capital structure, cost of capital, and retirement …€¦ · 17 table 1 18 recommended 2017 test...

Direct Testimony and Schedules Patrick L. Cutshall

Before the Minnesota Public Utilities Commission

State of Minnesota

In the Matter of the Application of Minnesota Power for Authority to Increase Rates for Electric Utility

Service in Minnesota

Docket No. E015/GR-16-664

Exhibit __________

CAPITAL STRUCTURE, COST OF CAPITAL, AND RETIREMENT PLAN ACCOUNTING

November 2, 2016

Table of Contents

I. INTRODUCTION AND QUALIFICATIONS ..................................................... 1

II. ALLETE CORPORATE STRUCTURE ............................................................... 5

III. RISKS FACING MINNESOTA POWER ............................................................. 8

A. Customer Base ......................................................................................... 10

B. Minnesota Power’s Recent Financial Performance ................................. 11

C. Credit Ratings .......................................................................................... 14

IV. RECOMMENDED TEST YEAR CAPITAL STRUCTURE .............................. 29

A. Debt .......................................................................................................... 30

B. Common Equity ....................................................................................... 34

V. RETIREMENT PLAN ACCOUNTING ............................................................. 39

A. Pension Expense ...................................................................................... 40

B. Other Post-Employment Benefit Expense ............................................... 54

C. Prepaid Pension Asset .............................................................................. 61

D. Prepaid OPEB Asset ................................................................................ 73

VI. CONCLUSION .................................................................................................... 76

1 Docket No. E015/GR-16-664

Cutshall Direct and Schedules

I. INTRODUCTION AND QUALIFICATIONS 1

Q. Please state your name and business address. 2

A. I am Patrick L. Cutshall, and my business address is 30 West Superior Street, 3

Duluth, Minnesota 55802. 4

5

Q. What is your present position with ALLETE, Inc.? 6

A. I am the Treasurer of ALLETE, Inc., doing business as Minnesota Power 7

(“Minnesota Power” or “the Company”). 8

9

Q. Please describe your educational background and work experience with 10

ALLETE, Inc. and Minnesota Power. 11

A. I have 29 years of experience in Finance. I earned a bachelor’s degree in 12

accounting from the University of Minnesota Duluth in 1987 and have the 13

professional designations of a CPA (Certified Public Accountant), which is 14

currently inactive, and a CFA (Chartered Financial Analyst). I began my career at 15

ALLETE in 1989 as an Accounting Analyst and became an Investment Analyst in 16

my first year. I was promoted to the Retirement Fund Manager in 2003, to 17

Director of Investments and Tax in 2014, and most recently to Treasurer. Prior to 18

my employment at ALLETE, I worked as a CPA for Ernst & Whinney, a 19

predecessor to Ernst & Young LLP. 20

21

Q. What are your present duties as Treasurer of ALLETE? 22

A. As Treasurer, I am responsible for raising capital, including both debt and equity, 23

banking and bank relationships, credit rating relationships, investor relations and 24

shareholder services, financial analysis, long-range financial forecasts, cash 25

management, benefit plan investments, and tax. 26

27

Q. What is the purpose of the testimony you are presenting on behalf of 28

Minnesota Power? 29

A. My testimony will address the recommended capital structure and overall rate of 30

return for the Company. I also address the Company’s proposals with respect to 31



recovery of test year pension and other post-employment benefit (“OPEB”) 1

expense, and provide support for the Company’s request to include our prepaid 2

pension and OPEB contributions in rate base. 3

4

Q. Please summarize your recommendations to the Minnesota Public Utilities 5

Commission (“Commission”) for Minnesota Power's test year capital 6

structure and overall rate of return. 7

A. My testimony provides support for the Commission to establish an overall rate of 8

return of 7.60 percent. This is based on a recommended capital structure that 9

consists of 53.81 percent common equity and a 10.25 percent return on equity 10

(“ROE”) as supported in the Direct Testimony of Mr. Robert Hevert. The 11

recommended capital structure and rate of return are needed to sustain the 12

adequate investment grade corporate credit ratings and financial integrity 13

necessary for Minnesota Power to continue to provide quality electric service. 14

My recommendations are summarized below in Table 1: 15

16

Table 1 17

Recommended 2017 Test Year Capital Structure and Rate of Return 18

Percentage Cost Weighted Cost

Long-Term Debt 46.19 % 4.52 % 2.09 %

Short-Term Debt 0.00 % 0.00 %

Common Equity 53.81 % 10.25 % 5.52 %

Total 100.0 % 7.60 %

19

I also support Minnesota Power’s forecasted 2017 test year pension and OPEB 20

expense, totaling $7,730,200 total Minnesota Power ($5,719,569 MN) and a 21

negative $829,460 total Minnesota Power (negative expense $613,717 MN) 22

respectively. I explain why the Company believes it is most reasonable to 23



establish pension expense based on our best estimate of current costs, rather than 1

on the five-year average of costs the Commission utilized in our last rate case. 2

This approach not only has the effect of accurately reflecting a test year expense, 3

but also reduces test year pension expense as compared to the five-year average. 4

5

Finally, I support the inclusion of our prepaid pension assets in rate base on the 6

grounds that this outcome is consistent with standard ratemaking treatment for 7

other prepaid expenses and that the Company's contributions are mandated. 8

9

Q. Please explain the organization of your testimony. 10

A. In Section II, I describe ALLETE’s corporate structure. In Section III, I describe 11

the unique business and financial risks facing Minnesota Power. Those risks must 12

be considered in fashioning an appropriate capital structure and in determining a 13

reasonable rate of return for the Company. That description will demonstrate the 14

Company's ongoing need to raise significant new capital and will explain the 15

importance of credit ratings to the ability of the Company to raise that new capital 16

at reasonable costs. Additionally, I discuss Minnesota Power’s financial 17

performance since the last rate case. In Section IV, I describe the recommended 18

test year capital structure. In Sections V, I discuss pension and OPEB accounting 19

and contributions. Lastly, in Section VI, I provide my overall conclusion and 20

recommendations. 21

22

Q. What exhibits are you sponsoring in this proceeding? 23

A. For General Rates, I am sponsoring rate of return and cost of capital exhibits in 24

Volume IV, including: 25

Schedule D-1 – Rate of Return/Cost of Capital Summary, and 26

Schedule D-2 – Embedded Cost of Long-Term Debt. 27

28

The Rate of Return/Cost of Capital Summary shows the cost of each capital 29

element, including rate of return on equity capital; capitalization amounts and 30



ratios; weighted cost of each capital element; and overall rate of return. The 1

actual cost is provided for the 2015 calendar year, and projected costs are 2

provided for 2016 and the 2017 calendar test year. The Embedded Cost of Long-3

Term Debt schedule shows the actual weighted cost of capital for all issuances of 4

long-term debt for 2015, and as projected for 2016 and the 2017 calendar test 5

year. 6

7

For Interim Rates, I am sponsoring rate of return and cost of capital exhibits in 8

Volume II, including: 9

Schedule D-1 IR – Rate of Return/Cost of Capital Summary, and 10

Schedule D-2 IR – Comparison of Most Recently Approved 11

Capital Structure and Rate of Return Calculations (Minnesota 12

Jurisdiction). 13

14

I am also sponsoring the following schedules, which immediately follow my 15

testimony and are identified as: 16

Exhibit ___ (PLC), Schedule 1: EEI Pension and OPEB Survey 2015-17

2016; 18

Exhibit __ (PLC), Schedule 2: EEI Member Companies, Per Company’s 19

2015 Annual Reports, Expected Return on Plan Assets; 20

Exhibit __ (PLC), Schedule 3: MN Jurisdictional Pension Contributions, 21

Expense, and Recovery; 22

Exhibit __ (PLC), Schedule 4: Prepaid Pension Roll Forward ; 23

Exhibit __ (PLC), Schedule 5: Prepaid Pension Balance Components and 24

Earnings; and 25

Exhibit__ (PLC), Schedule 6: Customer Benefits from Prepaid Pension 26

Assets. 27

28



II. ALLETE CORPORATE STRUCTURE 1

Q. Please explain the significance of Minnesota Power to ALLETE. 2

A. Minnesota Power is ALLETE's dominant business by a significant margin, 3

representing approximately 77 percent of ALLETE's capital. 4

5

Q. What are ALLETE’s other investments? 6

A. ALLETE's other investments are organized into two types of businesses: (1) other 7

regulated utility businesses; and (2) energy infrastructure and related services. 8

ALLETE's regulated utility investments include two investments in addition to 9

Minnesota Power: (1) American Transmission Company (“ATC”) (approximately 10

8 percent ownership), an independent transmission company in Wisconsin; and 11

(2) Superior Water Light & Power (“SWL&P”), an electric, water, and gas utility 12

in Wisconsin. ALLETE’s energy infrastructure and related services include three 13

investments: (1) ALLETE Clean Energy (“ACE”), a company that develops, 14

acquires, and manages clean and renewable energy projects; (2) U.S. Water, 15

which provides sustainable solutions for industrial customers to use water more 16

efficiently; and (3) BNI Energy, whose primary business is a lignite coal mining 17

operation in North Dakota that serves the Milton R. Young generating plant 18

located at the mine site. ALLETE also has some minor additional non-regulated 19

investments, the largest being ALLETE Properties, our legacy Florida real estate 20

investment. 21

22

Q. How does Minnesota Power's capital structure relate to that of ALLETE? 23

A. As an operating division of ALLETE, Minnesota Power has a capital structure 24

that is derived from ALLETE's consolidated capital structure.1 The ALLETE 25

consolidated capital structure includes common equity and debt that finances all 26

of ALLETE's business activities, including those of its subsidiary operations. The 27

Minnesota Power capital structure, which is the capital structure used for 28

1 ALLETE's capital structure is reflected in its 2015 ALLETE's Form 10-K filed with the U.S. Securities and Exchange Commission and included in this filing as Schedule F in Volume IV.



ratemaking purposes, is calculated by starting with ALLETE's capital structure 1

and then extracting the debt of ALLETE's subsidiaries and ALLETE's equity and 2

debt investments in those subsidiaries. 3

4

Q. Please give a brief history of ALLETE’s non-Minnesota Power investments. 5

A. The Company initiated a diversification strategy in the early 1980s in order to 6

reduce its dependence on revenues from a concentrated industrial base of taconite 7

and paper customers in northeastern Minnesota. Over the past 30 years, this 8

strategy has contributed significantly to the Company’s financial strength during a 9

period of substantial restructuring in the taconite and paper industries. Today, the 10

Company’s diversification investments consist primarily of regulated electric, 11

water, and gas services; coal mining; an investment in an independent 12

transmission company; a small portfolio of real estate holdings; and investments 13

aimed at creating energy solutions. Although individually and collectively 14

modest in size, these investments strengthen the Company by broadening the base 15

of customers, geographies, and products and services. 16

17

Q. Is the diversification beneficial to Minnesota Power? 18

A. Yes. Over the years, the Company’s efforts to diversify its revenue base have 19

resulted in a stronger company with broader capabilities and enhanced long-term 20

earnings and cash flow stability. As of December 31, 2015, approximately 10 21

percent of ALLETE’s assets were invested in ACE ($494 million), 5 percent of 22

ALLETE’s assets were at U.S. Water ($255 million), 3 percent of ALLETE’s 23

assets were at ATC ($124 million), 2 percent were at BNI Energy ($109 million), 24

2 percent were at SWL&P ($106 million), and 1 percent were at ALLETE 25

Properties ($56 million). Combined, these investments accounted for about 23 26

percent of ALLETE’s total assets. From 2010 through 2015, ALLETE’s 27

subsidiaries have averaged 14 percent of ALLETE’s total assets and contributed 28

to an average of 17 percent of ALLETE’s net income as illustrated in Figure 1 29

below. ALLETE’s diversified investments are expected to broaden the 30



Company’s revenue base and help mitigate business risks facing Minnesota 1

Power utility operations. 2

3

Figure 1. 4

ALLETE Subsidiaries Percent of Assets and Earnings 5

6

7

Q. Has ALLETE experienced change in its capital structure since the 8

Company’s last rate case? 9

A. Yes. In prior rate cases, there was no subsidiary debt held at the ALLETE level, 10

so only equity was removed to get the Minnesota Power capital structure. 11

ALLETE now has debt that supports the subsidiaries, which must be removed for 12

ratemaking purposes. This change comes from our diversification efforts and the 13

related growth at non-regulated subsidiaries since our last rate case. However, the 14

Minnesota Power capital structure determination is the same as in previous rate 15

cases. The Commission approved this approach in the Company's 1987, 1994, 16

2008, and 2009 rate filings (Docket Nos. E015/GR-87-223, E015/GR-94-001, 17

E015/GR-08-415, and E015/GR-09-1151). 18

19



III. RISKS FACING MINNESOTA POWER 1

Q. What unique risks affect Minnesota Power? 2

A. Minnesota Power’s significant industrial customer concentration makes it unique 3

compared to other utilities. Minnesota Power’s revenue from industrial customers 4

was approximately 63 percent and 64 percent of retail revenue in 2015 and 2014, 5

respectively. This compares to an industry average of 17 percent in 2015, making 6

Minnesota Power’s revenue as a percentage of industrial sales the highest 7

amongst investor-owned utilities.2 8

9

In addition, Minnesota Power’s retail customer mix is unique in that energy sales 10

to large industrial customers make up approximately 72 percent of the Company’s 11

total retail energy sales. Taconite processing, our largest industrial customer 12

group, had another economic downturn in 2015 and 2016, producing 13

approximately 80 percent of the average tons of taconite in 2015 compared to the 14

previous five years. 15

16

This industrial concentration is a factor that subjects Minnesota Power to 17

substantial earnings volatility risk relative to its peers. Minnesota Power operates 18

in a natural resource-based service territory with economic prospects closely 19

linked to the fortunes of a few large customers that operate in highly cyclical 20

industries: taconite processing, paper and wood products manufacturing, and oil 21

pipelines. This is unlike the typical utility with a stable base comprised mostly of 22

residential and commercial customers. 23

24

Q. Does this customer concentration specifically distinguish Minnesota Power 25

from other Minnesota investor-owned electric utilities? 26

A. Yes. Minnesota Power’s industrial customer concentration is significantly higher 27

than other Minnesota investor-owned electric utilities. As mentioned above, 28

2 Based on Form EIA-826 Monthly Electric Utility Sales and Revenue Report with State Distribution by EEI (2015).



Minnesota Power’s percentage of retail revenue from its industrial customers was 1

63 percent in 2015. Otter Tail Power Company and Northern States Power 2

Company’s (Minnesota) percentage of retail revenue from its industrial customers 3

was 14 percent and 20 percent in 2015.3 4

5

Q. Do the rating agencies recognize Minnesota Power's customer concentration 6

as a risk? 7

A. Yes. In the most recent credit reports from both Standard & Poor’s Corporation 8

(“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”), the rating agencies 9

cite Minnesota Power’s customer concentration as a risk factor for ALLETE. 10

S&P’s business risk position for ALLETE reflects the “company’s small size, 11

limited geographic diversity, and significant exposure to a cyclical industrial 12

customer base that includes taconite mining, iron concentrate, paper, pulp, and 13

pipeline customers.”4 14

15

Moody’s also explains that “[m]aterial industrial customer exposure adds 16

volatility to the company’s business risk profile.”5 Moody's continues with, 17

ALLETE's exposure to industrial customers is significant, 18 representing roughly 50 percent of annual sales volume in 19 most years, among the highest of the Moody’s US 20 regulated utility universe. The make-up of its industrial 21 customers consist of iron pellet and taconite producers (26 22 percent of regulated operating revenue in 2015), paper, 23 pulp and wood products (9 percent), and oil pipelines (8 24 percent). All three industries are currently facing 25 challenging market environments that translated into 26 weaker industrial sales in two of the three sectors in 2015.6 27

28

3 Based on Form EIA-826 Monthly Electric Utility Sales and Revenue Report with State Distribution by EEI (2015). 4 S&P credit report on ALLETE, Inc. (May 6, 2016). 5 Moody’s credit report on ALLETE, Inc. (Mar. 3, 2016). 6 Moody’s credit report on ALLETE, Inc. (Mar. 3, 2016).

10 Docket No. E015/GR-16-664


Due to the industrial customer concentration risk, S&P rates ALLETE’s business 1

risk profile among the riskiest in the utility industry. 2

3

A. Customer Base 4

Q. Do the large industrial customer contracts provide protection to the 5

Company during a business cycle downturn? 6

A. Minnesota Power’s nine Large Power customers have long-term Electric Service 7

Agreements with two- to four-year cancellation notice provisions. These 8

contracts, however, also contain operating flexibility provisions that allow the 9

customers to reduce their demand commitments significantly with minimal notice. 10

If all Large Power customers were to nominate their Minimum Service 11

Requirement, as stated in their Electric Service Agreements, Minnesota Power's 12

Large Power firm demand revenues could decline substantially – by 13

approximately 75 percent, which equates to $125 million annually. If select 14

Large Power customers were to shut down, and after proper notification is given, 15

in two years the impact would increase to a 94 percent revenue reduction or $159 16

million annually. 17

18

Q. Has the recent economic downturn affected sales to Minnesota Power's 19

industrial customers? 20

A. Yes. As noted in Company witness Mr. David McMillan’s testimony, the 21

economic downturn in 2015 affected the industrial customers. The downturn 22

resulted in shutdowns and layoffs at U.S. Steel’s Keewatin Taconite and Minntac 23

facilities, Cliffs Natural Resources’ North Shore Mine facility and United 24

Taconite plants, and Magnetation. 25

26

Q. Have sales in the Midcontinent Independent System Operator (“MISO”) 27

wholesale market offset the losses the Company experienced in 2016 when its 28

industrial customers' sales declined? 29

A. Only partially. 30

31

11 Docket No. E015/GR-16-664


Q. Please explain. 1

A. While the MISO market gives the Company a market into which power can be 2

sold, the margins in this market are based on day-ahead or spot prices and not the 3

Company’s cost of service. MISO prices have continued to remain low and 4

Minnesota Power expects to recover about 56 percent of the lost large industrial 5

customer retail margins in 2016. As explained in the Direct Testimony of 6

Company witness Ms. Julie Pierce, recovering approximately 56 percent was 7

possible only because Minnesota Power executed contracts for both bilateral and 8

spot market sales. 9

10

B. Minnesota Power’s Recent Financial Performance 11

Q. Please summarize Minnesota Power's present authorized capital structure 12

and rate of return. 13

A. In Minnesota Power’s 2009 general rate filing, the Commission found that an 14

equity ratio of 54.29 percent and a 10.38 percent ROE were appropriate, resulting 15

in an overall rate of return of 8.18 percent. 16

17

Q. Has Minnesota Power earned its allowed rate of return since its last rate 18

filing? 19

A. No. Despite extensive cost reduction efforts, Minnesota Power’s 2015 MN 20

Jurisdictional ROE was only 7.91 percent and it is projected to be only 7.06 21

percent and 7.36 percent in 2016 and 2017 respectively. Due to Minnesota 22

Power’s ongoing capital requirements, without rate relief, the Company’s return 23

will continue to endanger the utility’s financial integrity. 24

25

Q. Please describe Minnesota Power’s debt financing since its last rate case. 26

A. The capital structure for Minnesota Power has been prudently managed since the 27

last rate case, with the 2010 approved capital structure (equity to capital ratio of 28

54.29 percent) maintained within a reasonable corridor of 53.69 percent to 55.64 29

percent, with an average near 54.29 percent. Compared to our last rate case, 30

Minnesota Power’s long-term debt portion of the capital structure has increased 31

12 Docket No. E015/GR-16-664


by $531.9 million, while decreasing the cost of debt by 104 basis points. A 1

positive regulatory framework, supportive credit rating, and low interest rate 2

environment have been instrumental in the ability to raise debt at Minnesota 3

Power. 4

5

Q. Why is liquidity important to the Company? 6

A. Rating agencies and investors have regarded liquidity and financial flexibility to 7

be vital strategic assets since the 2008 financial crisis. S&P explains in its 8

Methodology and Assumptions: Liquidity Descriptors for Global Corporate 9

Issuers (December 2014): “Liquidity is an important component of financial risk 10

across the entire rating spectrum. Unlike most other rating factors with an 11

issuer’s risk profile, a lack of liquidity could precipitate the default of an 12

otherwise healthy entity.” These attributes have been particularly valuable for 13

Minnesota Power because of its concentrated industrial customer base, low prices 14

in the wholesale market, and uncertainty in its regulatory outcomes. 15

16

Q. How have the Company’s capital expenditures in recent years affected the 17

Company’s financial performance? 18

A. The large amount of capital expenditures in recent years for system reliability is 19

one of the driving forces behind this rate review as noted by Mr. McMillian’s 20

testimony. Since our last rate case, our cost of debt has come down, from 5.56 21

percent to 4.52 percent. Additionally, cost cutting measures have brought our 22

Operations and Maintenance (“O&M”) expenses to near the levels in our 2010 23

rate case, excluding O&M expenses related to our new Bison wind projects. 24

Thus, it is the large amount of capital spent and placed into service since our last 25

rate case that has driven down our ROE. 26

27

Q. Please summarize the Company's capital expenditure forecast. 28

A. As Company witnesses Mr. Joshua Skelton and Mr. Christopher Fleege explain in 29

their Direct Testimonies, the Company’s capital expenditure forecast includes 30

investments for transmission upgrades and expansion, environmental compliance, 31

13 Docket No. E015/GR-16-664


renewable generation additions, and the replacement and upgrading of other 1

electric system components. We invest capital to ensure safe, reliable, and 2

environmentally compliant electric service is delivered to our customers in a 3

least-cost, sustainable manner. To that end, we expect to spend $230 million on 4

total Company capital projects in 2017. 5

6

Q. How does this capital expenditure forecast help form the Company’s capital 7

structure proposal? 8

A. Minnesota Power’s ongoing capital expenditure requirements and major projects, 9

such as the Great Northern Transmission Line, will drive the need for Minnesota 10

Power to secure additional capital. In addition to the capital requirements, 11

Minnesota Power has significant first mortgage bond maturities each year 12

beginning in 2018 that will need to be refinanced. Because Minnesota Power’s 13

operations will not generate sufficient cash flow to fund these requirements, the 14

Company will need to secure additional capital from external sources. 15

16

Q. Has Minnesota Power maintained its approved equity ratio following its last 17

rate proceeding? 18

A. Yes. In support of its credit ratings, Minnesota Power has carried an equity ratio 19

in line with the approved ratio of 54.29 percent. Table 2 below shows Minnesota 20

Power’s actual capital structure from 2010-2015 as well as the projected amounts 21

for 2016. 22

Table 2. 23

Minnesota Power Capital Structure 2010-2016 24

2010 2011 2012 2013 2014 2015 2016 Common Equity

795,636

876,435

1,009,191

1,104,094

1,259,129

1,379,906

1,447,627

Short-term Debt

- - - - - - -

Long-term Debt

686,245

733,511

804,465

947,148

1,069,290

1,171,009

1,207,724

Total Capitalization

1,481,881

1,609,946

1,813,656

2,051,241

2,328,418

2,550,915

2,655,351

Equity Ratio 53.69% 54.44% 55.64% 53.83% 54.08% 54.09% 54.52%

Debt Ratio 46.31% 45.56% 44.36% 46.17% 45.92% 45.91% 45.48%

14 Docket No. E015/GR-16-664


1

2

C. Credit Ratings 3

1. Importance of Credit Ratings 4

Q. Why are adequate investment grade credit ratings important? 5

A. Credit ratings by major credit rating agencies are the primary measure used by 6

investors to evaluate the creditworthiness of companies. The credit ratings 7

assigned by rating agencies indicate their opinions of a company's capability to 8

meet its financial obligations. Rating agency opinions are considered by potential 9

investors and affect the number of potential buyers and the cost of a company's 10

debt. 11

12

Minnesota Power is an operating division of ALLETE. Therefore, ALLETE’s 13

credit ratings and its access to low-cost capital on behalf of Minnesota Power 14

directly impact the cost of capital incurred by Minnesota Power customers; the 15

stronger the Company’s credit ratings, the greater the number of investors willing 16

to consider investing in the Company’s debt and the less the Company will need 17

to pay investors to buy its debt. Investment grade credit ratings are crucial 18

because the cost of debt increases very rapidly – and the number of potential 19

buyers decreases substantially – for those companies rated below investment 20

grade. Because the income available to common equity holders is subordinate to 21

debt obligations, the weakening of a company's creditworthiness likewise 22

increases the cost of equity. 23

24

Q. Do Minnesota Power customers benefit if ALLETE has higher credit 25

ratings? 26

A. Yes, the higher the credit rating, the lower the debt cost to our customers. The 27

converse is also true – the lower the credit rating, the higher the cost to our 28

customers. ALLETE’s credit rating is also important to customers because it 29

allows for the availability of capital to support utility projects, especially during 30

economically challenging times. For example, because of ALLETE’s strong 31

15 Docket No. E015/GR-16-664


credit rating, we were able to price $160 million of first mortgage bonds in the 1

middle of the 2008-2009 financial crisis, while non-investment grade companies 2

struggled to issue debt. 3

4

Q. How do economic conditions affect the Company in terms of credit ratings? 5

A. Credit ratings take on greater importance when economic conditions worsen and 6

credit becomes more difficult to obtain. As credit availability tightens, investors 7

become increasingly selective with respect to the companies in which they will 8

invest. Therefore, lower credit ratings reduce access to capital markets, or 9

increase the expense of obtaining capital. 10

11

Minnesota Power is heavily impacted by downturns in the taconite industry, 12

which over time can have an impact on credit ratings. The impacts in 2015 were 13

significant. Taconite customer power nomination levels dropped to 80 percent of 14

capacity in September 2015. In the second quarter of 2015, USS Corporation 15

temporarily idled its Minnesota ore operations at its Keetac plant in Keewatin, 16

Minnesota, and a portion of its Minnesota ore operations at its Minntac plant in 17

Mountain Iron, Minnesota. In August 2015, Cliffs temporarily idled its United 18

Taconite plant in Eveleth, Minnesota. In addition, Magnetation, another 19

Minnesota Power customer, announced a temporary production curtailment at its 20

Plant 2 iron concentrate facility in January 2016. 21

22

Q. How has the Company been able to maintain its credit ratings since the last 23

rate proceeding despite a downturn in the economy and the recent fall-off in 24

industrial revenues? 25

A. ALLETE has been able to manage its credit ratings during this period through 26

increased off-systems sales, cost containment measures, and regulatory support 27

including tracker recovery mechanisms (fuel adjustment clause and riders) with 28

the Commission. 29

30

16 Docket No. E015/GR-16-664


Q. Are these mechanisms – off-system sales, cost containment measures, and 1

tracker recovery mechanisms – sufficient to protect ALLETE’s credit ratings 2

into the future? 3

A. No. S&P acknowledged a temporary decline in credit rating metrics, but expects 4

Funds From Operations (“FFO”)/Debt in the 20 percent to 22 percent range and 5

Debt to Earnings Before Interest, Taxes, Depreciation and Amortization 6

(“EBITDA”) less than 4.5x. Even with off-system sales, cost containment 7

measures, and tracker recovery mechanisms, Minnesota Power had FFO/Debt of 8

17.4 percent in 2015 which is significantly below the threshold S&P expects. 9

Consolidated ALLETE had 20.2 percent FFO/Debt in 2015. Further, Company 10

witness Mr. Steven Morris explains that while the Company has adopted many 11

permanent cost reductions, our O&M levels from 2015 are not sustainable long 12

term. 13

14

Q. What regulatory support is needed to maintain those credit ratings? 15

A. Regulatory advantage is heavily weighted by S&P when determining the business 16

risk profile. S&P’s 2016 report “Assessing U.S. Investor-Owned Utility 17

Regulatory Environments” explains four categories used to determine the 18

regulatory advantage in the credit analysis of an investor-owned utility. The four 19

categories include: 20

21

Regulatory stability; 22

Tariff-setting procedures and design (ability to timely recover costs including 23

fuel-adjustment clause); 24

Financial stability; and 25

Regulatory independence and insulation. 26

27

In S&P’s most recent 2016 credit report on ALLETE, S&P’s assessment of the 28

company’s business risk “includes the use of constructive regulatory mechanisms 29

17 Docket No. E015/GR-16-664


that allow for the recovery of environmental, transmission, and renewable energy 1

investments, and collectively supports ALLETE’s credit quality.”7 It is evident 2

that S&P views the Minnesota regulatory environment as favorable, but S&P also 3

comments “rate case outcomes can sometimes lead directly to a change in our 4

opinion of creditworthiness.”8 5

6

2. Determination of Credit Ratings 7

Q. How is ALLETE’s creditworthiness rated? 8

A. ALLETE is rated by S&P and Moody’s. S&P divides issuer ratings into 9

categories, ranging from AAA, reflecting the strongest credit quality, to D, the 10

lowest credit quality. Issues rated in S&P’s four highest rating categories: AAA, 11

AA, A, and BBB are recognized as being investment grade. In addition, ratings 12

within these categories may be modified with a plus or minus sign to reflect the 13

relative standing within these categories. A credit rating of BBB- is the lowest 14

rating considered investment grade; debt rated below BBB- is considered non-15

investment grade, or speculative. 16

17

Moody's divides issuer ratings into categories similar to S&P. The ratings are 18

modified with 1, 2, or 3. For example, Moody's Baa category (comprised of 19

Baa1, Baa2, Baa3) aligns with S&P's BBB+, BBB, BBB- categories. 20

21

Q. When establishing a credit rating, what factors do the rating agencies 22

consider? 23

A. According to S&P’s November 19, 2013, Corporate Methodology, credit ratings 24

are a blend of qualitative assessments and quantitative information. S&P’s 25

analysis starts with an assessment of the (1) business risk profile and (2) financial 26

risk profile of the company to create an anchor rating. It then uses additional 27

rating factors which modify the anchor rating. 28

7 S&P’s Ratings Direct Summary: ALLETE Inc. (May 6, 2016). 8 S&P’s Assessing U.S. Investor-Owned Utility Regulatory Environments (Aug. 10, 2016).

18 Docket No. E015/GR-16-664


1

S&P has historically provided the most specific guidelines regarding the financial 2

metrics expected for a particular rating, and the Company looks to these 3

guidelines when making capital structure decisions. While Moody’s analysis has 4

historically been more qualitative than S&P’s analysis, it also assesses the 5

business risk of a company by evaluating its regulatory framework, ability to 6

recover costs, diversification, and ability to earn reasonable returns. 7

8

Q. How do Minnesota Power’s utility operations affect ALLETE's credit 9

ratings? 10

A. As a division of ALLETE, Minnesota Power does not carry separate ratings. 11

Rather, Minnesota Power is ALLETE’s dominant business, representing 12

approximately 77 percent of ALLETE’s capital. Consequently, Minnesota 13

Power’s capital structure and financial performance substantially dictate 14

ALLETE’s credit ratings and financial integrity. 15

16

Q. What is the difference between business risk and financial risk? 17

A. In S&P’s Corporate Methodology, S&P describes the business risk profile as “the 18

risk and return potential for a company in the market in which it participates, the 19

country risk within those markets, the competitive climate, and competitive 20

advantages and disadvantages the company has.” S&P later describes the 21

financial risk profile as: 22

The outcome of decisions that management makes in the 23 context of its business risk profile and its financial risk 24 tolerances. This includes decisions about the manner in 25 which management seeks funding for the company and 26 how it constructs its balance sheet. It also reflects the 27 relationship of the cash flows the organization can achieve, 28 given its business risk profile, to its financial obligations. 29 The criteria use cash flow/leverage analysis to determine a 30 corporate issuer's financial risk profile assessment. 31 32

19 Docket No. E015/GR-16-664


Q. What are ALLETE’s credit ratings? 1

A. Table 3 below depicts the investment grade credit rating scales (described above) 2

used by S&P and Moody’s. ALLETE is currently rated BBB+ by S&P and A3 by 3

Moody’s. These ratings are only two and three notches above the lowest 4

investment grade rating by each respective agency. 5

6

Table 3. 7

Investment Grade Credit Ratings ALLETE’s ratings are circled in red

S&P Moody’s

AAA Aaa

AA+ / AA / AA- Aa1 / Aa2 / Aa3

A+ /A / A- A1 / A2 / A3

BBB+ / BBB / BBB- Baa1 / Baa2 / Baa3

Anything below these ratings is considered non-investment grade

8

Currently, ALLETE’s business risk profile is “strong” on a scale of: excellent, 9

strong, satisfactory, fair, weak, and vulnerable; and ALLETE’s financial risk 10

profile is “significant” on a scale of: minimal, modest, intermediate, significant, 11

aggressive, and highly leveraged. These profile rankings result in the Company 12

receiving an anchor rating of “BBB.” Minnesota Power’s regulatory framework 13

is instrumental in ALLETE receiving an adjusted rating of BBB+, one notch 14

above a BBB rating. 15

16

Q. Please provide additional information about ALLETE’s business risk profile 17

and how it compares to other utilities. 18

A. To put ALLETE’s “strong” business risk profile into perspective, of the 227 19

utilities rated in S&P’s most recent “U.S. Regulated Utilities Strongest to 20

Weakest” publication, 91 percent have “excellent” business risk profiles, and only 21

Higher

Lower

20 Docket No. E015/GR-16-664


9 percent have “strong” profiles.9 ALLETE’s business risk rating is worse than 1

other utilities’ ratings because of Minnesota Power’s high concentration of 2

cyclical industrial customers compared to its overall customer base, as discussed 3

previously. Consequently, with a higher (i.e., worse) business risk profile relative 4

to other rated utilities, ALLETE must sustain stronger financial metrics in order to 5

maintain comparable investment grade credit ratings. 6

7

Table 4 below summarizes the business risk of investor-owned neighboring 8

electric utilities. 9

10

Table 4. 11

Investor-Owned Neighboring Electric Utilities10

Business Risk

Madison Gas & Electric Excellent Interstate Power & Light Excellent Wisconsin Power & Light Excellent NSP – MN Excellent Wisconsin Electric Power Co Excellent MidAmerican Energy Co Excellent Wisconsin Public Service Co Excellent NSP – WI Excellent

Minnesota Power/ALLETE Strong

12

13

Q. Does ALLETE’s business risk profile reflect unique characteristics of 14

Minnesota Power’s operations? 15

A. Yes. According to S&P, credit ratings incorporate many subjective judgments. 16

To determine a utility’s business risk profile, S&P explains, “[w]e combine our 17

assessments of industry risk, country risk, and competitive position to determine 18

the assessment for a corporation’s business risk profile.” 11 ALLETE’s industry 19

risk and country risk components are highly rated, but its competitive position is 20

9 S&P’s Issuer Ranking: U.S. Regulated Utilities, Strongest to Weakest (July 30, 2013). 10 Table 4 is consistent with neighboring electric utilities on Table 7. 11 S&P’s Corporate Methodology, at ¶ 4 (Nov. 19, 2013).

21 Docket No. E015/GR-16-664


the reason ALLETE is only rated “strong.” The competitive position consists of 1

the company’s: (1) regulatory advantage, (2) scale, scope, and diversity, (3) 2

operating efficiency, and (4) profitability. The rationale for the “strong” rating as 3

stated in S&P’s April 14, 2014, rating of ALLETE is “the company’s risk profile 4

also reflects its high concentration of industrial customers (accounting for half of 5

all electric sales).”12 6

7

Q. What does the financial risk profile address? 8

A. Financial risk addresses the ability of a company to make scheduled payments of 9

principal and interest on its financial obligations. To assess a company’s ability 10

to make these payments, for a level of cash flow that is different from its business 11

risk, the credit agencies evaluate certain financial ratios to determine whether the 12

company will have sufficient levels of cash flow to cover its interest expense and 13

repay the principal amount of its debt. The credit rating agencies also evaluate 14

the relative amounts of debt and equity in the company’s capital structure to 15

determine whether the company is appropriately capitalized given its business 16

risk. 17

18

Q. What is ALLETE’s financial risk profile? 19

A. S&P considers ALLETE’s financial risk profile to be “significant” on a scale of 20

minimal, modest, intermediate, significant, aggressive, and highly leveraged: 21

Table 5. 22

23 12 S&P’s Ratings Direct Summary: ALLETE Inc. (Apr. 14, 2014).

22 Docket No. E015/GR-16-664


1

Q. What factors do the rating agencies consider to establish a company's 2

financial risk profile? 3

A. Among the rating agencies, S&P has historically provided the most specific 4

guidelines regarding financial metrics, and ALLETE looks to these guidelines 5

when making financing decisions. S&P looks at two core ratios to determine a 6

company’s financial risk profile: 7

(1) Funds From Operations to Debt, or FFO/Debt; and 8

(2) Debt to EBITDA or Debt/ EBITDA (EBITDA being a proxy for cash 9

flow). 10

As previously noted, S&P expects ALLETE’s core ratios to remain near 20 11

percent to 22 percent for FFO/Debt and less than 4.5x for Debt/EBITDA13 over 12

the next few years. However, Minnesota Power’s FFO/Debt ratio in 2015 was 13

17.4 percent – well below S&P expectations for ALLETE. 14

15

Q. How are ALLETE’s business and financial risk profiles used to identify 16

ALLETE’s anchor rating? 17

A. After determining ALLETE’s business risk profile and financial risk profile, S&P 18

combines the profiles to create ALLETE’s anchor rating of BBB, as shown in 19

Table 6 below. 20

21

Table 6. 22

Business risk profile 1 (minimal) 2 (modest) 3 (intermediate) 4 (significant) 5 (aggressive) 6 (highly leveraged)

1 (excellent) aaa/aa+ aa a+/a a- bbb bbb/bb+

2 (strong) aa/aa- a+/a a-/bbb+ bbb bb+ bb

3 (satisfactory) a/a- bbb+ bbb/bbb- bbb/bb+ bb b+

4 (fair) bbb/bbb- bbb- bb+ bb bb- b

5 (weak) bb+ bb+ bb bb- b+ b/b-

6 (vulnerable) bb- bb- bb-/b+ b+ b b-

Financial Risk Profile

23

24

13 S&P Global Ratings, RatingDirect, Summary: ALLETE Inc. (May 6, 2016).

23 Docket No. E015/GR-16-664


Q. What additional factors affect a company’s anchor rating to arrive at its 1

overall credit rating? 2

A. Once the anchor rating is established, S&P then considers additional factors such 3

as diversification, capital structure, liquidity, financial policy, management and 4

governance, and comparable rating analysis. The majority of these factors are 5

directly or indirectly influenced by the regulatory framework and rate case 6

outcomes. As described above, these factors lead to a one notch increase of the 7

company’s credit rating to BBB+. 8

9

Q. Do ALLETE’s other subsidiaries (other than Minnesota Power as an 10

operating division) impact its credit metrics? 11

A. Yes, they help positively offset Minnesota Power's credit metrics. ALLETE’s 12

credit rating is determined by ALLETE’s financial risk, business risk, and 13

modifiers for S&P and Moody’s. Aside from SWL&P, S&P and Moody’s do not 14

assess a credit rating by individual subsidiaries under ALLETE because 15

Minnesota Power is ALLETE’s dominant business, representing approximately 16

77 percent of ALLETE’s capital. ALLETE appropriately capitalizes its 17

subsidiaries, and in 2015 other ALLETE subsidiaries in aggregate had an 18

FFO/Debt ratio of 31.8 percent, enhancing Minnesota Power’s FFO/Debt rating of 19

17.4 percent for an overall FFO/Debt ratio of 20.2 percent for ALLETE. 20

Therefore, ALLETE’s other subsidiaries enhanced ALLETE’s credit metrics in 21

2015 and are expected to continue to enhance ALLETE’s credit metrics in the 22

2017 test year. 23

24

Q. Is the FFO/Debt and Debt/EBITDA range suggested by S&P calculated on 25

the basis of a company's balance sheet capital structure? 26

A. No. A company’s balance sheet by itself does not provide the information 27

necessary to determine the appropriateness of a company’s capital structure. It is 28

important to understand that credit ratings do not reflect unadjusted balance sheet 29

capital structure ratios, but rather financial ratios that include off-balance sheet 30

debt obligations. Consequently, ALLETE's balance sheet ratios are adjusted to 31

24 Docket No. E015/GR-16-664


reflect off-balance sheet debt obligations. 1

2

For example, S&P adjusts purchased power agreements (“PPA”) in S&P’s Key 3

Credit Factors for the Regulated Utilities Industry (November 2013): “[W]e 4

view long-term purchased power agreements (PPA) as creating fixed, debt-like 5

financial obligations that represent substitutes for debt-financed capital 6

investment in generation capacity.” 7

8

Therefore, the balance sheet is only a starting point in determining the metrics 9

used in assessing a company’s credit quality. S&P’s key credit factors include 10

off-balance sheet debt equivalents to determine a company’s credit standing. The 11

materiality of these debt equivalents varies considerably from company to 12

company. 13

14

Q. What debt equivalents are included in Minnesota Power's capital structure 15

for credit rating purposes? 16

A. As of December 31, 2015, we estimated that S&P included $288 million of 17

Minnesota Power debt equivalents, comprised of $97 million from pension and 18

OPEB obligations, $90 million from PPAs, $73 million from asset retirement 19

obligations, $17 million from accrued interest, and $11 million from operating 20

leases. 21

22

Q. Should debt equivalents be considered in determining the reasonableness of 23

Minnesota Power’s test year capital structure? 24

A. Yes. Since credit ratings are driven by financial ratios that include debt 25

equivalents for off-balance sheet obligations, the Company must consider these 26

obligations in its capital structure decisions. Due to the debt equivalents 27

associated with Minnesota Power’s operations, in order to maintain its credit 28

metrics and investment grade credit ratings, the Company is required to carry a 29

higher level of common equity in its capital structure. 30

31

25 Docket No. E015/GR-16-664


The Commission has recognized the credit rating agencies’ methodology of 1

adding obligations regarded as debt equivalents, such as PPAs, to reported 2

balance sheet debt. The Commission’s Order in the Company’s 2008 rate case 3

noted that “a company’s S&P bond-rating depends as much on the company's 4

adjusted debt ratio as it does on its equity ratio.”14 5

6

Q. How do the debt equivalents for Minnesota Power compare to those of other 7

electric utilities? 8

A. It would be very unusual for a utility to have no debt equivalents in the capital 9

structure used in its credit rating determination. The most significant debt 10

equivalents for utilities are usually obligations related to asset retirement 11

obligations, PPAs, operating leases, and pension and OPEB obligations. These 12

are the same obligations affecting Minnesota Power’s capital structure decisions. 13

14

The relative magnitude of debt equivalents, however, is greater for Minnesota 15

Power than for most other neighboring utilities. Approximately a third of the debt 16

equivalents consist of PPAs, which is one of the more manageable debt 17

equivalents. These PPAs, however, are mainly for our contracted purchase from 18

the Oliver Wind facility, Square Butte PPA, and Manitoba Hydro. For Minnesota 19

Power, debt equivalents increase the challenge of maintaining the Company’s 20

credit rating and therefore must be viewed as debt and taken into consideration 21

when determining the allowed equity ratio for the Company. Table 7 below 22

shows the relative magnitude of the debt equivalent balance for Minnesota Power 23

as compared to amounts included in other neighboring utilities. It is noteworthy 24

that the Company’s business risk position is “Strong,” whereas the neighboring 25

utilities all carry the better business risk profile of “Excellent”. 26

27

14 In the Matter of the Application of Minn. Power for Auth. to Increase Elec. Serv. Rates in Minn., Docket No. E015/GR-08-415, FINDINGS OF FACT, CONCLUSIONS OF LAW, AND ORDER at 33 (May 4, 2009).

26 Docket No. E015/GR-16-664


Table 7. 1

Investor-Owned Neighboring Electric Utilities15

Debt Equivalents as % of Total Capitalization1

Minnesota Power2 11%

Wisconsin Power & Light 11% NSP – MN 9% Interstate Power & Light 9% Wisconsin Public Service Co 8% Wisconsin Electric Power Co 8% Madison Gas & Electric 6% MidAmerican Energy Co 4% NSP – WI 4% 1 Calculated from data provided in Select Stats & Ratios by S&P as of December 31, 2015.

2 Minnesota Power's debt equivalent as a percent of total capitalization as of December 31, 2015.

2

Q. Will Minnesota Power continue to have significant amounts of debt 3

equivalents? 4

A. Yes. As previously discussed, S&P imputes debt for PPAs and as we find 5

innovative ways to find low cost financing structures for energy (especially 6

renewable energy), Minnesota Power will have more PPAs in the future. In May 7

2011, Minnesota Power and Manitoba Hydro signed a PPA that requires 8

Minnesota Power to purchase 250 MW of capacity and energy from Manitoba 9

Hydro starting in 2020. In October 2015, Minnesota Power and Manitoba Hydro 10

signed a PPA that provides for Minnesota Power to purchase 50 MW of capacity 11

at fixed prices starting in 2017. Any additional Minnesota Power PPAs will 12

increase imputed debt, which will put downward pressure on ALLETE’s credit 13

metrics (if not offset by a higher allowed equity ratio). 14

15

15 Otter Tail Power Company is not included in neighboring electric utilities. S&P does not specifically breakdown credit metric details for Otter Tail Power Company.

27 Docket No. E015/GR-16-664


Q. How does a company's capital structure affect its credit ratings? 1

A. In the determination of a company’s credit rating, rating agencies consider the 2

amount of debt and debt-like instruments (debt equivalents) that a company 3

utilizes relative to the company’s cash flow and total capital employed. All else 4

equal, a company’s financial risk profile will increase – and its credit rating will 5

face downward pressure – as a company increases the amount of leverage (debt 6

and debt equivalents) used in its capitalization. 7

8

Q. How should the Commission take these debt equivalents into account when 9

reviewing the Company’s capital structure proposal? 10

A. Since credit rating agencies include debt equivalents in their determination of 11

debt-to-capital ratios for credit rating purposes even though they are not included 12

in Minnesota Power’s test year capital structure, Minnesota Power’s proposed 13

46.19 percent unadjusted debt-to-capital ratio translates to a higher S&P debt-to-14

capital ratio for credit ratings purposes. It is therefore important to set Minnesota 15

Power’s permitted common equity levels for regulatory purposes high enough to 16

ensure Minnesota Power’s adjusted debt-to-equity ratio falls within S&P’s 17

expectations for its current credit ratings. I discuss the specifics of this 18

adjustment in more detail in Section IV.B. of my Direct Testimony, below. 19

20

Q. Does the overall nature of the Minnesota regulatory environment also affect 21

ALLETE’s credit ratings? 22

A. Yes. Based on the S&P ratings methodology for financial risk and business risk, 23

ALLETE’s anchor rating is currently BBB. A favorable regulatory 24

framework/regime has been instrumental to ensure an overall credit rating of 25

BBB+. Unfavorable regulatory decisions can increase the utility’s business risk 26

and put downward pressure on credit ratings. S&P specifically references 27

assessing the regulatory framework/regime as a critical factor in determining the 28

credit risk of a utility because of the environment in which the utility operates and 29

the influence on its financial performance. S&P’s 2013 report, Key Credit 30

Factors for the Regulated Utilities Industry, explains: “We base our assessment of 31

28 Docket No. E015/GR-16-664


the regulatory framework’s relative credit supportiveness on our view of how 1

regulatory stability, efficiency or tariff setting procedures, financial stability, and 2

regulatory independence protect a utility’s credit quality and its ability to recover 3

its costs and earn a timely return.” 4

5

Moody’s also notes in its 2013 report Regulated Electric and Gas Utilities two 6

key factors that are important in the assessment for a utility are: (1) regulatory 7

framework; and (2) the ability to recover costs and earn returns. These reports 8

and other discussion with both S&P and Moody’s confirm that regulatory stability 9

is critical for ALLETE. If not for regulatory support, ALLETE’s credit ratings 10

would be jeopardized, resulting in higher costs for our customers. 11

12

Q. What is the estimated impact of a ratings decrease on the Company's cost of 13

debt? 14

A. It is difficult to quantify the impact because the premium charged by investors is 15

dynamic and fluctuates widely with market conditions. However, based on 16

Bloomberg data, the additional cost in terms of added credit spread paid by BBB- 17

credit companies compared to BBB+ rated companies averaged 0.52 percent for 18

the period December 2006 through December 2015. Credit spreads between 19

BBB- and BBB+ rated companies were as high as 1.75 percent at one point 20

during the 2008-2009 financial crisis. Ultimately, a downgrade will result in a 21

higher cost of debt for Minnesota Power’s ratepayers. 22

23

Q. Has Minnesota Power proposed any alternative rate mechanisms to reduce 24

risk? 25

A. Yes, as referenced in the testimony of Ms. Podratz and Mr. McMillan, Minnesota 26

Power has proposed an Annual Rate Review Mechanism. 27

28

29 Docket No. E015/GR-16-664


Q. If approved, how would the rate mechanism impact the Company’s 1

management of its capital structure? 2

A. If the ratings agencies recognize this mechanism to be strong enough to reduce 3

risk and improve our business and or financial risk profile, it would lead to lower 4

borrowing costs and better access to the capital markets. Mr. Hevert addresses 5

how this proposal is factored into the Company's requested ROE. 6

7

8

IV. RECOMMENDED TEST YEAR CAPITAL STRUCTURE 9

Q. Please describe the components of Minnesota Power's capital structure. 10

A. Minnesota Power recommends a capital structure consisting of 53.81 percent 11

common equity and 46.19 percent long-term debt. Minnesota Power's capital 12

structures for the calendar years 2015, projected 2016, and the 2017 test year, are 13

shown in Schedule D-1. For 2015, Minnesota Power’s 13-month average capital 14

structure consisted of 54.09 percent common equity and 45.91 percent long-term 15

debt. For 2016, the average capital structure is expected to consist of 54.52 16

percent common equity and 45.48 percent long-term debt. These ratios do not 17

reflect any off-balance sheet obligations that, for credit rating purposes, are 18

viewed as the equivalent of debt. 19

20

Table 8 below summarizes Minnesota Power’s capital structure, ROE, and overall 21

rate of return provided in our 2009 retail rate case, 2015 actuals, and as projected 22

for 2016 and requested for the 2017 test year. 23

24

30 Docket No. E015/GR-16-664


Table 8. 1

($ 000)

Allowed

2009 Retail Rate Case

(E015/GR-09-1151)

Actual

2015

Projected 2016

Requested

Test Year

Long-Term Debt 696,667 1,171,009 1,207,724 1,228,550

Common Equity 827,534 1,379,906 1,447,627 1,431,272

Total Capital 1,524,211 2,550,915 2,655,351 2,659,822

Return on Equity 10.38% 7.91% 7.06% 10.25%

Overall Rate of Return

8.18% 6.37% 5.90% 7.60%

2

Q. Why is this capital structure reasonable? 3

A. The Company’s objective is to maintain adequate investment credit ratings in 4

order to access needed capital at reasonable costs. This means, at a minimum, 5

maintaining its credit ratings of BBB+ by S&P and A3 by Moody’s, which is 6

critical for efficiently accessing capital markets and allowing us to provide low 7

capital costs to our customers. The Company’s proposed capital structure is 8

reasonable because it supports the Company’s ability to achieve these important 9

objectives in order to keep overall customer costs at reasonable levels. 10

11

A. Debt 12

Q. Please describe the composition of Minnesota Power’s debt. 13

A. Debt attributable to Minnesota Power consists of first mortgage bonds and a 14

floating rate tax-exempt bond that was used to finance pollution control 15

equipment at Boswell Energy Center. Minnesota Power does not carry any short-16

term debt. 17

18

Q. Why does Minnesota Power not carry short-term debt? 19

A. Due to Minnesota Power’s risk as determined by rating agencies in the 20

Company’s business risk profile, using long-term, low-cost, fixed-rate debt better 21

31 Docket No. E015/GR-16-664


matches Minnesota Power’s assets and liabilities. Not having short-term debt is 1

prudent when considering the low seasonality affect compared to other utilities 2

and the cyclical nature of our large industrial customers. This is especially true 3

during economic downturns when access to capital markets is restricted and the 4

Company’s financial metrics are challenged, thus putting pressure on credit 5

ratings. Additionally, short-term debt adds repricing risk and subjects the 6

company to interest rate volatility. By issuing long-term debt, we are able to lock 7

in recent low rates for many years, similar to homeowners locking in fixed 8

mortgages rather than subjecting themselves to fluctuations in the market. This 9

has been especially prudent in the low interest rate environment we have been in, 10

in which the 10 year and 30 year treasury notes have hit all-time lows in 2016. 11

12

Q. Does ALLETE have other debt outstanding? 13

A. Yes, but all other debt held at ALLETE is allocated to subsidiaries. This debt is 14

all unsecured. 15

16

Q. What determines which debt supports Minnesota Power and which supports 17

the subsidiaries? 18

A. As described above, debt attributable to Minnesota Power consists of only first 19

mortgage bonds and a floating rate tax-exempt bond that was used to finance 20

pollution control equipment at Boswell Energy Center. The first mortgage bonds 21

are secured by all of Minnesota Power’s utility assets. The floating rate tax-22

exempt bond was issued by the City of Cohasset, but Minnesota Power is 23

obligated to make the payments on the bond. The Cohasset bond is supported by 24

a letter of credit issued by JP Morgan. 25

26

The ALLETE debt that supports subsidiaries consists of 5.99 percent unsecured 27

notes, a floating rate term loan, and a floating rate tax-exempt bond issued by 28

Collier County, Florida (supported by a letter of credit issued by Wells Fargo) 29

which was originally issued for ALLETE’s previously-owned Florida Water 30

32 Docket No. E015/GR-16-664


subsidiary. Minnesota Power assets do not secure any of the ALLETE debt used 1

by the subsidiaries. 2

3

Q. Is it beneficial for Minnesota Power to issue first mortgage bonds? 4

A. Yes, first mortgage bonds are rated two notches above the unsecured credit rating 5

for both Moody’s and S&P. The two notch upgrade provides the first mortgage 6

bonds with a lower interest rate which directly reduces the Company’s cost of 7

debt. 8

9

Q. Besides the Cohasset bond, was any of the unsecured debt included in 10

Minnesota Power’s capital structure in the previous rate case? 11

A. Yes. The Collier County bond and 5.99 percent senior unsecured notes were 12

previously included in the Minnesota Power capital structure, but the Company 13

was able to replace them with lower fixed rate first mortgage bonds in 2014. The 14

replacement bonds have an average rate of 3.77 percent and longer duration by 15

over ten years, benefitting the customer with better terms of lower-cost and longer 16

maturities. The Collier County bond and the 5.99 percent senior unsecured notes 17

were then allocated to the subsidiaries, essentially giving Minnesota Power a free 18

“call option” to benefit from the superior terms of the replacement bonds. 19

20

Q. Is this allocation of debt consistent with how the debt would be treated under 21

a holding company capital structure? 22

A. Yes. As Company witness Mr. McMillan indicates, ALLETE is considering a 23

future filing that would transition Minnesota Power into a separate corporate 24

subsidiary, rather than an operating division, of ALLETE, Inc. Mr. McMillan 25

explains that this potential separation will reflect the increasing levels of 26

ALLETE nonregulated activities. However, we do not expect such a change 27

would affect Minnesota Power’s cost structure given our current allocation 28

procedures. For example, if ALLETE transitions to a holding company capital 29

structure, the first mortgage bonds and the Cohasset floating rate demand revenue 30

33 Docket No. E015/GR-16-664


refunding bond would be part of the Minnesota Power capital structure and the 1

other unsecured debt would be part of the holding company capital structure. 2

3

Q. What are the Company's objectives when issuing long-term debt? 4

A. The primary objectives of the Company's debt financing strategy are to minimize 5

debt costs, maximize financing flexibility, minimize exposure to potential adverse 6

market conditions in the future, maintain a strong liquidity profile, and maintain 7

an adequate investment grade credit rating. Each of these objectives contributes 8

to the overall goal of reducing credit costs and risk. 9

10

Q. What new debt is expected to be issued in 2017 for Minnesota Power? 11

A. Minnesota Power expects to add $40 million in first mortgage bonds in 2017. 12

Minnesota Power’s projected long-term debt balance at the end of the test year 13

ending December 31, 2017, is detailed in Schedule D-2 and is expected to be 14

$1,247.4 million, or 46.19 percent of total ending capitalization. When calculated 15

from a 13-month average, however, the balance is $1,228.6 million, or 46.19 16

percent of total average capitalization. This amount is shown in Schedule D-1 17

and is used to calculate Minnesota Power’s overall cost of capital. The weighted 18

average cost of debt projected in the 2017 test year capital structure is 4.52 19

percent. 20

21

The precise size, timing, and tenor of debt issuances will depend on prevailing 22

financial market conditions and trends, as well as the timing of Minnesota 23

Power’s cash receipts and disbursements. 24

25

Q. Does ALLETE expect to issue any other debt in 2017? 26

A. Yes. In addition to the first mortgage bonds for Minnesota Power, ALLETE will 27

be issuing unsecured debt in support of subsidiary operations. The specific size, 28

timing, and tenor of the unsecured debt issuances will be dependent on the needs 29

of the subsidiaries. Since this debt is being issued for subsidiary use, it must not 30

34 Docket No. E015/GR-16-664


be included in calculations of Minnesota Power’s cost of debt or as part of 1

Minnesota Power’s capital structure. 2

3

Q. Please summarize the embedded cost of long-term debt. 4

A. The cost of long-term debt shown in Schedule D-2, calculated from a 13-month 5

average balance, is 4.56 percent for 2015, 4.52 percent projected for 2016, and 6

4.52 percent for the 2017 calendar test year. These amounts are shown in 7

Schedule D-1 and are used to calculate the overall returns. The cost of the first 8

mortgage bonds issued in 2017 is projected to be 3.90 percent, and the cost of 9

Minnesota Power’s floating rate tax-exempt bond is projected to be 1.00 percent. 10

Please see Table 9 below for a comparison of the long-term debt costs for 11

Minnesota utilities as requested in their most recent rate cases. 12

13

Table 9. 14

MN Utility Debt Costs 15

Utility Cost of Debt Test Year

Minnesota Power 4.52% 2017

Northern States Power 4.81% 2016

Minnesota Energy Resources 5.11% 2016

CenterPoint 5.38% 2016

Otter Tail Power 5.62% 2016

Great Plains Natural Gas 5.49% 2016

Interstate Power & Light 6.00% 2009

Greater Minnesota Gas 9.13% 2009

16

17

B. Common Equity 18

Q. Please summarize the level of common equity in the Minnesota Power capital 19

structure. 20

A. The projected common equity balance in Minnesota Power’s capital structure at 21

the end of the test year is expected to be $1,452.9 million, or 53.81 percent of 22

35 Docket No. E015/GR-16-664


total ending capitalization. When calculated from a 13-month average, however, 1

the balance is $1,431.3 million, or 53.81 percent of average capitalization. This 2

amount is used to calculate the overall rate of return Minnesota Power is 3

proposing in this case.16 4

5

Q. To determine Minnesota Power’s capital structure, what amount of common 6

equity in ALLETE's capital structure reflects investments in ALLETE 7

subsidiaries? 8

A. In the test year, ALLETE's average equity investment balance in subsidiary 9

activities is expected to be $530.6 million. The $530.6 million of equity is 10

removed from the ALLETE capital structure to determine Minnesota Power’s test 11

year capital structure. 12

13

Q. Does the determination of Minnesota Power’s common equity include any 14

other adjustments to ALLETE's balance sheet? 15

A. Yes. Equity in Minnesota Power’s capital structure includes an accounting entry 16

recorded in ALLETE’s “Accumulated Other Comprehensive Income” for certain 17

amounts associated with non-regulated operations’ post-employment plans as 18

required by SFAS 158 (Employers’ Accounting for Defined Benefit Pension and 19

Other Post-Employment Plans). 20

21

Q. Are these adjustments consistent with the adjustments made in previous rate 22

filings? 23

A. Yes, the SFAS 158 adjustment is consistent with the adjustment made in the 24

Company’s most recent rate orders in 2009 and 2010. Previous rate filings also 25

included an adjustment for the reversal of ALLETE’s Unearned ESOP Shares 26

contra equity entry. This adjustment is no longer needed as the ESOP contra 27

equity balance was reduced to zero at the end of 2015, as planned. 28

29

16 See Volume IV, Schedule D-1.

36 Docket No. E015/GR-16-664


Q. Please explain the SFAS 158 post-employment plan balance sheet entry. 1

A. In September 2006, the Financial Accounting Standards Board issued SFAS 158 2

(Employers’ Accounting for Defined Benefit Pension and Other Post-3

Employment Plans). SFAS 158 requires employers to recognize certain costs 4

associated with their defined benefit pension and other post-employment plans on 5

their balance sheets. While SFAS 158 amounts for regulated operations are 6

reflected as a long-term regulatory asset, amounts relating to non-regulated 7

operations are recorded in “Accumulated Other Comprehensive Income” in the 8

Equity section of the balance sheet. 9

10

Q. Please explain why ALLETE’s SFAS 158 post-employment plan entry is 11

reversed in Minnesota Power’s capital structure. 12

A. The SFAS 158 amounts recorded in ALLETE’s “Accumulated Other 13

Comprehensive Income” are removed from Minnesota Power’s capital structure 14

because they relate only to non-regulated operations. For the 2017 test year, the 15

projected non-regulated post-employment plan amount is $19.6 million. 16

17

Q. Please summarize the amount of common stock issued since the Company’s 18

last rate case in 2009. 19

A. In support of its credit rating and to fund capital investments, ALLETE has issued 20

over $600 million in common stock since 2009. This includes $306 million 21

through our ALLETE equity At the Market program, $151 million through an 22

Equity Forward offering, and $167 million through our Invest Direct, Employee 23

Stock Purchase Plan, and Retirement Savings and Stock Ownership Plan as 24

detailed in Table 10 below. Flotation costs were incurred for the market and 25

Equity Forward issuances, as described in Mr. Hevert’s testimony. 26

27

37 Docket No. E015/GR-16-664


Table 10. 1

Common Stock Issuances 2010-2016 2

2010 2011 2012 2013 2014 2015 2016 Total

At the Market $6.0 $16.0 $53.1 $63.3 $90.0 $69.9 $8.0 $306.4

Equity Forward17 - - - - $85.2 $65.4 - $150.6

Other18 $14.5 $23.1 $23.9 $34.8 $25.4 $25.9 $19.0 $166.6

Total $20.5 $39.1 $77.0 $98.2 $200.6 $161.2 $27.0 $623.6

3

Q. How much equity does ALLETE carry in its capitalization? 4

A. Minnesota Power is by far ALLETE’s dominant business. Consequently, 5

ALLETE’s equity ratios are driven by Minnesota Power’s capital structure. For 6

the test year, ALLETE is expected to be capitalized with a projected equity ratio 7

of 56.0 percent and Minnesota Power with a projected equity ratio of 53.8 percent 8

(precisely, 53.81 percent). 9

10

Q. Does ALLETE expect to issue common stock in 2017? 11

A. Yes. As previously indicated, Minnesota Power has a need for additional external 12

financing. To maintain a capital structure that will support adequate investment 13

grade credit ratings and allow the Company to access needed capital at reasonable 14

costs, ALLETE expects to issue both debt and equity capital. 15

16

Q. Please explain why the recommended test year capital structure for 17

Minnesota Power is reasonable and appropriate. 18

A. The Company’s objective is to maintain adequate investment grade credit ratings 19

in order to continue to access the capital it needs at reasonable terms and maintain 20

17 Equity Forward net of carrying costs associated with delayed draw. 18 Includes common stock issued through Invest Direct, Employee Stock Purchase Plan, and Retirement Savings and Stock Ownership Plan.

38 Docket No. E015/GR-16-664


its financial integrity. The ongoing capital expenditure requirements and debt 1

maturities facing Minnesota Power make this objective both more difficult and 2

more important. The Company’s recommended test year capital structure 3

produces an adjusted FFO/Debt and Debt/EBITDA ratio within the expected 4

range for ALLETE’s current S&P credit rating. ALLETE expects to issue 5

additional equity to fund Minnesota Power’s capital requirements. 6

7

Q. What do the credit rating benchmarks indicate regarding the 8

appropriateness of Minnesota Power’s test year capital structure? 9

A. Minnesota Power’s test year capital structure includes a 46.19 percent unadjusted 10

debt-to-capital ratio. After applying S&P’s adjustments for debt equivalents, 11

Minnesota Power’s test year debt-to-capital ratio for credit rating purposes 12

increases to 51.46 percent. With the S&P adjustments for debt, Minnesota 13

Power’s FFO/Debt is at 20.1 percent and debt to EBITDA at 4.0x. As I 14

mentioned earlier, S&P expects ALLETE to remain near 20 percent to 22 percent 15

for FFO/Debt and debt to EBITDA less than 4.5x. 16

17

Q. Please explain why a capital structure that produces an adjusted debt-to-18

capital ratio of 51.46 percent is acceptable. 19

A. As discussed above, the adjusted debt-to-capital ratio of 51.46 percent produces 20

an FFO/Debt ratio that is within the acceptable range for S&P. If the Company’s 21

requested equity ratio falls below 53.81 percent, Minnesota Power’s financial 22

metrics would move below the standard for ALLETE’s current rating. A decline 23

in credit quality would increase Minnesota Power’s cost of capital at a time when 24

the Company continues to have substantial external financing needs. 25

26

Q. Do you support the analysis and the rate of return on common equity of 27

10.25 percent presented by Mr. Hevert? 28

A. Yes. Mr. Hevert's result of 10.25 percent is reasonable in today’s economic 29

environment, including the risks that are unique to Minnesota Power, and is 30

representative of the range of equity investors’ required rate of return for 31

39 Docket No. E015/GR-16-664


investment in integrated electric utilities in today’s capital markets. The 1

significance of the ROE increases in volatile markets because the level of 2

earnings authorized by the Commission directly impacts the Company’s ability to 3

fund capital investment with internally generated funds. 4

5

Mr. Hevert’s recommended ROE considers the Company’s unique risk profile, 6

including its customer concentration, capital expenditure program, and debt 7

maturities. With the Company required to access debt and equity markets for a 8

substantial amount of capital, our ability to attract capital at reasonable returns to 9

ensure continued safe and reliable electric service while maintaining the 10

Company’s financial integrity is crucial. Potential investors will evaluate the 11

Company’s ability to meet its fixed obligations and provide an acceptable return 12

before committing their capital to the Company. 13

14

V. RETIREMENT PLAN ACCOUNTING 15

Q. What is the purpose of this section of your Direct Testimony? 16

A. In this section of my testimony, I explain how the Company’s pension and OPEB 17

expense amounts for the 2017 test year were derived. I note that Company 18

witness Ms. Nicole Johnson’s Direct Testimony provides background information 19

on overall compensation, including how retirement plans fit into our 20

compensation planning. Therefore, this section focuses just on pension and 21

OPEB expense accounting and the resulting accumulated contributions in excess 22

of net periodic benefit costs. Note that because the pension and OPEB plans are 23

managed at the total Minnesota Power level, which includes non-regulated 24

operations as well as regulated operations, many costs included in the testimony 25

are at the total Minnesota Power level. In most cases, the Minnesota 26

jurisdictional numbers (MN) are also included. 27

28

40 Docket No. E015/GR-16-664


A. Pension Expense 1

Q. What amount of pension expense is included in Minnesota Power’s 2017 test 2

year budget? 3

A. The 2017 pension expense is projected to be $7,730,200 total Minnesota Power 4

($5,719,569 MN). 5

6

Q. How many pension plans does ALLETE have? 7

A. Company witness Ms. Johnson discusses the Company’s pension plans and plan 8

components in her Direct Testimony. In summary, for purposes of my testimony, 9

ALLETE has three qualified pension plans, collectively referred to as the 10

Company’s pension or pension plan: 11

12

Plan A – “non-bargaining plan,” for active non-bargaining unit employees as 13

of January 1, 2016, 14

Plan B – “bargaining plan,” for active bargaining unit employees as of 15

January 1, 2016, and 16

Plan C – “inactive plan,” for participants with a deferred vested benefit, 17

retired participants, or surviving spouse status as of December 31, 2015, 18

including former non-bargaining unit and bargaining unit participants which 19

are no longer represented by the union contract. 20

21

Q. How are ALLETE’s pension plan contributions and pension expense 22

determined? 23

A. The amounts of the Company’s (1) contributions to its pension plan and (2) its 24

annual pension expense are different because they are governed by two different 25

authorities. Contributions to the pension plan are made to comply with the 26

funding requirements of the Employee Retirement Income Security Act of 1974 27

(“ERISA”) and the Internal Revenue Code (“IRC”), including the provisions of 28

the Pension Protection Act of 2006. 29

30

41 Docket No. E015/GR-16-664


The pension expense is determined by Generally Accepted Accounting Principles 1

(“GAAP”) determined by the Financial Accounting Standards Board (“FASB”) 2

and accepted by the U.S. Securities and Exchange Commission (“SEC”). 3

4

Q. Can you provide more detail explaining how the Company’s annual pension 5

expense is derived? 6

A. Yes. Minnesota Power’s actuary, Mercer (US) Inc. (“Mercer”), calculates the 7

Company’s pension expense using actuarial analyses, which are performed in 8

accordance with Financial Accounting Standards Codification 715-30 Defined 9

Benefit Plans – Pension (now “ASC 715-30”). 10

11

ASC 715-30 requires the pension expense for a given year to be determined 12

annually, which is calculated by Mercer. In addition, the Company’s independent 13

auditor, PricewaterhouseCoopers, LLP, audits the actuarial assumptions used to 14

ensure compliance with GAAP. 15

16

Q. Has the Company taken steps in recent years to reduce its pension expense? 17

A. Yes. Below is a summary of these changes. Company witness Ms. Johnson 18

provides more detail regarding several of these changes in her Direct Testimony. 19

20

Closed Plan B to new entrants – February 1, 2011 21

Determined discount rate using Mercer Bond Model to support a higher 22

discount rate, lowering liabilities and overall expense – 2014 23

Created Plan C – January 1, 2016. The purpose of creating Plan C was to 24

restructure Plan A and Plan B into a third plan (Plan C) for inactive 25

participants to deliver benefits in a more cost-effective method. Plan C was 26

established to place all participants not accruing benefits in one plan with the 27

assets and liabilities associated with those accrued benefits and take advantage 28

of accounting rules that allow longer amortization period for unrealized losses 29

within the pension calculation for plans covering inactive participants only. 30

Accordingly, assets and liabilities were transferred from Plans A and B to 31

42 Docket No. E015/GR-16-664


Plan C with this change. As explained in Ms. Johnson’s testimony, because 1

no new Minnesota Power employees are eligible for pension benefits, this is 2

just a shifting of participants from one plan to another plan. The estimated 3

expense savings when we decided to adopt Plan C was $4.7 million total 4

Minnesota Power ($3.4 million MN) and $4.6 million total Minnesota Power 5

($3.4 million MN) for 2016 and 2017 respectively. 6

Q. What are the components of the 2017 pension expense calculation? 7

A. ALLETE’s pension expense is determined by calculating and aggregating five 8

components: 9

10

1. Service Cost – The present value (using the Discount Rate as described below) 11

of the projected retirement benefits earned by each employee in the current 12

year. 13

2. Interest Cost – The amount the present value (using the Discount Rate as 14

described below) of future benefit payments is expected to increase during the 15

year due to one year’s interest accrual. In other words, this is the expense 16

incurred because the employees are one year closer to receiving their benefit. 17

3. Expected Return on Plan Assets – The amount expected to be earned on the 18

plan’s assets. It is estimated by multiplying the Expected Return on Assets 19

(“EROA”) to the five-year smoothed pension asset balance. 20

4. Amortization of Prior Service Cost – The cost of increased/(decreased) 21

benefits, amortized over the remaining service life of the affected participants. 22

5. Amortization of Net Gain or Loss – Gains or losses accumulate when the 23

annual change in the benefit obligation or the plan assets deviate from 24

expectations, i.e. the difference between the prior years’ actual return on plan 25

assets vs. the prior years’ Expected Return on Plan Assets. If these 26

accumulated gains or losses exceed 10 percent of the greater of the benefit 27

obligation or plan assets, the excess is amortized over a period of time based on 28

participant demographics. 29

30

43 Docket No. E015/GR-16-664


Q. What information does the actuary utilize to calculate the annual pension 1

expense? 2

A. The primary pension assumptions used to estimate the Company’s 2017 pension 3

expense are listed below: 4

5

Discount Rate of 4.25 percent: The discount rate is computed using the 6

Mercer Bond Model, which creates a hypothetical portfolio of AA or 7

better rated corporate bonds such that bond yields and principal payments 8

would fully match the projected benefit payments from the pension plan. 9

The discount rate is set equal to the yield on this hypothetical portfolio. 10

This methodology is the most precise and yields the highest discount rate 11

(lowest expense) that we are allowed to use per the SEC. 12

EROA of 7.50 percent: The 7.50 percent rate compares to average rates of 13

7.10 percent from the EEI Pension and OPEB Survey 2015-2016 14

(Exhibit__ (PLC), Schedule 1), and 7.30 percent as determined in 15

ALLETE’s internally calculated survey of EEI member companies’ 2015 16

annual reports (Exhibit__ (PLC), Schedule 2). As shown, ALLETE’s 17

EROA is higher than average (which produces a lower expense). 18

2017 contributions of $18,006,400 total Minnesota Power. 19

20

Q. Did the Commission establish the Company’s 2010 test year pension expense 21

on the basis of the Company’s forecasted or actual 2010 test year costs in 22

Minnesota Power’s last rate case? 23

A. No. In our last rate case, Department of Commerce, Division of Energy 24

Resources (formerly the Office of Energy Resources) (“Department”) observed 25

that Minnesota Power’s pension expense at that time had been volatile, and 26

recommended that “the most effective means of neutralizing this volatility and 27

arriving at a reasonable estimate of the Company’s annual costs over the next few 28

years – when the rates set in this case will be in effect – was to use the Company’s 29

44 Docket No. E015/GR-16-664


five-year historical-average pension expense.”19 However, the Administrative 1

Law Judge “found that the Company’s methodology for forecasting pension 2

expense was reasonable and consistent with generally accepted accounting 3

principles all publicly traded companies must use.”20 Ultimately, the Commission 4

concluded that the Company’s pension expense should not be based on the 5

pension discount rate in effect at one point in time.21 Rather, the Commission 6

applied a five-year average, establishing the 2010 test year pension expense on 7

the basis of the Company’s average annual pension costs for calendar years 2006 8

through 2010.22 9

10

Q. Did the Company consider applying a five-year average of pension expense 11

for purposes of establishing the 2017 test year expense? 12

A. Yes. We considered utilizing the five-year average pension expense for the years 13

2013 through 2017. However, as shown in Table 11 below, this five-year average 14

results in 2017 test year pension expense that would be much higher than 15

Minnesota Power’s forecasted pension expense of $7,730,200 total Minnesota 16

Power ($5,719,569 MN) for 2017: 17

18

Table 11. 19

5-year Pension Expense 20

Year

Total Minnesota Power

Pension Expense

Minnesota

Jurisdictional

2013 19,141,329 14,793,063

2014 11,587,063 8,852,034

2015 13,741,693 10,357,502

Est 2016 5,019,858 3,701,178

Est 2017 7,730,200 5,719,569

Average 11,444,029 8,684,669 21

19 In the Matter of the Application of Minn. Power for Auth. to Increase Rates for Elec. Serv. in Minn., Docket No. E015/GR-09-1151, FINDINGS OF FACT, CONCLUSIONS, AND ORDER at 24 (Nov. 2, 2010). 20 Id. at 25. 21 Id. at 26. 22 Id.

45 Docket No. E015/GR-16-664


1

Q. Why is the five-year average pension expense higher than the Company’s 2

actuarially-determined forecasted pension expense for 2017? 3

A. There are two main reasons the five-year pension expense is higher than the 4

actuarially determined forecasted 2017 pension expense. The first reason is the 5

creation of Plan C. As described above, the creation of Plan C significantly 6

reduced pension expense starting in 2016. The second reason is the Company has 7

contributed a total of $35 million total Minnesota Power to the pension plans 8

during the five-year period, which has increased plan assets and lowered the 9

pension expense. 10

11

Q. Did the Company also consider utilizing a five-year average of pension 12

expense assuming Plan C was implemented as the basis for 2017 test year 13

pension expense? 14

A. Yes. However, the actuarially-determined 2017 pension expense, based on the 15

actuarial analysis, is still substantially lower than the five-year average assuming 16

Plan C for all five years, as illustrated in Table 12 below: 17

18

Table 12. 19

Year

Total

Minnesota Power MN Jurisdictional

2013 14,593,976 11,278,715

2014 8,288,214 6,331,851

2015 9,464,956 7,134,005

est 2016 5,019,858 3,701,178

est 2017 7,730,200 5,719,569

Average 9,019,441 6,833,064 20

21

Q. Why is the five-year average with the Plan C adjustment still higher than 22

anticipated 2017 pension expense? 23

A. As stated previously, the Company has contributed $35 million total Minnesota 24

Power to the pension plans during the five-year period. Contributions increase 25

plan assets and lower pension expense. These contributions and associated 26

46 Docket No. E015/GR-16-664


returns were made throughout the five-year period, and the full effect is realized 1

in 2017. 2

3

Q. Does averaging of historic pension expense have predictive attributes for 4

future pension expenses? 5

No. The correlation between the historical five-year average pension expense 6

(current year plus four historical years) to the actual year pension expense or even 7

the actual average three-year pension expense (current year plus two future years) 8

is low. The correlation coefficient or r-squared values are very low at .50 and .30 9

respectively. The r-squared value is a statistical measurement which measures 10

how the proportion of the variance of one number is attributable to another 11

number. An r-squared value of 1 is perfectly correlated, 0 is uncorrelated, and -1 12

is perfectly negatively correlated. The uncorrelated association of the average 13

five-year pension expense can also be seen visually in Figure 2 below, where the 14

two lines appear to move in different or almost random directions and therefore 15

visually are not correlated. One would expect if these numbers were more 16

correlated they would move in the same direction in a given year. The graph also 17

shows, as was discussed above, on average the five-year average methodology 18

was significantly below the actual pension expense since our last rate case. 19

20

Figure 2. 21

22

23

47 Docket No. E015/GR-16-664


Q. Did you examine the correlation between other averaging methods to arrive 1

at a test year pension expense and actual pension expenses? 2

A. Yes. We also examined the correlation between determining pension expense 3

based on a five-year average of actual discount rates and actual pension expense. 4

This averaging method has a higher correlation than the five-year average 5

expense with respect to its prediction of the next year’s pension expense, but does 6

not accurately predict pension expense beyond that. The correlation coefficient is 7

.90 to the actual current year’s pension expense and .55 to the actual average 8

three-year’s pension expense (current year plus two future years), respectively. 9

Due to its inability to predict pension expense into the future, this methodology is 10

not consistent with a representative test year construct. 11

12

Figure 3. 13

14

15

Q. Have you evaluated another way pension expense can be projected? 16

A. Yes. We evaluated the correlation between the prior year’s actual expense and 17

current year’s expense. The correlation was better with an r-squared of .69 and .38 18

to the actual current year’s pension expense and the actual average three-year’s 19

pension expense (current year plus two future years). The improved correlation 20

over the averaging methods can be seen in Figure 4 below, where the lines appear 21

to move in tandem with one another. 22

23

48 Docket No. E015/GR-16-664


Figure 4. 1

2

3

Q. Have you evaluated additional other ways pension expense can be projected? 4

A. Yes, the final way we evaluated projected pension expense was with our annual 5

autumn forecast of pension expense, which has been done every year since 2007 6

by Mercer. Prior to 2008, GAAP allowed September pension numbers to be used 7

for calendar year-end financial statements, so no estimates were needed because 8

we knew what the pension expense would be before the end of the year and the 9

budget was due. This method was the best method evaluated with an r-squared of 10

.99 and .76 to the actual current year’s pension expense and the actual average 11

three-year’s pension expense (current year plus two future years). Visually, in 12

Figure 5 below, the high correlation between the estimate and actual pension 13

expense can be seen. 14

Figure 5. 15

16

49 Docket No. E015/GR-16-664


Q. Can you summarize the correlation results for the different methods you 1

evaluated? 2

A. Yes, of the four methods used to project the next year’s expense or three-year 3

average expense, Mercer’s actuarially determined estimated pension expense was 4

far superior to any other method. This can be seen in Table 13 below which 5

shows the correlation coefficient of the four methods. 6

7

Table 13. 8

Correlation Coefficient (R-Squared) To Current Year ExpenseTo Next 3-year actual average

(current + 2 future years)Estimated Pension Expense .99 .765-Year Historic Average Discount Rate Pension Expense .90 .55Actual Previous Year Pension Expense .69 .385-Year Historic Average Pension Expense .50 .30 9

10

Q. What does this comparison of five-year averages to current pension expense 11

illustrate? 12

A. This comparison illustrates three important points that contribute to the reason 13

Minnesota Power proposes to utilize its 2017 pension expense (not an averaging 14

method of past expense or discount rates) to set 2017 test year rates. 15

16

First, past average pension expense or average past discount rates are not a 17

reliable indicator of future pension expense due to the unpredictability of 18

investment returns, discount rates, plan benefit changes, and other pension plan 19

assumption changes resulting from the current and projected economic 20

environment. This is why GAAP requires pension expenses to be re-determined 21

annually on the basis of updated information, and why the Company establishes a 22

forecasted pension expense for budgeting purposes that is then updated on 23

December 31 of the year to determine actual expense for the following year. 24

25

Second, averaging of past discount rates or past pension expense can have 26

unintended effects on customers. Utilizing a five-year average of pension 27

expense reduced the test year expense in our 2009 rate case filing, but utilizing a 28

50 Docket No. E015/GR-16-664


five-year average in the current rate case would increase the test year pension 1

expense – and by far more than the averaging in 2009 reduced test year costs. 2

3

Third, switching to a different smoothing mechanism would unfairly punish the 4

utility investors because, over the long run, the utility investors would never 5

recover the long-term pension expense average. This is why we believe the 6

current estimated 2017 test year pension expense is the appropriate expense for 7

determining rates. 8

9

As Company witness Mr. McMillan describes in his Direct Testimony, Minnesota 10

Power’s rate case filing is intended to provide an accurate and transparent picture 11

of the Company’s reasonable costs of providing electric service to customers. 12

Utilizing an average of discount rates or actual historical expense obscures that 13

goal, as it bases pension expense included in rates on past numbers rather than on 14

the financial circumstances in effect during the test year and beyond. Further, 15

applying an averaging method over time may actually increase customer costs in 16

the long run. 17

18

Q. But isn't a purpose of averaging to “normalize” test year pension expense, 19

especially in a volatile market, rather than utilizing a potentially aberrant 20

discount rate or expense estimate? 21

A. That is my understanding of the goal of averaging, but it can undermine the 22

concept of a representative test year. “Normalizing” one potentially changing 23

cost but not others interferes with the idea that all or most costs will change in the 24

course of a year, but that the test year is reasonably representative of the utility’s 25

overall cost of service. Further, in the case of pension expense, GAAP 26

incorporates a different form of smoothing into the annual forecasted and actual 27

expense, thereby already “normalizing” without additional ratemaking 28

adjustments. 29

30

51 Docket No. E015/GR-16-664


Q. How does the 2017 forecasted and actual pension expense already 1

incorporate a “smoothing” mechanism to moderate the volatility of discount 2

rates and other factors? 3

A. For purposes of calculating pension expense, the Company already utilizes all 4

smoothing methods allowed under pension accounting rules (ASC 715-30) that 5

are designed to reduce pension expense volatility. Under these methods: 6

7

ALLETE uses a market-related value of assets in calculating expense. 8

The market-related value of assets phases in gains or losses over a five-9

year period. This reduces volatility by using a more stable asset value to 10

determine the expected return on plan assets component of expense. The 11

market-related value of assets also reduces volatility in the amortization of 12

gains and losses, described below, because recent gains and losses are 13

excluded from the amortization calculation to the extent they are not 14

phased in. 15

ALLETE amortizes accumulated gains and losses, excluding gains and 16

losses not yet phased into the market-related value of assets, in the pension 17

expense. 18

o ALLETE uses a corridor to determine if gains and losses will be 19

amortized in expense. The corridor is the greater of 10 percent of 20

the plan’s obligation or 10 percent of the plan’s market-related 21

value of assets. 22

If accumulated gains and losses fall within the corridor, no 23

gains and losses are amortized in expense. 24

If accumulated gains and losses exceed the corridor, the 25

excess is amortized over the average working lifetime of 26

active participants, or the average lifetime of inactive 27

participants if there are no active participants in the plan. 28

Increases or decreases in plan liabilities resulting from plan amendments 29

are amortized over the average working lifetime of the active participants 30

affected by the plan amendment. 31

52 Docket No. E015/GR-16-664


1

Q. What are the effects of the smoothing on previous years? 2

A. Without the current smoothing mechanisms in place, the pension expense would 3

have varied much more. For the last five years, the standard deviation of the 4

unsmoothed pension expenses is $49.2 million total Minnesota Power, while our 5

GAAP pension expense’s (which is smoothed) standard deviation is $3.4 million 6

total Minnesota Power. This volatility can also be seen in Table 14 below when 7

comparing the expense not smoothed with the GAAP smoothed expense: 8

9

Table 14. 10

Total Minnesota Power Pension Expense 12/31/2011 12/31/2012 12/31/2013 12/31/2014 12/31/2015

Pension Expense without Smoothing 47,163,800 30,074,052 (64,759,889) 61,088,931 17,087,748

GAAP (smoothed expense) 10,494,374 14,928,430 19,141,329 11,587,063 13,741,693

Difference 36,669,426 15,145,622 (83,901,218) 49,501,868 3,346,055 11

12

Q. How does this smoothing principle compare to the averaging that has been 13

applied to utility pension expense in past Minnesota rate cases? 14

A. These smoothing approaches reduce volatility over time, and therefore differ from 15

the averaging approach in several ways. First, the smoothing methods are 16

consistent with GAAP, thereby aligning ratemaking with financial accounting. 17

Second, the smoothing approaches, unlike averaging, do not reduce the utility’s 18

recovery of actually incurred costs to serve customers, but rather change the 19

timing of cost recognition under GAAP accounting. This is because the 20

smoothing incorporates actual costs on an annual rolling basis, as opposed to an 21

average of costs using an expense amount or discount rate that may not reflect 22

actual conditions. Third, averaging the smoothing already implemented under 23

GAAP and then averaging (or smoothing again) is not necessary. Fourth, the 24

averaging (unlike GAAP smoothing methods) does not always reduce volatility. 25

For example, as stated above, the five-year GAAP expense has a standard 26

deviation of $3.4 million total Minnesota Power but the standard deviation of the 27

five-year average expense is $4.5 million total Minnesota Power; this outcome 28

illustrates that averaging does not always reduce volatility. 29

53 Docket No. E015/GR-16-664


1

Q. Is there an alternative way to recover pension expense? 2

A. Yes. As illustrated above, pension expense varies considerably and averaging 3

methods are not reasonably representative of actual pension expense for a test 4

year or for multiple years into the future. An alternative approach would be to 5

institute a mechanism that adjusts rates annually for pension expense and the 6

associated contributions. An annual true-up would sync with the Company’s 7

annual incentive plan filing and would be consistent with the Commission’s past 8

approval of true-ups related to other volatile costs, such as property taxes. This 9

would be the most accurate, timely, and direct recovery mechanism supporting 10

true cost of service. 11

12

Q. What do you conclude regarding the Company’s pension expense included in 13

Minnesota Power’s 2017 test year? 14

A. Minnesota Power supports recovery of the Company’s forecasted 2017 pension 15

expense as determined by Mercer or an annual adjustment mechanism as 16

described previously if the Annual Rate Review Mechanism is not approved. 17

Throughout the years, the Company has been consistent in supporting the 18

determination of pension expense based on the Company’s GAAP pension 19

expense as determined by our actuary, including the current year’s assumptions. 20

Using another method to determine rates, such as an historic average, has the 21

strong potential to distort the forecasting methodology mandated by the SEC and 22

GAAP to measure the cost of the plan, thereby precluding the Company from 23

recovering its costs of providing retirement benefits to Company employees. 24

Further, historic averages do not incorporate changes in the economic 25

environment or plan and assumption changes implemented by the Company to 26

help control the cost of the pension plans. Finally, as demonstrated, GAAP 27

already uses a very effective smoothing approach to account for various gains, 28

losses, and other changes, and therefore further averaging is not necessary. 29

30

54 Docket No. E015/GR-16-664


B. Other Post-Employment Benefit Expense 1

Q. What Post-Employment Benefit Expenses are included in the OPEB? 2

A. ALLETE’s OPEB expense reflects post-employment medical, dental, and life 3

benefits. Please see Ms. Johnson’s testimony for more details regarding these 4

benefits for employees. 5

6

Q. What amount of OPEB expense is included in Minnesota Power's 2017 test 7

year budget? 8

A. The 2017 OPEB expense is projected to be a negative expense of $829,460 total 9

Minnesota Power (negative expense $613,717 MN). This negative expense has 10

the customer benefit of reducing Minnesota Power’s overall revenue requirement. 11

This expense, however, may not stay negative in the future for a variety of 12

reasons, including asset returns, discount rate changes, etc. Another reason is 13

GAAP only requires Minnesota Power to accrue expenses for eligible employees 14

that are 45 years of age or older. Although we have closed our OPEB plans to 15

new employees (as explained in Ms. Johnson’s testimony), some of our current 16

eligible employees are younger than 45. Therefore, when they attain this age, we 17

will begin to accrue for their benefits and this will increase future OPEB expense. 18

19

Q. How do utilities fund OPEB plans and calculate OPEB expense? 20

A. There is no legal mandate to fund OPEB plans as there is for pension plans; 21

however, utilities have typically funded their OPEB plans as mandated or agreed 22

upon by their governing commissions. ALLETE’s OPEB funding policy is to 23

fund, at a minimum, its OPEB expense. The OPEB expense is determined by 24

GAAP mandated by Financial Accounting Standards and accepted by the SEC, 25

which is similar to pension expense. 26

27

55 Docket No. E015/GR-16-664


Q. Why does the Company have the policy to fund OPEB expense? 1

A. On September 22, 1992, the Commission adopted “SFAS 106 accrual accounting 2

for Minnesota utility recordkeeping and ratemaking purposes.”23 The Order 3

stated, “SFAS 106 does not require funding for OPEB obligations.”24 The 4

Department, however, “recommended that external funding be required, in order 5

to provide assurance of future payment of these obligations.”25 In 1992, “the 6

Commission required Xcel to establish an external funding mechanism by its next 7

general rate case for FAS 106.”26 Later, Minnesota Power filed its 1994 rate case, 8

in which Company witness Bruce E. Gagnon testified, based largely on the Xcel 9

Energy precedent, that “[t]he Company intends to fund the SFAS 106 liabilities as 10

the funds are collected.”27 Since then, Minnesota Power has not only funded its 11

expense, it has funded more than its expense. 12

13

On June 27, 2012, the Company requested the ability to determine on an annual 14

basis whether to fund its post-employment benefit trust obligations; 28 however, 15

the Commission denied this request.29 One of the reasons for the denial was that 16

23 In the Matter of the Accounting and Ratemaking Effects of the Statement of Fin. Accounting Standards, Docket U999/CI-92-96, ORDER ADOPTING ACCOUNTING STANDARD AND ALLOWING

DEFERRED ACCOUNTING at 7 (Sept. 22, 1992). 24 Id. at 4. 25 Id. 26 In the Matter of Xcel’s Petition for Approval to Discontinue Funding of Tax Advantaged Extern Fund (VEBA Fund) for Retiree Medical Costs and the Withdrawal of the Accumulated VEBA Fund Balance over a Five-Year Period, Docket No. E,G002/M-02-2188, ORDER APPROVING

PETITION WITH MODIFICATION AND REQUIRING COMPLIANCE FILING at 1 (Oct. 17, 2003) (citing the Commission’s Order in Docket No. U999/CI-92-96). 27 In the Matter of the Application of Minn. Power for Auth. to Change its Schedule of Rates for Retail Elec. Serv. in the State of Minn., Docket No. E-015/GR-94-001, DIRECT TESTIMONY OF

BRUCE E. GAGNON at 8 (Jan. 3, 1994). 28 In the Matter of Minn. Power’s Petition for Approval of Deferred Accounting Related to Pension Plan Contributions and Expenses, Docket No. E015/M-11-1264, REPLY COMMENTS

(June 27, 2012). 29 In the Matter of Minn. Power’s Petition for Approval of Deferred Accounting Related to Pension Plan Contributions and Expenses, Docket No. E015/M-11-1264, ORDER DENYING

PETITION (Mar. 11, 2013).

56 Docket No. E015/GR-16-664


the “request would appear to defeat the trust account’s purpose, which is to ensure 1

that funds are available to pay benefits when they are due.”30 2

3

Q. What is the benefit of the policy to fund, at a minimum, the OPEB expense? 4

A. As with pension funding, by funding expense we are providing an assurance of 5

future payments of these obligations and reducing annual expense amounts. For 6

test year 2017, Mercer projected the earnings on these funds will reduce our 7

OPEB expense by total Minnesota Power $9.4 million ($7.0 million MN). 8

9

Q. Can you provide more detail explaining how the Company’s annual OPEB 10

expense is derived? 11

A. Yes. Minnesota Power had the OPEB expense calculated by Mercer using 12

actuarial analyses, which are performed in accordance with Accounting Standards 13

Codification 715-60 Defined Benefit Plans – Other Post-Employment (“ASC 715-14

60”). Consistent with GAAP, ASC 715-60 sets forth the methodologies and 15

assumptions used to calculate OPEB expense. 16

17

ASC 715-60 requires the OPEB expense for a given year to be determined 18

annually, which is calculated by Mercer. In addition, the Company’s independent 19

auditor, PricewaterhouseCoopers, LLP, audits the actuarial assumptions used to 20

ensure compliance with GAAP. 21

22

Q. Has the Company taken steps to reduce/control OPEB costs in recent years? 23

A. Yes. We have made five recent major changes, which are explained in more 24

detail in Ms. Johnson’s Direct Testimony: 25

26

1. Beginning on February 1, 2011, new employees were no longer eligible for 27

OPEB health benefits; 28

30 Id. at 2.

57 Docket No. E015/GR-16-664


2. Effective January 1, 2012, the age requirement for retiree health eligibility 1

was increased to age 55, up from age 50; 2

3. In 2013, retiree health cost sharing was changed from 75 percent Company/25 3

percent retiree to 70 percent Company/30 percent retiree for post-65 retirees; 4

4. Post-employment life insurance for non-bargaining unit participants was 5

eliminated unless the employee retired prior to January 1, 2016; and 6

5. Minnesota Power added a high deductible consumer directed health plan 7

option in 2014, and a second high deductible consumer directed health plan 8

option in 2017. 9

10

Q. What are the components of the 2017 OPEB calculation? 11

A. ALLETE’s OPEB expense is determined in largely the same manner as pension 12

expense – that is, by calculating and aggregating five components: 13

14

1. Service Cost – The present value (using the Discount Rate as described below) 15

of the projected post-employment benefits earned by each employee in the 16

current year. 17

2. Interest Cost – The amount the present value (using the Discount Rate as 18

described below) of future benefit payments is expected to increase during the 19

year due to one year’s interest accrual. In other words, this is the expense 20

incurred because the employees are one year closer to receiving their benefits. 21

3. Expected Return on Plan Assets – The amount expected to be earned on the 22

plan’s assets. It is estimated by multiplying the EROA by the five-year 23

smoothed OPEB asset balance. 24

4. Amortization of Prior Service Cost – The amortization of the cost of increased/ 25

(decreased) benefits, amortized over the remaining service life of the affected 26

participants. 27

5. Amortization of Net Gain or Loss – Gains or losses accumulate when the 28

annual change in the benefit obligation or the plan assets deviate from 29

expectations, i.e. the difference between the prior years’ actual return on plan 30

assets vs. the prior years’ Expected Return on Plan Assets. If these 31

58 Docket No. E015/GR-16-664


accumulated gains or losses exceed 10 percent of the greater of the benefit 1

obligation or plan assets, the excess is amortized over a period of time based on 2

participant demographics. 3

4

Q. What information does the actuary utilize to calculate the annual OPEB 5

expense? 6

A. The primary OPEB assumptions used to estimate the Company’s 2017 OPEB 7

expense are listed below: 8

9

Discount Rate of 4.25 percent: The discount rate is computed using the 10

Mercer Bond Model, which creates a hypothetical portfolio of AA or 11

better rated corporate bonds such that bond yields and principal payments 12

would fully match the projected benefit payments from the pension plan. 13

The discount rate is set equal to the yield on this hypothetical portfolio. 14

This methodology is the most precise and yields the highest discount rate 15

(lowest expense) which we are allowed to use per the SEC. 16

EROA of 7.50 percent for non-taxable plans and 6.0 percent for taxable 17

plans: These rates compared to the Pension and OPEB Survey 2015-2016 18

average of 7.10 percent (Exhibit__ (PLC), Schedule 1) and OPEB EROA 19

rates of 6.57 percent as determined in ALLETE’s internally calculated 20

survey of EEI member companies 2015 annual reports (Exhibit__ (PLC), 21

Schedule 2). As shown, ALLETE EROA is higher than average (which 22

produces a lower expense). 23

Health care trend rates: Initial trend rate of 6.25 percent with ultimate 24

trend rate of 5.0 percent. This is in comparison to the EEI Pension and 25

OPEB Survey 2015-2016 average of Initial Trend Rate of 6.84 percent and 26

ultimate average trend rate of 4.81 percent (Exhibit__ (PLC), Schedule 1). 27

28

29

30

59 Docket No. E015/GR-16-664


Q. Were test year OPEB costs, like pension costs, determined in the Company’s 1

last Minnesota rate case by averaging five years of actual expense? 2

A. No. OPEB costs for the 2010 test year were based on the Company’s forecasted 3

expense solely for the 2010 test year. While the Commission noted that the 4

dependence of these costs on a single, potentially volatile discount rate could call 5

into question the reasonableness of those costs, the issue had not been addressed 6

in the record and, therefore, was not decided by the Commission.31 7

8

Q. Does the OPEB expense calculation, like the pension expense calculation, 9

incorporate a smoothing mechanism? 10

A. Yes, the OPEB expense calculation incorporates the same smoothing mechanisms 11

as the pension expense, including use of the market-related value of assets, 12

amortizations of prior service costs/(credits), amortizations of (gains)/losses, and 13

the application of the corridor, described below, for determining if (gains)/losses 14

need to be amortized. 15

16

For purposes of calculating OPEB expense, the Company already utilizes all 17

smoothing methods allowed under OPEB accounting rules (ASC 715-60) that are 18

designed to reduce OPEB expense volatility. Under these methods: 19

20

ALLETE uses a market-related value of assets in calculating expense. 21

The market-related value of assets phases in gains or losses over a five-22

year period. This reduces volatility by using a more stable asset value to 23

determine the expected return on plan assets component of expense. The 24

market-related value of assets also reduces volatility in the amortization of 25

gains and losses, described below, because recent gains and losses are 26

excluded from the amortization calculation to the extent they are not 27

phased in. 28

31 In the Matter of the Application of Minn. Power for Auth. to Increase Rates for Elec. Serv. in Minn., Docket No. E015/GR-09-1151, FINDINGS OF FACT, CONCLUSIONS, AND ORDER at 27 (Nov. 2, 2010).

60 Docket No. E015/GR-16-664


ALLETE amortizes accumulated gains and losses, excluding gains and 1

losses not yet phased into the market-related value of assets, in the OPEB 2

expense. 3

o ALLETE uses a corridor to determine if gains and losses will be 4

amortized in expense. The corridor is the greater of 10 percent of 5

the plan’s obligation or 10 percent of the plan’s market-related 6

value of assets. 7

If accumulated gains and losses fall within the corridor, no 8

gains and losses are amortized in expense. 9

If accumulated gains and losses exceed the corridor, the 10

excess is amortized over the average working lifetime of 11

active participants, or the average lifetime of inactive 12

participants if there are no active participants in the plan. 13

Increases or decreases in plan liabilities resulting from plan amendments 14

are amortized over the average working lifetime of the active participants 15

affected by the plan amendment. 16

17

Q. Is there an alternative way to recover OPEB expense? 18

A. Yes, as with the pension expense discussed previously, we could institute a 19

mechanism that adjusts rates annually for pension expense, and the associated 20

contributions. This would be the most accurate and direct recovery mechanism. 21

22

Q. What do you recommend with respect to including OPEB costs in Minnesota 23

Power’s 2017 test year? 24

A. Similar to the pension expense, the Company supports recovery of the Company’s 25

forecasted 2017 OPEB expense as determined by the actuaries, including the 26

current year’s assumptions or an annual adjustment mechanism as described 27

previously if the Annual Rate Review Mechanism is not approved. We believe 28

this is the most accurate and consistent method for determining OPEB expense, 29

and was approved in our prior rate case. Using another method, such as an 30

historic average, has the strong potential to distort the forecasting methodology 31

61 Docket No. E015/GR-16-664


required by the SEC and GAAP to measure the cost of the plan, thereby 1

precluding the Company from recovering its actual costs of providing these 2

benefits to utility employees. Further, historic averages do not incorporate 3

changes in the economic environment, or plan and assumption changes 4

implemented by the Company, to help control the cost of the OPEB plans. 5

6

C. Prepaid Pension Asset 7

1. Background 8

Q. Please describe how the Company funds its pension plans. 9

A. Most years, the Company makes contributions to its pension plan to ensure 10

adequate funding to cover future benefit obligations to employees. As the 11

Internal Revenue Service describes, “[c]ontributions to a defined benefit plan are 12

based on what is needed to provide definitely determinable benefits to plan 13

participants. Actuarial assumptions and computations are required to figure these 14

contributions.”32 15

16

More specifically, the Pension Protection Act of 2006 (“Pension Protection Act”) 17

established certain minimum funding requirements for plan years beginning in 18

2008 and through the present. Prior to enactment of the Pension Protection Act, 19

pension contributions and pension expense were largely equal or in balance. 20

However, the Pension Protection Act established new requirements for calculating 21

the necessary levels of pension plan contributions, which resulted in significant 22

increases in the contributions employers must make to the pension plan in any 23

given year. 24

25

When an employer contributes more to the pension plan than it has expensed, the 26

result is a prepaid pension asset. Conversely, contributing less than expensed will 27

result in a liability. 28

32 IRS Retirement Topics - Defined Benefit Plan Benefit Limits, available at https://www.irs.gov/retirement-plans/plan-participant-employee/retirement-topics-defined-benefit-plan-benefit-limits (last visited Sept. 20, 2016).

62 Docket No. E015/GR-16-664


1

Q. Why are the Company’s pension expenses and contributions different? 2

A. The pension expense and contributions represent different aspects of the pension 3

plan and are governed by two different authorities. The pension expense 4

represents the Company’s annual pension plan costs on the income statement, and 5

is determined by GAAP as set forth by the FASB and accepted by the SEC. 6

Contributions to the pension plan are made by the Company to satisfy the funding 7

requirements of the Employee Retirement Income Security Act of 1974 8

(“ERISA”) and the IRC, including the provisions of the Pension Protection Act 9

for contributions to pension plans. 10

11

Q. What is the level of Minnesota Power’s pension contributions since the 12

Pension Protection Act took effect? 13

A. As illustrated in Exhibit__ (PLC), Schedule 3 and in Figure 6 below, Minnesota 14

Power’s pension contributions from 2008 through 2016 have totaled $119.2 15

million total Minnesota Power ($91.2 million MN). In addition, Minnesota Power 16

has incurred pension expense totaling $78.4 million total Minnesota Power ($59.9 17

million MN), of which it has only collected approximately $7.0 million MN 18

through rates since 2008. 19

20

Figure 6. 21

MN Jurisdictional Historical Pension Contributions, Expense, and Recovery 22

23

24

63 Docket No. E015/GR-16-664


Q. Please describe Minnesota Power’s prepaid pension asset. 1

A. Minnesota Power’s prepaid pension asset arises from the fact the Company has 2

contributed more to the pension plan than it has expensed since 1952, the 3

inception year of the plan. Increased contributions to the pension plan 4

substantially increase the prepaid pension asset balance, which in turn reduces 5

pension expenses. 6

7

Q. What is the amount of ALLETE’s prepaid pension asset? 8

A. The amount of ALLETE’s estimated 2017 test year 13-month average prepaid 9

pension asset is $80,685,986 total Minnesota Power ($59,707,183 MN). 10

11

Q. Are there other naming conventions for prepaid pension assets? 12

A. Yes. Historically, when a Company contributed more to its pension plan than it 13

expensed, this has been called a “prepaid pension expense” or a “prepaid pension 14

asset.” More recently this has been called “accumulated contributions in excess 15

of net periodic benefit cost.” Due to the familiarity with the naming, we will use 16

the “prepaid pension asset” convention. 17

18

Q. What is the status of Minnesota Power’s current cost recovery for pension 19

contributions and pension expense? 20

A. As previously noted, Minnesota Power proposes to recover its actual 2017 21

pension expense through rates. Currently, the Company is recovering through 22

rates an amount of pension expense based on a five-year average as calculated in 23

our 2009 rate case. Minnesota Power also makes contributions to its pension plan 24

on behalf of its employees, which is necessary to comply with federal law and to 25

provide employees with job benefits appropriate to their work delivering utility 26

service to Minnesota Power customers. Although these contributions result in a 27

utility net asset that has the effect of reducing the pension expense, this asset is 28

not presently in rate base and therefore is not earning a return. 29

30

64 Docket No. E015/GR-16-664


Q. Has Minnesota Power ever earned a return on its prepaid pension assets? 1

A. No. Minnesota Power requested recognition of the prepaid asset in our Petition 2

for Approval of Deferred Accounting Related to Pension Plan (Docket No. 3

E015/M-11-1264) filed on December 22, 2011. Minnesota Power’s request for 4

deferred accounting treatment was denied in part because the cost was not 5

considered “unusual, unforeseeable, and large enough to have a significant impact 6

on the utility’s financial condition,” which are the traditional Commission criteria 7

for deferred accounting.33 8

9

Q. What is Minnesota Power proposing with respect to its prepaid pension asset 10

in this proceeding? 11

A. Minnesota Power is proposing to include the MN Jurisdictional portion of the 12

prepaid pension asset, which exists as a balance sheet asset, as a component of 13

Minnesota Power’s working capital section of its rate base and be entitled to a 14

return. 15

16

Q. Why is it appropriate to include Minnesota Power’s prepaid pension asset in 17

rate base? 18

A. Minnesota Power believes strongly that recognition of pension funding as a 19

component of rate base is appropriate for several reasons: (1) they are a necessary 20

cost of providing electric service; (2) a certain level of pension contribution is 21

required by law to fund pension plans; (3) contributions to the pension plan are 22

made by the Company’s shareholders and benefit customers; and (4) other 23

utilities are permitted to include an asset in rate base, consistent with standard 24

ratemaking treatment when contributions and expenses differ significantly for an 25

expenditure. Given that the Company is entitled to a fair return on costs incurred 26

by shareholders as necessary to provide utility service, these costs should be 27

included in rate base. 28

33 In the Matter of Minn. Power’s Petition for Approval of Deferred Accounting Related to Pension Plan Contributions and Expenses, Docket No. E015/M-11-1264, ORDER DENYING

PETITION at 2 (Mar. 11, 2013).

65 Docket No. E015/GR-16-664


1

2. Legal Requirements 2

Q. How has Minnesota Power determined what level of contributions to make to 3

the pension plan each year? 4

A. On an annual basis, the Company has contributed at least the IRC minimum 5

statutory required contribution to the pension plans. The Company has made 6

additional contributions to the pension plans to the level at which they will not be 7

subject to benefit restrictions as described in IRC Section 436 of the Pension 8

Protection Act, and at which they will not be considered “at-risk” status as 9

defined in IRC Section 412 of the Pension Protection Act. Periodically, the 10

timing of contributions was accelerated typically just to the preceding year for a 11

variety of reasons, including the availability of funds and to reduce the implied 12

debt rating agencies compute for debt equivalents related to pension obligations.34 13

However, we are given credit for this contribution in the following years. For 14

more information regarding debt equivalents, see Section III(C)(2), of my 15

testimony. 16

17

Q. What if the Company does not make the minimum contributions and only 18

contributes expense? 19

A. We would be in violation of federal laws. ERISA and the IRC establish minimum 20

funding requirements for defined benefit pension plans. Although there is no 21

requirement that a defined benefit pension plan be 100 percent funded (except 22

upon plan termination), the Company, as plan sponsor, must make minimum 23

annual contributions to the plan equal to the cost of annual benefit accruals plus a 24

seven-year amortization of the unfunded liability. In addition to interest on 25

underpayments, an initial excise tax of 10 percent is levied upon an unpaid 26

funding deficiency, which may increase to 100 percent of the liability if the 27

34 Standard & Poor’s Rating Services, RatingsDirect, Corporate Methodology: Ratios and Adjustments at 25 (Nov. 19, 2013).

66 Docket No. E015/GR-16-664


deficiency is not promptly corrected after notice from the IRS. The penalties are 1

imposed each year that the deficiency is not paid. 2

3

Q. Why is it reasonable for the Company to make contributions above the 4

minimum? 5

A. The Company has a written policy of funding the plan to keep the plan at least 80 6

percent funded on an actuarial basis in order to avoid certain financial and 7

administrative penalties. We have contributed to this 80 percent level. If a plan 8

falls below 80 percent funded, it is considered “at-risk,” no amendment can be 9

made that has the effect of increasing plan liabilities, and certain payments from 10

the plan are prohibited. If the funding goes below 60 percent, all benefit accruals 11

must cease. In addition, the 80 percent funding level is a term negotiated with the 12

International Brotherhood of Electrical Workers (“IBEW”) Local 31. We agreed 13

to this term, which allowed the creation of Plan C. As stated previously, the 14

adoption of Plan C created an expense decrease of $4.7 million total Minnesota 15

Power ($3.4 million MN) and $4.6 million total Minnesota Power ($3.4 million 16

MN) for 2016 and 2017 respectively. 17

18

As will be shown later in my testimony, contributions decrease expense because 19

earnings on these contributions decrease pension expense more than they increase 20

the cost of capital. 21

22

Q. What is the likely effect if the Company’s pension contribution were equal 23

only to the pension expense? 24

A. It would increase expenses dramatically and violate pension terms negotiated with 25

our union. There would be four major issues: 26

27

1. As stated previously, a tax of 100 percent would be applied on the amount 28

of the IRC established minimum contribution not funded which is above the 29

pension expense; 30

67 Docket No. E015/GR-16-664


2. For every $10 million not funded, the pension expense would increase by 1

$750,000 ($10 million x EROA of 7.5 percent); 2

3. Compounded earnings on the contributions would not be available to 3

reduce pension expense; and 4

4. We would need to renegotiate, when appropriate, contract terms negotiated 5

with the IBEW if we prefer not to fund pension Plan B and Plan C at 80 6

percent or higher (based on the adjusted funding target attainment percentage 7

(“AFTAP”)). 8

9

Q. Is it possible for the Company to have a prepaid pension asset and also have 10

a currently underfunded pension plan? 11

A. Yes. A plan can be underfunded at the same time it has a prepaid pension asset 12

because they measure different things. The prepaid pension asset is the amount 13

by which cumulative contributions exceed cumulative recognized pension 14

expense. A pension plan is underfunded when its pension benefit obligations 15

exceed the value of its assets. However, without the prepaid asset, the plan would 16

be more underfunded because the value of the assets would be lower, and 17

therefore even less than the Company’s pension benefit obligations. As I discuss 18

above, this would be to the detriment of pension expense and could put the 19

Company in violation of federal law. 20

21

Q. Can the Company withdraw assets from the pension plan other than to pay 22

benefits or plan expenses? 23

A. No, federal law prohibits the Company from withdrawing any assets from the 24

pension other than to pay employee benefits and plan expenses. 25

26

3. Cost of Fairly Compensating Employees 27

Q. Can you expand on your comment that pension contributions should be 28

included in rate base because they are a necessary cost of providing electric 29

service? 30

68 Docket No. E015/GR-16-664


A. Yes. Pension costs – like other employee compensation expenses – are a 1

necessary cost of fairly compensating employees, as described by Company 2

witness Ms. Johnson. Skilled, reliable employees are critical to providing safe, 3

reliable electric service; therefore, the cost of compensating those employees at 4

market-competitive levels, including retirement benefits, is likewise appropriately 5

included in electric service rates. It is a long-standing principle in Minnesota rate 6

regulation that a utility’s reasonable and prudent employee retirement plans are 7

necessary to fairly compensate employees for their work in providing electric 8

service to customers. As such, Minnesota Power customers currently receive the 9

benefit of employee service without fully contributing to the cost of compensating 10

these employees, as the amount of pension expense recovered does not adequately 11

account for the full cost of pensions. 12

13

4. Uncompensated Shareholder Investment that Benefits Customers 14

Q. Why is it relevant that pension contributions are made by the Company 15

rather than by customers? 16

A. Pension contributions are made by the Company, rather than by customers. 17

However, these contributions have benefited customers as the earnings on these 18

funds have significantly reduced the Company’s annual pension expense under 19

ASC 715-30, yet the Company has not earned any return on these funds. The 20

customer benefits by having a lower pension expense, which is included in base 21

electric rates. More specifically, the prepaid pension asset can provide benefits to 22

the customer in at least three ways: 23

24

1. Customers benefit from a reduction in the unfunded balance of the pension 25

obligation because the risk of being required to fund more in future years is 26

also reduced. 27

2. The earnings applied to this balance reduces the current year pension expense 28

through the workings of the EROA on this balance and ASC 715-30. 29

3. Customers benefit from applying the EROA to the accumulated earnings on 30

the prepaid pension asset (the compounding of earnings). 31

69 Docket No. E015/GR-16-664


1

It is a long-standing ratemaking principle that utilities are entitled to and need a 2

reasonable return on investments made for the benefit of customers.35 Here, 3

customers benefit from the federally-mandated contributions made to fund 4

pension benefits available to utility employees. 5

6

Q. Does the prepaid pension asset include any accumulated earnings on the 7

prepaid pension asset? 8

A. No. The prepaid asset is only the excess of the Company’s accumulated 9

contributions over its accumulated expense. Exhibit__ (PLC), Schedule 4 10

illustrates how the prepaid pension balance was created by adding each year’s 11

contributions and subtracting each year’s pension expense since 1987. 12

13

Q. Please explain how applying the EROA reduces 2017 test year pension 14

expense and revenue requirement. 15

A. Minnesota Power’s annual pension expense is determined under ASC 715-30. 16

ASC 715-30 instructs that pension expense be reduced by the expected earnings 17

on the assets in the pension trust. That reduction in pension expense is 18

determined by multiplying the 7.50 percent EROA to the five-year smoothed 19

pension asset balance. The result is then subtracted from the Company’s annual 20

pension cost. This means the earnings that are available to reduce pension 21

expense are greater as a result of the prepaid pension asset. 22

23

Q. Have you determined the expense reduction that results from applying the 24

EROA to the prepaid pension asset? 25

A. Yes. As shown in Exhibit__ (PLC), Schedule 5, the 2017 Minnesota Power 26

prepaid pension asset will reduce the 2017 test year pension expense by 27

$5,479,280 total Minnesota Power ($4,054,115 MN). Note this expense reduction 28

35 See Bluefield Waterworks & Improvement Co. v. Pub. Serv. Comm’n of W. Va., 262 U.S. 679, 692 (1923) (stating that a “public utility is entitled to such rates as will permit it to earn a return on the value of the property which it employs for the convenience of the public.”).

70 Docket No. E015/GR-16-664


example does not reflect the savings that would have been generated in prior 1

years if the EROA had been applied to the accumulated earnings on the prepaid 2

pension asset in those years. 3

4

Q. Can you calculate the added benefit of applying the EROA to the 5

accumulated earnings on the prepaid pension asset? 6

A. Yes. The estimated 2017 test year benefit of applying the EROA on the 7

accumulated earnings on the prepaid balance is shown in Exhibit__ (PLC), 8

Schedule 5. This will reduce 2017 test year pension expense by $7,843,211 total 9

Minnesota Power ($5,803,186 MN). 10

11

Q. Why is including the prepaid pension asset in rate base consistent with 12

standard ratemaking? 13

A. Including the prepaid pension asset in rate base is consistent with standard 14

ratemaking treatment when contributions and expenses differ significantly for an 15

expenditure. These include adjustments in working capital included in rate base 16

for prepaid assets or expenses and deferred tax assets and tax liabilities, both of 17

which investor provided/received funds in excess/under expense are included in 18

rate base. This is further exemplified by the fact many U.S. utilities currently 19

recover, in some manner, contributions to their pensions which include allowing 20

prepaid pension assets in their rate base.36 This includes at least one Minnesota 21

utility that has been allowed to include the prepaid pension asset in its rate base.37 22

23

Q. Is Minnesota Power seeking recovery of actual contributions minus expense? 24

A. Yes, we are seeking recovery of our prepaid asset, which consists of the 25

cumulative contributions minus cumulative expense. This can be seen in 26

36 Oregon Public Utility Commission Pension Survey, Pension Treatment in Rate Making Survey, Summary Report, (Mar. 28, 2013). 37 In the Matter of the Application of N. States Power Co. for Auth. to Increase Rates for Elec. Serv. in the State of Minn., Docket No. E002/GR-13-868, FINDINGS OF FACT, CONCLUSIONS, AND ORDER at 20 (May 8, 2015).

71 Docket No. E015/GR-16-664


Exhibit__ (PLC), Schedule 4 by year since 1987, when the prepaid pension 1

balance materially began. This is consistent with the Commission's May 8, 2015, 2

Findings of Fact, Conclusions, and Order in Docket No. E015/GR-13-868, Xcel 3

Energy's most recent past rate case. 38 4

5

Q. Are there offsets to the Company’s proposal to include the full amount of the 6

Jurisdictional prepaid pension asset in rate base? 7

A. Yes. The full MN Jurisdictional amount in rate base will be reduced by the 8

corresponding accumulated deferred income tax (“ADIT”). Like other prepaid 9

assets where book and tax expense are different, the prepaid pension asset is 10

reduced by the ADIT related to it. The ADIT related to the MN Jurisdictional 11

prepaid asset of $59,707,183 is $31,890,236 MN Jurisdictional. Included in the 12

ADIT is the advanced contribution deduction, which is created when the 13

Company elects to take an advanced tax deduction of contributions made by 14

September 15, 2018, on our 2017 tax return; therefore, the net rate base increase 15

will be $27,816,947 MN. Company witness Ms. Jamie Jago describes the overall 16

ADIT in more detail in her Direct Testimony. 17

18

Q. How is the ADIT created in regards to the prepaid pension asset? 19

A. The Company’s contribution to the pension plan is tax deductible up to the IRS 20

limit. When this contribution exceeds the expense in any given year it creates a 21

deferred tax liability (or deferred tax asset if expense exceeds contributions). 22

Since the plan’s inception, the accumulation of these annual deferred tax 23

liabilities/assets creates the ADIT related to the prepaid pension asset. The ADIT 24

liability is subtracted from the rate base (or, for example, netted with the prepaid) 25

38 While we understand Minnesota Energy Resources Corporation’s (“MERC”) recent request to include the prepaid pension asset in rate base was denied, MERC’s primary position appears to be that the full pension funded status should be included in rate base. Minnesota Power’s proposal is more in line with the Xcel Energy precedent. Further, we understand that Otter Tail Power Company is also seeking to include its prepaid pension asset in rate base. Clearly this is an important issue for Minnesota utilities seeking to recover their costs of providing utility service.

72 Docket No. E015/GR-16-664


because the company receives a tax deduction for the prepaid amount plus the 1

advanced deduction (because the contributions are greater than the expense). 2

Thus, this lowers the taxes we pay compared to our GAAP expense. We therefore 3

need to decrease rate base for this ADIT related to the prepaid pension asset, 4

consistent with how we treat all other ADIT in rate base. 5

6

Q. Have you calculated the net customer benefit resulting from applying the 7

EROA and other expense reductions and revenue requirement from the 8

prepaid pension asset? 9

A. Yes. There is a net benefit to customers for the 2017 test year as summarized in 10

Table 15 below and detailed in Exhibit__ (PLC), Schedule 6. This benefit does 11

not include any of the advanced deduction tax deduction benefit as described 12

previously. 13

14

Table 15. 15

All numbers in table are MN Jurisdictional 16

Customer benefits from prepaid pension asset: $4,054,115

Revenue requirement for financing prepaid pension asset: $3,643,079

Estimated 2017 net benefit prepaid benefit to customer $411,036

17

Q. Why doesn’t recovery of pension expense adequately compensate the 18

Company for its pension investments? 19

A. By recovering only the pension expense, the Company is not recovering all of its 20

pension cost if the prepaid is not included in rate base. This is because the 21

Company is not recovering the cost of its capital that it is mandated to contribute 22

which is in excess of the recovered pension expense. This amount is easily 23

calculated as the weighted average cost of capital multiplied by the Company’s 24

prepaid pension asset, which is the mechanism that would be used if the prepaid 25

asset were to be included in rate base. This cost of capital is the true cost of 26

shareholders funding the pension in excess of what the Company is recovering. 27

28

73 Docket No. E015/GR-16-664


Q. Please summarize the Company’s request with respect to the prepaid pension 1

asset. 2

A. The Company requests the prepaid pension asset of $59,707,183 (MN) be 3

included in the working capital section of rate base and that it be allowed to earn a 4

return on these assets, the same as any other working capital prepayments and 5

other Minnesota and U.S. utilities. 6

7

Because the prepaid pension asset represents contributions in excess of expense, 8

investor capital is required to fund the prepaid pension asset balance and investors 9

are entitled to a return on their capital. Further, the Company is required to fund 10

the pension plan. Customers also benefit from these contributions because 11

earnings on these contributions directly reduce pension expense. Accordingly, it 12

is necessary to include the prepaid pension asset in rate base to fully reimburse the 13

Company for its reasonable costs of service. 14

15

D. Prepaid OPEB Asset 16

Q. What is ALLETE proposing with respect to its prepaid OPEB asset? 17

A. Minnesota Power is providing information regarding its prepaid OPEB asset. We 18

are not asking to include the prepaid asset in rate base at this time, as I explain 19

later in my testimony. 20

21

Q. Are there other naming conventions for Prepaid OPEB Assets? 22

A. Yes. Historically, when a Company contributed more to its OPEB plan than 23

expense, this has been called a “prepaid OPEB expense” or a “prepaid OPEB 24

asset.” More recently this has been called “accumulated contributions in excess 25

of net periodic benefit cost.” Due to the familiarity with the naming, we use the 26

“prepaid OPEB asset” convention. 27

28

Q. Why does the Company have a prepaid OPEB asset? 29

A. The prepaid OPEB asset arises from the fact the Company has contributed more 30

to the OPEB plans than it has expensed since the inception of the plans. 31

74 Docket No. E015/GR-16-664


1

Q. Are the Company’s OPEB plans currently fully funded? 2

A. Yes. 3

4

Q. What is the amount of ALLETE’s prepaid OPEB asset? 5

A. The amount of ALLETE’s estimated 2017 test year end prepaid OPEB asset is 6

$3,326,430 total Minnesota Power ($2,461,223 MN). 7

8

Q. Is there a legal requirement regarding OPEB funding? 9

A. No. 10

11

Q. What is the Company’s OPEB funding policy? 12

A. ALLETE’s OPEB funding policy is to fund, at a minimum, its OPEB expense. 13

As previously noted, the Company has been funding OPEB based on Commission 14

precedent and past Department recommendations. The Company sought to 15

discontinue funding in 2013, but the request was denied at that time. The 16

Company is not making a separate request to end funding of the OPEB at this 17

time. 18

19

Q. What is the benefit of at least funding the expense? 20

A. By funding expense, we are providing an assurance of future payments of these 21

obligations and for 2017 test year, we project the earnings on these funds will 22

reduce our OPEB expense by total Minnesota Power $9.4 million ($7.0 million 23

MN). 24

25

Q. Can the Company withdraw assets from the OPEB plans other than to pay 26

benefits or plan expenses? 27

A. Doing so is technically possible, but ill-advised, because the funds are held in a 28

Voluntary Employees Beneficiary Association (“VEBA”) trust. The Company 29

would pay a federal excise tax of 50 percent in addition to the Company’s 30

75 Docket No. E015/GR-16-664


statutory tax rate on the withdrawn amount. Consequently, we cannot realistically 1

use these funds for any purpose but covering employee benefits. 2

3

Q. If the Company has generally matched OPEB funding to the level of expense, 4

why is there a prepaid OPEB asset? 5

A. Prepaid assets are created when cumulative contributions exceed expense. Due to 6

the Company’s policy of funding OPEB expenses and changes in OPEB benefits 7

as discussed previously and in more detail in Company witness Ms. Johnson’s 8

testimony, the Company’s OPEB expenses have been negative since 2013 and are 9

projected to be negative in the Company’s 2017 test year. If the Company funds 10

expense and expense is negative, the Company would need to withdraw funds 11

from the OPEB or VEBA trust to avoid a prepaid asset39; however, as described 12

above, it would be ill-advised for the Company to withdraw funds due to tax 13

penalties. Consequently, we will continue to have a prepaid OPEB asset. 14

15

Q. Why do other utilities in Minnesota have unfunded accrued benefit liabilities 16

instead of a prepaid asset for their OPEB plans? 17

A. As previously discussed in the early 1990’s, when FAS 106 was adopted, other 18

utilities were required to fund their expenses; however, they later requested and 19

received approval to discontinue funding their VEBAs.40 Therefore, because their 20

contributions were no longer at least equal to their expense, they now have 21

unfunded accrued benefit liabilities for their OPEB plans. 22

23

39 A prepaid asset is created when contributions exceed expense. The math holds true when a prepaid asset is created even when expense is negative. For example, if the contribution is 0 and the expense is negative the prepaid will increase because the contribution is greater than the expense. 40 In the Matter of Xcel’s Petition for Approval to Discontinue Funding of Tax Advantaged External Fund (VEBA Fund) for Retiree Medical Costs and the Withdrawal of the Accumulated VEBA Fund balance over a Five-Year Period, Docket No. E,G002/M-02-2188, ORDER

APPROVING PETITION WITH MODIFICATION AND REQUIRING COMPLIANCE FILING (Oct. 17, 2003).

76 Docket No. E015/GR-16-664


Q. Why isn't the Company asking to include its prepaid OPEB asset in rate 1

base? 2

A. Because there is no legal mandate to fund the OPEB, as there is for the pension, 3

the prepaid OPEB asset should not grow significantly over time or become a 4

liability and will likely shrink. In addition, since the Company has a long-5

standing policy and agreement with the Commission to fund, at a minimum, the 6

Company’s OPEB expense, we will not have an unfunded accrued benefit liability 7

as other utilities have. Therefore, we are not seeking to include the prepaid OPEB 8

assets in rate base, as we have for the prepaid pension asset. 9

10

11

VI. CONCLUSION 12

Q. Does this conclude your Direct Testimony? 13

A. Yes, it does. 14

15

EEI-1 4.70% Willis Towers Watson BOND:Link 6.60% 2.50%

EEI-2 4.35% Willis Towers Watson Other 6.90% 0.00%




EEI-6 4.50% Willis Towers Watson BOND:Link 7.13% -1.00%


EEI-8 Willis Towers Watson BOND:Link

EEI-9 4.00% Fidelity Bond Model 7.50% -2.00%

EEI-10 4.54% Aon Hewitt AA Above Median 8.00% 8.00%


EEI-12 4.40% Willis Towers Watson Rate:Link 7.55% -0.27%



EEI-15 4.70% Aon Hewitt Above Median Bonds 8.20% -0.20%



EEI-18 4.02% Citigroup Discount Curve 6.75% 0.00%

EEI-19 4.18% Aon Hewitt AA Only Bond Universe 7.00% 1.80%

EEI-20 4.60% Other Actuarial 8.00% 8.00%

EEI-21 4.51% Prudential Above Mean 7.65%

EEI-22 Other Bond model 7.75% 1.30%



EEI-25 4.25% Other Actuarial 7.80% 0.00%

EEI-26 4.57% Willis Towers Watson Other 7.00% 6.00%

EEI-27 4.60% Other Bond model 7.50% -1.40%

EEI-28 4.42% Mercer Above Mean Yield Curve 6.75% 6.75%


EEI-30 Other Actuarial 7.63%


EEI-32 4.39% Mercer Above Mean Yield Curve 6.50% 6.50%

EEI-33 4.67% Aon Hewitt AA Above Median 7.75% -1.00%

EEI-34 4.29% Willis Towers Watson Rate:Link 7.00% 0.29%

EEI-35 4.30% Citigroup Pension Discount 8.00% 3.00%

EEI-36 4.37% Willis Towers Watson Rate:Link 6.10% -0.20%

EEI-37 4.35% Aon Hewitt AA Only Bond Universe 7.75% 0.60%


EEI-39 4.76% Mercer Bond Model 7.75% -3.70%


EEI-41 4.50% Other Proprietary 7.00% -4.20%


EEI-43 4.28% Aon Hewitt AA-AAA Bond Universe 5.83% -3.50%





EEI-48 4.57% Mercer Proprietary 5.00% 1.00%

EEI-49 4.59% Aon Hewitt AA Above Median 6.75%



EEI-52 4.49% Other Proprietary 7.00% 7.50%



Average 4.49% 7.10% 1.83%

Quartile 0% (Min) 4.00% 5.00% -4.20%Quartile 25% 4.37% 6.75% -0.34%Quartile 50% (Median) 4.50% 7.05% 0.00%Quartile 75% 4.60% 7.75% 6.25%Quartile 100% (Max) 4.95% 8.25% 8.30%

# Responses 51 54 54 52 51

2014 Median 4.11% 7.25% 7.50%2013 Median 4.94% 7.25% 9.88%2012 Median 4.10% 7.50% 12.30%2011 Median 4.82% 7.75% 3.50%2010 Median 5.40% 7.88% 8.75%2009 Median 5.75% 8.44% 17.00%

For more information, please contact:Bill Pfister Richard McMahonManager, Financial Analysis Vice President, Finance and Energy Supply202.508.5531 [email protected] [email protected] Page 1 of 2

EEI Pension and OPEB Survey 2015-16

CompanyExpected

Discount RateYield Curve / Model (Firm) Yield Curve / Model (Specific)

Long-Run Expected

ReturnExpected Return, 2015

mailto:[email protected]

mailto:[email protected]

pcutshall

Oval

pcutshall

Text Box

MP Exhibit__________(PLC) Direct Schedule 1 Docket No. E015/GR-16-664 Page 1 of 6

EEI-1

EEI-2

EEI-3

EEI-4

EEI-5

EEI-6

EEI-7

EEI-8

EEI-9

EEI-10

EEI-11

EEI-12

EEI-13

EEI-14

EEI-15

EEI-16

EEI-17

EEI-18

EEI-19

EEI-20

EEI-21

EEI-22

EEI-23

EEI-24

EEI-25

EEI-26

EEI-27

EEI-28

EEI-29

EEI-30

EEI-31

EEI-32

EEI-33

EEI-34

EEI-35

EEI-36

EEI-37

EEI-38

EEI-39

EEI-40

EEI-41

EEI-42

EEI-43

EEI-44

EEI-45

EEI-46

EEI-47

EEI-48

EEI-49

EEI-50

EEI-51

EEI-52

EEI-53

EEI-54

Average

Quartile 0% (Min)Quartile 25%Quartile 50% (Median)Quartile 75%Quartile 100% (Max)

# Responses

2014 Median2013 Median2012 Median2011 Median2010 Median2009 Median

Company

Equ

itie

s: P

ub

lic

Fixe

d In

com

e:

Gro

wth

Ass

ets

Equ

itie

s: P

riva

te

Fixe

d In

com

e:

Liab

ility

Dri

ven

Inve

stm

ents

Rea

l Ass

ets:

Pu

blic

(co

mm

od

itie

s,

REI

TS, e

tc.)

Rea

l Ass

ets:

Pri

vate

Glo

bal

Ass

et

Allo

cati

on

Ris

k P

arit

y

Alt

ern

ativ

es

(hed

ge f

un

ds,

etc

.)

Oth

er

Funded

Status

(PPA)

Funded

Status

(GAAP)

Unfunded

Liab / Mkt.

Cap.

Initial

Rate

Ultimate

Rate

Year

Reached

21% 5% 65% 4% 5% 90% 86% 3% 7.00% 5.00% 2020

22% 1% 60% 6% 11% 103% 91% 7.00% 5.00% 2020

19% 58% 6% 8% 9% 124% 90% 3% 6.00% 5.00% 2020

25% 3% 5% 60% 7% 100% 97% 1% 7.00% 5.00% 2024

60% 40% 100% 80% 10% 7.00% 5.00% 2020

56% 40% 4% 108% 89% 5% 5.00% 5.00% 2015

65% 30% 5% 108% 101% 7.70% 5.00% 2025

40% 60% 100% 88% 2% 6.10% 5.00% 2037

70% 15% 15% 93% 2% 6.00% 4.75% 2025

51% 40% 6% 4% 102% 69% 6.75% 4.50% 2025

48% 33% 20% 107% 75% 5% 7.00% 5.00% 2020

60% 35% 5% 101% 86% 2% 8.00% 5.00% 2018

58% 35% 5% 2% 103% 81% 5% 8.25% 4.50% 2022

51% 0% 9% 23% 3% 11% 0% 0% 0% 3% 136% 94% 3% 6.50% 4.50% 2024

62% 5% 33% 100% 73% 6% 7.50% 5.00% 2021

40% 60% 108% 79% 6% 7.25% 5.00% 2025

5.50% 5.50% 2017

50% 36% 10% 4% 107% 77% 5% 7.25% 5.00% 2015

49% 8% 38% 5% 76% 80% 5%

63% 30% 7% 115% 85% 7.00% 4.75% 2025

65% 25% 10% 90% 89% 2085

45% 25% 9% 21% 80% 80% 7% 6.50% 4.50% 2027

50% 10% 20% 10% 10% 102% 77% 4% 7.25% 5.00% 2023

57% 33% 1% 9% 102% 76% 19% 6.00% 4.50% 2024

85% 80% 6.70% 4.90% 2020

54% 26% 2% 6% 6% 6% 112% 67% 8% 9.70% 4.80% 2099

60% 40% 114% 90% 3% 7.05% 4.50% 2038

27% 68% 5% 104% 85% 5% 6.67% 5.00% 2020

46% 18% 4% 32% 77% 12% 7.25% 5.00% 2022

25% 13% 3% 48% 3% 7% 2% 125% 88% 2% 6.80% 5.00% 2020

28% 7% 65% 113% 84% 6% 6.85% 4.50% 2036

65% 32% 3% 93% 67% 15% 6.50% 4.75% 2024

35% 34% 31% 102% 82% 12% 5.50% 5.00% 2017

46% 37% 10% 7% 100% 63% 11% 8.00% 4.00% 2019

35% 3% 57% 5% 10% -10% 128% 87% 8% 7.20% 4.00% 2024

45% 16% 5% 26% 5% 3% 172% 147% 6.50% 4.50% 2024

40% 30% 12% 3% 7% 8% 109% 79% 6% 6.50% 4.50% 2023

57% 36% 3% 4% 120% 77% 7% 6.47% 5.00%

17% 17% 62% 5% 87% 79% 3%

39% 21% 10% 5% 15% 10% 0% 0% 0% 0% 54% 8.00% 5.00% 2019

39% 24% 4% 17% 10% 7% 79% 70% 6%

29% 7% 61% 3% 105% 74% 6.00% 5.00% 2024

28% 3% 63% 3% 1% 2% 126% 105% 7.50% 4.75% 2023

35% 9% 25% 11% 15% 5% 91% 61% 25% 6.00% 4.50% 2025

58% 33% 9% 117% 92% 1% 7.00% 5.00% 2021

25% 14% 43% 6% 8% 4% 100% 80% 0% 6.80% 5.00% 2020

65% 35% 130% 6.10% 4.50% 2037

26% 4% 57% 4% 7% 2% 117% 81% 3% 7.00%

70% 30% 107% 67% 8.00% 5.00% 2028

39% 13% 5% 27% 2% 6% 7% 108% 81% 4% 6.00% 4.50% 2019

50% 40% 5% 5% 113% 81% 4% 7.00% 4.50% 2026

20% 80% 108% 75% 6.00% 5.00% 2024

50% 48% 3% 124% 102% 6.75% 5.00% 2021

45% 23% 6% 40% 5% 6% 6% 3% 8% 2% 107% 83% 6% 6.84% 4.81% 2026

17% 0% 1% 3% 2% 1% 0% 0% 0% -10% 76% 54% 0% 5.00% 4.00% 201532% 11% 3% 31% 3% 5% 0% 0% 5% 2% 100% 76% 3% 6.47% 4.50% 202046% 23% 5% 39% 5% 6% 8% 2% 7% 3% 106% 81% 5% 6.85% 5.00% 202358% 32% 9% 58% 6% 7% 10% 5% 10% 5% 113% 89% 7% 7.25% 5.00% 202570% 80% 17% 65% 15% 11% 10% 10% 31% 9% 172% 147% 25% 9.70% 5.50% 2099

51 30 18 38 13 18 5 4 29 11 48 52 38 49 48 48

103% 84% 6% 7.00% 5.00% 2023100% 90% 1% 7.33% 5.00% 2020

96% 78%

Page 1 of 2

EEI Pension and OPEB Survey 2015-16

It is not possible to compare to previous results as the categories have changed.

Funded Status Health Care Trend RateAsset Allocation

pcutshall

Oval

pcutshall

Oval

pcutshall

Text Box


2015 Distribution: Expected Discount Rate

Company

Expected

Discount

Rate

EEI-1 4.70% Bin Range Frequency

EEI-2 4.35% <= 3.85% 0

EEI-3 4.62% 3.86 - 4.10% 2

EEI-4 4.30% 4.11 - 4.35% 10

EEI-5 4.95% 4.36 - 4.60% 27

EEI-6 4.50% 4.61 - 4.85% 11

EEI-7 4.50% > 4.85% 1

EEI-8

EEI-9 4.00%

EEI-10 4.54%

EEI-11 4.55%

EEI-12 4.40%

EEI-13 4.35%

EEI-14 4.22%

EEI-15 4.70%

EEI-16 4.36%

EEI-17 4.40%

EEI-18 4.02%

EEI-19 4.18%

EEI-20 4.60%

EEI-21 4.51%

EEI-22

EEI-23 4.50%

EEI-24 4.50%

EEI-25 4.25%

EEI-26 4.57%

EEI-27 4.60%

EEI-28 4.42%

EEI-29 4.65%

EEI-30

EEI-31 4.60%

EEI-32 4.39%

EEI-33 4.67%

EEI-34 4.29%

EEI-35 4.30%

EEI-36 4.37%

EEI-37 4.35%

EEI-38 4.60%

EEI-39 4.76%

EEI-40 4.62%

EEI-41 4.50%

EEI-42 4.61%

EEI-43 4.28%

EEI-44 4.40%

EEI-45 4.50%

EEI-46 4.68%

EEI-47 4.65%

EEI-48 4.57%

EEI-49 4.59%

EEI-50 4.60%

EEI-51 4.66%

EEI-52 4.49%

EEI-53 4.57%

EEI-54 4.45%

Average 4.49%

Quartile 0% (Min) 4.00%

Quartile 25% 4.37%

Quartile 50% (Median) 4.50%

Quartile 75% 4.60%

Quartile 100% (Max) 4.95%

# Responses 51

2014 Median 4.11%

2013 Median 4.94%

2012 Median 4.10%

2011 Median 4.82%

2010 Median 5.40%

2009 Median 5.75%

0

5

10

15

20

25

30

<= 3.85% 3.86 - 4.10% 4.11 - 4.35% 4.36 - 4.60% 4.61 - 4.85% > 4.85%

Fre

qu

en

cy

2015 Distribution: Expected Discount Rate

pcutshall

Text Box


2015 Distribution: Long-Run Expected Return Rate

Company

Long-Run

Expected

Return


EEI-2 6.90% <= 5.50% 2

EEI-3 5.30% 5.51 - 6.00% 3

EEI-4 6.00% 6.01 - 6.50% 6

EEI-5 8.00% 6.51 - 7.00% 15

EEI-6 7.13% 7.01 - 7.50% 9

EEI-7 7.00% 7.51 - 8.00% 15

EEI-8 > 8.00% 2

EEI-9 7.50%

EEI-10 8.00%

EEI-11 7.10%

EEI-12 7.55%

EEI-13 7.50%

EEI-14 8.00%

EEI-15 8.20%

EEI-16 7.50%

EEI-17 6.25%

EEI-18 6.75%

EEI-19 7.00%

EEI-20 8.00%

EEI-21 7.65%

EEI-22 7.75%

EEI-23 7.75%

EEI-24 7.60%

EEI-25 7.80%

EEI-26 7.00%

EEI-27 7.50%

EEI-28 6.75%

EEI-29 6.75%

EEI-30

EEI-31 7.00%

EEI-32 6.50%

EEI-33 7.75%

EEI-34 7.00%

EEI-35 8.00%

EEI-36 6.10%

EEI-37 7.75%

EEI-38 8.25%

EEI-39 7.75%

EEI-40 6.22%

EEI-41 7.00%

EEI-42 6.50%

EEI-43 5.83%

EEI-44 6.50%

EEI-45 7.50%

EEI-46 7.50%

EEI-47 7.00%

EEI-48 5.00%

EEI-49 6.75%

EEI-50 7.75%

EEI-51 6.87%

EEI-52 7.00%

EEI-53 5.64%

EEI-54 7.13%

Average 7.10%

Quartile 0% (Min) 5.00%

Quartile 25% 6.75%


Quartile 75% 7.75%


# Responses 52

2014 Median 7.25%

2013 Median 7.25%

2012 Median 7.50%

2011 Median 7.75%

2010 Median 7.88%

2009 Median 8.44%

0

2

4

6

8

10

12

14

16

<= 5.50% 5.51 - 6.00% 6.01 - 6.50% 6.51 - 7.00% 7.01 - 7.50% 7.51 - 8.00% > 8.00%

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2015 Distribution: Long-Run Expected Return Rate

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2015 Distribution: Expected Return Rate for 2015

Company

Expected

Return,

2015


EEI-2 0.00% <= -4.00% 1

EEI-3 5.30% -3.99 - -3.00% 3

EEI-4 6.00% -2.99 - -2.00% 4

EEI-5 2.00% -1.99 - -1.00% 4

EEI-6 -1.00% -0.99 - 0.00% 14

EEI-7 0.00% 0.01 - 1.00% 4

EEI-8 1.01 - 2.00% 3

EEI-9 -2.00% 2.01 - 3.00% 2

EEI-10 8.00% 3.01 - 4.00% 0

EEI-11 0.00% 4.01 - 5.00% 0

EEI-12 -0.27% 5.01 - 6.00% 3

EEI-13 0.00% 6.01 - 7.00% 6

EEI-14 8.30% 7.01 - 8.00% 6

EEI-15 -0.20% 8.01 - 9.00% 1

EEI-16 6.78% > 9.00% 0

EEI-17 6.50%

EEI-18 0.00%

EEI-19 1.80%

EEI-20 8.00%

EEI-21

EEI-22 1.30%

EEI-23 0.00%

EEI-24 -2.50%

EEI-25 0.00%

EEI-26 6.00%

EEI-27 -1.40%

EEI-28 6.75%

EEI-29 6.50%

EEI-30 7.63%

EEI-31 0.00%

EEI-32 6.50%

EEI-33 -1.00%

EEI-34 0.29%

EEI-35 3.00%

EEI-36 -0.20%

EEI-37 0.60%

EEI-38 0.50%

EEI-39 -3.70%

EEI-40 -2.90%

EEI-41 -4.20%

EEI-42 6.50%

EEI-43 -3.50%

EEI-44 -0.40%

EEI-45 -2.80%

EEI-46 0.00%

EEI-47 0.00%

EEI-48 1.00%

EEI-49

EEI-50 7.75%

EEI-51 7.09%

EEI-52 7.50%

EEI-53 -3.10%

EEI-54 -1.85%

Average 1.83%

Quartile 0% (Min) -4.20%

Quartile 25% -0.34%


Quartile 75% 6.25%


# Responses 51

2014 Median 7.50%

2013 Median 9.88%

2012 Median 12.30%

2011 Median 3.50%

2010 Median 8.75%

2009 Median 17.00%

0

2

4

6

8

10

12

14

16

<= -4.00%

-3.99 - -3.00%

-2.99 - -2.00%

-1.99 - -1.00%

-0.99 -0.00%

0.01 -1.00%

1.01 -2.00%

2.01 -3.00%

3.01 -4.00%

4.01 -5.00%

5.01 -6.00%

6.01 -7.00%

7.01 -8.00%

8.01 -9.00%

> 9.00%

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26 Willis Towers Watson

21 BOND:Link

3 RATE:Link

2 (other)

13 Aon Hewitt

9 AA Above Median

2 AA Only Bond Universe

1 AA-AAA Bond Universe

1 (other)

4 Mercer

1 Bond Model

3 (other)

2 CitiGroup

9 (other)

Total 54

Yield Curve / Model (2015 Survey)

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capital structure, cost of capital, and retirement …€¦ · 17 table 1 18 recommended 2017 test...

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