonable regardless of its role in setting rates.

75. This issue is one of the 60 issues the Settlement “resolves” and is discussed in detail below.

Capital Structure

76. NSP’s cost of capital is the sum of costs for long-term debt, short-term debt, and equity, weighted by the amount of each type of financing employed.69 NSP is a separate legal entity and has its own capital structure and issues its own debt.70

77. A 9.20 percent ROE applied to the capital structure initially proposed by Xcel. In that structure, common equity remains constant through the MYRP at 52.50 percent, long-term debt falls from 46.24 percent to 45.81 percent and short-term debt increases from 1.26 percent to 1.69 percent while the rate on long-term debt falls from 4.81 percent to 4.75 percent while the rate on short-term debt increases from 1.84 percent to 4.31 percent. The cost of capital holds fairly constant ranging from 7.07 percent to 7.09 percent.71

78. The Department was the only party other than the Company to address capital structure. The DOC-DER’s witness, Craig Addonizio, testified there was “no simple way to analytically determine a company’s optimal capital structure.”72 Instead he compared NSP’s proposed capital structure to risk-comparable peers (the DOC Proxy Group).73 He found that although NSP’s proposed equity ratio was higher than the average of the DOC Proxy Group, it was within the range he observed. Similarly, the Company’s long- and short-term debt ratios were lower than the DOC Proxy Group averages, but within the ranges he observed.74

79. Mr. Addonizio also reviewed the Company’s proposed common equity ratio and its short- and long-term debt ratios from 2016 through 2018, and found they were quite stable. From these observations, Mr. Addonizio concluded that the ratios of common equity, long- and short-term debt were reasonable.75

80. Mr. Addonizio was concerned that the Company relied upon IHS Global Insight’s forecasts of short- and long-term interest rates which had consistently been too high in recent years. Accordingly, the Company’s estimates of its costs for long-term debt

68 Id. at 5. 69 Ex. 803 at 34 (Addonizio Direct). 70 Ex. 41 at 11 (Van Abel Direct). 71 Ex. 28 at 6-7, Attachment 5 (Stipulation of Settlement). 72 Ex. 803 at 35 (Addonizio Direct). 73 Id. 74 Id. at 36. 75 Id. at 37.

[88507/1] 16

issuances in 2016 and 2018 were too high.76 He recommended that if a MYRP is approved, the Commission require the Company to make compliance filings with an updated estimate of its costs of short- and long-term debt for the upcoming year.77

81. NSP’s proposed equity ratio is higher than the average equity ratio of the DOC Proxy Group members but within the range of the group. Its long- and short-term debt ratios are lower than average but within the range of the DOC Proxy Group. NSP’s proposed capital structures for 2017 and 2018 vary little from the structure in 2016. Accordingly, the DOC-DER concludes that NSP’s capital structure is reasonable.78

82. The OAG disagrees with the Settlement’s authorized ROE. The debate over the appropriate ROE is discussed in detail in Part III.

83. The Administrative Law Judge finds the Company’s capital structure as proposed in the Settlement is reasonable.

Customer Protections

84. The Settlement obliges the Company to continue to file annual reports “with its actual recorded jurisdictional financials and earnings to provide transparency in its financial performance.” Minnesota Statute, section 216B.16, subdivision 19(e) (2016), provides that “[a]ny time prior to the conclusion of a multiyear rate plan, the commission, upon its own motion or upon petition of any party, has the discretion to examine the reasonableness of the utility’s rates under the plan, and adjust rates as necessary.”

85. The Commission’s authority to examine the Company’s rates during an MYRP is an important assurance that rates will be just and reasonable.

86. The Settlement’s increase of 6.1 percent over the MYRP is less than the projected rates of increase for the Consumer Price Index, the Producer Price Index, and the Corporate Escalation Index as forecasted by Global Insight.79 It appears unlikely that the Settlement’s proposed rate increases will cause electric rates to substantially exceed the changes in these broad measures of price levels.

Provisional Recovery of Prairie Island Life-Cycle Maintenance Costs and Use of Nuclear Expert

87. The Commission directed the Company to present its estimates for costs of performing Life-Cycle Maintenance (LCM) at Prairie Island (PI).80 These costs were to be provisionally recovered in this proceeding, subject to the Commission’s prudence review.

88. Because the DOC-DER included revenue requirement adjustments relating to the PI LCM costs and other nuclear capital projects, the Settling Parties propose that there

76 Id. at 39-40. 77 Id. at 42. 78 Id. at 36-37. 79 Ex. 36, Schedule 12 (Burdick Direct); Ex. 38 at 6 (Burdick Surrebuttal). 80 NOTICE AND ORDER FOR HEARING at 8 (Dec. 22, 2015) (eDocket No. 201512-116721-01).

[88507/1] 17

is no need to make any recovery provisional, or for the DOC-DER to retain a nuclear expert, in this proceeding.

89. The Company’s nuclear operations and costs can be examined in the Integrated Resource Plan (IRP) proceeding to consider capital and O&M expenses for years following the MYRP. The Settlement further provides that the DOC may retain a nuclear expert for the IRP proceeding at the Company’s expense.81

90. As a practical matter, review of PI LCM costs requires specialized expertise not available in this proceeding. The Settlement provides for rates that are “informed by the Department’s recommendations, which include revenue requirement adjustments for the Company’s Prairie Island LCM, as well as other nuclear capital projects.”82 The Administrative Law Judge does not find the record sufficient to support any other recommendation concerning PI LCM costs other than what the Settlement provides.

Riders

91. For the term of the Settlement, the Company may use only the riders identified in the MYRP Revenue Rider Schedule. Any rider recovery during the term will be in addition to the rate increases under the Settlement.83

92. The Company may retain the three CapX2020 transmission projects in the Transmission Cost Recovery (TCR) Rider during the term.84

93. The Department noted that the CapX2020 costs are likely to decrease over the MYRP. If those costs were included in 2016 Test Year costs, the 2016 Test Year amount would be carried forward through 2019. By retaining these costs in the TCR rider, ratepayers benefit from the decreasing costs.85 It is also significant that the Company was, prior to the Settlement, considering pursuing at least one more rider, rendering the bar against new riders meaningful.86

94. In direct testimony, XLI advised the Commission that if a MYRP is approved, the Commission should disallow the majority of existing riders because the Company has ample opportunity to seek to recover its costs in this proceeding.87

95. The OAG countered that there may be little value to this provision in the Settlement because the existing 26 riders “seem to represent the primary areas where the

81 Ex. 28 at 7 (Stipulation of Settlement). 82 Id. 83 Id. 84 Id. 85 Tr. Vol. 2 at 179-80 (O’Connell). 86 Ex. 802 at 7 (O’Connell Surrebuttal). 87 Ex. 250 at 39-40 (Pollock Direct).

[88507/1] 18

utility will be making investments.”88 In addition, the rate stability that is supposed to result from an MYRP is undermined by increasing rates through riders during the plan.89

96. The Administrative Law Judge agrees that, in light of the many existing riders and the purpose of the MYRP, allowing new riders during the MYRP undermines rate stability, which is an objective of an MYRP. There is value to ratepayers in the assurance that no new riders will be developed during the Settlement’s term. In the event the Commission rejects the Settlement but approves a MYRP, it should consider such a provision.

Interim Rate Refund

97. The Settlement provides that the Company will apply its long-term cost of debt of 4.81 percent to any interim rate refund ordered by the Commission.90

98. By the time the final rates established under the Settlement go into effect, assuming they do, the Company will have collected ratepayer funds in excess of amounts owed for many months. It is appropriate to use a long-term rate rather than a short-term rate to represent the time value of money during this period. A similar provision should be considered in any resolution of this proceeding.

Deferral of 2016 Property Taxes

99. Under the Settlement, the Company defers as a regulatory asset the difference between the amount of property tax expense approved in the last rate case and its actual 2016 property tax expense. The deferral will not exceed $28 million or the amount deferred using the Company’s 2016 Test Year property tax expense. The regulatory asset will be amortized evenly over 2018 and 2019. The property tax deferral will not impact rate increases as provided in this Settlement.91


Bill Pay Assistance for Customers with Medical Needs

101. The Settling Parties agree with ECC’s proposal to use PowerON as a model in developing a customer bill payment assistance program for medical needs customers. The program will:

(1) provide an affordability credit to limit the percentage of household income spent on electricity;

(2) provide an arrearage forgiveness component;

88 OAG Initial Brief (Br.) at 130 (Nov. 30, 2016) (eDocket No. 201611-126884-01). 89 Id. at 139. 90 Ex. 28 at 8 (Stipulation of Settlement). 91 Id.

[88507/1] 19

(3) set income eligibility at 50 percent of the state median income, (increasing to 60 percent if sufficient funds are available);

(4) provide assistance on a first come/first served basis until program resources are exhausted;

(5) cap administrative costs at 5 percent of the annual budget;

(6) follow the reporting and program fund tracking procedures of POWER ON; and

(7) recover program costs on the same basis as POWER ON.

102. No party opposed this provision of the Settlement. Even if the Commission rejects the Settlement, it should consider requiring the Company to develop this program.

LED Street Lighting

103. The Settlement removes from this rate case all revenue requirements arising from capital additions for Light Emitting Diode (LED) street lights. The lower revenue requirement will be used in setting final street lighting rates. Installed LED street lights will be billed as the Commission ordered in Docket No. M-15-920 and consistent with any final order in this proceeding. The Company will create a regulatory asset from the revenue requirements directly related to actual LED streetlight capital additions during the MYRP. The Settlement requires the Commission to permit the LED deferral during the MYRP Term, without an addition of any time value, such as a carrying cost.

104. LED street lighting revenues will be credited against the LED deferral. Minneapolis and the SRA will not contest the Company’s recovery of the LED deferral in its next rate case, which will be recovered as part of the test year, but can challenge the Company’s claimed costs, alleged savings, as well as any other aspect of street lighting rates, including the street lighting cost of service and revenue apportionment.

105. No party opposed this provision of the Settlement. Even if the Commission rejects the Settlement, it should consider requiring the Company to develop this program.

Fuel Clause Adjustment

106. The Settling Parties agree that the Fuel Clause Adjustment mechanism will be addressed pursuant to the Commission’s previous orders in dockets E999/CI-03-802, E-999/AA-12-757, E-999/AA-13-599, and E-999/AA-14-579.


[88507/1] 20

Other Provisions of the Settlement

108. The Settling Parties further agree to keep confidential their settlement discussions during mediation. They also agree that if the Commission does not approve the Settlement, it shall not be part of the record of this proceeding.92

109. The Settling Parties agree that, unless expressly stated in the Settlement or in pre-filed testimony or other exhibits in the record, the Settlement is not binding on the parties as if the issues had been litigated.

The Effect of the Settlement on Future Proceedings

110. One factor to consider in evaluating the Settlement is the effect it will have on future rate cases. Without specific resolutions of specific key issues in this proceeding, the next rate case will lack information regarding how much of each type of cost is being recovered in existing rates. This may impact how interim rates and final rates will be established in the Company’s next rate case.93

111. Minnesota Statutes, section 216B.16, subdivision 3(b) (2016), provides that “unless exigent circumstances exist,” the:

interim rate schedule shall be calculated using the proposed test year cost of capital, rate base, and expenses, except that it shall include: (1) a rate of return on common equity for the utility equal to that authorized by the commission in the utility’s most recent rate proceeding; (2) rate base or expense items the same in nature and kind as those allowed by a currently effective order of the commission in the utility’s most recent rate proceeding; and (3) no change in the existing rate design.

The Settlement provides an authorized rate of return but it does not specify the rate base or expense items. The Department’s position is that the phrase “the same in nature and kind” permits the Company to propose interim rates as long as they bear a substantial relationship to the expenses and rate base from the utility’s most recent rate proceeding.94 While it cannot be presumed that interim rates in the next proceeding will be established without controversy, because revenues collected under interim rates are trued-up when final rates are determined, interim rates are of less concern. It is more important that the final rates reflect the Company’s actual costs and authorized return.

112. With regard to establishing final rates in a subsequent rate case proceeding, the Department explains that when a settlement has not resolved issues on an item-by-item basis, it looks back to the most recent case where an expense or other item was specifically resolved and makes an appropriate adjustment. For example, it is not uncommon for the

92 The Settlement was received into evidence at the hearing on October 25, 2016. See Tr. Vol. 1 at 28. 93 Ex. 801 at 8 (O’Connell Rebuttal). 94 Id. at 5-6.

[88507/1] 21

Department to make an adjustment for inflation occurring during the intervening years, in orderto establish a reasonable estimate for the new test year.95

113. While the Department provided its method for analyzing costs in future rate cases, it did not vouchsafe all of the costs at issue in this proceeding. Clearly, failing to specifically resolve cost elements will make future rate cases more difficult.

114. The longer the period since the last Commission-approved cost, the larger the adjustments that are likely necessary. The adjustments will not only reflect changes in the prices of various inputs, but perhaps also changes in the Company’s use of an input as its processes and technologies change.

115. A revenue requirement established by an aggregate level settlement in this proceeding might make a follow-on MYRP, for the next rate proceeding, more difficult to complete.

Comparison of Company-Proposed, DOC-Recommended, and Settlement Revenue Requirements

116. Table 2 compares the Company’s incremental revenue deficiencies from 2016 through 2020 (including its three-year and five-year rate increase proposals), with the incremental revenue deficiencies and rate increases the DOC calculated for 2016 through 2019 and the Settlement’s proposed rate increases.

Table 296

2016 2017 2018 2019 2020 Xcel Incremental Revenue Requirement Deficiency

$194,612 $52,054 $50,467 $82,489 $48,055

DOC Incremental Revenue Requirement Deficiency

$45,558 $99,406 $94,363 $189,049

Xcel Incremental Rate Increase 3-Year MYRP and Cumulative Rate Increase

6.41 percent 6.41 percent



Xcel Incremental Rate Increase 5-

5.4 percent

1.8 percent

1.8 percent

1.8 percent

1.8 percent

95 Id. at 9-12. 96 Ex. 28 at 5 (Stipulation of Settlement).

[88507/1] 22

2016 2017 2018 2019 2020 Year MYRP and Cumulative

5.4 percent 7.2 percent 9.0 percent 10.8 percent 12.6 percent

DOC Incremental Rate Increase and Cumulative



-0.2 percent 3.1 percent


Settlement Incremental Rate Increase and Cumulative





Issues Resolved by the Settlement

117. Attachment 4 to the Settlement is titled “Issues Resolved for Settlement Purposes.” It identifies 60 issues (Settlement Items) which the Settling Parties have resolved concerning the Company’s revenue requirements over a four-year MYRP.97 The DOC-DER analyzed the Company’s 2016 Test Year and projected revenue requirements through 2020. Its analysis led to the DOC-DER proposing over 35 expense adjustments. These adjustments significantly reduce the Company’s proposed revenue requirement.98

118. Most Items are not explicitly resolved in the Settlement. Although the Settlement proposes a revenue requirement, it does not establish the specific adjustments to the Company’s initially proposed costs that result in the Settlement’s revenue requirement.

119. For example, the Settlement does not explain how the issue of North Dakota Investment Tax Credits and Research and Experimentation Tax Credits is resolved. Thus, although the Commission directed this proceeding to recommend the “appropriate rate-recovery treatment of other states’ investment tax credits for facilities constructed outside Minnesota,” the Settlement does not include a specific recommendation on this issue.99

120. Thus, many issues in the Settlement are resolved only in the sense that the Settling Parties have agreed as to an overall revenue requirement.

121. The DOC-DER explains there is a trade-off between resolving issues in a contested case proceeding versus a settlement. A contested case hearing “may provide more record development of issues” but necessarily involves litigation expense and risk. This settlement will resolve fewer issues going forward because it includes a provision that the resolution cannot be used in other proceedings.100

97 Id., Attachment 4. 98 Ex. 809 at 8-9 (Campbell Direct). 99 See NOTICE AND ORDER FOR HEARING at 3 (Dec. 22, 2015) (eDocket No. 201512-116721-01). 100 Ex. 801 at 5 (O’Connell Rebuttal).

[88507/1] 23

122. To assist the Commission in evaluating the Settlement, this Report presents the positions the Settling Parties took on the settled issues and the adjustments they recommend to the Company’s proposals in their direct testimonies.

123. The DOC-DER was the only party in the proceeding to propose a full cost of service recommendation.

124. The DOC-DER explained that “agreed-upon rates compare favorably with the Department’s direct testimony recommendations. The Department’s recommendations in direct testimony considered each of the issues in light of the information provided as well as the public interest.”101 Thus, from the DOC-DER’s perspective, the 60 revenue requirement issues addressed by the Settlement were resolved consistently with its recommendations.

125. Due to the Settlement, the Settling Parties did not rebut each other’s direct testimony on the issues in the accord. In particular, the Commission does not have rebuttal testimony from the Company responding to the direct testimony of the other Settling Parties.

126. For example, while the DOC-DER recommends that state research and development tax credits should be apportioned to the respective jurisdictions based on an allocator that assigns 73.5 percent of the generation and transmission plant to Minnesota and 26.5 percent to North Dakota, the Settlement does not prevent the Company from challenging these assignments in other proceedings.102

127. While the Commission cannot predict how the issues resolved in the Settlement may have been further developed at a fully litigated hearing in the Settlement’s absence, understanding the Settling Parties’ initial positions provides some basis for evaluating the Settlement. Further, if the Commission chooses to reject the Settlement, the Commission may find the discussion of the “settled” issues useful in considering modifications to the Settlement’s terms.

128. Below, this Report separately considers each issue or item resolved in the Settlement. Because the Company’s revenue requirement is “informed by” the DOC-DER’s revenue requirement recommendations, the Department tacitly encourages the Commission to analyze the Settlement through the lens of its recommendations.

129. Yet, the Settlement does not actually adopt any of the adjustments proposed by any party. Instead, the Settlement only adopts the aggregate impact of proposed adjustments on the revenue requirement. If the Commission rejects the Settlement, the Company and other Settling Parties are at liberty to dispute each and every one of the 60 Settlement Items resolved.

130. The Settlement also is “expressly conditioned on its acceptance by the Commission in its entirety.”103 If the Commission modifies the Settlement in a way that has

101 Id. at 4. 102 Ex. 809 at 35 (Campbell Direct). 103 Ex. 28 at 8 (Stipulation of Settlement).

[88507/1] 24

a material adverse effect on a Settling Party, that Party has three days to notify the other Settling Parties and the Commission of its desire to withdraw from the Settlement. If that happens, the Settlement provides that it shall be null and void “and not constitute any part of the record in this Proceeding.”104 The withdrawing party will file a motion to refer the proceeding back to the Administrative Law Judge with the other Settling Parties filing comments in support. The Settling Parties may then argue their original positions.105

131. The Administrative Law Judge admitted the Settlement into the hearing record without making it subject to later removal from the record.

132. In the event a party withdraws from the Settlement, the OAG urges the Commission to refuse to order further contested case proceedings. The OAG is concerned that ratepayers have been paying excessive interim rates since January 2015 and continued contested case proceedings would be unfair to them. The OAG also argues that withdrawal of a party from a non-unanimous Settlement is insufficient cause for continued proceedings.106 The OAG contends that by proposing the Settlement, the Settling Parties waived their rights to provide further rebuttal and surrebuttal testimony into the hearing record.

133. The Administrative Law Judge does not agree. The revenue requirement adjustments reflected in the Settlement were not subjected to rebuttal and surrebuttal rounds of testimony or to cross examination by other Settling Parties. The Commission may find it requires additional evidence on the Settlement Items. However, the Commission should condition additional proceedings upon the Company’s agreement to extend the timeframe for the establishment of final rates and on reducing interim rates.107

134. The OAG disputes the Settlement’s statement that its views were taken into account in arriving at the agreement and demands that specific findings be made on every revenue requirement issue raised by a non-settling party.108

135. The Administrative Law Judge agrees that it is appropriate to make findings and recommendations on revenue requirement issues raised by non-settling parties.

136. Although the record is incomplete with respect to some of the Settlement Items, it is not necessarily incomplete as to every Settlement Item. The Commission could limit any possible referral for further contested case proceedings to a subset of the 60 Settlement Items. Table 5 follows the discussion of the 60 Settlement Items and indicates the the Administrative Law Judge’s findings regarding which Settlement Items do not require further record development or would best be considered in a separate proceeding, as well

104 Id. at 12. 105 Id. 106 OAG Initial Br. at 127-28 (Nov. 30, 2016) (eDocket No. 201611-126884-01). 107 Minn. Stat. § 216B.16, subd. 3 (2016), does not contemplate any midstream adjustment of interim rates. However, if the Commission approves an ROE less than the Company’s currently authorized ROE of 9.72, interim rates could, with the Company’s agreement, be adjusted for the new ROE. The Commission could also consider reducing the Company’s expenses and rate base as indicated by Settlement Items the Commission deems resolved. 108 OAG Initial Br. at 126. 131 (Nov. 30, 2016) (eDocket No. 201611-126884-01).

[88507/1] 25

as those Items where additional evidence from the parties could be helpful to the Commission. If the Commission considers additional contested case proceedings, the Administrative Law Judge suggests that the Commission require that parties seeking additional contested case proceedings on any Settlement Item make an offer of proof so the Commission can weigh the potential value of further evidentiary proceedings.

137. To assist the Commission’s review of the Settlement and consideration of options in the event that it rejects the Settlement, this section of the Report discusses each Settlement Item individually. Issues raised by a non-settling party are discussed together with the Settling Parties’ direct testimonies.109

Overall Revenue Requirements

138. The Settlement’s revenue requirement is “informed by” the DOC-DER’s revenue requirement recommendation. The DOC-DER analyzed both the Company’s 2016 Test Year and projected revenue requirements through 2020, and then proposed over 35 expense adjustments. These adjustments significantly reduce the Company’s proposed revenue requirement.110

139. The OAG’s witness, Mr. Lindell, criticized the Settlement’s revenue requirement because it was not, in percentage terms, as large a reduction from the Company’s initial proposal as in the Company’s previous rate cases. Sixty-two percent of the request is allowed by the Settlement versus an average in the Company’s three most recent prior rate cases of 43 percent.111

140. The DOC-DER’s witness, Ms. O’Connell, believes the comparison has little merit because the monetary value of the issues in each rate case vary. She also noted that, to the extent the Company does not propose costs that have been previously denied, it would be reasonable to expect the percentage of the Company’s request granted by the Commission would decline from rate case to rate case. Finally, Ms. O’Connell pointed out errors in Mr. Lindell’s calculation that reduced the Settlement’s percentage of the Company’s initial request allowed to 47 percent.112

141. The Company’s witness, Mr. Burdick, responded that Mr. Lindell had compared the Company’s initial three-year MYRP with the four-year period of the Settlement.

109 The Report generally discusses issues in the order of the Final Issues List. See eDocket No. 201612-127654-01. However, there are two exceptions. First, rather than discuss the issues the OAG disputes in a separate section as the Final Issues List does, the Report addresses the OAG disputes alongside the Settlement terms. Second, the Report has a separate section devoted to an in-depth presentation of the ROE proposals. In the event the Commission rejects the Settlement and/or its authorized ROE, the Report separately explains an ROE recommended by the Administrative Law Judge. 110 Ex. 809 at 8-9 (Campbell Direct). 111 Ex. 712 at 2-3 (Lindell Rebuttal). 112 Ex. 802 at 3-4 (O’Connell Surrebuttal).

[88507/1] 26

The Company’s proposed revenue requirement for 2019 should be included when calculating the percentage of the requested metric.113

142. The Administrative Law Judge does not recommend that the Commission find the Settlement unacceptable because the percentage of the Company’s initial request is too high. If the Settlement is waived or rejected, the Commission must separately decide all of the issues resolved by the Settlement as they each factor into the revenue requirement.

Return on Equity114

143. The non-settling parties’ analyses and positions concerning the appropriate return on equity are fully discussed below in Part III. This section considers the Settling Parties’ views on ROE in their direct testimonies.

144. The Company’s currently authorized ROE is 9.72 percent. The Company’s witness, James Coyne, recommended an ROE of 10.00 percent.115 The Settlement proposes an authorized ROE of 9.20 percent.116

145. Using well-established methods for estimating ROE, the DOC-DER’s witness, Craig Addonizio, recommended an ROE of 9.06 percent.117 One of the reasons the DOC-DER supported the Settlement is the rates proposed therein are consistent with the rates the DOC-DER proposed after making its revenue requirement adjustments and applying its recommended ROE of 9.06 percent:

Thus, from the Department’s perspective as a practical matter, the rates sets forth in Table A118 are informed by the Department’s recommendations, which include revenue requirement adjustments that reflect the Dep

findings of fact, table of contents...oah 19-2500-33074 . mpuc e-002/gr-15-826 . state of minnesota...

Documents