Clark Hill PLC 151 S. Old Woodward Suite 200 Birmingham

216161833.1 07411/315138

Clark Hill PLC

151 S. Old Woodward

Suite 200

Birmingham, MI 48009

Robert A. W. Strong T 248.642.9692

T 248.988.5861 F 248.642.2174

F 248.988.2323

Email: [email protected] clarkhill.com

August 29, 2017

VIA ELECTRONIC CASE FILING

Ms. Kavita KaleExecutive SecretaryMichigan Public Service Commission7109 West Saginaw HighwayLansing, Michigan 48917

Re: MPSC Case No. U-18255: In the matter of the application of DTE ElectricCompany for authority to increase its rates, amend its rate schedule and rulesgoverning the distribution and supply of electric energy, and for miscellaneousaccounting authority.

Dear Ms. Kale:

Enclosed for filing are the Direct Testimony and Exhibits of Christopher C. Walters andthe Direct Testimony and Exhibits of James R. Dauphinais on behalf of ABATE, along with aProof of Service in the case referenced above.

Very truly yours,

CLARK HILL PLC

Robert A. W. Strong

RAWS/lllm

cc w/enc.: Parties of RecordALJ Mark D. Eyster

216161833.1 07411/315138

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

In the matter of the Application ofDTE ELECTRIC COMPANYfor authority to increase its rates, amendits rate schedules and rules governing thedistribution and supply of electric energy, andfor miscellaneous accounting authority.

))))))

Case No. U-18255

Hon. Mark D. Eyster

PROOF OF SERVICE

STATE OF MICHIGAN )) ss

COUNTY OF OAKLAND )

Robert A. W. Strong, being first duly sworn, deposes and says that on August 29, 2017,

he did cause to be served the Direct Testimony and Exhibits of Christopher C. Walters and the

Direct Testimony and Exhibits of James R. Dauphinais on behalf of ABATE, as well as this

Proof of Service, in the above docket, via electronic mail, to the persons identified on the

attached service list.

____________________________________Robert A. W. Strong

Subscribed and sworn to before methis 29th day of August 2017.

______________________________________Linda L. McCauley, Notary PublicOakland County, MichiganMy Commission Expires: October 18, 2019Acting in Oakland County

2216161833.1 07411/315138

SERVICE LISTMPSC Case No. U-18255

Administrative Law JudgeMark D. EysterEmail: [email protected]

Counsel for MPSC StaffBryan A. BrandenburgLauren D. DonofrioHeather M. S. DurianLori Mayabb, Staff AssistantEmail: [email protected]

[email protected]@[email protected]

Counsel for DTE Electric CompanyJon P. ChristinidisAndrea E. HaydenRichard P. MiddletonDavid S. MaqueraMichael J. SoloEmail: [email protected]

[email protected]@[email protected]@[email protected]

Counsel for Attorney GeneralBill SchuetteMichael MoodyEmail: [email protected]

[email protected]

Counsel for the Kroger CompanyKurt J. BoehmJody Kyler CohnBoehm, Kurtz & LowryEmail: [email protected]

[email protected]

Counsel for Environmental Law & PolicyCenterMargrethe K. KearneyBradley KleinKristen Field, Legal AssistantEnvironmental Law & Policy CenterEmail: [email protected]

[email protected]@elpc.org

Counsel for Constellation NewEnergy Inc.Jennifer Utter HestonFraser, Trebilcock, Davis & Dunlap, PCEmail: [email protected]

Counsel for Wal-Mart Stores East, LP,and Sam’s East, Inc.Melissa M. HorneHiggins, Cavanagh & Cooney, LLPEmail: [email protected]

Counsel for Michigan Environmental Council(MEC) and Natural Resources DefenseCouncil (NRDC) and The Sierra ClubChristopher M. BzdokTracy Jane AndrewsKarla GerdsKimberly FlynnOlsen, Bzdok & HowardEmail: [email protected]


Legal Assistant for The Sierra ClubFlora ChampenoisGabrielle WinickEarthjustice, Washington D.C.Email: [email protected]

[email protected]

mailto:[email protected]


























3216161833.1 07411/315138

Counsel for Michigan CableTelecommunications AssociationDavid E. S. MarvinMichael S. AshtonFraser Trebilcock Davis & DunlapEmail: [email protected]

[email protected]

Counsel for Detroit Public SchoolsMichael G. OlivaLeah J. BrooksLoomis, Ewart, Parsley, Davis & Gotting P.C.Email: [email protected]

[email protected]

Counsel for Residential Customer GroupDon L. KeskeyBrian W. CoyerPublic Law Resource Center PLLCEmail:

[email protected]@publiclawresourcecenter.com

Counsel for Michigan Waste Energy, Inc.d/b/a Detroit Renewable Power andDetroit Thermal, LLC:Arthur LeVasseurFischer, Franklin & FordEmail: [email protected]

Counsel for Midwest CogenerationAssociationJohn R. LiskeyPatricia F. SharkeyJohn R. Liskey Attorney at Law PLLCEmail: [email protected]

[email protected]

Counsel for Local 223, Utility WorkersUnion of America (UWUA), AFL-CIOJohn R. CanzanoPatrick R. RoraiMcKnight, Canzano, Smith Radtke &Brault, P.C.Email: [email protected]

[email protected]

Counsel for ABATE:Michael J. PattwellRobert A. W. StrongSean P. GallagherStephen A. CampbellClark Hill PLCEmail: [email protected]


Counsel for Energy Michigan, Inc.Timothy J. LundgrenLaura ChappelleToni L. NewellVarnum Law FirmEmail: [email protected]

[email protected]@vernumlaw.com

Consultants for ABATE:James R. DauphinaisChris WaltersMaria Decker, Admin. AssistantBrubaker & Associates, Inc.MAILING: P.O. Box 412000

St. Louis, MO 53141-2000Email: [email protected]

[email protected]@consultbai.com










































































STATE OF MICHIGAN


In the matter of the Application of DTE ELECTRIC COMPANY for authority to increase its rates, amend its rate schedules and rules governing the distribution and supply of electric energy, and for miscellaneous accounting authority.

))))))))))

Case No. U-18255

Direct Testimony and Exhibits of

Christopher C. Walters

On behalf of

Association of Businesses Advocating Tariff Equity

August 29, 2017

Project 10427

Christopher C. Walters Table of Contents

BRUBAKER & ASSOCIATES, INC.

STATE OF MICHIGAN



))))))))))

Case No. U-18255

Table of Contents for the Direct Testimony of Christopher C. Walters

Page

I. SUMMARY ........................................................................................................................... 2

II. RATE OF RETURN .............................................................................................................. 3 II.A. Electric Industry Authorized Returns on Equity, .......................................................... 4 II.B. Regulated Utility Industry Market Outlook ................................................................. 11 II.C. DTE Investment Risk ................................................................................................. 15

III. DTE’S PROPOSED CAPITAL STRUCTURE .................................................................... 16 III.A. Embedded Cost of Debt ........................................................................................... 17

IV. RETURN ON EQUITY ....................................................................................................... 18 IV.A. Risk Proxy Group ..................................................................................................... 19 IV.B. Discounted Cash Flow Model ................................................................................... 20 IV.C. Sustainable Growth DCF ......................................................................................... 25 IV.D. Multi-Stage Growth DCF Model ............................................................................... 26 IV.E. Risk Premium Model ................................................................................................ 34 IV.F. Capital Asset Pricing Model (“CAPM”) ..................................................................... 40 IV.G. Return on Equity Summary ...................................................................................... 45 IV.H. Financial Integrity ..................................................................................................... 46

V. RESPONSE TO DTE WITNESS DR. MICHAEL VILBERT ............................................... 50 V.A. Summary of Rebuttal ................................................................................................. 50 V.B. ATWACC ................................................................................................................... 53 V.C. Dr. Vilbert’s CAPM Analysis ...................................................................................... 57 V.D. Dr. Vilbert’s Risk Premium Analyses ......................................................................... 63 V.E. Dr. Vilbert’s DCF Analyses ........................................................................................ 65

Qualifications of Christopher C. Walters ....................................................................... Appendix A

Exhibit AB-1 through Exhibit AB-19

Christopher C. Walters Page 1


STATE OF MICHIGAN



))))))))))

Case No. U-18255

Direct Testimony of Christopher C. Walters

Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 1

A Christopher C. Walters. My business address is 16690 Swingley Ridge Road, 2

Suite 140, Chesterfield, MO 63017. 3

Q WHAT IS YOUR OCCUPATION? 4

A I am a consultant in the field of public utility regulation with the firm of Brubaker & 5

Associates, Inc. (“BAI”), energy, economic and regulatory consultants. 6

Q PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE. 7

A This information is included in Appendix A to my testimony. 8

Q ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING? 9

A I am appearing on behalf of Association of Businesses Advocating Tariff Equity 10

(“ABATE”). ABATE’s members are customers of DTE Electric Company (“DTE” or 11

“Company”). 12



Q WHAT IS THE SUBJECT MATTER OF YOUR TESTIMONY? 1

A My testimony will address the current market cost of equity, and resulting overall rate 2

of return, for DTE. In my analyses, I consider the results of several market models 3

and the current economic environment and outlook for the electric utility industry as 4

well as the financial integrity of DTE given my recommended return on equity, capital 5

structure, and overall rate of return. 6

My silence in regard to any issue should not be construed as an endorsement 7

of DTE’s position. 8

I. SUMMARY 9

Q PLEASE SUMMARIZE YOUR RECOMMENDATIONS AND CONCLUSIONS ON 10

RATE OF RETURN. 11

A I recommend the Michigan Public Service Commission (the “Commission”) award a 12

return on common equity of 9.35%, which is the midpoint of my recommended range 13

of 9.10% to 9.60%. My recommended return on equity will fairly compensate DTE for 14

its current market cost of common equity, and it will mitigate the claimed revenue 15

deficiency in this proceeding by fairly balancing the interests of all stakeholders. 16

The overall rate of return produced by my recommended return on common 17

equity, and DTE’s ratemaking capital structure for DTE produces an overall rate of 18

return of 5.14%, as shown on my Exhibit AB-1. 19

Finally, I will show that DTE witness Dr. Vilbert’s recommended range of 20

975% to 10.75%, as well as the Company’s requested return on equity of 10.50% are 21

excessive and unreasonable. 22



II. RATE OF RETURN 1

Q PLEASE DESCRIBE THIS SECTION OF YOUR TESTIMONY. 2

A In this section of my testimony, I will explain the analysis I performed to determine the 3

reasonable rate of return in this proceeding and present the results of my analysis. I 4

begin my estimate of a fair return on equity by reviewing the authorized returns 5

approved by the regulatory commissions in various jurisdictions, the market 6

assessment of the regulated utility industry investment risk, credit standing, and stock 7

price performance. I used this information to get a sense of the market’s perception 8

of the risk characteristics of regulated electric utility investments in general, which is 9

then used to produce a refined estimate of the market’s return requirement for 10

assuming investment risk similar to DTE’s utility operations. 11

As described below, I find the credit rating outlook of the industry to be strong 12

and supportive of the industry’s financial integrity and access to capital. Further, 13

regulated utilities’ stocks have exhibited strong price performance over the last 14

several years, which is evidence of utility access to capital. 15

Based on this review of credit outlooks and stock price performance, I 16

conclude that the market continues to embrace the regulated utility industry as a 17

safe-haven investment and views utility equity and debt investments as low-risk 18

securities. 19



II.A. Electric Industry Authorized Returns on Equity, 1 Access to Capital, and Credit Strength 2 Q PLEASE DESCRIBE THE OBSERVABLE EVIDENCE ON TRENDS IN 3

AUTHORIZED RETURNS ON EQUITY FOR ELECTRIC AND GAS UTILITIES, 4

UTILITIES’ CREDIT STANDING, AND UTILITIES’ ACCESS TO CAPITAL TO FUND 5

INFRASTRUCTURE INVESTMENT. 6

A Authorized returns on equity for both electric and gas utilities have been steadily 7

declining over the last 10 years, as illustrated in Figure 1 below. More recent 8

authorized returns on equity for electric utilities have declined down to about 9.60%, 9

and local gas delivery utilities’ returns on equity have declined to 9.50%. Further, 10

authorized returns for local gas delivery utilities have consistently trended at or below 11

the returns authorized for electric utilities. 12

__________Source and Note: S&P Global Market Intelligenc e, RRA Regulatory Focus, Major Rate Case Decisions -- January - June 2017,

July 26, 2017 at pages 5 and 6.

FIGURE 1

10.34% 10.31% 10.37%10.52%

10.29%10.19%

10.01%

9.81% 9.75%9.60% 9.60% 9.61%

10.40%

10.22%

10.39%

10.22%10.15%

9.92% 9.94%

9.68%9.78%

9.60%9.50% 9.50%

8.50%

9.00%

9.50%

10.00%

10.50%

11.00%

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Authorized Returns on Equity(Excludes Limited Issue Riders)

Electric Gas



While the declines in authorized returns on equity are public knowledge, and 1

align with declining capital market costs, utilities are maintaining stable investment 2

grade credit standing, and have been able to attract large amounts of capital at low 3

costs to fund very large capital programs. 4

Q PLEASE DESCRIBE THE TREND IN CREDIT RATING CHANGES IN THE 5

ELECTRIC UTILITY INDUSTRY OVER THE LAST FIVE YEARS. 6

A As shown in Figure 2 below, over the period 2010-2016, the electric utility industry 7

has experienced a significant number of upgrades in credit ratings by all of the major 8

credit rating agencies (Fitch Ratings, Moody’s, and Standard & Poor’s). 9

2010 2011 2012 2013 2014 2015 2016 2017 Q1Upgrades 29 39 37 60 103 35 49 13Downgrades 51 21 39 20 3 15 18 5% Upgrades 36.3% 65.0% 48.7% 75.0% 97.2% 70.0% 73.1% 72.2%Total Rating Activity 80 60 76 80 106 50 67 18

Source: EEI 2017 Q1 Credit Ratings. Tab IV. Direction of Rating Action.

FIGURE 2

Credit Rating Changes(U.S. Investor-Owned Electric Utility Industry)

36.3%

65.0%

48.7%

75.0%

97.2%

70.0%73.1% 72.2%

80

60

76

80

106

50

67

18

0

20

40

60

80

100

120

0%

25%

50%

75%

100%

2010 2011 2012 2013 2014 2015 2016 2017 Q1

% Upgrades Total Rating Activity



As noted above in Figure 2, the upgrades in utility credit ratings started 1

outpacing downgrades in 2011, and more recently, the number of upgrades has 2

substantially exceeded the number of downgrades. For example, in 2014, there were 3

103 upgrades and only three downgrades. In 2015, the number of upgrades was 4

more than twice the number of downgrades (35 upgrades and 15 downgrades). This 5

trend was even more profound in 2016 and continued with data available for early 6

2017. 7

Q HOW DID THIS CREDIT RATING ACTIVITY IMPACT THE CREDIT RATING OF 8

THE ELECTRIC UTILITY INDUSTRY? 9

A The credit rating changes for the electric utility industry reflected a significant 10

strengthening of the electric utility industry credit rating as shown below in Table 1. 11

As shown in this table, in 2008, approximately 69% of the electric utility industry was 12

rated from BBB- to BBB+, 18% had a bond rating better than BBB+, and around 13% 13

of the industry was below investment grade. This industry rating improved steadily 14

over the subsequent eight years. By 2017, only about 3% of the industry is below 15

investment grade, around 62% continue to be in the range of BBB- to BBB+, and 16

approximately 67% of the industry has a bond rating at or above BBB+. Overall, the 17

improvement to the credit rating of the electric utility industry has been very 18

significant. 19



Q HAVE CREDIT RATING AGENCIES COMMENTED ON DECLINING AUTHORIZED 1

RETURNS ON EQUITY? 2

A Yes. Credit rating agencies recognize the declining trend in authorized returns and 3

the expectation that regulators will continue lowering the returns for U.S. utilities while 4

maintaining a stable credit profile. Specifically, Moody’s states: 5

Lower Authorized Equity Returns Will Not Hurt Near-Term Credit 6 Profiles 7 The credit profiles of US regulated utilities will remain intact over the 8 next few years despite our expectation that regulators will continue to 9 trim the sector’s profitability by lowering its authorized returns on equity 10 (ROE).1 11

Further, in a recent report, Standard & Poor’s (“S&P”) states: 12

2. Earned returns will remain in line with authorized returns 13 Authorized returns on equity granted by U.S. utility regulators in rate 14 cases this year have been steady at about 9.5%. Utilities have been 15 adept at earning at or very near those authorized returns in today’s 16 economic and fiscal environment. A slowly recovering economy, 17 natural gas and electric prices coming down and then stabilizing at 18

1Moody’s Investors Service, “US Regulated Utilities: Lower Authorized Equity Returns Will

Not Hurt Near-Term Credit Profiles,” March 10, 2015.

Description 2008 2009 2010 2011 2012 2013 2014 2015 2016

Regulated

A or higher 8% 7% 9% 8% 6% 3% 3% 3% 6% 6%

A‐ 10% 15% 14% 14% 17% 20% 21% 22% 28% 31%

BBB+ 23% 22% 17% 19% 14% 17% 32% 33% 36% 31%

BBB 23% 27% 31% 35% 36% 49% 37% 33% 22% 20%

BBB‐ 23% 20% 17% 14% 17% 6% 3% 3% 8% 11%

Below BBB‐ 13% 10% 11% 11% 11% 6% 5% 6% 0% 0%

Total 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

Source: EEI 2017 Q1 Credit Ratings. Tab V. S&P Rating by Comp. Category.

2017 Q1

TABLE 1

S&P Ratings by Category(Year End)



fairly low levels, and the same experience with interest rates have led 1 to a perfect “non-storm” for utility ratepayers and regulators, with 2 utilities benefitting alongside those important constituencies. Utilities 3 have largely used this protracted period of favorable circumstances to 4 consolidate and institutionalize the regulatory practices that support 5 earnings and cash flow stability. We have observed and we project 6 continued use of credit-supportive policies such as short lags between 7 rate filings and final decisions, up-to-date test years, flexible and 8 dynamic tariff clauses for major expense items, and alternative 9 ratemaking approaches that allow faster rate recognition for some new 10 investments.2 11

Q HAVE UTILITIES BEEN ABLE TO ACCESS EXTERNAL CAPITAL TO SUPPORT 12

INFRASTRUCTURE CAPITAL PROGRAMS? 13

A Yes. While cost of capital and authorized returns on equity were declining, the utility 14

industry has been able to fund substantial increases in capital investments needed for 15

infrastructure modernization and expansion. The Edison Electric Institute (“EEI”) 16

reported in a 2015 financial review of the electric industry financial performance that 17

electric “industry-wide capex has more than doubled since 2005.”3 18

EEI also observed that, despite this significant increase in capital expenditures 19

during the period 2005-2015, a majority of the funding for utilities’ capital 20

expenditures has been provided by internal funds. EEI reports that approximately 21

25% of funding needed to meet these increasing capital expenditures has been 22

derived from external sources and 75% of these capital expenditures have been 23

funded by internal cash. Further, despite nearly tripling capital expenditures and 24

increases in the amount of outstanding debt, the electric utility industry’s debt interest 25

expense has declined by approximately 1.9%.4 This fact is clear evidence that 26

2Standard & Poor’s Ratings Services: “Corporate Industry Credit Research: Industry Top

Trends 2016, Utilities,” December 9, 2015, at 23, emphasis added. 3Edison Electric Institute, 2015 Financial Review, Annual Report of the U.S. Investor-Owned

Electric Utility Industry, page 17. 4Id., pages 8 and 11.



utilities have enjoyed access to large amounts of capital, since it shows utilities are 1

paying less over time to borrow because the costs of capital have declined. 2

Similarly, in its March 21, 2017 Capital Expenditure Update report, RRA 3

Financial Focus, a division of S&P Global Market Intelligence, made several relevant 4

comments about utility investments generally: 5

Capital expenditures throughout the U.S. power and gas sectors in 6 2017 are projected to reach an all-time high of $117.5 billion. The 7 nation's largest electric and gas utilities are investing in infrastructure 8 to comply with sweeping environmental regulations, implement new 9 technologies, build new natural gas, solar and wind generation and 10 upgrade aging transmission and distribution systems. Moreover, their 11 near-term capital spending forecasts continue to escalate — see below 12 for individual examples. Total CapEx in 2016 for the companies in the 13 RRA utility universe was $110.3 billion. We expect considerable levels 14 of spending to serve as the basis for solid profit expansion for the 15 foreseeable future, although our data indicates that CapEx in the 16 industry may fall modestly in 2018 and 2019.517

Indeed, historical versus projected outlooks for the electric and gas industries’ capital 18

investments are shown in Figure 3 below. As shown in this graph, electric industry 19

investment outlooks are expected to be considerably higher relative to the last 20

10-year historical period. As noted by S&P Global Market Intelligence, this capital 21

investment is exceeding internal sources of funds to the electric utilities, requiring 22

them to seek external capital to fund capital investments. 23

5S&P Global Market Intelligence, RRA Financial Focus: “Capital Expenditure Update,”

March 21, 2017 at 1.



Q IS THERE EVIDENCE OF ROBUST VALUATIONS OF ELECTRIC UTILITY EQUITY 1

SECURITIES? 2

A Yes. On my Exhibit AB-2, I show the historical valuation of the electric utility industry 3

followed by Value Line based on price-to-earnings ratio, price-to-cash flow ratio and 4

market price-to-book value ratio indicators. These electric utility industry security 5

valuation metrics show that current electric utility stock valuations are very strong and 6

robust relative to the last 10 to 15 years. These robust valuations are an indication 7

that utilities can sell equity securities at high prices, which is a strong indication that 8

they can access capital under reasonable terms and conditions, and at relatively low 9

cost. 10

Q HOW SHOULD THE COMMISSION USE THIS MARKET INFORMATION IN 11

ASSESSING A FAIR RETURN FOR DTE? 12

A Market evidence is quite clear that capital market costs are near historically low 13

levels. Authorized returns on equity have fallen to the mid 9.0% range; utilities 14

0

20,000

40,000

60,000

80,000

100,000

120,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Dollars (in millions)

Figure 3

Electric Utility Capital Expenditures

Source:S&P Global Market Intelligence, Financial Focus, Capital Expenditure Update, March 21, 2017, Page 7

Actual Forecast



continue to have access to large amounts of external capital to fund large capital 1

programs; and utilities’ investment grade credit standings are stable and have 2

improved due, in part, to supportive regulatory treatment. The Commission should 3

carefully weigh all this important observable market evidence in assessing a fair 4

return on equity for DTE. 5

II.B. Regulated Utility Industry Market Outlook 6

Q PLEASE DESCRIBE THE CREDIT RATING OUTLOOK FOR REGULATED 7

UTILITIES. 8

A Regulated utilities’ credit ratings have improved over the last few years and the 9

outlook has been labeled “Stable” by credit rating agencies. Credit analysts have 10

also observed that utilities have strong access to capital at attractive pricing (i.e., low 11

capital costs), which has supported very large capital programs. 12

S&P recently published a report titled “Corporate Industry Credit Research: 13

Industry Top Trends 2017, Utilities.” In that report, S&P noted the following: 14

– Ratings Outlook: Rating trends across regulated utilities remain 15 mostly stable supported by stable regulatory oversight, slow but steady 16 demand for utility services, and tempered by aggressive capital 17 spending that will keep credit metrics from improving. Emerging new 18 political trends in historically stable regions like Europe and the U.S. 19 may have far-reaching effect on utilities over time, but S&P Global 20 Ratings sees little immediate influence from those factors in 2017. 21 Sovereign rating developments can influence utility ratings in some 22 countries and we expect them to vary in different parts of the globe. 23 – Forecasts: Credit ratios are likely to be stable in 2017 with some 24 slight downside risk as revenue growth will be modest in most regions 25 in keeping with the slow demand growth in regions where the utility 26 industries are mature. In contrast, growth can be higher in countries 27 and regions where utility services have not fully penetrated the market 28 offset by large investment needs. We expect margins across the 29 industries globally to be flat to improving slightly as operating 30 conditions and favorable fuel cost trends are maintained. 31 – Assumptions: Sales growth at most utilities is closely tied to the 32 general economic outlook in its service territory, which can vary 33 considerably from utility to utility. We project solid regulatory support 34



for utility earnings and cash flow, with the occasional exception due to 1 specific political or policy issues at the local level. Capital spending will 2 continue to be elevated in most areas, with substantial infrastructure 3 needs. 4 – Risks: Transformative risks abound in utility industries. Corporate 5 transformations (M&A) are an ever-present risk to ratings. Electric 6 generation transformation is ongoing as carbon concerns and other 7 environmental considerations lead utilities to change the mix of fuel 8 sources. Grid transformation is becoming more prominent as utilities 9 react to technological advances and the need for greater attention to 10 cyber security. 11 – Industry Trends: The utility industry in most regions is stable, 12 consistent with our general ratings outlook and the nature of the 13 essential products and services utilities sell. The unsettled state of the 14 world economy, buffeted by political volatility and uncertain capital 15 flows as international trade and tax reform emerge as urgent issues, 16 could spill over into the utility space. However, the industry as a whole 17 is well positioned to withstand mild shocks, and we see steady growth 18 and stable credit quality overall.6 19

Moody’s recent comments on the U.S. Utility Sector state as follows: 20

2017 Outlook - Timely Cost-Recovery Drives Stable Outlook 21 Our outlook for the US regulated utilities industry is stable. This 22 outlook reflects our expectations for the fundamental business 23 conditions in the industry over the next 12 to 18 months. 24 A credit-supportive regulatory environment is the main driver of 25 our stable outlook. Our stable outlook for the US regulated utility 26 industry is based on our expectation that utilities will continue to 27 recover costs in a timely manner and maintain stable cash flows. 28 CFO-to-debt ratios will hold steady in 2017. Utilities are contending 29 with flat to lower power demand and lower allowed returns on equity. 30 However, we expect that the continued use of cost-recovery 31 mechanisms, the ongoing management of operating costs and 32 extension of bonus depreciation will support cash flow, such that the 33 industrywide average ratio of CFO to debt will remain at about 22% 34 next year, in line with the 10-year average. 35

* * * 36

What could change our outlook. We could consider shifting our 37 outlook to positive if the sector’s average ratio of CFO to debt rose 38 toward 25% on a sustainable basis, which could happen if utilities 39 de-lever significantly, which we do not expect. A more contentious 40 regulatory environment resulting in a material deterioration in cash 41

6Standard & Poor’s Global Ratings: ““Industry Top Trends 2017: Utilities,” February 16, 2017, at 1, emphasis added.



flow, such that the ratio fell toward 18%, could cause us to take a 1 negative view.7 2

Q PLEASE DESCRIBE UTILITY STOCK PRICE PERFORMANCE OVER THE LAST 3

SEVERAL YEARS. 4

A As shown in Figure 4 below, SNL Financial has recorded utility stock price 5

performance compared to the market. The industry’s stock performance data from 6

2004 through the first quarter of 2017 shows that the SNL Electric Company Index 7

has outperformed the market in downturns and trailed the market during recovery. 8

This relatively stable price performance for utilities supports my conclusion that utility 9

stock investments are regarded by market participants as a moderate- to low-risk 10

investment. 11

7Moody’s Investors Service: “Regulated Utilities - US: 2017 Outlook – Timely Cost-Recovery

Drives Stable Outlook,” November 4, 2016, at 1, emphasis added.

‐50.0%

‐40.0%

‐30.0%

‐20.0%

‐10.0%

0.0%

10.0%

20.0%

30.0%

40.0%

2017*2016201520142013201220112010200920082007200620052004

Percent Return

Source: SNL Financial.*Data through June 30, 2017

Index Comparison

SNL Electric Company

S&P 500

FIGURE 4



Q HAVE ELECTRIC UTILITY INDUSTRY TRADE ORGANIZATIONS COMMENTED 1

ON ELECTRIC UTILITY STOCK PRICE PERFORMANCE? 2

A Yes. In its 4th Quarter 2016 Financial Update, the EEI stated the following 3

concerning the EEI Electric Utility Stock Index (“EEI Index”): 4

Industry Fundamentals Remain Stable 5 There was little meaningful change in the industry’s fundamental 6 picture during 2016. Electricity demand remained virtually flat; total 7 electric output rose only 0.2% over the level in 2015 in the lower 48 8 states. Nationwide power demand has, in fact, been about flat for a 9 decade. . . In response, a number of state utility commissions have 10 adapted rate designs that help utilities cope with flat demand while still 11 enabling investment required to comply with environmental 12 requirements, grid modernization and upgrades to vital infrastructure. 13 Nevertheless, the outlook for flat demand is a “new normal” that 14 represents a departure from the consistent demand growth that 15 characterized the industry’s experience for more than a century. 16

* * * 17

While utility regulation largely occurs at the state level and must be 18 analyzed state by state, industry analysts at yearend generally viewed 19 regulation as largely fair and balanced overall for the industry taken as 20 a whole. While allowed return on equity has come down in recent 21 years, so have interest rates. Moody’s in early 2017 called the 22 industry’s credit outlook “stable” based on expectation that utilities will 23 continue to recover costs in a timely manner and maintain stable cash 24 flows. 25

* * * 26

The industry is now focused largely on regulated businesses with a 27 strong 3.4% dividend yield (at December 31, 2016), healthy balance 28 sheets and the chance to drive the nation’s ongoing transition to 29 cleaner energy and a modernized grid. The classic 20th century utility 30 formula — slow earnings and dividend growth — should continue to 31 attract investors. Provided inflation doesn’t surge and produce sharply 32 higher interest rates, utility shares should continue to do well on a 33 relative (and possibly absolute) basis when bearish sentiment 34 dominates the broader stock market.8 35

8EEI Q4 2016 Financial Update: “Stock Performance” at 5-6, emphasis added.



Q WHAT ARE THE IMPORTANT TAKEAWAY POINTS FROM THIS ASSESSMENT 1

OF UTILITY INDUSTRY CREDIT AND INVESTMENT RISK OUTLOOKS? 2

A Credit rating agencies consider the regulated utility industry to be “Stable” and believe 3

investors will continue to provide an abundance of low-cost capital to support utilities’ 4

large capital programs at attractive costs and terms. All of this reinforces my belief 5

that utility investments are generally regarded as safe-haven or low-risk investments 6

and the market continues to demand low-risk investments such as utility securities. 7

The ongoing demand for low-risk investments can reasonably be expected to 8

continue to provide attractive low-cost capital for regulated utilities. 9

II.C. DTE Investment Risk 10

Q PLEASE DESCRIBE THE MARKET’S ASSESSMENT OF THE INVESTMENT RISK 11

OF DTE. 12

A. The market’s assessment of DTE’s investment risk is described by credit rating 13

analysts’ reports. DTE’s current corporate bond ratings from S&P and Moody’s are 14

BBB+ and A2, respectively.9 The Company’s outlook from S&P and Moody’s is 15

“Stable” after its recent ratings affirmation by Moody’s. While DTE’s current rating 16

from S&P is BBB+, on a stand-alone basis it would be rated A-. In other words, S&P 17

has lowered DTE Electric’s rating by one notch simply because of its affiliation with, 18

and lack of ring-fence or protective insulating measures from its parent company, 19

DTE Energy. In its most recent report on DTE, S&P specifically stated: 20

Business Risk: Excellent 21

We based our assessment of DTEE's stand-alone business risk 22 profile on the very low risk of the regulated utility industry that 23 provides indispensable services that are strategically important to 24 economies, have material barriers to entry, and essentially operate 25

9SNL Financial, downloaded on March 28, 2017.



as a monopoly insulated from market challenges. DTE benefits 1 from the strength of regulatory support in Michigan by filing forward-2 looking rate cases, using a six-month self-implementation, and 3 various riders that enhance cash flow predictability. This is further 4 enhanced with controlling operating costs. The utility has a good 5 track record of operating owned generation assets effectively. 6 Currently there is reliance on coal as a fuel source, but the 7 expectation is the fuel mix will shift from coal toward more natural 8 gas and renewable generation to comply with environmental 9 requirements. 10

Financial Risk: Significant 11

Our baseline forecast includes adjusted FFO to debt ranging from 12 approximately 16% to 19%, around the midpoint of the significant 13 category. The supplemental ratio of FFO cash interest coverage 14 bolsters this determination since in our base-case scenario we 15 expect this measure to average around 7.3x to 7.7x through 2017. 16 Debt leverage, as measured by total debt to EBITDA, is expected to 17 average about 4.5x. We expect capital spending to be elevated, 18 and when combined with ongoing dividends, to drive negative 19 discretionary cash flow, averaging over $500 million per year. This 20 will lead to external funding needs and will limit any significant 21 deleveraging. We expect mostly steady cash flow as a regulated 22 generation and distribution electric utility with ongoing and timely 23 cost recovery through base rates and rate surcharges. Our financial 24 risk assessment is based on our medial volatility financial ratio 25 benchmarks.10 26

III. DTE’S PROPOSED CAPITAL STRUCTURE 27

Q WHAT IS DTE’S PROPOSED CAPITAL STRUCTURE? 28

A DTE’s proposed capital structure is shown below in Table 2. The forecasted capital 29

structure ending on October 31, 2018 is sponsored by DTE witness Mr. Solomon. 30

10Standard & Poor's RatingsDirect: "Summary: DTE Electric Co.," December 22, 2016 at 3-4.



TABLE 2

DTE's

Proposed Capital Structure (October 31, 2018)

Description Regulatory Weight

Permanent Weight

Long-Term Debt 36.09% 48.98% Common Equity 37.59% 51.02% Short-Term Debt 1.31% ITC-Debt 0.03% ITC-Equity 0.03% ADIT 24.96% Total 100.00% 100.00% __________________

Source: Exhibit A-11 Schedule D1.

Q ARE YOU TAKING ISSUE WITH DTE’S PROPOSED CAPITAL STRUCTURE? 1

A While DTE is proposing to increase its common equity capital over its most recently 2

authorized weight, I am not taking issue with it at this time. However, I would urge the 3

Commission to monitor DTE’s capital structure to make sure that it does not exceed a 4

common equity ratio that is required to maintain its financial integrity. I reserve the 5

right to comment further based on additional evidence and testimony offered by the 6

parties to this proceeding. 7

III.A. Embedded Cost of Debt 8

Q WHAT IS THE COMPANY’S EMBEDDED COST OF DEBT? 9

A DTE is proposing an embedded cost of debt of 4.42% as developed on its Exhibit 10

A-11, Schedule D1. 11



Q ARE YOU TAKING ISSUE WITH DTE’S PROPOSED EMBEDDED COST OF 1

LONG-TERM DEBT? 2

A Not at this time. But I reserve the right to comment further based on additional 3

evidence and testimony offered by the parties to this proceeding. 4

IV. RETURN ON COMMON EQUITY 5

Q PLEASE DESCRIBE WHAT IS MEANT BY A “UTILITY’S COST OF COMMON 6

EQUITY.” 7

A A utility’s cost of common equity, alternately described as the return on common 8

equity (commonly, “ROE”), is the expected return that investors require on an 9

investment in the utility. Investors expect to earn their required return from receiving 10

dividends and through stock price appreciation. 11

Q PLEASE DESCRIBE THE FRAMEWORK FOR DETERMINING A REGULATED 12

UTILITY’S COST OF COMMON EQUITY. 13

A In general, determining a fair cost of common equity for a regulated utility has been 14

framed by two hallmark decisions of the U.S. Supreme Court: Bluefield Water Works 15

& Improvement Co. v. Pub. Serv. Comm’n of W. Va., 262 U.S. 679 (1923) and Fed. 16

Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591 (1944). 17

These decisions identify the general financial and economic standards to be 18

considered in establishing the cost of common equity for a public utility. Those 19

general standards provide the authorized return should: (1) be sufficient to maintain 20

financial integrity; (2) attract capital under reasonable terms; and (3) be 21

commensurate with returns investors could earn by investing in other enterprises of 22

comparable risk. 23



Q PLEASE DESCRIBE THE METHODS YOU HAVE USED TO ESTIMATE DTE’S 1

COST OF COMMON EQUITY. 2

A I have used several models based on financial theory to estimate DTE’s cost of 3

common equity. These models are: (1) a constant growth Discounted Cash Flow 4

(“DCF”) model using consensus analysts’ growth rate projections; (2) a constant 5

growth DCF using sustainable growth rate estimates; (3) a multi-stage growth DCF 6

model; (4) a Risk Premium model; and (5) a Capital Asset Pricing Model (“CAPM”). I 7

have applied these models to a group of publicly traded utilities with investment risk 8

similar to DTE. 9

IV.A. Risk Proxy Group 10

Q PLEASE DESCRIBE HOW YOU IDENTIFIED A PROXY UTILITY GROUP THAT 11

COULD BE USED TO ESTIMATE DTE’S CURRENT MARKET COST OF EQUITY. 12

A I relied on the same proxy group developed by DTE witness Dr. Vilbert with the 13

exception of Avista Corporation. After Dr. Vilbert filed his direct testimony, Avista 14

announced that it is being acquired by Toronto-based Hydro One. Additionally, I do 15

not agree with the inclusion of Avangrid, Inc. in the proxy group for two reasons: 1) 16

more than 85% of its outstanding stock is owned by its ultimate parent, Iberdola, S.A., 17

and; 2) it does not have a published Value Line beta. However, to limit issues in this 18

rate case, I will not remove it from my proxy group. 19

Q PLEASE DESCRIBE WHY YOU BELIEVE YOUR PROXY GROUP IS 20

REASONABLY COMPARABLE IN INVESTMENT RISK TO DTE. 21

A The proxy group shown in Exhibit AB-3, has an average corporate credit rating from 22

S&P of BBB+, which is identical to DTE’s BBB+ issuer credit rating from S&P, but one 23



notch less than its stand-alone credit profile rating of ‘a-’. The proxy group has an 1

average corporate credit rating from Moody’s of Baa1, which is two notches lower 2

than DTE’s credit rating of A2. Based on this information, I believe my proxy group is 3

reasonably comparable, if not conservative, in investment risk to DTE. 4

I also note that the proxy group has an average common equity ratio of 45.4% 5

(including short-term debt) from SNL Financial (“SNL”) and 48.7% (excluding 6

short-term debt) from The Value Line Investment Survey (“Value Line”) in 2016. The 7

Company’s proposed common equity ratio of 51.0% is relatively higher than the 8

average proxy group common equity ratio. For these reasons, I believe my proxy 9

group is reasonably comparable to DTE. 10

IV.B. Discounted Cash Flow Model 11

Q PLEASE DESCRIBE THE DCF MODEL. 12

A The DCF model posits that a stock price is valued by summing the present value of 13

expected future cash flows discounted at the investor’s required rate of return or cost 14

of capital. This model is expressed mathematically as follows: 15

P0 = D1 + D2 . . . . D∞ (Equation 1) 16 (1+K)1 (1+K)2 (1+K)∞ 17

P0 = Current stock price 18

D = Dividends in periods 1 - ∞ 19

K = Investor’s required return 20

This model can be rearranged in order to estimate the discount rate or 21

investor-required return otherwise known as “K.” If it is reasonable to assume that 22

earnings and dividends will grow at a constant rate, then Equation 1 can be 23

rearranged as follows: 24



K = D1/P0 + G (Equation 2) 1

K = Investor’s required return 2

D1 = Dividend in first year 3

P0 = Current stock price 4

G = Expected constant dividend growth rate 5

Equation 2 is referred to as the annual “constant growth” DCF model. 6

Q PLEASE DESCRIBE THE INPUTS TO YOUR CONSTANT GROWTH DCF MODEL. 7

A As shown in Equation 2 above, the DCF model requires a current stock price, 8

expected dividend, and expected growth rate in dividends. 9

Q WHAT STOCK PRICE HAVE YOU RELIED ON IN YOUR CONSTANT GROWTH 10

DCF MODEL? 11

A I relied on the average of the weekly high and low stock prices of the utilities in the 12

proxy group over a 13-week period ending on August 4, 2017. An average stock 13

price is less susceptible to market price variations than a price at a single point in 14

time. Therefore, an average stock price is less susceptible to aberrant market price 15

movements, which may not reflect the stock’s long-term value. 16

A 13-week average stock price reflects a period that is still short enough to 17

contain data that reasonably reflects current market expectations but the period is not 18

so short as to be susceptible to market price variations that may not reflect the stock’s 19

long-term value. In my judgment, a 13-week average stock price is a reasonable 20

balance between the need to reflect current market expectations and the need to 21

capture sufficient data to smooth out aberrant market movements. 22



Q WHAT DIVIDEND DID YOU USE IN YOUR CONSTANT GROWTH DCF MODEL? 1

A I used the most recently paid quarterly dividend as reported in Value Line.11 This 2

dividend was annualized (multiplied by 4) and adjusted for next year’s growth to 3

produce the D1 factor for use in Equation 2 above. In other words, I calculate D1 by 4

multiplying the annualized dividend (D0) by (1+G). 5

Q WHAT DIVIDEND GROWTH RATES HAVE YOU USED IN YOUR CONSTANT 6

GROWTH DCF MODEL? 7

A There are several methods that can be used to estimate the expected growth in 8

dividends. However, regardless of the method, for purposes of determining the 9

market-required return on common equity, one must attempt to estimate investors’ 10

consensus about what the dividend, or earnings growth rate, will be and not what an 11

individual investor or analyst may use to make individual investment decisions. 12

As predictors of future returns, securities analysts’ growth estimates have 13

been shown to be more accurate than growth rates derived from historical data.12 14

That is, assuming the market generally makes rational investment decisions, analysts’ 15

growth projections are more likely to influence investors’ decisions, which are 16

captured in observable stock prices, than growth rates derived only from historical 17

data. 18

For my constant growth DCF analysis, I have relied on a consensus, or mean, 19

of professional securities analysts’ earnings growth estimates as a proxy for investor 20

consensus dividend growth rate expectations. I used the average of analysts’ growth 21

rate estimates from three sources: Zacks, SNL, and Reuters. All such projections 22

were available on August 4, 2017, and all were reported online. 23 11The Value Line Investment Survey, May 19, June 16, and July 28, 2017. 12See, e.g., David Gordon, Myron Gordon, and Lawrence Gould, “Choice Among Methods of Estimating Share Yield,” The Journal of Portfolio Management, Spring 1989.



Each consensus growth rate projection is based on a survey of securities 1

analysts. There is no clear evidence whether a particular analyst is most influential 2

on general market investors. Therefore, a single analyst’s projection does not as 3

reliably predict consensus investor outlooks as does a consensus of market analysts’ 4

projections. The consensus estimate is a simple arithmetic average, or mean, of 5

surveyed analysts’ earnings growth forecasts. A simple average of the growth 6

forecasts gives equal weight to all surveyed analysts’ projections. Therefore, a 7

simple average, or arithmetic mean, of analyst forecasts is a good proxy for market 8

consensus expectations. 9

Q WHAT ARE THE GROWTH RATES YOU USED IN YOUR CONSTANT GROWTH 10

DCF MODEL? 11

A The growth rates I used in my DCF analysis are shown in Exhibit AB-4. The average 12

growth rate for my proxy group is 5.57%. 13

Q WHAT ARE THE RESULTS OF YOUR CONSTANT GROWTH DCF MODEL? 14

A As shown in Exhibit AB-5, the average and median constant growth DCF returns for 15

my proxy group for the 13-week analysis are 8.99% and 9.14%, respectively. 16

Q DO YOU HAVE ANY COMMENTS ON THE RESULTS OF YOUR CONSTANT 17

GROWTH DCF ANALYSIS? 18

A Yes. The constant growth DCF analysis for my proxy group is based on a group 19

average long-term sustainable growth rate of 5.57%. The three- to five-year growth 20

rates are higher than my estimate of a maximum long-term sustainable growth rate of 21



4.20%, which I discuss later in this testimony. I believe the constant growth DCF 1

analysis produces a reasonable high-end return estimate. 2

Q HOW DID YOU ESTIMATE A MAXIMUM LONG-TERM SUSTAINABLE GROWTH 3

RATE? 4

A A long-term sustainable growth rate for a utility stock cannot exceed the growth rate 5

of the economy in which it sells its goods and services. Hence, the long-term 6

maximum sustainable growth rate for a utility investment is best proxied by the 7

projected long-term Gross Domestic Product (“GDP”). Blue Chip Financial Forecasts 8

projects that over the next 5 and 10 years, the U.S. nominal GDP will grow at an 9

annual rate of approximately 4.20%. These GDP growth projections reflect a real 10

growth outlook of around 2.1% and an inflation outlook of around 2.1% going forward. 11

As such, the average growth rate over the next 10 years is around 4.20%, which I 12

believe is a reasonable proxy of long-term sustainable growth.13 13

In my multi-stage growth DCF analysis, I discuss academic and investment 14

practitioner support for using the projected long-term GDP growth outlook as a 15

maximum sustainable growth rate projection. Hence, using the long-term GDP 16

growth rate as a conservative projection for the maximum sustainable growth rate is 17

logical, and is generally consistent with academic and economic practitioner accepted 18

practices. 19

13Blue Chip Financial Forecasts, June 1, 2017, at 14.



IV.C. Sustainable Growth DCF 1

Q PLEASE DESCRIBE HOW YOU ESTIMATED A SUSTAINABLE LONG-TERM 2

GROWTH RATE FOR YOUR SUSTAINABLE GROWTH DCF MODEL. 3

A A sustainable growth rate is based on the percentage of the utility’s earnings that is 4

retained and reinvested in utility plant and equipment. These reinvested earnings 5

increase the earnings base (rate base). Earnings grow when utility plant funded by 6

reinvested earnings is put into service, and the utility is allowed to earn its authorized 7

return on such additional rate base investment. 8

The internal growth methodology is tied to the percentage of earnings retained 9

in the company and not paid out as dividends. The earnings retention ratio is 1 minus 10

the dividend payout ratio. As the payout ratio declines, the earnings retention ratio 11

increases. An increased earnings retention ratio will fuel stronger growth because 12

the business funds more investments with retained earnings. 13

The payout ratios of the proxy group are shown in my Exhibit AB-6. These 14

dividend payout ratios and earnings retention ratios then can be used to develop a 15

sustainable long-term earnings retention growth rate. A sustainable long-term 16

earnings retention ratio will help gauge whether analysts’ current three- to five-year 17

growth rate projections can be sustained over an indefinite period of time. 18

The data used to estimate the long-term sustainable growth rate is based on 19

the Company’s current market-to-book ratio and on Value Line’s three- to five-year 20

projections of earnings, dividends, earned returns on book equity, and stock 21

issuances. 22

As shown in Exhibit AB-7, the average sustainable growth rate for the proxy 23

group using this internal growth rate model is 4.51%. 24



Q WHAT IS THE DCF ESTIMATE USING THESE SUSTAINABLE LONG-TERM 1

GROWTH RATES? 2

A A DCF estimate based on these sustainable growth rates is developed in 3

Exhibit AB-8. As shown there, and using the same formula in Equation 2 above, a 4

sustainable growth DCF analysis produces proxy group average and median DCF 5

results for the 13-week period of 7.90% and 7.57%, respectively. 6

IV.D. Multi-Stage Growth DCF Model 7

Q HAVE YOU CONDUCTED ANY OTHER DCF STUDIES? 8

A Yes. My first constant growth DCF is based on consensus analysts’ growth rate 9

projections so it is a reasonable reflection of rational investment expectations over the 10

next three to five years. The limitation on this constant growth DCF model is that it 11

cannot reflect a rational expectation that a period of high or low short-term growth can 12

be followed by a change in growth to a rate that is more reflective of long-term 13

sustainable growth. Hence, I performed a multi-stage growth DCF analysis to reflect 14

this outlook of changing growth expectations. 15

Q WHY DO YOU BELIEVE GROWTH RATES CAN CHANGE OVER TIME? 16

A Analyst-projected growth rates over the next three to five years will change as utility 17

earnings growth outlooks change. Utility companies go through cycles in making 18

investments in their systems. When utility companies are making large investments, 19

their rate base grows rapidly, which in turn accelerates earnings growth. Once a 20

major construction cycle is completed or levels off, growth in the utility rate base 21

slows and its earnings growth slows from an abnormally high three- to five-year rate 22

to a lower sustainable growth rate. 23



As major construction cycles extend over longer periods of time, even with an 1

accelerated construction program, the growth rate of the utility will slow simply 2

because rate base growth will slow and the utility has limited human and capital 3

resources available to expand its construction program. Therefore, the three- to 4

five-year growth rate projection should be used as a long-term sustainable growth 5

rate but not without making a reasonable informed judgment to determine whether it 6

considers the current market environment, the industry, and whether the three- to 7

five-year growth outlook is sustainable. 8

Q PLEASE DESCRIBE YOUR MULTI-STAGE GROWTH DCF MODEL. 9

A The multi-stage growth DCF model reflects the possibility of non-constant growth for 10

a company over time. The multi-stage growth DCF model reflects three growth 11

periods: (1) a short-term growth period consisting of the first five years; (2) a transition 12

period, consisting of the next five years (6 through 10); and (3) a long-term growth 13

period starting in year 11 through perpetuity. 14

For the short-term growth period, I relied on the consensus analysts’ growth 15

projections described above in relationship to my constant growth DCF model. For 16

the transition period, the growth rates were reduced or increased by an equal factor 17

reflecting the difference between the analysts’ growth rates and the long-term 18

sustainable growth rate. For the long-term growth period, I assumed each company’s 19

growth would converge to the maximum sustainable long-term growth rate. 20



Q WHY IS THE GDP GROWTH PROJECTION A REASONABLE PROXY FOR THE 1

MAXIMUM SUSTAINABLE LONG-TERM GROWTH RATE? 2

A Utilities cannot indefinitely sustain a growth rate that exceeds the growth rate of the 3

economy in which they sell services. Utilities’ earnings/dividend growth is created by 4

increased utility investment or rate base. Such investment, in turn, is driven by 5

service area economic growth and demand for utility service. In other words, utilities 6

invest in plant to meet sales demand growth. Sales growth, in turn, is tied to 7

economic growth in their service areas. 8

The U.S. Department of Energy, Energy Information Administration (“EIA”) 9

has observed utility sales growth tracks the U.S. GDP growth, albeit at a lower level, 10

as shown in Exhibit AB-9. Utility sales growth has lagged behind GDP growth for 11

more than a decade. As a result, nominal GDP growth is a very conservative proxy 12

for utility sales growth, rate base growth, and earnings growth. Therefore, the U.S. 13

GDP nominal growth rate is a conservative proxy for the highest sustainable 14

long-term growth rate of a utility. 15

Q IS THERE RESEARCH THAT SUPPORTS YOUR POSITION THAT, OVER THE 16

LONG TERM, A COMPANY’S EARNINGS AND DIVIDENDS CANNOT GROW AT 17

A RATE GREATER THAN THE GROWTH OF THE U.S. GDP? 18

A Yes. This concept is supported in published analyst literature and academic work. 19

Specifically, in a textbook titled “Fundamentals of Financial Management,” published 20

by Eugene Brigham and Joel F. Houston, the authors state as follows: 21

The constant growth model is most appropriate for mature companies 22 with a stable history of growth and stable future expectations. 23 Expected growth rates vary somewhat among companies, but 24 dividends for mature firms are often expected to grow in the future at 25



about the same rate as nominal gross domestic product (real GDP 1 plus inflation).14 2

The use of the economic growth rate is also supported by investment 3

practitioners as outlined as follows: 4

Estimating Growth Rates 5 One of the advantages of a three-stage discounted cash flow model is 6 that it fits with life cycle theories in regards to company growth. In 7 these theories, companies are assumed to have a life cycle with 8 varying growth characteristics. Typically, the potential for extraordinary 9 growth in the near term eases over time and eventually growth slows 10 to a more stable level. 11

* * * 12

Another approach to estimating long-term growth rates is to focus on 13 estimating the overall economic growth rate. Again, this is the 14 approach used in the Ibbotson Cost of Capital Yearbook. To obtain 15 the economic growth rate, a forecast is made of the growth rate’s 16 component parts. Expected growth can be broken into two main parts: 17 expected inflation and expected real growth. By analyzing these 18 components separately, it is easier to see the factors that drive 19 growth.15 20

Q IS THERE ANY ACTUAL INVESTMENT HISTORY THAT SUPPORTS THE 21

NOTION THAT THE CAPITAL APPRECIATION FOR STOCK INVESTMENTS WILL 22

NOT EXCEED THE NOMINAL GROWTH OF THE U.S. GDP? 23

A Yes. This is evident by a comparison of the compound annual growth of the U.S. 24

GDP compared to the geometric growth of the U.S. stock market. Morningstar 25

measures the historical geometric growth of the U.S. stock market over the period 26

1926-2016 to be approximately 5.8%. During this same time period, the U.S. nominal 27

compound annual growth of the U.S. GDP was approximately 6.4%.16 28

14“Fundamentals of Financial Management,” Eugene F. Brigham and Joel F. Houston, Eleventh Edition 2007, Thomson South-Western, a Division of Thomson Corporation at 298, emphasis added. 15Morningstar, Inc., Ibbotson SBBI 2013 Valuation Yearbook at 51 and 52. 16U.S. Bureau of Economic Analysis, February 28, 2017.



As such, the geometric annual growth of the U.S. nominal GDP has been 1

higher but comparable to the geometric annual growth of the U.S. stock market 2

capital appreciation. This historical relationship indicates the U.S. GDP growth 3

outlook is a conservative estimate of the long-term sustainable growth of U.S. stock 4

investments. 5

Q HOW DID YOU DETERMINE A SUSTAINABLE LONG-TERM GROWTH RATE 6

THAT REFLECTS THE CURRENT CONSENSUS OUTLOOK OF THE MARKET? 7

A I relied on the consensus analysts’ projections of long-term GDP growth. Blue Chip 8

Financial Forecasts publishes consensus economists’ GDP growth projections twice 9

a year. These consensus analysts’ GDP growth outlooks are the best available 10

measure of the market’s assessment of long-term GDP growth. These analyst 11

projections reflect all current outlooks for GDP and are likely the most influential on 12

investors’ expectations of future growth outlooks. The consensus economists’ 13

published GDP growth rate outlook is 4.20% over the next 10 years.17 14

Therefore, I propose to use the consensus economists’ projected 5- and 15

10-year average GDP consensus growth rates of 4.20%, as published by Blue Chip 16

Financial Forecasts, as an estimate of long-term sustainable growth. Blue Chip 17

Financial Forecasts projections provide real GDP growth projections of approximately 18

2.1% and GDP inflation of approximately 2.1%18 over the 5-year and 10-year 19

projection periods. These consensus GDP growth forecasts represent the most likely 20

views of market participants because they are based on published consensus 21

economist projections. 22

17 Blue Chip financial Forecasts, June 1, 2017 at 14. 18Id.



Q DO YOU CONSIDER OTHER SOURCES OF PROJECTED LONG-TERM GDP 1

GROWTH? 2

A Yes, and these sources corroborate my consensus analysts’ projections, as shown 3

below in Table 3. 4

5

The EIA in its Annual Energy Outlook projects real GDP out until 2050. In its 6

2017 Annual Report, the EIA projects real GDP through 2050 to be 2.0% and a 7

long-term GDP price inflation projection of 2.1%. The EIA data supports a long-term 8

nominal GDP growth outlook of 4.2%.19 9

Also, the Congressional Budget Office (“CBO”) makes long-term economic 10

projections. The CBO is projecting real GDP growth to be 1.9% during the next 11

6 years with a GDP price inflation outlook of 2.0%. The CBO 6-year outlook for 12

nominal GDP based on this projection is 4.0%.20 13

Moody’s Analytics also makes long-term economic projections. In its recent 14

25-year outlook to 2046, Moody’s Analytics is projecting real GDP growth of 2.0% 15

19DOE/EIA Annual Energy Outlook 2017 With Projections to 2050, March 1 2017, Table 20. 20CBO: The Budget and Economic Outlook: 2017 to 2027, January 2017, downloaded

March 1, 2017.

Real NominalSource Term GDP Inflation GDP

Blue Chip Financial Forecasts 5-10 Yrs 2.1% 2.1% 4.2%EIA - Annual Earnings Outlook 29 Yrs 2.0% 2.1% 4.2%Congressional Budget Office 6 Yrs 1.9% 2.0% 4.0%Moody's Analytics 25 Yrs 2.0% 2.0% 4.0%Social Security Administration 49 Yrs 4.4%The Economist Intelligence Unit 25 Yrs 1.7% 1.9% 3.6%

TABLE 3

GDP Forecasts



with GDP inflation of 2.0%.21 Based on these projections, Moody’s is projecting 1

nominal GDP growth of 4.0% over the next 25 years. 2

The Social Security Administration (“SSA”) makes long-term economic 3

projections out to 2090. The SSA’s nominal GDP projection, under its intermediate 4

cost scenario of approximately 50 years, is 4.4%.22 5

The Economist Intelligence Unit, a division of The Economist and a third-party 6

data provider to SNL Financial, makes a long-term economic projection out to 2050. 7

The Economist Intelligence Unit is projecting real GDP growth of 1.7% with an 8

inflation rate of 1.9% out to 2050. The real GDP growth projection is in line with the 9

consensus economists. The long-term nominal GDP projection based on these 10

outlooks is approximately 3.6%.23 11

The real GDP and nominal GDP growth projections made by these 12

independent sources support the use of the consensus economist 5-year and 10-year 13

projected GDP growth outlooks as a reasonable estimate of market participants’ 14

long-term GDP growth outlooks. 15

Q WHAT STOCK PRICE, DIVIDEND, AND GROWTH RATES DID YOU USE IN YOUR 16

MULTI-STAGE GROWTH DCF ANALYSIS? 17

A I relied on the same 13-week average stock prices and the most recent quarterly 18

dividend payment data discussed above. For stage one growth, I used the 19

consensus analysts’ growth rate projections discussed above in my constant growth 20

DCF model. The first stage covers the first five years, consistent with the time 21

horizon of the securities analysts’ growth rate projections. The second stage, or 22

transition stage, begins in year 6 and extends through year 10. The second stage 23

21www.economy.com, Moody’s Analytics Forecast, February 6, 2017. 22www.ssa.gov, “2017 OASDI Trustees Report,” Table VI.G4. 23SNL Financial, Economist Intelligence Unit, downloaded on March 1, 2017.



growth transitions the growth rate from the first stage to the third stage using a 1

straight linear trend. For the third stage, or long-term sustainable growth stage, 2

starting in year 11, I used a 4.20% long-term sustainable growth rate based on the 3

consensus economists’ long-term projected nominal GDP growth rate. 4

Q WHAT ARE THE RESULTS OF YOUR MULTI-STAGE GROWTH DCF MODEL? 5

A As shown in Exhibit AB-10, the average and median DCF returns on equity for my 6

proxy group using the 13-week average stock price are 7.89% and 7.80%, 7

respectively. 8

Q PLEASE SUMMARIZE THE RESULTS FROM YOUR DCF ANALYSES. 9

A The results from my DCF analyses are summarized in Table 4 below: 10

TABLE 4

Summary of DCF Results

Proxy Group Description Average Median Constant Growth DCF Model (Analysts’ Growth) 8.99% 9.14%

Constant Growth DCF Model (Sustainable Growth) 7.90% 7.57%

Multi-Stage Growth DCF Model 7.89% 7.80%

I conclude that my DCF studies support a return on equity of 9.1%, primarily 11

based on my constant growth DCF result. I will give primary consideration to my 12

constant growth DCF analysis based on analysts’ growth rate projections. Based on 13

an assessment of my proxy group results, I believe the proxy group median most 14

accurately describes the central tendency of the proxy group DCF return results. 15



IV.E. Risk Premium Model 1

Q PLEASE DESCRIBE YOUR BOND YIELD PLUS RISK PREMIUM MODEL. 2

A This model is based on the principle that investors require a higher return to assume 3

greater risk. Common equity investments have greater risk than bonds because 4

bonds have more security of payment in bankruptcy proceedings than common equity 5

and the coupon payments on bonds represent contractual obligations. In contrast, 6

companies are not required to pay dividends or guarantee returns on common equity 7

investments. Therefore, common equity securities are considered to be riskier than 8

bond securities. 9

This risk premium model is based on two estimates of an equity risk premium. 10

First, I estimated the difference between the required return on utility common equity 11

investments and U.S. Treasury bonds. The difference between the required return on 12

common equity and the Treasury bond yield is the risk premium. I estimated the risk 13

premium on an annual basis for each year over the period January 1986 through 14

2016. The common equity required returns were based on regulatory 15

commission-authorized returns for electric utility companies. Authorized returns are 16

typically based on expert witnesses’ estimates of the contemporary investor-required 17

return. 18

The second equity risk premium estimate is based on the difference between 19

regulatory commission-authorized returns on common equity and contemporary 20

“A” rated utility bond yields by Moody’s. I selected the period January 1986 through 21

June 2017 because public utility stocks consistently traded at a premium to book 22

value during that period. This is illustrated in Exhibit AB-11, which shows the 23

market-to-book ratio since 1986 for the electric utility industry was consistently above 24

a multiple of 1.0x. Over this period, regulatory authorized returns were sufficient to 25



support market prices that at least exceeded book value. This is an indication that 1

regulatory authorized returns on common equity supported a utility’s ability to issue 2

additional common stock without diluting existing shares. It further demonstrates 3

utilities were able to access equity markets without a detrimental impact on current 4

shareholders. 5

Based on this analysis, as shown in Exhibit AB-12, the average indicated 6

equity risk premium over U.S. Treasury bond yields has been 5.51%. Since the risk 7

premium can vary depending upon market conditions and changing investor risk 8

perceptions, I believe using an estimated range of risk premiums provides the best 9

method to measure the current return on common equity for a risk premium 10

methodology. 11

I incorporated five-year and 10-year rolling average risk premiums over the 12

study period to gauge the variability over time of risk premiums. These rolling 13

average risk premiums mitigate the impact of anomalous market conditions and 14

skewed risk premiums over an entire business cycle. As shown on my Exhibit AB-12, 15

the five-year rolling average risk premium over Treasury bonds ranged from 4.25% to 16

6.72%, while the 10-year rolling average risk premium ranged from 4.38% to 6.51%. 17

As shown on my Exhibit AB-13, the average indicated equity risk premium 18

over contemporary Moody’s utility bond yields was 4.13%. The five-year and 10-year 19

rolling average risk premiums ranged from 2.88% to 5.57% and 3.20% to 5.16%, 20

respectively. 21



Q DO YOU BELIEVE THAT THE TIME PERIOD USED TO DERIVE THESE EQUITY 1

RISK PREMIUM ESTIMATES IS APPROPRIATE TO FORM ACCURATE 2

CONCLUSIONS ABOUT CONTEMPORARY MARKET CONDITIONS? 3

A Yes. The time period I use in this risk premium study is a generally accepted period 4

to develop a risk premium study using “expectational” data. 5

Contemporary market conditions can change dramatically during the period 6

that rates determined in this proceeding will be in effect. A relatively long period of 7

time where stock valuations reflect premiums to book value is an indication the 8

authorized returns on equity and the corresponding equity risk premiums were 9

supportive of investors’ return expectations and provided utilities access to the equity 10

markets under reasonable terms and conditions. Further, this time period is long 11

enough to smooth abnormal market movement that might distort equity risk 12

premiums. While market conditions and risk premiums do vary over time, this 13

historical time period is a reasonable period to estimate contemporary risk premiums. 14

Alternatively, some studies, such as Duff & Phelps referred to later in this 15

testimony, have recommended that use of “actual achieved investment return data” in 16

a risk premium study should be based on long historical time periods. These studies 17

find that achieved returns over short time periods may not reflect investors’ expected 18

returns due to unexpected and abnormal stock price performance. Short-term, 19

abnormal actual returns would be smoothed over time and the achieved actual 20

investment returns over long time periods would approximate investors’ expected 21

returns. Therefore, it is reasonable to assume that averages of annual achieved 22

returns over long time periods will generally converge on the investors’ expected 23

returns. 24



My risk premium study is based on expectational data, not actual investment 1

returns, and, thus, need not encompass a very long historical time period. 2

Q BASED ON HISTORICAL DATA, WHAT RISK PREMIUM HAVE YOU USED TO 3

ESTIMATE DTE’S COST OF COMMON EQUITY IN THIS PROCEEDING? 4

A The equity risk premium should reflect the relative market perception of risk in the 5

utility industry today. I have gauged investor perceptions in utility risk today in 6

Exhibit AB-14, where I show the yield spread between utility bonds and Treasury 7

bonds over the last 38 years. As shown in this schedule, the average utility bond 8

yield spreads over Treasury bonds for “A” and “Baa” rated utility bonds for this 9

historical period are 1.51% and 1.95%, respectively. The utility bond yield spreads 10

over Treasury bonds for “A” and “Baa” rated utilities for 2017 are 1.15% and 1.55%, 11

respectively. The current average “A” rated utility bond yield spread over Treasury 12

bond yields is now lower than the 38-year average spread. The current “Baa” rated 13

utility bond yield spread over Treasury bond yields is also lower than the 38-year 14

average spread. 15

A current 13-week average “A” rated utility bond yield of 3.99% when 16

compared to the current Treasury bond yield of 2.86%, as shown in Exhibit AB-15, 17

page 1, implies a yield spread of 113 basis points. This current utility bond yield 18

spread is lower than the 38-year average spread for “A” rated utility bonds of 19

151 basis points. The current spread for the “Baa” rated utility bond yield of 20

151 basis points is also lower than the 38-year average spread of 1.95%. 21

These utility bond yield spreads are evidence that the market perception of 22

utility risk is about average relative to this historical time period and demonstrate that 23

utilities continue to have strong access to capital in the current market. 24



Q HOW DO YOU DETERMINE WHERE A REASONABLE RISK PREMIUM IS IN THE 1

CURRENT MARKET? 2

A I observed the spread of Treasury securities relative to public utility bonds and 3

corporate bonds in gauging whether or not the risk premium in current market prices 4

is stable relative to the past. What this observation of market evidence clearly 5

demonstrates is that the valuations in the current market place an above average risk 6

premium on securities that have greater risk. 7

The observable yield spreads shown in Exhibit AB-15 illustrate that securities 8

of greater risk have recently had above average risk premiums relative to the long-9

term historical average risk premium. Specifically, A-rated utility bonds to Treasuries, 10

a relatively low-risk investment, have a yield spread in 2017 that has been lower than, 11

though comparable to that of, its long-term historical yield spread. The A-rated utility 12

bond yield spread is actually below the yield spread over the last 38 years. This is an 13

indication that low risk investments like A-rated utility bonds have premium values 14

relative to minimal risk Treasury securities. 15

Only recently have Baa-rated utility bond yield spreads gone below the 16

38-year average of 1.95%. For example, in 2016, the Baa-rated yield spread 17

averaged 2.08%, which is approximately 13 basis points above the long-term average 18

of 1.95%. While the higher risk Baa utility bond yields currently have a below-19

average yield spread of approximately 40 basis points (1.55% vs. 1.95%), there 20

appears to be more volatility in the spread. The higher risk Baa utility bond yields do 21

not have the same premium valuations as their lower risk A-rated utility bond yields, 22

and thus the yield spread for greater risk investments is wider than lower risk 23

investments. 24



This dynamic illustrates that securities with greater risk, such as Baa-rated 1

bonds versus A-rated bonds, have recently commanded above average risk premium 2

spreads in the marketplace. Utility equity securities are greater risk than Baa utility 3

bonds. Because greater risk securities appear to support an above-average risk 4

premium relative to historical averages, this would support an above-average risk 5

premium in measuring a fair return on equity for a utility stock or equity security. 6

Q WHAT IS YOUR RECOMMENDED RETURN FOR DTE BASED ON YOUR RISK 7

PREMIUM STUDY? 8

A While a risk premium closer to the long-term average could be warranted at this time, 9

to be conservative, I am recommending more weight to the high-end risk premium 10

estimates than the low-end. Hence, I propose to provide 75% weight to my high-end 11

risk premium estimates and 25% to the low-end. Applying these weights, the risk 12

premium for Treasury bond yields would be approximately 6.1%,24 which is 13

considerably higher than the 32-year average risk premium of 5.51% and reasonably 14

reflective of the 3.7% projected Treasury bond yield. A Treasury bond risk premium 15

of 6.1% and projected Treasury bond yield of 3.7% produce a risk premium estimate 16

of 9.80%. 17

Similarly, applying 75% weight to my high-end risk premium and 25% weight 18

to my low-end risk premium indicates a utility bond risk premium of 4.9%.25 This risk 19

premium is above the 32-year historical average risk premium of 4.13%. This risk 20

premium added to the current observable Baa utility bond yield of 4.37% produces an 21

estimated return on equity of approximately 9.30%. 22

24(4.25% * 25%) + (6.72% * 75%) = 6.1%. 25(2.88% * 25%) + (5.57% * 75%) = 4.9%.



Based on this methodology, my Treasury bond risk premium and my utility 1

bond risk premium indicate a return in the range of 9.3% to 9.8%, with a midpoint of 2

9.55%, rounded to 9.6%. 3

IV.F. Capital Asset Pricing Model (“CAPM”) 4

Q PLEASE DESCRIBE THE CAPM. 5

A The CAPM method of analysis is based upon the theory that the market-required rate 6

of return for a security is equal to the risk-free rate, plus a risk premium associated 7

with the specific security. This relationship between risk and return can be expressed 8

mathematically as follows: 9

Ri = Rf + Bi x (Rm - Rf) where: 10

Ri = Required return for stock i 11 Rf = Risk-free rate 12 Rm = Expected return for the market portfolio 13 Bi = Beta - Measure of the risk for stock 14

The stock-specific risk term in the above equation is beta. Beta represents 15

the investment risk that cannot be diversified away when the security is held in a 16

diversified portfolio. When stocks are held in a diversified portfolio, firm-specific risks 17

can be eliminated by balancing the portfolio with securities that react in the opposite 18

direction to firm-specific risk factors (e.g., business cycle, competition, product mix, 19

and production limitations). 20

The risks that cannot be eliminated when held in a diversified portfolio are 21

non-diversifiable risks. Non-diversifiable risks are related to the market in general 22

and referred to as systematic risks. Risks that can be eliminated by diversification are 23

non-systematic risks. In a broad sense, systematic risks are market risks and 24

non-systematic risks are business risks. The CAPM theory suggests the market will 25

not compensate investors for assuming risks that can be diversified away. Therefore, 26



the only risk investors will be compensated for are systematic, or non-diversifiable, 1

risks. The beta is a measure of the systematic, or non-diversifiable risks. 2

Q PLEASE DESCRIBE THE INPUTS TO YOUR CAPM. 3

A The CAPM requires an estimate of the market risk-free rate, the Company’s beta, and 4

the market risk premium. 5

Q WHAT DID YOU USE AS AN ESTIMATE OF THE MARKET RISK-FREE RATE? 6

A As previously noted, Blue Chip Financial Forecasts’ projected 30-year Treasury bond 7

yield is 3.70%.26 The current 30-year Treasury bond yield is 2.86%, as shown in 8

Exhibit AB-15. I used Blue Chip Financial Forecasts’ projected 30-year Treasury 9

bond yield of 3.70% for my CAPM analysis. 10

Q WHY DID YOU USE LONG-TERM TREASURY BOND YIELDS AS AN ESTIMATE 11

OF THE RISK-FREE RATE? 12

A Treasury securities are backed by the full faith and credit of the United States 13

government so long-term Treasury bonds are considered to have negligible credit 14

risk. Also, long-term Treasury bonds have an investment horizon similar to that of 15

common stock. As a result, investor-anticipated long-run inflation expectations are 16

reflected in both common stock required returns and long-term bond yields. 17

Therefore, the nominal risk-free rate (or expected inflation rate and real risk-free rate) 18

included in a long-term bond yield is a reasonable estimate of the nominal risk-free 19

rate included in common stock returns. 20

26Blue Chip Financial Forecasts, August 1, 2017 at 2.



Treasury bond yields, however, do include risk premiums related to 1

unanticipated future inflation and interest rates. A Treasury bond yield is not a 2

risk-free rate. Risk premiums related to unanticipated inflation and interest rates 3

reflect systematic market risks. Consequently, for companies with betas less than 4

1.0, using the Treasury bond yield as a proxy for the risk-free rate in the CAPM 5

analysis can produce an overstated estimate of the CAPM return. 6

Q WHAT BETA DID YOU USE IN YOUR ANALYSIS? 7

A As shown in Exhibit AB-16, the proxy group average Value Line beta estimate is 0.70. 8

Q HOW DID YOU DERIVE YOUR MARKET RISK PREMIUM ESTIMATE? 9

A I derived two market risk premium estimates: a forward-looking estimate and one 10

based on a long-term historical average. 11

The forward-looking estimate was derived by estimating the expected return 12

on the market (as represented by the S&P 500) and subtracting the risk-free rate from 13

this estimate. I estimated the expected return on the S&P 500 by adding an expected 14

inflation rate to the long-term historical arithmetic average real return on the market. 15

The real return on the market represents the achieved return above the rate of 16

inflation. 17



Duff & Phelps’ 2017 SBBI Yearbook estimates the historical arithmetic 1

average real market return over the period 1926 to 2016 as 8.9%.27 A current 2

consensus analysts’ inflation projection, as measured by the Consumer Price Index, 3

is 2.4%.28 Using these estimates, the expected market return is 11.50%.29 The 4

market risk premium then is the difference between the 11.50% expected market 5

return and my 3.70% risk-free rate estimate, or approximately 7.80%. 6

My historical estimate of the market risk premium was also calculated by using 7

data provided by Duff & Phelps in its 2017 SBBI Yearbook. Over the period 1926 8

through 2016, the Duff & Phelps study estimated that the arithmetic average of the 9

achieved total return on the S&P 500 was 12.0%30 and the total return on long-term 10

Treasury bonds was 6.00%.31 The indicated market risk premium is 6.0% (12.0% - 11

6.0% = 6.0%). 12

Q HOW DOES YOUR ESTIMATED MARKET RISK PREMIUM RANGE COMPARE TO 13

THAT ESTIMATED BY DUFF & PHELPS? 14

A The Duff & Phelps analysis indicates a market risk premium falls somewhere in the 15

range of 5.5% to 6.9%. My market risk premium falls in the range of 6.0% to 7.8%. 16

My average market risk premium of 6.9% is at the high-end of the Duff & Phelps 17

range. 18

Q HOW DOES DUFF & PHELPS MEASURE A MARKET RISK PREMIUM? 19

A Duff & Phelps makes several estimates of a forward-looking market risk premium 20

based on actual achieved data from the historical period of 1926 through 2016 as well 21

27Duff & Phelps, 2017 SBBI Yearbook at 6-18. 28Blue Chip Financial Forecasts, August 1, 2017 at 2. 29{ [ (1 + 0.089) (1 + 0.024) ] – 1 } 100.

30Duff & Phelps, 2017 Yearbook at 6-17. 31Id.



as normalized data. Using this data, Duff & Phelps estimates a market risk premium 1

derived from the total return on large company stocks (S&P 500), less the income 2

return on Treasury bonds. The total return includes capital appreciation, dividend or 3

coupon reinvestment returns, and annual yields received from coupons and/or 4

dividend payments. The income return, in contrast, only reflects the income return 5

received from dividend payments or coupon yields. 6

Duff & Phelps claims the income return is the only true risk-free rate 7

associated with Treasury bonds and is the best approximation of a truly risk-free 8

rate.32 I disagree with this assessment from Duff & Phelps because it does not reflect 9

a true investment option available to the marketplace and therefore does not produce 10

a legitimate estimate of the expected premium of investing in the stock market versus 11

that of Treasury bonds. Nevertheless, I will use Duff & Phelps’ conclusion to show 12

the reasonableness of my market risk premium estimates. 13

Duff & Phelps’ range is based on several methodologies. First, Duff & Phelps 14

estimates a market risk premium of 6.94% based on the difference between the total 15

market return on common stocks (S&P 500) less the income return on Treasury bond 16

investments over the 1926-2016 period. 17

Second, Duff & Phelps updated the Ibbotson & Chen supply-side model, 18

which found that the 6.94% market risk premium based on the S&P 500 was 19

influenced by an abnormal expansion of price-to-earnings (“P/E”) ratios relative to 20

earnings and dividend growth during the period, primarily over the last 30 years. Duff 21

& Phelps believes this abnormal P/E expansion is not sustainable.33 Therefore, Duff 22

& Phelps adjusted this market risk premium estimate to normalize the growth in the 23

P/E ratio to be more in line with the growth in dividends and earnings. Based on this 24

32Duff & Phelps 2017 Valuation Handbook at 3-32. 33Id. at 3-36.



alternative methodology, Duff & Phelps published a long-horizon supply-side market 1

risk premium of 5.97%.34 2

Finally, Duff & Phelps develops its own recommended equity, or market, risk 3

premium by employing an analysis that takes into consideration a wide range of 4

economic information, multiple risk premium estimation methodologies, and the 5

current state of the economy by observing measures such as the level of stock 6

indices and corporate spreads as indicators of perceived risk. Based on this 7

methodology, and utilizing a “normalized” risk-free rate of 3.5%, Duff & Phelps 8

concludes the current expected, or forward-looking, market risk premium is 5.5%, 9

implying an expected return on the market of 9.0%.35 10

Q WHAT ARE THE RESULTS OF YOUR CAPM ANALYSIS? 11

A As shown in Exhibit AB-17 based on my low market risk premium of 6.0% and my 12

high market risk premium of 7.8%, a risk-free rate of 3.7%, and a beta of 0.70, my 13

CAPM analysis produces a return of 7.89% to 9.15%. Based on my assessment of 14

risk premiums in the current market, as discussed above, I recommend the high-end 15

CAPM return estimate because it closely aligns the market risk premium with the 16

prevailing risk-free rate. I recommend a CAPM return of 9.15%. 17

IV.G. Return on Equity Summary 18

Q BASED ON THE RESULTS OF YOUR RETURN ON COMMON EQUITY 19

ANALYSES DESCRIBED ABOVE, WHAT RETURN ON COMMON EQUITY DO 20

YOU RECOMMEND FOR DTE? 21

A Based on my analyses, I estimate DTE’s current market cost of equity to be 9.35%. 22

34Id.

35Id. at 3-48.



TABLE 5

Return on Common Equity Summary Description Results

DCF 9.10%

Risk Premium 9.60%

CAPM

9.15%

My recommended return on common equity of 9.35% is at the midpoint of my 1

estimated range of 9.10% to 9.60%. As shown in Table 5 above, the high-end of my 2

estimated range is based on my risk premium studies. The low-end is based on my 3

DCF return. My CAPM result falls within my recommended range. 4

My return on equity estimates reflect observable market evidence, the impact 5

of Federal Reserve policies on current and expected long-term capital market costs, 6

an assessment of the current risk premium built into current market securities, and a 7

general assessment of the current investment risk characteristics of the electric utility 8

industry and the market’s demand for utility securities. 9

IV.H. Financial Integrity 10

Q WILL YOUR RECOMMENDED OVERALL RATE OF RETURN SUPPORT AN 11

INVESTMENT GRADE BOND RATING FOR DTE? 12

A Yes. I have reached this conclusion by comparing the key credit rating financial 13

ratios for DTE at my proposed return on equity and the Company’s proposed capital 14

structure to S&P’s benchmark financial ratios using S&P’s new credit metric ranges. 15



Q PLEASE DESCRIBE THE MOST RECENT S&P FINANCIAL RATIO CREDIT 1

METRIC METHODOLOGY. 2

A S&P publishes a matrix of financial ratios corresponding to its assessment of the 3

business risk of utility companies and related bond ratings. On May 27, 2009, S&P 4

expanded its matrix criteria by including additional business and financial risk 5

categories.36 6

Based on S&P’s most recent credit matrix, the business risk profile categories 7

are “Excellent,” “Strong,” “Satisfactory,” “Fair,” “Weak,” and “Vulnerable.” Most 8

utilities have a business risk profile of “Excellent” or “Strong.” 9

The financial risk profile categories are “Minimal,” “Modest,” “Intermediate,” 10

“Significant,” “Aggressive,” and “Highly Leveraged.” Most of the utilities have a 11

financial risk profile of “Significant” or “Aggressive.” DTE has an “Excellent” business 12

risk profile and a “Significant” financial risk profile. 13

DTE combines that profile with being in a middle category for financial risk 14

profile. This puts DTE in a strong position as viewed by financial analytics. 15

Q PLEASE DESCRIBE S&P’S USE OF THE FINANCIAL BENCHMARK RATIOS IN 16

ITS CREDIT RATING REVIEW. 17

A S&P evaluates a utility’s credit rating based on an assessment of its financial and 18

business risks. A combination of financial and business risks equates to the overall 19

assessment of DTE’s total credit risk exposure. On November 19, 2013, S&P 20

updated its methodology. In its update, S&P published a matrix of financial ratios that 21

defines the level of financial risk as a function of the level of business risk. 22

36S&P updated its 2008 credit metric guidelines in 2009, and incorporated utility metric benchmarks with the general corporate rating metrics. Standard & Poor’s RatingsDirect: “Criteria Methodology: Business Risk/Financial Risk Matrix Expanded,” May 27, 2009.



S&P publishes ranges for primary financial ratios that it uses as guidance in its 1

credit review for utility companies. The two core financial ratio benchmarks it relies 2

on in its credit rating process include: (1) Debt to Earnings Before Interest, Taxes, 3

Depreciation and Amortization (“EBITDA”); and (2) Funds From Operations (“FFO”) to 4

Total Debt.37 5

6

Q HOW DID YOU APPLY S&P’S FINANCIAL RATIOS TO TEST THE 7

REASONABLENESS OF YOUR RATE OF RETURN RECOMMENDATIONS? 8

A I calculated each of S&P’s financial ratios based on DTE’s cost of service for its retail 9

jurisdictional operations. While S&P would normally look at total consolidated DTE 10

financial ratios in its credit review process, my investigation in this proceeding is not 11

the same as S&P’s. I am attempting to judge the reasonableness of my proposed 12

cost of capital for rate-setting in DTE’s retail regulated utility operations. Hence, I am 13

attempting to determine whether my proposed rate of return will in turn support cash 14

flow metrics, balance sheet strength, and earnings that will support an investment 15

grade bond rating and DTE’s financial integrity. 16

17

Q DID YOU INCLUDE ANY OFF-BALANCE SHEET DEBT EQUIVALENTS? 18

A Yes, I did. The off-balance sheet debt related to operating leases and the associated 19

amortization and interest expense were obtained from the Company’s responses to 20

ABATE data requests 2.24 and 2.25, as shown on my Exhibit AB-18, page 3. 21

However, I will point out that in addition to the Company’s operating leases debt, DTE 22

also has significant pension and asset retirement obligations that need to be 23

managed more efficiently. 24

37Standard & Poor’s RatingsDirect: “Criteria: Corporate Methodology,” November 19, 2013.



Q PLEASE DESCRIBE THE RESULTS OF THIS CREDIT METRIC ANALYSIS AS IT 1

RELATES TO DTE. 2

A The S&P financial metric calculations for DTE at a 9.35% return are developed on 3

Exhibit AB-18, page 1. The credit metrics produced below, with DTE’s financial risk 4

profile from S&P of “Significant” and business risk score by S&P of “Excellent,” will be 5

used to assess the strength of the credit metrics based on DTE’s retail operations in 6

the state of Minnesota. 7

Based on an equity return of 9.35%, DTE will be provided an opportunity to 8

produce a debt to Earnings Before Interest, Taxes, Depreciation and Amortization 9

(“EBITDA”) ratio of 3.9x. This is within S&P’s “Intermediate” guideline range of 3.5x 10

to 4.5x.”38 This ratio supports an investment grade credit rating. 11

DTE’s retail operations FFO to total debt coverage at a 9.35% equity return is 12

20.9%, which is within S&P’s “Significant” metric guideline range of 13% to 23%. This 13

FFO/total debt ratio will support an investment grade bond rating. 14

At my recommended return on equity of 9.35%, my proposed capital structure 15

and the Company’s embedded debt, DTE’s financial credit metrics will continue to 16

support credit ratings at an investment grade utility level. 17

38Id.



V. RESPONSE TO DTE 1 WITNESS DR. MICHAEL VILBERT 2

V.A. Summary of Rebuttal 3

Q WHAT RETURN ON COMMON EQUITY IS DTE PROPOSING IN THIS 4

PROCEEDING? 5

A DTE’s proposed return on equity is supported by its witness Dr. Michael Vilbert. He 6

recommends a return on equity for DTE in the range of 9.75% to 10.75%, with a point 7

estimate of 10.5% (Vilbert Direct at 6). 8

Q PLEASE DESCRIBE DR. VILBERT’S METHODOLOGY SUPPORTING HIS 9

RETURN ON COMMON EQUITY. 10

A Dr. Vilbert arrived at his estimate using several models: a traditional CAPM and an 11

empirical CAPM (“ECAPM”), a simple DCF, a multi-stage growth DCF, and a risk 12

premium model using a regression formula derived from allowed returns on equity 13

and long-term Treasury yields. These models were applied to a sample of 28 utility 14

companies, which Dr. Vilbert found had risk comparable to DTE. (Vilbert Direct at 15

33). Dr. Vilbert also developed a subsample, which includes 9 electric utilities that 16

have net plant greater than $6 billion but less than $20 billion, as established by ALJ’s 17

order in Case No. U-18014. However, Dr. Vilbert found that the size restriction does 18

not produce materially different results for the subsample. 19

Q IS DR. VILBERT’S ESTIMATED RETURN ON EQUITY FOR DTE REASONABLE? 20

A No. Dr. Vilbert’s recommended return on equity of 10.50% for DTE is excessive and 21

unreasonable for a low-risk regulated utility company. Further, Dr. Vilbert asserts that 22

considering DTE’s extensive capital expenditure program and increased operating 23

leverage relative to the proxy group, along with his 10 basis points adder to account 24



for past unrecovered flotation costs, warrants a return in the upper end of his range. 1

(Vilbert Direct at 63). The unreasonableness of Dr. Vilbert’s recommendation is 2

evident from a detailed assessment of the rate of return models supporting his 3

recommendation in this proceeding. 4

Q PLEASE SUMMARIZE DR. VILBERT’S RETURN ON EQUITY STUDY RESULTS. 5

A Dr. Vilbert’s return on equity study results are summarized in Table 6 below. 6

TABLE 6

Summary of Dr. Vilbert’s Results

Dr. Vilbert’s Results Model

Model Results

ATWACC Adder

Recommended ROE

Adjusted ROE

(1) (2) (3) (4) CAPM Traditional CAPM 8.7% - 9.1% 0.6% - 0.7% 9.3% - 9.8% 8.7% - 9.1% ECAPM (0.5%) 8.8% - 9.3% 0.6% 9.4% - 9.9% Reject ECAPM (1.5%) 9.1% - 9.6% 0.7% 9.8% - 10.3% Reject Traditional CAPM (Hamada) 8.9% - 9.4% Reject ECAPM (0.5%) (Hamada) 9.0% - 9.6% Reject ECAPM (1.5%) (Hamada) 9.3% - 9.9% Reject DCF Simple (1/4 Growth) 9.5% 1.4% 10.9% 9.5% Multi-Stage (Blue Chip 4.1%) 8.0% 1.1% 9.1% 8.0% Simple (Sensitivity) 9.2% 1.3% 10.5% 9.2% Multi-Stage (Sensitivity) 7.9% 1.0% 8.9% 7.9% Risk Premium 10.4% 9.8% Range 9.75% - 10.75% 8.7% - 9.8%

Requested ROE 10.50%

_______________ ROE = Return on Equity ATWACC = After-Tax Weighted Average Cost of Capital



As shown in Table 6 above, the model return on equity results of Dr. Vilbert’s 1

studies applied to his proxy group indicate that DTE’s current market return on equity 2

is in the range of 7.9% to 9.5% based on his DCF and CAPM studies, and 10.4% 3

based on his risk premium study. 4

He then increases his market return on equity estimate by adding a return on 5

equity adder in the range of 0.6% to 1.4% using an After-Tax Weighted Average Cost 6

of Capital (“ATWACC”) methodology. This ATWACC adder increases his 7

recommended range up to 10.25% to 10.75%. Dr. Vilbert asserts this ATWACC 8

return on equity adder is necessary to properly recognize DTE’s financial risk when 9

applying a market return on equity to its book value common equity. (Vilbert Direct at 10

12). 11

Q DO DR. VILBERT’S RETURN ON EQUITY MODEL RESULTS SUPPORT THE 12

COMPANY’S REQUESTED 10.5% RETURN ON EQUITY, OR EVEN THE RETURN 13

ON EQUITY RANGE HE RECOMMENDS? 14

A No. As described below and as shown in Table 6 above under Column 4, 15

Dr. Vilbert’s own studies, adjusted to remove his flawed ATWACC return on equity 16

adder and incorporate reasonable adjustments, would only support a return on equity 17

in the range of 8.7% to 9.8%. 18

Q PLEASE DESCRIBE THE ISSUES YOU HAVE WITH DR. VILBERT’S ANALYSES. 19

A The issues and concerns I have with Dr. Vilbert’s analyses in support of the 20

Company’s requested return on equity include the following: 21

1. He includes an ATWACC adjustment to his DCF return estimate. 22

2. For his CAPM analysis he includes both an ATWACC, and alternatively a 23 leveraged beta adjustment to the CAPM results. 24



3. He also relies on an ECAPM analysis and includes adders for ATWACC and 1

leveraged beta adjustments. In addition to my concerns for these two adders, 2 Dr. Vilbert’s ECAPM analysis is miscalculated because he uses adjusted betas 3 within an ECAPM format. This is inappropriate because an adjusted beta 4 accomplishes the same thing as an ECAPM analysis. Both levelize the security 5 market line in measuring a fair return on equity based on a given level of 6 systematic risk or beta risk. His ECAPM analysis double counts the increase in 7 the CAPM return estimates for companies with betas less than 1, which reflects 8 his proxy group and DTE in this case. 9

4. I take issue with his risk premium analysis because it is based only on a simple 10 inverse relationship between equity risk premiums and interest rates. Equity risk 11 premiums should be measured based on the current market’s assessment of 12 investment risk of equity versus debt securities. While interest rate changes are 13 one factor in assessing this risk differential, they are not the only factor. Dr. 14 Vilbert’s model is simply unreliable. 15

5. Finally, Dr. Vilbert’s DCF return results are upwardly biased and based on 16 excessive growth rate estimates and should be used only as high-end cost of 17 equity returns. 18

V.B. ATWACC 19

Q PLEASE DESCRIBE DR. VILBERT’S PROPOSED ATWACC RETURN ON EQUITY 20

ADJUSTMENT. 21

A Dr. Vilbert uses the ATWACC to increase the estimated market return on equity 22

based on his CAPM and DCF analyses, to a higher return that can be applied to 23

DTE’s book value common equity. He does this by calculating the ATWACC using 24

the market return on equity estimate (CAPM and DCF estimates) and market 25

weighted capital structures for each proxy company. He then uses this market 26

ATWACC for each proxy group company and applies DTE’s capital structure 27

parameters to produce an ATWACC adjusted return for DTE. 28

These ATWACC adjustments to his return on equity estimates are discussed 29

on pages 10-15 of his direct testimony, and developed in the workpapers 30

accompanying his schedules for the CAPM and DCF return estimates. 31



Q WHY DOES DR. VILBERT BELIEVE THE ATWACC ADJUSTMENT TO HIS CAPM 1

AND DCF RETURN ESTIMATES IS REASONABLE? 2

A Dr. Vilbert technically suggests that the sample firms’ financial risk is different based 3

on the market value of common equity than is the financial risk based on the book 4

value of common equity. Therefore, Dr. Vilbert proposes to upwardly adjust his 5

CAPM and DCF model results for the difference in financial risk based on the proxy 6

companies’ market value of common equity, compared to their book value common 7

equity. (Vilbert Direct at 13) 8

He is in effect suggesting that firms have a different level of financial risk, 9

depending on whether one is observing their market value capital structure or the 10

book value capital structure. 11

Q IS THE ATWACC ADJUSTMENT TO THE BASE RETURN ON EQUITY 12

REASONABLE? 13

A No. This adjustment is flawed for several reasons. First, the Company only has one 14

level of financial risk, not two. Investors do not assess a different amount of financial 15

risk for market and book common equity valuation. Rather, financial risk is a singular 16

risk factor, which describes its financial capital structure, cash flow strength to support 17

financial obligations, and default provisions in its financial obligations. 18

Dr. Vilbert’s belief that there are two levels of financial risk is simply not 19

supported. Indeed, it is contradicted by data used by independent market 20

participants to assess investment risk and security valuation. For example, S&P and 21

Value Line provide general assessments of the financial and operating (or total 22

investment) risks to the market investors. S&P does this in terms of rating the credit 23

quality of the utility, based on the utility’s ability to produce cash flows adequate to 24



meet its book value financial obligations. S&P assesses a company’s risk of failing to 1

meet its financial obligations and is a direct assessment of a company’s financial risk. 2

Value Line provides information to the market participants to help them assess 3

the total investment risk including both financial risk and business risk for the utilities 4

and other stock investments. The data Value Line provides to investors concerning 5

these investment risk characteristics relates to book value factors, including book 6

value capital structure, book value cash flows, and book value earnings. All these 7

book value factors are then used by investors to assess investment risk which allows 8

them to derive market value stock prices. The book value parameters are an integral 9

part of assessing risk and allowing investors to produce market valuations. 10

There is not a difference in financial risk for a company if you are examining 11

its book value financial risk or market value financial risk. Rather, the book value and 12

market value financial risks for the same company are interconnected to one another, 13

and produce a single level of financial risk for the company. 14

Q DO YOU BELIEVE THAT THE ATWACC METHODOLOGY IS REASONABLE 15

POLICY FOR SETTING AN APPROVED RETURN ON EQUITY? 16

A No. As I testified in the last DTE rate case, which testimony the ALJ and the 17

Commission credited and accepted, the ATWACC methodology is poor regulatory 18

policy and should be rejected for several reasons: 19

1. It does not produce clear and transparent objectives for management to use that 20 will accomplish the objective of minimizing its overall rate of return while 21 preserving its financial integrity. Therefore, a regulatory commission cannot 22 oversee the reasonableness and prudence of management decisions in 23 managing its capital structure. Under the ATWACC theory, management’s 24 decisions to manage its capital structure can be skewed by changes in market 25 value which change the market value capitalization mix. Management simply has 26 no control over the market value capital structure, but it does have control over 27 the book value capital structure. As such, setting the rate of return and measuring 28 risk based on book value capital structure creates a more transparent and clear 29



path for regulatory oversight of management’s effort to maintain a balanced and 1 reasonable capital structure. 2

2. The ATWACC introduces significant additional instability and unreliability into the 3 utility’s cost of service and tariff rates. Book value capital structure weights permit 4 the utility to hedge or lock-in a large portion of capital market costs in arriving at 5 the rate of return used to set rates. This rate of return cost hedge stabilizes the 6 utility’s cost of service, which in turn helps stabilize utility rates. A stable method 7 of setting rates also allows investors to more accurately assess the future 8 earnings and cash flow outlooks for the utility, which will reduce the business risk 9 of the utility. The ATWACC, on the other hand, will produce an overall rate of 10 return which will change based on both changes to market value capital structure 11 weights and also based on changes to market capital costs. Hence, a major 12 component of the cost structure of the utility (i.e., the overall rate of return) will 13 vary based on market forces from rate case to rate case. This rate of return 14 variability will introduce significant instability in the utility’s cost of service (via rate 15 of return changes) and hence instability in tariff rates. Introducing additional 16 instability and unreliability in the utility’s cost structure and rates will not benefit 17 either investors or ratepayers. 18

3. The ATWACC artificially increases rates to produce an excessive return on equity 19 opportunity for utility investors. Inflating utility’s rates to provide this excessive 20 earnings opportunity is unjust and unreasonable and should be rejected. 21

Q IS THE ATWACC METHODOLOGY PROPOSED BY DR. VILBERT COMMONLY 22

ACCEPTED IN ELECTRIC RATE-SETTING PROCEEDINGS IN THE UNITED 23

STATES? 24

A No. As Dr. Vilbert states at page 14 of his Direct testimony, “[…] use of the ATWACC 25

is not prevalent in the U.S.” Importantly, this Commission has recently rejected Dr. 26

Vilbert’s application of the ATWACC methodology in U-18014, stating: “[…] the 27

Commission does agree with the PFD that little or no weight should be given to the 28

utility’s ATWACC calculations.” 39 29

39Michigan Public Service Commission, Case No. U-18014, Final Order, page 66, January 31,

2017.



V.C. Dr. Vilbert’s CAPM Analysis 1

Q PLEASE DESCRIBE DR. VILBERT’S CAPM ANALYSIS. 2

A Dr. Vilbert develops two versions of the CAPM model, a traditional CAPM and an 3

ECAPM.40 4

In his analyses, Dr. Vilbert relied upon two different scenarios. In the first 5

scenario, he used a projected risk-free rate of 3.8% with a market risk premium of 6

6.9%. In this scenario, Dr. Vilbert’s risk-free rate is based on a Blue Chip report from 7

January 10, 2017 of 3.1% for 2018, including adjustments for term to maturity of 8

0.30%, and outlooks for changes in yield spreads between Treasuries and corporate 9

bonds of 0.40 basis points with lower historical market risk premiums. In the second 10

scenario, he used a risk-free rate of 3.55% with a market risk premium of 7.9%.41 11

As shown in Table 7 below, based on his two scenarios, Dr. Vilbert produced 12

a traditional CAPM before any adders in the range of 8.7% to 9.1% (Column 1). 13

Similarly, applying the ECAPM before any adders, he produces a return estimate in 14

the range of 8.8% to 9.6% (Column 1). 15

40Vilbert Direct at 43-57. 41Id. at 24-27 and 55.



To these barebones or “base” CAPM returns, Dr. Vilbert proposes either one 1

of two return on equity adders. First, he proposes to add to his base CAPM return 2

estimate an ATWACC return on equity adder in the range of approximately 60 to 70 3

basis points. For the reasons outlined above, this ATWACC adder should be rejected 4

as unreliable and an imbalanced return on equity component. Alternatively, Dr. 5

Vilbert proposes a return on equity adder to reflect a leveraged beta adjustment. This 6

leveraged beta adjustment adds approximately 20 to 40 basis points to the base 7

CAPM return. 8

Dr. Vilbert’s leverage adjustment, however, is unreliable and flawed and 9

should be rejected. This leverage adjustment return on equity adder to the base 10

CAPM return estimate produces an excessive and unreasonable return on equity for 11

DTE. 12

Line ATWACC Hamada Tax Hamada(5) (6) (7)

Traditional CAPM

1 Scenario 1 8.7% 1 9.3% 3 9.0% 4 8.9% 4 0.63% 0.33% 0.23%

2 Scenario 2 9.1% 2 9.8% 3 9.5% 5 9.4% 5 0.68% 0.38% 0.28%

Empirical CAPM (α = 0.5%)

3 Scenario 1 8.8% 1 9.4% 3 9.1% 4 9.0% 4 0.58% 0.28% 0.18%

4 Scenario 2 9.3% 2 9.9% 3 9.6% 5 9.5% 5 0.63% 0.33% 0.23%

Empirical CAPM (α = 1.5%)

5 Scenario 1 9.1% 1 9.8% 3 9.4% 4 9.3% 4 0.69% 0.29% 0.19%

6 Scenario 2 9.6% 2 10.3% 3 9.9% 5 9.8% 5 0.73% 0.33% 0.23%

Sources:1 Exhibit A-11, Schedule D6.10 at 1.2 Exhibit A-11, Schedule D6.10 at 2.3 Exhibit A-11, Schedule D6.12.4 Exhibit A-11, Schedule D6.15 at 1.5 Exhibit A-11, Schedule D6.15 at 2.

Dr. Vilbert's CAPM Results

TABLE 7

Adjusted ROEDescription

AddersBase Tax Hamada

(4)(1)ATWACC

(2)Hamada

(3)



Q PLEASE EXPLAIN DR. VILBERT’S LEVERAGED BETA ADJUSTMENT. 1

A As an alternative to his ATWACC adder to his CAPM results, Dr. Vilbert measures an 2

additional return on equity adder based on leveraged adjustments to the beta 3

component of the CAPM study. In producing this adder, he applies the Hamada 4

method for de-levering and re-levering the beta component in both the CAPM and the 5

ECAPM with and without the effect of income taxes.42 6

Applying the Hamada formula increases the Value Line beta from 0.71 to 0.75 7

(without taxes) and 0.74 (with taxes).43 The Hamada model produces CAPM results 8

in the range of 8.9% to 9.5% and ECAPM results in the range of 9.0% to 9.8%.44 9

Q IS DR. VILBERT’S APPLICATION OF THE LEVERAGED BETA RETURN ON 10

EQUITY ADDER REASONABLE? 11

A No. Dr. Vilbert’s application of the Hamada adjustment in his CAPM and ECAPM 12

analyses is inappropriate in determining DTE’s cost of equity. While the Hamada 13

adjustment may be an empirically recognized adjustment to raw or unadjusted beta 14

estimates, it has not been shown to be applicable to an already-adjusted Value Line 15

beta. While Dr. Vilbert discusses at length the appropriateness for each individual 16

adjustment he makes to the CAPM model and its components, he has not provided 17

empirical support for all the adjustments he makes to be used in concert with one 18

another. I am unaware of any unchallenged academic support for the use of a 19

Hamada leverage adjustment to an already Blume adjusted (Value Line) beta. 20

42Vilbert Direct at 16-19. 43Exhibit A-11, Schedule D6.13 and D6.14. 44Id.



Q DO YOU HAVE ANY OTHER CONCERNS WITH DR. VILBERT’S CAPM RETURN 1

ESTIMATES? 2

A Yes. I also have concerns with Dr. Vilbert’s development of an ECAPM return 3

estimates. Specifically, Dr. Vilbert included an adjusted beta within his ECAPM 4

studies. This adjustment is inconsistent with the academic research supporting the 5

development of an ECAPM methodology.45 Bottom line, using adjusted betas within 6

an ECAPM study double counts the purpose of the ECAPM study – that is, to flatten 7

the security market line and increase a CAPM return estimate for companies with 8

betas less than 1, and decrease the CAPM return estimate for betas greater than 1. 9

Dr. Vilbert discusses the objective of the ECAPM at pages 50-54 of his 10

testimony. As shown in Dr. Vilbert’s Figure 4, the ECAPM will raise the intercept 11

point of the security market line and flatten the slope. Again, this has the effect of 12

increasing CAPM return estimates for companies with betas less than 1, and 13

decreasing the CAPM return estimates for companies with betas greater than 1. 14

Importantly, however, the use of an adjusted beta such as those published by Value 15

Line, produces comparable adjustments to the security market line and CAPM return 16

estimate. In effect, using an adjusted beta within an ECAPM study has the effect of a 17

double adjustment to the slope and intercept of the security market line. This is 18

illustrated in my Figure 4 below. 19

45See Black, Fischer, “Beta and Return,” The Journal of Portfolio Management, Fall 1993,

8-18; and Black, Fischer, Michael C. Jensen and Myron Scholes, “The Capital Asset Pricing Model: Some Empirical Tests,” 1972.



Figure 4

As shown in Figure 4 above, the CAPM using a Value Line beta, versus a 1

CAPM using a raw beta shows that the Value Line beta raises the intercept slope and 2

flattens the security market line. Further, the ECAPM using a raw beta, and an 3

ECAPM using a Value Line beta, have a magnified effect of increasing the intercept 4

slope and further flattening the security market line. 5

There is simply no legitimate basis to use an adjusted beta within an ECAPM 6

because they are designed to produce the same effect on the CAPM return estimate. 7

Q IS THERE ANY ACADEMIC SUPPORT FOR DR. VILBERT’S PROPOSED USE OF 8

AN ADJUSTED BETA IN AN ECAPM STUDY? 9

A No. I am unaware of any peer reviewed academic study showing that the ECAPM is 10

more accurate using adjusted betas. To my knowledge, the ECAPM has been tested 11

Assumptions:Market Risk Premium is 7.50%Risk-Free Rate is 3.50%

0.00%

2.00%

4.00%

6.00%

8.00%

10.00%

12.00%

14.00%

16.00%

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00 1.10 1.20 1.30 1.40

0.35 0.42 0.48 0.55 0.62 0.69 0.75 0.82 0.89 0.95 1.02 1.09 1.15 1.22 1.29

Expected Return

Beta

Variations of the CAPM

CAPM ‐ Raw Beta

CAPM ‐ VL Beta

ECAPM ‐ Raw Beta

ECAPM ‐ VL Beta

Raw Beta

Value Line Beta



and published with raw beta estimates. Further, Dr. Vilbert has not provided any 1

academic research that was subjected to academic peer review, which supports his 2

proposed use of an adjusted beta in an ECAPM study. As such, the practice of using 3

an adjusted beta in an ECAPM study is simply not supported by academic research. 4

While I have encountered the ECAPM analysis in several proceedings over the last 5

few years, I have failed to find any utility witness in support of this methodology that 6

can provide academic support for use of an ECAPM analysis with an adjusted beta 7

such as a Value Line published beta. Rather, the ECAPM is designed to be used 8

with an unadjusted beta. Support for this academic study is identified above. For the 9

reasons outlined above, Dr. Vilbert’s proposal to use adjusted betas in an ECAPM 10

study should be rejected. 11

Q IS THERE A WAY TO MORE ACCURATELY MEASURE THE COST OF EQUITY 12

FOR DTE USING THE ECAPM? 13

A Because the makeup of the ECAPM model is based on a raw or regression beta, if 14

the appropriate beta is used in the ECAPM it would produce a reasonable return 15

estimate. As such, if the adjusted Value Line betas are modified to remove Value 16

Line’s adjustment to the regression beta for the long-term tendency to converge on 17

the market beta of 1, the Value Line unadjusted beta can be properly used in the 18

ECAPM study. 19

Removing the beta adjustment to reflect a raw beta for an ECAPM will 20

generally produce a more accurate ECAPM result. For example, Dr. Vilbert produces 21

an average CAPM cost for his proxy group of 8.7%, and an ECAPM return of 9.1% (α 22

= 0.5%). The average proxy group adjusted Value Line beta to produce a 8.7% 23

CAPM return is approximately 0.71. This would equate to an unadjusted/raw beta 24



estimate of 0.54.46 Using a raw beta of 0.54 and Dr. Vilbert’s ECAPM methodology 1

produces an ECAPM estimate of approximately 8.20%.47 2

V.D. Dr. Vilbert’s Risk Premium Analyses 3

Q PLEASE DESCRIBE DR. VILBERT’S RISK PREMIUM ANALYSES. 4

A As discussed on pages 57-59 of Dr. Vilbert’s testimony, he measured the relationship 5

of authorized returns on equity to long-term Treasury yields during the period 6

1990-2016 through a regression analysis.48 He then uses the resulting regression 7

formula to predict a risk premium based on a forecasted long-term Treasury yield of 8

3.8% from January 2017. This regression formula and his forecasted Treasury yield 9

of 3.8% produced an estimated risk premium of 6.59%, which resulted in a return on 10

equity of 10.39%, rounded to 10.4%.49 11

Q DO YOU HAVE ANY ISSUES WITH DR. VILBERT’S RISK PREMIUM ANALYSIS? 12

A Yes. Dr. Vilbert’s regression model reflects a simplistic, linear relationship between 13

equity risk premiums and interest rates. This overly simplistic relationship is not 14

based on basic risk and return valuation principles. While academic studies have 15

shown that there has been a positive and negative linear relationship between these 16

variables in the past, these studies have found that the relationship changes over 17

time and is influenced by changes in perception of the investment risk of bond 18

46(Adj. Beta - 0.35)/0.67 = Raw Bea. (0.71 – 0.35)/0.67 = 0.54. 47ECAPM (Raw Beta) = RF + 0.19 x MRP + 0.81 x MRP x Raw Beta. ECAPM (0.54) = 3.8% + 0.21 x 6.9% + 0.79 x 6.9% x 0.54 = 8.2%. 48Exhibit A-11, Schedule D6.16. 49 Vilbert Direct Testimony at 59.



investments relative to equity investments, rather than only changes to nominal 1

interest rates.50 2

In the 1980s, equity risk premiums were inversely related to interest rates, but 3

that was likely attributable to the interest rate volatility that existed at that time. When 4

interest rates were more volatile, the relative perception of bond investment risk 5

increased relative to the investment risk of equities. This changing investment risk 6

perception caused changes in equity risk premiums. 7

In today’s marketplace, interest rate volatility is not as extreme as it was 8

during the 1980s.51 Nevertheless, changes in the perceived risk of bond investments 9

relative to equity investments still drive changes in equity premiums. However, a 10

relative investment risk differential cannot be measured simply by observing nominal 11

interest rates. Changes in nominal interest rates are highly influenced by changes to 12

inflation outlooks, which also change equity return expectations. As such, the 13

relevant factor needed to explain changes in equity risk premiums is the relative 14

changes to the risk of equity versus debt securities investments, and not simply 15

changes in interest rates. 16

Importantly, Dr. Vilbert’s analysis simply ignores investment risk differentials. 17

He bases his adjustment to the equity risk premium exclusively on changes in 18

nominal interest rates. This is a flawed methodology and does not produce accurate 19

or reliable risk premium estimates. As such, his argument should be rejected by the 20

Commission. 21

50“The Market Risk Premium: Expectational Estimates Using Analysts’ Forecasts,” Robert S.

Harris and Felicia C. Marston, Journal of Applied Finance, Volume 11, No. 1, 2001; “The Risk Premium Approach to Measuring a Utility’s Cost of Equity,” Eugene F. Brigham, Dilip K. Shome, and Steve R. Vinson, Financial Management, Spring 1985.

51Duff & Phelps, 2017 SBBI Yearbook 6-7 – 6-10.



Q CAN DR. VILBERT’S RISK PREMIUM STUDY BE MODIFIED TO PRODUCE A 1

REASONABLE RETURN FOR DTE? 2

A Yes. Disregarding Dr. Vilbert’s simplistic inverse relationship and using a projected 3

Treasury yield published by independent economists of 3.7%, and adding this 3.7% 4

Treasury yield to an equity risk premium of 6.1%, produces a risk premium return on 5

equity for DTE of 9.8%. 6

V.E. Dr. Vilbert’s DCF Analyses 7

Q PLEASE DESCRIBE DR. VILBERT’S DCF ANALYSIS. 8

A Dr. Vilbert developed a constant growth DCF model based on a combined growth 9

rate from IBES consensus analysts’ and Value Line growth rate projections. 10

Dr. Vilbert’s DCF model results fall in the range 7.9% to 9.5%52, with the higher 11

estimate produced by his simple constant growth DCF model. He applied an 12

ATWACC adjustment to the DCF model results and increased the DCF range to 8.9% 13

to 10.9%.53 14

Dr. Vilbert also develops a sensitivity analysis for his simple and multi-stage 15

DCF models, to account for the extremely high growth rate for Avangrid of over 23% 16

from Value Line and 8.0% from IBES. He also excludes two estimates (AEP and 17

Entergy Corp.) from the average because their cost of equity was not 150 basis 18

points higher than the cost of debt. This sensitivity methodology produced slightly 19

lower results. He concludes that even though he did not make any specific 20

adjustments to the DCF estimates to account for the current market turmoil his 21

multi-stage DCF results in the range of 8.9% to 9.1% (including the ATWACC 22

adjustment) are consistent with his other methodologies. Dr. Vilbert believes that the 23

52Exhibit A-11, Schedule D6.6. 53Vilbert Direct Testimony at 64-65.



DCF estimates are less susceptible to economic uncertainties and he places higher 1

reliance on his DCF results. (Vilbert Direct at 65). 2

Q PLEASE DESCRIBE THE ISSUES YOU HAVE WITH DR. VILBERT’S DCF 3

ANALYSIS. 4

A My primary concern with Dr. Vilbert’s DCF analysis, as I discussed at length above, is 5

the use of the ATWACC methodology is inappropriate and should be rejected. 6

While I appreciate Dr. Vilbert’s attempt to gauge the reasonableness of his 7

DCF results by taking into consideration the high and low outliers in his DCF results, I 8

do not necessarily agree with his methodology. Measuring the median of the proxy 9

group results is the more appropriate measure of central tendency in the event of 10

outlier results. The median of Dr. Vilbert’s DCF results is approximately 9.15%, which 11

is in line with his sensitivity analysis results and my constant growth DCF results. 12

Therefore, I will not take issue with Dr. Vilbert’s removing of low outlier results at this 13

time. 14

Q DID DR. VILBERT ALSO OFFER AN ASSESSMENT OF CURRENT MARKET 15

CONDITIONS IN SUPPORT OF HIS RECOMMENDED RETURN ON EQUITY? 16

A Yes. Dr. Vilbert suggests a few factors that gauge investor sentiment, including 17

interest rates, yield spreads and P/E ratios.54 He concludes that low interest rates 18

resulted in high utility spreads, which remained elevated relative to historical 19

averages. 20

54Vilbert Direct at 19-24.



Q DO YOU BELIEVE THAT DR. VILBERT’S USE OF THESE MARKET SENTIMENTS 1

SUPPORTS HIS FINDINGS THAT DTE’S MARKET COST OF EQUITY IS 10.5%? 2

A No. In many instances Dr. Vilbert’s analysis simply ignores market sentiments 3

favorable toward utility companies and instead lumps utility investments in with 4

higher- risk corporate investments. A fair analysis of utility securities shows the 5

market generally regards utility securities as low-risk investment instruments and 6

supports the finding that utilities’ cost of capital is very low in today’s marketplace. 7

Q WHAT IS THE MARKET SENTIMENT FOR UTILITY INVESTMENTS? 8

A I have gauged market/investor perceptions in utility risk today in Exhibit AB-14, where 9

I show the yield spread between utility bonds and Treasury bonds over the last 10

37 years. As shown in this schedule, the average utility bond yield spreads over 11

Treasury bonds for “A” and “Baa” rated utility bonds for this historical period are 12

1.51% and 1.95%, respectively. The utility bond yield spreads over Treasury bonds 13

for “A” and “Baa” rated utilities for 2016 were 1.33% and 2.08%, respectively. The 14

yield spreads for the first three months of 2017 were considerably lower, 1.14% (A) 15

and 1.56% (Baa). The current average “A” rated utility bond yield spread over 16

Treasury bond yields is now lower than the 37-year average spread. The current 17

“Baa” rated utility bond yield spread over Treasury bond yields is also lower than the 18

37-year average spread. 19

These yield spreads show that utility capital costs are lower than they have 20

been historically relative to Treasury bond yields, and also that the bond yield 21

spreads expand above historical norms as the investment risk of the security 22

increases. This information allows for an informed determination of the current 23



market sentiment for utility investments. Currently, the market is placing high value 1

on utility securities recognizing their low risk and stable characteristics. 2

For example, this is illustrated by my Exhibit AB-14, under column 11 showing 3

the spread between “A” rated utility bond yields and “Aaa” rated corporate bond 4

yields. Currently, the spread is approximately 0.28%. This is a relatively low spread 5

over the 37-year time horizon. Indeed, current spreads of utility versus high-grade 6

corporate bond yields are at the lowest level they have been in most periods over the 7

last 37 years. This is also reflective of the spreads between “Baa” utility bond yields 8

relative to “Baa” corporate bond yields. Currently, utility bonds are trading at a 9

premium to corporate bonds. This has been largely the case during the significant 10

market turbulence that has occurred over the last five to eight years. However, over 11

longer periods of time, utility bond yields on average trade at parity to a premium to 12

corporate “Baa” rated bond yields. The current strong utility bond valuation is an 13

indication of the market’s sentiment that utility bonds have lower risk than general 14

corporate bonds and are generally regarded as a safe haven by the investment 15

industry. 16

Further, other measures of utility stock valuations also support a robust 17

market for utility stocks. As shown on my Exhibit AB-2, utility valuation measures – 18

e.g., price-to-earnings ratio, market-to-book ratio, and market price to cash flow ratio 19

– show stock valuation measures for the proxy groups are robust. For example, for 20

the proxy group, the current price-to-earnings ratio is comparable to and the cash 21

flow ratio is stronger than the 15-year average valuation metrics. 22

For all these reasons, direct assessments of valuation measures and market 23

sentiment toward utility securities support the credit rating agencies’ findings, as 24

quoted above, that the utility industry is largely regarded as a low-risk, safe haven 25



investment. All of this supports my finding that utilities’ market cost of equity is very 1

low in today’s very low cost capital market environment. 2

Q DO YOU HAVE ANY FURTHER COMMENTS IN REGARD TO DR. VILBERT’S 3

INTEREST RATE PROJECTIONS? 4

A Yes. First, it is simply not known how much, if any, long-term interest rates will 5

increase from current levels or whether they have already fully accounted for the 6

termination of the Federal Reserve’s Quantitative Easing program and the increase in 7

the Federal Funds Rate. Nevertheless, I do agree that this Federal Reserve program 8

introduced risk or uncertainty in long-term interest rate markets. Because of this 9

uncertainty, caution should be taken in estimating DTE’s current return on common 10

equity in this case. However, as noted by EEI, the increase in short-term interest 11

rates had no impact on longer-term yields that “remain at historically low levels and 12

are influenced more by the level of inflation and economic strength than by the 13

Federal Reserve’s short-term rate policy.”55 14

Second, I would note DTE is largely shielded from significant changes in 15

capital market costs. To the extent interest rates ultimately increase above current 16

levels, which may have an impact on required returns on common equity, at that point 17

in time DTE, like all other utilities, can file to change rates to restate its authorized 18

rate of return at the prevailing market levels. 19

. Finally, while current observable interest rates are actual market data that 20

provides a measure of the current cost of capital, the accuracy of forecasted interest 21

rates is problematic at best. 22

55EEI Q4 2015 Financial Update: “Stock Performance” at 6.



Q WHY DO YOU BELIEVE THAT THE ACCURACY OF FORECASTED INTEREST 1

RATES IS HIGHLY PROBLEMATIC? 2

A Over the last several years, observable current interest rates have been a more 3

accurate predictor of future interest rates than economists’ consensus projections. 4

Exhibit AB-19 illustrates this point. On this exhibit, under Columns 1 and 2, I show 5

the actual market yield at the time a projection is made for Treasury bond yields two 6

years in the future. In Column 1, I show the actual Treasury yield. In Column 2, I 7

show the projected yield two years out. 8

As shown in Columns 1 and 2, over the last several years, Treasury yields 9

were projected to increase relative to the actual Treasury yields at the time of the 10

projection. In Column 4, I show what the Treasury yield actually turned out to be two 11

years after the forecast. In Column 5, I show the actual yield change at the time of 12

the projections relative to the projected yield change. 13

As shown in this exhibit, economists consistently have been projecting that 14

interest rates will increase over several years. However, as shown in Column 5, 15

those yield projections have turned out to be overstated in almost every case. 16

Indeed, actual Treasury yields have decreased or remained flat over the last several 17

years rather than increased as the economists’ projections indicated. As such, 18

current observable interest rates are just as likely, maybe more likely, to accurately 19

predict future interest rates as are current economists’ projections. 20

Q DID DR. VILBERT CONSIDER ADDITIONAL BUSINESS RISKS TO JUSTIFY HIS 21

PROPOSED RETURN ON EQUITY? 22

A Yes. Dr. Vilbert points out that DTE’s large capital investment program relative to the 23

proxy group, heavy dependency on the auto industry and the overall weak economic 24



condition in its service territory are additional risk factors that will influence the cost of 1

equity.56 I disagree. Setting the return on equity as proposed by Dr. Vilbert’s model 2

results will place an unreasonable burden on the ratepayers and should be rejected. 3

DTE’s relative risk is comparable to the risk of the utility companies included in the 4

proxy group as outlined at the beginning of my testimony. Additionally, ratings 5

agencies have already taken into consideration DTE’s service economy and 6

projected capital program in assessing its total risk. Therefore, the return on equity 7

produced by the market based models applied to the proxy group companies will 8

produce a fair return on equity for DTE. 9

Q WILL YOU PLEASE SUMMARIZE THE REVENUE IMPACT TO CUSTOMERS AT 10

VARIOUS LEVELS OF AUTHORIZED RETURN ON EQUITY? 11

A Yes. As shown below in Table 8, the authorized return on equity plays a major role 12

on the outcome of this rate case. 13

56Vilbert Direct at 63.

ROE

RevenueImpactfrom

Current ROE

RevenueImpactfrom

Requested ROE

10.50% $38.00 -10.10% - ($38.00)9.60% ($47.50) ($85.40)9.35% ($71.20) ($109.10)

ROE Revenue Impact$ Millions

TABLE 8



Currently, DTE is authorized a return on equity of 10.1%, or 40 basis points less than 1

what they are requesting in the rate case. This 40 basis point increase in the return 2

on equity increases DTE’s claimed revenue deficiency by approximately $38.0 million. 3

Lowering DTE’s requested return on equity of 10.5% to the high end of my range, 4

which is also consistent with industry averages, would decrease its claimed revenue 5

deficiency by approximately $85.4 million. 6

Q DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 7

A Yes, it does. 8

Appendix A Christopher C. Walters

Page 1


Qualifications of Christopher C. Walters Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 1

A Christopher C. Walters. My business address is 16690 Swingley Ridge Road, 2


Q PLEASE STATE YOUR OCCUPATION. 4

A I am a Consultant in the field of public utility regulation with the firm of Brubaker & 5

Associates, Inc. (“BAI”), energy, economic and regulatory consultants. 6

Q PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND PROFESSIONAL 7

EMPLOYMENT EXPERIENCE. 8

A I graduated from Southern Illinois University Edwardsville in 2008 where I received a 9

Bachelor of Science Degree in Business Economics and Finance. I graduated with a 10

Master of Business Administration Degree from Lindenwood University in 2011. 11

In January 2009, I accepted the position Financial Representative with 12

American General Finance and was quickly promoted to Senior Assistant Manager. 13

In this position I was responsible for assisting in the management of daily operations 14

of the branch, analyzing and reporting on the performance of the branch to upper 15

management, performing credit analyses for consumers and small businesses, as 16

well as assisting home buyers obtain mortgage financing. 17

In January 2011, I accepted the position of Analyst with BAI. As an Analyst, I 18

performed detailed analysis, research, and general project support on regulatory and 19

competitive procurement projects. In July 2013, I was promoted to the position of 20

Consultant. As a Consultant, I have performed detailed technical analyses and 21

research to support regulatory projects including expert testimony, and briefing 22


Page 2


assistance covering various regulatory issues. At BAI, I have been involved with 1

several regulated projects for electric, natural gas and water and wastewater utilities, 2

as well as competitive procurement of electric power and gas supply. My regulatory 3

filing tasks have included measuring the cost of capital, capital structure evaluations, 4

assessing financial integrity, merger and acquisition related issues, risk management 5

related issues, depreciation rate studies, other revenue requirement issues and 6

wholesale market and retail regulated power price forecasts. Since 2011, I have 7

been working with BAI witnesses on utility rate of return filings. Specifically, I have 8

assisted BAI witnesses in analyzing rate of return studies, drafting discovery requests 9

and analyzing responses, drafting rate of return testimony and exhibits and assisting 10

with the review of the briefs. 11

BAI was formed in April 1995. BAI and its predecessor firm have participated 12

in more than 700 regulatory proceedings in 40 states and Canada. 13

BAI provides consulting services in the economic, technical, accounting, and 14

financial aspects of public utility rates and in the acquisition of utility and energy 15

services through RFPs and negotiations, in both regulated and unregulated markets. 16

Our clients include large industrial and institutional customers, some utilities and, on 17

occasion, state regulatory agencies. We also prepare special studies and reports, 18

forecasts, surveys and siting studies, and present seminars on utility-related issues. 19

In general, we are engaged in energy and regulatory consulting, economic 20

analysis and contract negotiation. In addition to our main office in St. Louis, the firm 21

also has branch offices in Phoenix, Arizona and Corpus Christi, Texas. 22


Page 3


Q HAVE YOU EVER TESTIFIED BEFORE A REGULATORY BODY? 1

A Yes. I have sponsored testimony before state regulatory commissions including: 2

Arkansas, Delaware, Kansas, Kentucky, Michigan, Minnesota, Ohio and Oklahoma. I 3

have also filed an affidavit before the Federal Energy Regulatory Commission 4

(“FERC”). 5

Q PLEASE DESCRIBE ANY PROFESSIONAL REGISTRATIONS OR 6

ORGANIZATIONS TO WHICH YOU BELONG. 7

A I earned the Chartered Financial Analyst (“CFA”) designation from the CFA Institute. 8

The CFA charter was awarded after successfully completing three examinations 9

which covered the subject areas of financial accounting and reporting analysis, 10

corporate finance, economics, fixed income and equity valuation, derivatives, 11

alternative investments, risk management, and professional and ethical conduct. I 12

am a member of the CFA Institute and the CFA Society of St. Louis. 13

\\Doc\Shares\ProlawDocs\SDW\10427\Testimony-BAI\327075.docx

Case No.: U-18255Exhibit AB-1

Witness: Christopher C. WaltersPage 1 of 1

Weighted

Line Description Amount1 Weight Cost Cost(1) (2) (3) (4)

Ratemaking Capital:

1 Common Equity 5,786,095$ 37.59% 9.35% 3.51%

Long-Term Debt 5,554,238$ 36.09% 4.42% 1.60%

2 Short-Term Debt 201,903$ 1.31% 1.85% 0.02%

3 Deferred Income Taxes 3,841,151$ 24.96% 0.00% 0.00%

4 Investment Tax Credit 7,952$ 0.05% 6.94% 0.00%

5 Total 15,391,339$ 100.00% 5.14%

Investor Supplied Capital:

6 Common Equity 5,786,095$ 51.02% 9.35% 4.77%

7 Long-Term Debt 5,554,238$ 48.98% 4.42% 2.16%

8 Total 11,340,333$ 100.00% 6.94%

Source:1Exhibit A-11, Schedule D-1.

DTE Electric Company

Rate of Return



16-Year

Line Average 2017 2 2016 2015 2014 2013 2012 2011 2010 2009 2008 2007 2006 2005 2004 2003 2002(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17)

2 4 5 6 7 8 9 10 11 12 13 14 15 16 17 181 ALLETE 17.34 22.20 18.63 15.06 17.23 18.59 15.88 14.66 15.98 16.08 13.95 14.78 16.55 17.91 25.21 N/A N/A2 Alliant Energy 15.80 20.70 22.30 18.07 16.60 15.28 14.50 14.45 12.47 13.86 13.43 15.08 16.82 12.59 14.00 12.69 19.933 Ameren Corp. 15.45 20.70 18.29 17.55 16.71 16.52 13.35 11.93 9.66 9.26 14.21 17.45 19.39 16.72 16.28 13.51 15.784 American Electric Power 13.88 20.00 15.16 15.77 15.88 14.49 13.77 11.92 13.42 10.03 13.06 16.27 12.91 13.70 12.42 10.66 12.685 Avangrid, Inc. 27.41 20.80 20.49 40.94 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A6 Avista Corp. 18.10 25.50 18.80 17.60 17.28 14.64 19.30 14.08 12.74 11.42 14.97 30.88 15.39 19.45 24.43 13.84 19.277 Black Hills 17.66 19.30 22.29 16.14 19.03 18.24 17.13 31.13 18.10 9.93 N/A 15.02 15.77 17.27 17.13 15.95 12.528 CenterPoint Energy 14.81 21.10 21.91 18.10 16.96 18.75 14.85 14.58 13.78 11.81 11.27 15.00 10.27 19.06 17.84 6.05 5.599 CMS Energy Corp. 16.74 22.00 20.94 18.29 17.30 16.32 15.07 13.62 12.46 13.56 10.87 26.84 22.18 12.60 12.39 N/A N/A10 Consol. Edison 15.21 19.50 18.80 15.59 15.90 14.72 15.39 15.08 13.30 12.55 12.29 13.78 15.49 15.13 18.21 14.30 13.2811 Dominion Resources 18.09 22.80 21.33 22.14 22.97 19.25 18.91 17.27 14.35 12.74 13.78 20.63 15.98 24.89 15.07 15.24 12.0512 DTE Energy 15.34 19.20 18.97 18.11 14.91 17.92 14.89 13.51 12.27 10.41 14.81 18.27 17.43 13.80 16.04 13.69 11.2813 Duke Energy 16.65 17.70 21.25 18.22 17.91 17.45 17.46 13.76 12.69 13.32 17.28 16.13 N/A N/A N/A N/A N/A14 Edison Int'l 13.98 18.30 17.92 14.77 13.05 12.70 9.71 11.81 10.32 9.72 12.36 16.03 12.99 11.74 37.59 6.97 7.7815 El Paso Electric 17.05 20.90 18.66 18.33 16.38 15.88 14.47 12.60 10.72 10.79 11.89 15.26 16.92 26.72 22.03 18.26 22.9916 Entergy Corp. 13.56 16.70 10.92 12.53 12.89 13.21 11.22 9.06 11.57 11.98 16.56 19.30 14.28 16.28 15.09 13.77 11.5317 Eversource Energy 17.55 19.10 18.69 18.11 17.92 16.94 19.86 15.35 13.42 11.96 13.66 18.75 27.07 19.76 20.77 13.35 16.0718 Exelon Corp. 14.30 12.00 18.68 12.58 16.02 13.43 19.08 11.30 10.97 11.49 17.97 18.22 16.53 15.37 12.99 11.77 10.4619 FirstEnergy Corp. 17.37 12.80 15.91 17.02 39.79 13.06 21.10 22.39 11.75 13.02 15.64 15.59 14.23 16.07 14.13 22.47 12.9520 Fortis Inc. 19.39 19.00 21.60 18.00 24.29 19.97 20.12 18.79 18.22 16.36 17.48 21.14 17.68 N/A N/A N/A N/A21 Great Plains Energy 16.36 29.00 17.98 19.37 16.47 14.19 15.53 16.11 12.10 16.03 20.55 16.35 18.30 13.96 12.59 12.23 11.0922 Hawaiian Elec. 17.94 19.90 13.56 20.40 15.88 16.21 15.81 17.09 18.59 19.79 23.16 21.57 20.33 18.27 19.18 13.76 13.4723 IDACORP, Inc. 15.93 20.80 19.06 16.22 14.67 13.45 12.41 11.54 11.83 10.20 13.93 18.19 15.07 16.70 15.49 26.51 18.8824 MGE Energy 18.07 27.50 24.90 20.28 17.19 17.01 17.23 15.82 14.98 15.14 14.22 15.01 15.88 22.40 17.98 17.55 15.9625 NextEra Energy, Inc. 15.71 19.70 20.71 16.89 17.25 16.57 14.43 11.54 10.83 13.42 14.48 18.90 13.65 17.88 13.65 17.88 13.6026 NorthWestern Corp 16.71 17.20 17.19 18.36 16.24 16.86 15.72 12.62 12.90 11.54 13.87 21.74 25.95 17.09 N/A N/A N/A27 OGE Energy 14.89 18.40 17.68 17.69 18.27 17.69 15.16 14.37 13.31 10.83 12.41 13.75 13.68 14.95 14.13 11.84 14.1228 Otter Tail Corp. 24.39 23.40 20.19 18.20 18.84 21.12 21.75 47.48 55.10 31.16 30.06 19.02 17.35 15.40 17.34 17.77 16.0129 PG&E Corp. 16.77 18.00 21.13 26.40 15.00 23.67 20.70 15.46 15.80 13.01 12.08 16.85 14.84 15.37 13.81 9.50 N/A30 Pinnacle West Capital 15.59 20.20 18.74 16.04 15.89 15.27 14.35 14.60 12.57 13.74 16.07 14.93 13.69 19.24 15.80 13.96 14.4331 PNM Resources 17.79 20.30 19.83 16.85 18.68 16.13 14.97 14.53 14.05 18.09 N/A 35.65 15.57 17.38 15.02 14.73 15.0832 Portland General 16.10 19.90 19.06 17.71 15.32 16.88 13.98 12.37 12.00 14.40 16.30 11.94 23.35 N/A N/A N/A N/A33 PPL Corp. 14.30 17.80 12.83 13.92 14.08 12.84 10.88 10.52 11.93 25.69 17.64 17.26 14.10 15.12 12.51 10.59 11.0634 Public Serv. Enterprise 13.26 15.10 15.35 12.41 12.61 13.50 12.79 10.40 10.37 10.04 13.65 16.54 17.81 16.74 14.26 10.58 10.0035 SCANA Corp. 14.07 16.20 16.80 14.67 13.68 14.43 14.80 13.67 12.93 11.63 12.67 14.96 15.42 14.44 13.57 13.05 12.1736 Sempra Energy 14.51 22.20 24.37 19.73 21.87 19.68 14.89 11.77 12.60 10.09 11.80 14.01 11.50 11.79 8.65 8.96 8.1937 Southern Co. 15.76 16.70 17.76 15.85 16.04 16.19 16.97 15.85 14.90 13.52 16.13 15.95 16.19 15.92 14.68 14.83 14.6338 Vectren Corp. 17.03 23.30 19.18 17.92 19.98 20.66 15.02 15.83 15.10 12.89 16.79 15.33 18.92 15.11 17.57 14.80 14.1639 WEC Energy Group 15.95 20.30 19.95 21.33 17.71 16.50 15.76 14.25 14.01 13.35 14.77 16.47 15.97 14.46 17.51 12.43 10.4640 Westar Energy 15.43 21.10 21.59 18.45 15.36 14.04 13.43 14.78 12.96 14.95 16.96 14.10 12.18 14.79 17.44 10.78 14.0241 Xcel Energy Inc. 16.76 20.20 18.48 16.54 15.44 15.04 14.82 14.24 14.13 12.66 13.69 16.65 14.80 15.36 13.65 11.62 40.80

42 Average 16.57 19.94 18.97 18.00 17.39 16.38 15.69 15.30 14.28 13.56 15.18 17.74 16.47 16.52 16.57 13.70 14.3143 Median 15.91 20.00 18.80 17.71 16.54 16.27 15.04 14.31 12.91 12.82 14.21 16.41 15.88 15.92 15.29 13.60 13.47

Sources:1 The Value Line Investment Survey Investment Analyzer Software, downloaded on June 21, 2017.2 The Value Line Investment Survey, May 19, June 16, and July 28, 2017.


Electric Utilities(Valuation Metrics)

Price to Earnings (P/E) Ratio 1

Company





16-Year

Line Average 2017 2/a 2016 2015 2014 2013 2012 2011 2010 2009 2008 2007 2006 2005 2004 2003 2002(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) (17)

6 7 8 9 10 11 12 13 14 15 16 17 18 19 201 ALLETE 9.24 9.33 8.26 7.49 8.80 9.15 8.18 7.91 8.04 8.51 9.29 10.30 11.06 11.54 11.46 N/A N/A2 Alliant Energy 7.30 9.81 10.67 8.86 8.40 7.52 7.50 7.21 6.59 6.23 7.49 7.92 8.00 5.09 5.52 4.76 5.203 Ameren Corp. 6.80 7.87 7.44 6.87 6.95 6.61 5.48 5.02 4.23 4.25 6.35 7.69 8.57 8.57 8.24 6.74 7.964 American Electric Power 6.12 8.51 7.57 7.09 7.00 6.57 5.93 5.46 5.54 4.71 5.71 6.84 5.54 6.07 5.50 4.69 5.195 Avangrid, Inc. 9.43 8.42 8.56 11.30 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A6 Avista Corp. 6.39 7.83 7.63 6.76 7.30 6.21 6.88 6.40 5.80 4.06 5.12 7.58 5.30 6.58 7.58 5.36 5.907 Black Hills 7.52 8.98 9.33 8.06 8.81 8.03 6.04 7.85 6.16 4.25 11.26 7.62 6.92 7.57 6.69 6.89 5.928 CenterPoint Energy 4.83 6.87 5.96 5.75 6.25 6.56 5.15 5.39 4.70 4.05 4.29 5.17 3.94 4.70 4.26 2.08 2.169 CMS Energy Corp. 5.42 8.40 8.50 7.53 7.13 6.68 6.03 5.41 4.48 3.64 3.45 5.57 4.40 4.04 3.20 2.88 NMF10 Consol. Edison 8.12 9.07 9.39 7.96 7.89 7.77 8.31 8.15 7.39 6.72 6.89 8.31 8.65 8.59 9.31 7.90 7.6411 Dominion Resources 9.29 11.13 11.59 11.84 12.27 10.88 9.92 9.45 8.12 6.98 8.27 8.65 7.81 10.09 7.68 7.51 6.5312 DTE Energy 6.03 8.66 8.64 8.52 6.42 6.65 5.91 5.18 4.69 3.59 4.90 5.73 5.21 5.54 6.00 5.62 5.2013 Duke Energy 7.52 7.60 8.57 7.95 8.12 8.11 9.53 6.56 6.01 5.96 7.13 7.16 N/A N/A N/A N/A N/A14 Edison Int'l 5.27 6.94 6.77 5.92 5.68 5.46 4.59 4.22 4.11 3.95 5.63 7.01 5.87 5.61 6.84 2.82 2.9615 El Paso Electric 5.69 8.07 7.46 6.47 6.33 6.19 5.78 5.16 4.31 3.98 4.95 6.44 6.25 6.67 4.65 3.90 4.3916 Entergy Corp. 5.74 4.42 4.01 4.11 4.21 4.03 4.23 3.90 4.66 5.68 7.96 9.21 7.16 8.76 7.12 6.84 5.5717 Eversource Energy 6.47 9.88 10.14 10.12 10.14 8.08 9.30 6.99 4.97 4.61 4.12 6.18 6.02 3.55 3.78 2.85 2.7518 Exelon Corp. 6.20 4.34 4.80 4.70 5.09 4.61 5.54 5.86 5.10 5.98 9.65 9.89 8.62 7.97 6.29 5.71 4.9719 FirstEnergy Corp. 6.21 5.02 5.12 5.38 7.43 6.15 7.42 7.33 4.49 4.91 7.58 7.89 7.53 6.04 5.15 6.90 5.1020 Fortis Inc. 8.21 8.32 10.46 7.29 9.25 7.93 8.09 8.38 7.40 6.76 7.58 9.18 7.89 N/A N/A N/A N/A21 Great Plains Energy 6.53 8.88 8.63 6.66 6.45 5.73 6.09 5.74 4.49 5.06 7.71 7.13 7.68 6.70 6.52 5.92 5.1422 Hawaiian Elec. 7.91 9.01 7.44 9.25 7.64 8.15 8.05 7.73 7.81 6.95 9.10 7.95 8.47 8.29 8.44 6.12 6.2023 IDACORP, Inc. 7.54 5.93 10.95 9.37 8.59 7.78 7.05 6.64 6.52 5.31 7.10 8.23 7.73 7.55 7.15 7.27 7.5324 MGE Energy 10.81 16.46 15.66 12.53 11.42 11.20 10.77 9.48 9.05 8.40 8.42 9.23 9.30 11.73 11.04 10.20 8.0925 NextEra Energy, Inc. 7.18 9.15 9.23 7.93 7.98 7.60 7.58 5.98 5.33 6.09 7.34 9.02 6.51 6.71 6.71 5.97 5.7726 NorthWestern Corp 7.52 8.60 8.65 8.99 9.01 7.61 6.85 5.89 5.79 5.05 5.57 8.45 9.39 7.31 8.13 N/A N/A27 OGE Energy 7.64 10.32 9.03 9.25 10.65 9.93 7.35 7.48 6.61 5.37 6.43 7.58 7.50 7.04 6.73 5.62 5.3928 Otter Tail Corp. 9.06 10.51 9.38 9.04 9.45 9.58 8.43 9.04 8.07 8.01 11.65 9.53 8.66 8.18 9.01 8.13 8.3329 PG&E Corp. 6.25 7.04 7.26 7.24 5.65 6.84 5.86 5.32 5.42 4.71 4.61 5.84 5.28 5.07 5.13 4.05 14.6930 Pinnacle West Capital 5.97 8.35 7.89 6.91 7.03 6.85 6.34 5.80 5.65 3.84 4.19 4.76 4.48 7.48 5.88 4.80 5.2131 PNM Resources 6.72 8.16 7.64 6.95 7.48 6.47 5.80 4.94 4.58 4.53 7.10 10.67 7.50 7.62 6.84 5.55 5.7232 Portland General 5.62 7.44 7.12 6.73 5.49 6.06 5.08 4.86 4.13 4.63 4.81 5.34 5.74 N/A N/A N/A N/A33 PPL Corp. 7.46 9.80 8.37 8.73 7.32 6.59 5.87 5.98 7.46 8.82 9.17 8.90 7.58 7.57 6.49 5.41 5.3034 Public Serv. Enterprise 7.27 8.01 8.56 6.66 6.48 6.40 6.40 6.03 6.04 6.20 8.46 9.83 8.41 8.59 7.17 6.79 6.2435 SCANA Corp. 7.17 9.41 9.59 8.33 7.50 7.49 7.40 6.75 6.52 5.88 6.38 7.15 7.03 5.40 6.86 6.59 6.3636 Sempra Energy 7.56 10.03 10.88 9.99 10.77 9.37 7.26 6.13 6.53 6.07 7.07 8.61 7.22 6.96 5.16 4.85 4.0037 Southern Co. 8.22 7.80 8.83 8.23 8.42 8.30 8.75 8.22 7.79 7.08 8.18 8.62 8.47 8.41 8.28 8.28 7.8338 Vectren Corp. 7.04 9.77 8.60 7.82 7.57 6.82 5.79 5.81 5.58 5.24 6.90 6.53 7.37 7.06 7.63 7.27 6.9239 WEC Energy Group 8.23 10.69 10.95 12.90 10.27 9.58 9.24 8.43 8.15 6.87 7.57 7.84 7.27 6.40 6.27 4.91 4.2740 Westar Energy 6.92 10.91 10.86 9.05 7.93 7.23 6.71 6.67 5.51 5.32 7.09 6.88 5.81 7.00 6.54 4.24 2.9441 Xcel Energy Inc. 6.35 8.05 8.10 7.62 7.31 7.00 6.85 6.47 6.28 5.43 5.71 6.51 5.54 5.62 5.31 4.27 5.46

42 Average 7.29 8.63 8.65 8.05 7.85 7.39 6.98 6.53 6.00 5.59 6.95 7.72 7.12 7.13 6.77 5.70 5.8543 Median 7.18 8.51 8.57 7.93 7.54 7.12 6.85 6.27 5.80 5.35 7.09 7.76 7.37 7.04 6.71 5.62 5.52


Note:a Based on the average of the high and low price for 2017 and the projected 2017 Cash Flow per share,

published in The Value Line Investment Survey, May 19, June 16, and July 28, 2017.

Company

Market Price to Cash Flow (MP/CF) Ratio 1





13-Year

Line Average 2017 2/b 2016 2015 2014 2013 2012 2011 2010 2009 2008 2007 2006 2005(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14)

6 7 8 9 10 11 12 13 14 15 16 171 ALLETE 1.57 1.71 1.53 1.37 1.42 1.51 1.34 1.35 1.28 1.15 1.55 1.89 2.09 2.222 Alliant Energy 1.62 2.25 2.17 1.86 1.86 1.70 1.57 1.46 1.31 1.04 1.33 1.67 1.52 1.333 Ameren Corp. 1.35 1.80 1.67 1.46 1.45 1.29 1.18 0.90 0.83 0.78 1.25 1.60 1.62 1.684 American Electric Power 1.50 1.83 1.81 1.55 1.54 1.40 1.31 1.23 1.23 1.08 1.48 1.85 1.56 1.575 Avangrid, Inc. 0.79 0.83 0.83 0.72 N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A6 Avista Corp. 1.25 1.55 1.57 1.36 1.33 1.25 1.21 1.19 1.07 0.94 1.11 1.29 1.30 1.137 Black Hills 1.47 2.07 1.94 1.59 1.79 1.62 1.21 1.14 1.07 0.83 1.22 1.57 1.47 1.638 CenterPoint Energy 2.46 3.23 2.73 2.43 2.27 2.30 1.99 1.87 1.96 1.77 2.49 3.13 2.75 3.069 CMS Energy Corp. 1.86 2.74 2.72 2.43 2.26 2.09 1.91 1.66 1.48 1.10 1.23 1.82 1.42 1.3210 Consol. Edison 1.39 1.56 1.58 1.42 1.34 1.38 1.47 1.38 1.22 1.08 1.17 1.47 1.47 1.5211 Dominion Resources 2.67 2.99 3.15 3.34 3.55 2.97 2.84 2.37 2.01 1.80 2.42 2.69 2.07 2.5012 DTE Energy 1.41 1.98 1.82 1.65 1.62 1.51 1.35 1.20 1.16 0.89 1.10 1.35 1.29 1.3913 Duke Energy 1.16 1.34 1.35 1.29 1.28 1.19 1.12 1.11 1.00 0.91 1.06 1.15 N/A N/A14 Edison Int'l 1.63 2.00 1.92 1.76 1.68 1.57 1.53 1.24 1.07 1.04 1.56 2.05 1.80 1.9315 El Paso Electric 1.53 1.81 1.68 1.48 1.52 1.49 1.59 1.64 1.17 0.98 1.33 1.69 1.71 1.7616 Entergy Corp. 1.71 1.63 1.67 1.40 1.33 1.21 1.31 1.35 1.62 1.66 2.44 2.65 1.89 2.0117 Eversource Energy 1.39 1.64 1.64 1.53 1.47 1.38 1.28 1.50 1.31 1.12 1.31 1.60 1.22 1.0518 Exelon Corp. 2.36 1.20 1.20 1.14 1.28 1.17 1.46 1.95 2.07 2.57 4.39 4.79 3.89 3.6019 FirstEnergy Corp. 1.69 2.02 2.37 1.16 1.15 1.28 1.44 1.33 1.36 1.54 2.52 2.23 1.92 1.6420 Fortis Inc. 1.49 1.29 1.26 1.33 1.35 1.45 1.59 1.59 1.56 1.33 1.48 1.63 1.96 N/A21 Great Plains Energy 1.20 1.16 1.17 1.12 1.11 1.02 0.96 0.93 0.87 0.80 1.11 1.66 1.77 1.8622 Hawaiian Elec. 1.60 1.70 1.63 1.71 1.49 1.54 1.62 1.54 1.44 1.16 1.61 1.57 2.01 1.7823 IDACORP, Inc. 1.26 0.98 1.76 1.54 1.45 1.33 1.19 1.17 1.13 0.92 1.09 1.26 1.37 1.2224 MGE Energy 1.99 2.88 2.60 2.10 2.10 2.06 1.92 1.75 1.65 1.54 1.62 1.75 1.83 2.0925 NextEra Energy, Inc. 1.95 2.33 2.30 2.09 2.15 1.93 1.74 1.55 1.49 1.70 2.06 2.34 1.80 1.9326 NorthWestern Corp 1.45 1.67 1.68 1.60 1.54 1.56 1.42 1.35 1.22 1.07 1.15 1.48 1.65 1.4227 OGE Energy 1.85 1.96 1.73 1.79 2.22 2.24 1.94 1.90 1.70 1.37 1.52 1.98 1.91 1.8028 Otter Tail Corp. 1.70 2.10 1.90 1.78 1.90 1.96 1.58 1.35 1.19 1.18 1.71 1.93 1.76 1.7429 PG&E Corp. 1.59 1.73 1.69 1.57 1.39 1.38 1.41 1.46 1.56 1.41 1.50 1.94 1.83 1.8430 Pinnacle West Capital 1.35 1.85 1.72 1.52 1.44 1.47 1.39 1.25 1.14 0.95 1.00 1.26 1.26 1.2531 PNM Resources 1.10 1.56 1.56 1.33 1.21 1.09 0.98 0.80 0.69 0.56 0.66 1.23 1.21 1.4532 Portland General 1.26 1.67 1.56 1.42 1.37 1.28 1.14 1.09 0.94 0.92 1.05 1.32 1.36 N/A33 PPL Corp. 2.17 2.35 2.46 2.24 1.64 1.55 1.58 1.47 1.61 2.10 3.19 3.05 2.43 2.5034 Public Serv. Enterprise 1.92 1.68 1.67 1.58 1.57 1.44 1.46 1.59 1.67 1.78 2.58 2.99 2.46 2.4535 SCANA Corp. 1.51 1.66 1.74 1.47 1.48 1.48 1.48 1.36 1.33 1.20 1.45 1.62 1.64 1.7236 Sempra Energy 1.74 2.04 2.00 2.17 2.20 1.84 1.53 1.28 1.35 1.32 1.60 1.87 1.70 1.7337 Southern Co. 2.05 1.91 2.01 1.99 2.02 2.04 2.15 1.99 1.83 1.73 2.12 2.24 2.23 2.3538 Vectren Corp. 1.82 2.54 2.29 2.11 2.08 1.82 1.57 1.53 1.41 1.34 1.64 1.74 1.77 1.8239 WEC Energy Group 1.85 2.04 2.09 1.82 2.34 2.21 2.05 1.81 1.65 1.40 1.57 1.77 1.71 1.6240 Westar Energy 1.37 1.95 1.95 1.49 1.44 1.33 1.26 1.20 1.10 0.93 1.10 1.36 1.30 1.4141 Xcel Energy Inc. 1.51 1.96 1.88 1.66 1.55 1.50 1.51 1.41 1.32 1.19 1.30 1.53 1.40 1.38

42 Average 1.63 1.88 1.85 1.67 1.68 1.60 1.51 1.43 1.35 1.25 1.63 1.90 1.78 1.8043 Median 1.53 1.83 1.74 1.57 1.53 1.49 1.47 1.37 1.31 1.15 1.48 1.71 1.71 1.73


Notes:b Based on the average of the high and low price for 2017 and the projected 2017 Book Value per share,

published in The Value Line Investment Survey, May 19, June 16, and July 28, 2017.

Market Price to Book Value (MP/BV) Ratio 1

Company


Witness: Christopher C. Walters

Line Company S&P Moody's SNL1 Value Line2

(1) (2) (3) (4)

1 ALLETE, Inc. BBB+ A3 54.9% 58.0%

2 Alliant Energy Corporation A- Baa1 44.3% 47.2%

3 Ameren Corporation BBB+ Baa1 47.1% 51.3%

4 American Electric Power Company, Inc. A- Baa1 43.8% 50.0%

5 Avangrid, Inc. BBB+ Baa1 75.0% 77.0%

6 CenterPoint Energy, Inc. A- Baa1 28.7% 31.5%

7 CMS Energy Corporation BBB+ Baa1 29.7% 32.6%

8 Consolidated Edison, Inc. A- A3 47.4% 49.2%

9 Dominion Resources, Inc. BBB+ Baa2 28.1% 32.6%

10 DTE Energy Company BBB+ Baa1 42.3% 44.4%

11 Edison International BBB+ A3 45.0% 49.2%

12 El Paso Electric Company BBB Baa1 44.1% 47.3%

13 Entergy Corporation BBB+ Baa2 34.3% 35.5%

14 Eversource Energy A Baa1 49.5% 54.4%

15 IDACORP, Inc. BBB Baa1 54.9% 55.2%

16 OGE Energy Corp. A- A3 54.6% 58.9%

17 Otter Tail Corporation BBB Baa2 53.5% 57.0%

18 PG&E Corporation A- A3 48.9% 52.1%


Proxy Group

Credit Ratings1 Common Equity Ratios

19 Pinnacle West Capital Corporation A- A3 51.9% 54.4%

20 PNM Resources, Inc. BBB+ Baa3 37.8% 44.0%

21 Portland General Electric Company BBB A3 49.9% 51.6%

22 PPL Corporation A- Baa2 34.0% 35.7%

23 Public Service Enterprise Group Incorporated BBB+ Baa1 52.7% 54.7%

24 SCANA Corporation BBB+ Baa3 43.5% 46.9%

25 Sempra Energy BBB+ Baa1 40.0% 47.3%

26 Vectren Corporation A- N/A 48.1% 52.7%

27 Xcel Energy Inc. A- A3 42.6% 43.7%

28 Average BBB+ Baa1 45.4% 48.7%

29 DTE Electric Company BBB+ A2 51.0%3

1 SNL Financial, Downloaded on August 8, 2017.2 The Value Line Investment Survey , May 19, June 16, and July 28, 2017.3 Solomon direct at 5.

Sources:



Average ofEstimated Number of Estimated Number of Estimated Number of Growth

Line Growth %1 Estimates Growth %2 Estimates Growth %3 Estimates Rates(1) (2) (3) (4) (5) (6) (7)

1 ALLETE, Inc. 6.10% N/A 7.20% 1 5.00% 1 6.10%

2 Alliant Energy Corporation 5.50% N/A 5.90% 5 6.45% 2 5.95%

3 Ameren Corporation 6.50% N/A 6.10% 3 6.05% 2 6.22%

4 American Electric Power Company, Inc. 5.40% N/A 4.99% 7 2.31% 3 4.23%

5 Avangrid, Inc. 8.50% N/A 8.50% 5 9.00% 1 8.67%

6 CenterPoint Energy, Inc. 5.00% N/A 6.89% 5 6.21% 4 6.03%

7 CMS Energy Corporation 7.00% N/A 7.43% 6 7.52% 5 7.32%

8 Consolidated Edison, Inc. 3.50% N/A 3.59% 3 3.97% 3 3.69%

9 Dominion Resources, Inc. 6.00% N/A 5.70% 4 3.56% 4 5.09%

10 DTE Energy Company 5.90% N/A 5.64% 4 4.59% 3 5.38%

11 Edison International 6.20% N/A 4.84% 3 4.11% 3 5.05%

12 El Paso Electric Company 7.60% N/A 7.55% 2 6.50% 1 7.22%

13 Entergy Corporation 0.00% N/A 6.00% 2 - 6.47% 2 6.00%

14 Eversource Energy 6.00% N/A 5.85% 5 5.81% 3 5.89%

15 IDACORP, Inc. 4.50% N/A 5.00% 1 4.00% 2 4.50%

16 OGE Energy Corp. 5.30% N/A 5.57% 3 6.30% 2 5.72%

17 Otter Tail Corporation N/A N/A 6.55% 2 5.20% 1 5.88%

Company


Consensus Analysts' Growth Rates

Zacks SNL Reuters

18 PG&E Corporation 5.00% N/A 4.00% 6 3.59% 3 4.20%

19 Pinnacle West Capital Corporation 5.20% N/A 5.69% 5 6.07% 4 5.65%

20 PNM Resources, Inc. 4.70% N/A 5.55% 4 7.35% 2 5.87%

21 Portland General Electric Company 3.40% N/A 3.35% 2 5.55% 2 4.10%

22 PPL Corporation 5.00% N/A 5.17% 3 - 0.06% 3 5.09%

23 Public Service Enterprise Group Incorporated 2.40% N/A 4.57% 3 0.19% 2 2.39%

24 SCANA Corporation 4.30% N/A 4.88% 4 4.00% 1 4.39%

25 Sempra Energy 8.70% N/A 7.97% 3 9.35% 2 8.67%

26 Vectren Corporation 5.70% N/A 5.67% 3 5.50% 2 5.62%

27 Xcel Energy Inc. 5.40% N/A 5.52% 8 5.32% 3 5.41%

28 Average 5.55% N/A 5.77% 4 5.34% 2 5.57%

1 Zacks Elite, http://www.zackselite.com/, downloaded on August 4, 2017.2 SNL Interactive, http://www.snl.com/, downloaded on August 4, 2017.3 Reuters, http://www.reuters.com/, downloaded on August 4, 2017.

Sources:



13-Week AVG Analysts' Annualized Adjusted Constant

Line Stock Price1 Growth2 Dividend3 Yield Growth DCF(1) (2) (3) (4) (5)

1 ALLETE, Inc. $72.03 6.10% $2.14 3.15% 9.25%

2 Alliant Energy Corporation $40.72 5.95% $1.26 3.28% 9.23%

3 Ameren Corporation $55.67 6.22% $1.76 3.36% 9.57%

4 American Electric Power Company, Inc. $70.11 4.23% $2.36 3.51% 7.74%

5 Avangrid, Inc. $44.87 8.67% $1.73 4.18% 12.85%

6 CenterPoint Energy, Inc. $27.96 6.03% $1.07 4.06% 10.09%

7 CMS Energy Corporation $46.58 7.32% $1.33 3.06% 10.38%

8 Consolidated Edison, Inc. $81.95 3.69% $2.76 3.49% 7.18%

9 Dominion Resources, Inc. $78.26 5.09% $3.02 4.06% 9.14%

10 DTE Energy Company $107.37 5.38% $3.30 3.24% 8.62%

11 Edison International $79.27 5.05% $2.17 2.88% 7.93%

12 El Paso Electric Company $52.51 7.22% $1.34 2.74% 9.95%

13 Entergy Corporation $77.34 6.00% $3.48 4.77% 10.77%

14 Eversource Energy $61.13 5.89% $1.90 3.29% 9.18%

15 IDACORP, Inc. $86.29 4.50% $2.20 2.66% 7.16%

16 OGE Energy Corp. $35.10 5.72% $1.21 3.64% 9.37%

17 Otter Tail Corporation $39.76 5.88% $1.28 3.41% 9.28%

18 PG&E Corporation $67.29 4.20% $2.12 3.28% 7.48%

19 Pinnacle West Capital Corporation $86.46 5.65% $2.62 3.20% 8.85%

20 PNM Resources, Inc. $38.41 5.87% $0.97 2.67% 8.54%

21 Portland General Electric Company $45.95 4.10% $1.36 3.08% 7.18%

22 PPL Corporation $38.81 5.09% $1.58 4.28% 9.36%


Constant Growth DCF Model(Consensus Analysts' Growth Rates)

Company

23 Public Service Enterprise Group Incorporated $43.83 2.39% $1.72 4.02% 6.40%

24 SCANA Corporation $66.51 4.39% $2.45 3.85% 8.24%

25 Sempra Energy $113.57 8.67% $3.29 3.15% 11.82%

26 Vectren Corporation $59.99 5.62% $1.68 2.96% 8.58%

27 Xcel Energy Inc. $46.69 5.41% $1.44 3.25% 8.66%

28 Average $61.65 5.57% $1.98 3.43% 8.99%

29 Median 9.14%

1 SNL Financial, Downloaded on August 8, 2017.2 Exhibit AB-4.3 The Value Line Investment Survey , May 19, June 16, and July 28, 2017.

Sources:



Line 2016 Projected 2016 Projected 2016 Projected(1) (2) (3) (4) (5) (6)

1 ALLETE, Inc. $2.08 $2.50 $3.14 $4.00 66.24% 62.50%2 Alliant Energy Corporation $1.18 $1.58 $1.65 $2.50 71.52% 63.20%3 Ameren Corporation $1.72 $2.15 $2.68 $3.50 64.18% 61.43%4 American Electric Power Company, Inc. $2.27 $2.90 $4.23 $4.75 53.66% 61.05%

5 Avangrid, Inc. $1.73 $1.85 $1.98 $2.75 87.37% 67.27%

6 CenterPoint Energy, Inc. $1.03 $1.23 $1.00 $1.65 103.00% 74.55%

7 CMS Energy Corporation $1.24 $1.70 $1.98 $2.75 62.63% 61.82%

8 Consolidated Edison, Inc. $2.68 $3.08 $3.94 $4.50 68.02% 68.44%

9 Dominion Resources, Inc. $2.80 $4.20 $3.44 $4.50 81.40% 93.33%

10 DTE Energy Company $3.06 $4.30 $4.83 $6.75 63.35% 63.70%

11 Edison International $1.98 $2.90 $3.94 $5.25 50.25% 55.24%

12 El Paso Electric Company $1.23 $1.75 $2.39 $3.00 51.46% 58.33%

13 Entergy Corporation $3.42 $3.80 $6.88 $5.00 49.71% 76.00%

14 Eversource Energy $1.78 $2.30 $2.96 $4.00 60.14% 57.50%

15 IDACORP, Inc. $2.08 $2.90 $3.94 $4.75 52.79% 61.05%

16 OGE Energy Corp. $1.16 $1.75 $1.69 $2.50 68.64% 70.00%

17 Otter Tail Corporation $1.25 $1.38 $1.60 $2.30 78.13% 60.00%

18 PG&E Corporation $1.93 $2.90 $2.83 $4.50 68.20% 64.44%

19 Pinnacle West Capital Corporation $2.56 $3.25 $3.95 $5.25 64.81% 61.90%

20 PNM Resources, Inc. $0.88 $1.37 $1.65 $2.50 53.33% 54.80%

21 Portland General Electric Company $1.26 $1.70 $2.16 $3.00 58.33% 56.67%

22 PPL Corporation $1.52 $1.82 $2.79 $2.75 54.48% 66.18%

23 Public Service Enterprise Group Incorporated $1.64 $2.10 $2.83 $3.50 57.95% 60.00%

24 SCANA Corporation $2.30 $2.90 $4.16 $5.00 55.29% 58.00%

25 Sempra Energy $3.02 $4.55 $4.24 $7.50 71.23% 60.67%

26 Vectren Corporation $1.62 $2.00 $2.55 $3.35 63.53% 59.70%

27 Xcel Energy Inc. $1.36 $1.80 $2.21 $2.75 61.54% 65.45%

28 Average $1.88 $2.47 $3.02 $3.87 64.49% 63.82%

Source:The Value Line Investment Survey , May 19, June 16, and July 28, 2017.

Company


Payout Ratios

Dividends Per Share Earnings Per Share Payout Ratio



Sustainable

Dividends Earnings Book Value Book Value Adjustment Adjusted Payout Retention Internal Growth

Line Per Share Per Share Per Share Growth ROE Factor ROE Ratio Rate Growth Rate Rate(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1 ALLETE, Inc. $2.50 $4.00 $46.00 3.80% 8.70% 1.02 8.86% 62.50% 37.50% 3.32% 4.34%2 Alliant Energy Corporation $1.58 $2.50 $19.05 2.35% 13.12% 1.01 13.28% 63.20% 36.80% 4.89% 5.90%3 Ameren Corporation $2.15 $3.50 $35.50 3.93% 9.86% 1.02 10.05% 61.43% 38.57% 3.88% 3.88%

4 American Electric Power Company, Inc. $2.90 $4.75 $43.25 4.10% 10.98% 1.02 11.20% 61.05% 38.95% 4.36% 4.37%

5 Avangrid, Inc. $1.85 $2.75 $52.00 1.24% 5.29% 1.01 5.32% 67.27% 32.73% 1.74% 1.74%

6 CenterPoint Energy, Inc. $1.23 $1.65 $10.00 4.49% 16.50% 1.02 16.86% 74.55% 25.45% 4.29% 4.79%

7 CMS Energy Corporation $1.70 $2.75 $21.00 6.64% 13.10% 1.03 13.52% 61.82% 38.18% 5.16% 6.58%

8 Consolidated Edison, Inc. $3.08 $4.50 $55.00 3.25% 8.18% 1.02 8.31% 68.44% 31.56% 2.62% 3.11%

9 Dominion Resources, Inc. $4.20 $4.50 $24.25 0.84% 18.56% 1.00 18.63% 93.33% 6.67% 1.24% 1.24%

10 DTE Energy Company $4.30 $6.75 $62.75 4.56% 10.76% 1.02 11.00% 63.70% 36.30% 3.99% 4.94%

11 Edison International $2.90 $5.25 $44.75 3.98% 11.73% 1.02 11.96% 55.24% 44.76% 5.35% 5.35%

12 El Paso Electric Company $1.75 $3.00 $32.25 3.99% 9.30% 1.02 9.48% 58.33% 41.67% 3.95% 4.18%

13 Entergy Corporation $3.80 $5.00 $50.25 2.18% 9.95% 1.01 10.06% 76.00% 24.00% 2.41% 2.48%

14 Eversource Energy $2.30 $4.00 $41.00 3.94% 9.76% 1.02 9.94% 57.50% 42.50% 4.23% 4.23%

15 IDACORP, Inc. $2.90 $4.75 $51.50 3.80% 9.22% 1.02 9.40% 61.05% 38.95% 3.66% 3.76%

16 OGE Energy Corp. $1.75 $2.50 $20.50 3.52% 12.20% 1.02 12.41% 70.00% 30.00% 3.72% 3.91%

17 Otter Tail Corporation $1.38 $2.30 $22.75 5.96% 10.11% 1.03 10.40% 60.00% 40.00% 4.16% 7.18%

18 PG&E Corporation $2.90 $4.50 $45.50 5.15% 9.89% 1.03 10.14% 64.44% 35.56% 3.60% 4.58%

19 Pinnacle West Capital Corporation $3.25 $5.25 $51.75 3.70% 10.14% 1.02 10.33% 61.90% 38.10% 3.93% 4.41%

20 PNM Resources, Inc. $1.37 $2.50 $25.50 3.92% 9.80% 1.02 9.99% 54.80% 45.20% 4.52% 4.59%

Company


Sustainable Growth Rate

3 to 5 Year Projections

21 Portland General Electric Company $1.70 $3.00 $31.25 3.47% 9.60% 1.02 9.76% 56.67% 43.33% 4.23% 4.41%

22 PPL Corporation $1.82 $2.75 $19.25 5.74% 14.29% 1.03 14.68% 66.18% 33.82% 4.97% 7.36%

23 Public Service Enterprise Group Incorporated $2.10 $3.50 $31.25 3.74% 11.20% 1.02 11.41% 60.00% 40.00% 4.56% 4.59%

24 SCANA Corporation $2.90 $5.00 $50.00 4.53% 10.00% 1.02 10.22% 58.00% 42.00% 4.29% 4.85%

25 Sempra Energy $4.55 $7.50 $58.25 2.39% 12.88% 1.01 13.03% 60.67% 39.33% 5.12% 5.12%

26 Vectren Corporation $2.00 $3.35 $28.50 5.97% 11.75% 1.03 12.09% 59.70% 40.30% 4.87% 6.21%

27 Xcel Energy Inc. $1.80 $2.75 $26.25 3.85% 10.48% 1.02 10.67% 65.45% 34.55% 3.69% 3.69%

28 Average $2.47 $3.87 $37.01 3.89% 11.01% 1.02 11.22% 63.82% 36.18% 3.95% 4.51%

Sources and Notes:Cols. (1), (2) and (3): The Value Line Investment Survey , May 19, June 16, and July 28, 2017.

Col. (4): [ Col. (3) / Page 2 Col. (2) ] ^ (1/number of years projected) - 1.Col. (5): Col. (2) / Col. (3).Col. (6): [ 2 * (1 + Col. (4)) ] / (2 + Col. (4)).Col. (7): Col. (6) * Col. (5).Col. (8): Col. (1) / Col. (2).Col. (9): 1 - Col. (8).Col. (10): Col. (9) * Col. (7).Col. (11): Col. (10) + Page 2 Col. (9).



13-Week 2016 Market

Average Book Value to Book

Line Stock Price1 Per Share2 Ratio 2016 3-5 Years Growth S Factor3 V Factor4 S * V(1) (2) (3) (4) (5) (6) (7) (8) (9)

1 ALLETE, Inc. $72.03 $38.17 1.89 49.60 52.50 1.14% 2.16% 47.01% 1.01%2 Alliant Energy Corporation $40.72 $16.96 2.40 227.67 236.00 0.72% 1.73% 58.35% 1.01%3 Ameren Corporation $55.67 $29.27 1.90 242.63 242.63 0.00% 0.00% 47.42% 0.00%

4 American Electric Power Company, Inc. $70.11 $35.38 1.98 491.71 492.00 0.01% 0.02% 49.54% 0.01%

5 Avangrid, Inc. $44.87 $48.90 0.92 308.99 309.00 0.00% 0.00% - 8.98% - 0.00%

6 CenterPoint Energy, Inc. $27.96 $8.03 3.48 430.68 435.00 0.20% 0.70% 71.28% 0.50%

7 CMS Energy Corporation $46.58 $15.23 3.06 279.21 289.00 0.69% 2.12% 67.30% 1.42%

8 Consolidated Edison, Inc. $81.95 $46.88 1.75 305.00 315.00 0.65% 1.13% 42.79% 0.48%

9 Dominion Resources, Inc. $78.26 $23.26 3.36 627.80 615.00 - 0.41% - 1.38% 70.28% - 0.97%

10 DTE Energy Company $107.37 $50.22 2.14 179.43 187.00 0.83% 1.77% 53.23% 0.94%

11 Edison International $79.27 $36.82 2.15 325.81 325.81 0.00% 0.00% 53.55% 0.00%

12 El Paso Electric Company $52.51 $26.52 1.98 40.52 41.00 0.24% 0.47% 49.50% 0.23%

13 Entergy Corporation $77.34 $45.12 1.71 179.13 180.00 0.10% 0.17% 41.66% 0.07%

14 Eversource Energy $61.13 $33.80 1.81 316.89 316.89 0.00% 0.00% 44.71% 0.00%

15 IDACORP, Inc. $86.29 $42.74 2.02 50.40 50.65 0.10% 0.20% 50.47% 0.10%

16 OGE Energy Corp. $35.10 $17.24 2.04 199.70 201.50 0.18% 0.37% 50.89% 0.19%

17 Otter Tail Corporation $39.76 $17.03 2.33 39.35 44.00 2.26% 5.27% 57.17% 3.02%

18 PG&E Corporation $67.29 $35.39 1.90 506.89 535.00 1.09% 2.06% 47.40% 0.98%

19 Pinnacle West Capital Corporation $86.46 $43.15 2.00 111.34 114.00 0.47% 0.95% 50.09% 0.48%

20 PNM Resources, Inc. $38.41 $21.04 1.83 79.65 80.00 0.09% 0.16% 45.22% 0.07%

Outstanding (in Millions)2

Company


Sustainable Growth Rate

Common Shares

21 Portland General Electric Company $45.95 $26.35 1.74 88.95 90.00 0.23% 0.41% 42.65% 0.17%

22 PPL Corporation $38.81 $14.56 2.67 679.73 730.00 1.44% 3.83% 62.48% 2.39%

23 Public Service Enterprise Group Incorporated $43.83 $26.01 1.69 504.87 506.00 0.04% 0.08% 40.66% 0.03%

24 SCANA Corporation $66.51 $40.06 1.66 142.90 149.00 0.84% 1.39% 39.77% 0.55%

25 Sempra Energy $113.57 $51.77 2.19 250.15 236.00 - 1.16% - 2.54% 54.42% - 1.38%

26 Vectren Corporation $59.99 $21.33 2.81 82.90 86.00 0.74% 2.07% 64.44% 1.34%

27 Xcel Energy Inc. $46.69 $21.73 2.15 507.22 507.00 - 0.01% - 0.02% 53.46% - 0.01%

28 Average $61.65 $30.85 2.13 268.49 272.81 0.50% 1.13% 52.14% 0.65%

Sources and Notes:1 SNL Financial, Downloaded on August 8, 2017.2 The Value Line Investment Survey , May 19, June 16, and July 28, 2017.3 Expected Growth in the Number of Shares, Column (3) * Column (6).4 Expected Profit of Stock Investment, [ 1 - 1 / Column (3) ].



13-Week AVG Sustainable Annualized Adjusted Constant

Line Stock Price1 Growth2 Dividend3 Yield Growth DCF(1) (2) (3) (4) (5)

1 ALLETE, Inc. $72.03 4.34% $2.14 3.10% 7.44%2 Alliant Energy Corporation $40.72 5.90% $1.26 3.28% 9.17%3 Ameren Corporation $55.67 3.88% $1.76 3.28% 7.16%4 American Electric Power Company, Inc. $70.11 4.37% $2.36 3.51% 7.89%5 Avangrid, Inc. $44.87 1.74% $1.73 3.92% 5.66%6 CenterPoint Energy, Inc. $27.96 4.79% $1.07 4.01% 8.80%7 CMS Energy Corporation $46.58 6.58% $1.33 3.04% 9.63%8 Consolidated Edison, Inc. $81.95 3.11% $2.76 3.47% 6.58%9 Dominion Resources, Inc. $78.26 1.24% $3.02 3.91% 5.15%10 DTE Energy Company $107.37 4.94% $3.30 3.23% 8.16%11 Edison International $79.27 5.35% $2.17 2.88% 8.24%12 El Paso Electric Company $52.51 4.18% $1.34 2.66% 6.84%13 Entergy Corporation $77.34 2.48% $3.48 4.61% 7.09%14 Eversource Energy $61.13 4.23% $1.90 3.24% 7.47%15 IDACORP, Inc. $86.29 3.76% $2.20 2.65% 6.41%16 OGE Energy Corp. $35.10 3.91% $1.21 3.58% 7.49%17 Otter Tail Corporation $39.76 7.18% $1.28 3.45% 10.63%18 PG&E Corporation $67.29 4.58% $2.12 3.30% 7.88%19 Pinnacle West Capital Corporation $86.46 4.41% $2.62 3.16% 7.57%20 PNM Resources, Inc. $38.41 4.59% $0.97 2.64% 7.23%21 Portland General Electric Company $45.95 4.41% $1.36 3.09% 7.50%22 PPL Corporation $38.81 7.36% $1.58 4.37% 11.73%23 Public Service Enterprise Group Incorporated $43.83 4.59% $1.72 4.10% 8.70%24 SCANA Corporation $66.51 4.85% $2.45 3.86% 8.71%25 Sempra Energy $113.57 5.12% $3.29 3.05% 8.17%26 Vectren Corporation $59.99 6.21% $1.68 2.97% 9.18%27 Xcel Energy Inc. $46.69 3.69% $1.44 3.20% 6.89%

28 Average $61.65 4.51% $1.98 3.39% 7.90%29 Median 7.57%

Sources:1 SNL Financial, Downloaded on August 8, 2017.2 Exhibit AB-7, page 1.3 The Value Line Investment Survey , May 19, June 16, and July 28, 2017.


Constant Growth DCF Model(Sustainable Growth Rate)

Company




Electricity Sales Are Linked to U.S. Economic Growth

Real GDP

Electricity Use

120130140150160170180190200

Index 1988 = 100

Note:1988 represents the base year. Graph depicts increases or decreases from the base year.

Sources:U.S. Energy Information AdministrationFederal Reserve Bank of St. Louis

Total Energy Use

90100110120



13-Week AVG Annualized First Stage Third Stage Multi-Stage

Line Stock Price1 Dividend2 Growth3 Year 6 Year 7 Year 8 Year 9 Year 10 Growth4 Growth DCF(1) (2) (3) (4) (5) (6) (7) (8) (9) (10)

1 ALLETE, Inc. $72.03 $2.14 6.10% 5.78% 5.47% 5.15% 4.83% 4.52% 4.20% 7.69%

2 Alliant Energy Corporation $40.72 $1.26 5.95% 5.66% 5.37% 5.08% 4.78% 4.49% 4.20% 7.80%

3 Ameren Corporation $55.67 $1.76 6.22% 5.88% 5.54% 5.21% 4.87% 4.54% 4.20% 7.94%

4 American Electric Power Company, Inc. $70.11 $2.36 4.23% 4.23% 4.22% 4.22% 4.21% 4.21% 4.20% 7.71%

5 Avangrid, Inc. $44.87 $1.73 8.67% 7.92% 7.18% 6.43% 5.69% 4.94% 4.20% 9.46%

6 CenterPoint Energy, Inc. $27.96 $1.07 6.03% 5.73% 5.42% 5.12% 4.81% 4.51% 4.20% 8.67%

7 CMS Energy Corporation $46.58 $1.33 7.32% 6.80% 6.28% 5.76% 5.24% 4.72% 4.20% 7.83%

8 Consolidated Edison, Inc. $81.95 $2.76 3.69% 3.77% 3.86% 3.94% 4.03% 4.11% 4.20% 7.59%

9 Dominion Resources, Inc. $78.26 $3.02 5.09% 4.94% 4.79% 4.64% 4.50% 4.35% 4.20% 8.45%

10 DTE Energy Company $107.37 $3.30 5.38% 5.18% 4.98% 4.79% 4.59% 4.40% 4.20% 7.65%

11 Edison International $79.27 $2.17 5.05% 4.91% 4.77% 4.63% 4.48% 4.34% 4.20% 7.20%

12 El Paso Electric Company $52.51 $1.34 7.22% 6.71% 6.21% 5.71% 5.21% 4.70% 4.20% 7.42%

13 Entergy Corporation $77.34 $3.48 6.00% 5.70% 5.40% 5.10% 4.80% 4.50% 4.20% 9.43%

14 Eversource Energy $61.13 $1.90 5.89% 5.61% 5.32% 5.04% 4.76% 4.48% 4.20% 7.80%

15 IDACORP, Inc. $86.29 $2.20 4.50% 4.45% 4.40% 4.35% 4.30% 4.25% 4.20% 6.89%

16 OGE Energy Corp. $35.10 $1.21 5.72% 5.47% 5.22% 4.96% 4.71% 4.45% 4.20% 8.15%

17 Otter Tail Corporation $39.76 $1.28 5.88% 5.60% 5.32% 5.04% 4.76% 4.48% 4.20% 7.93%

18 PG&E Corporation $67.29 $2.12 4.20% 4.20% 4.20% 4.20% 4.20% 4.20% 4.20% 7.48%

19 Pinnacle West Capital Corporation $86.46 $2.62 5.65% 5.41% 5.17% 4.93% 4.68% 4.44% 4.20% 7.66%

20 PNM Resources, Inc. $38.41 $0.97 5.87% 5.59% 5.31% 5.03% 4.76% 4.48% 4.20% 7.12%

21 Portland General Electric Company $45.95 $1.36 4.10% 4.12% 4.13% 4.15% 4.17% 4.18% 4.20% 7.25%

22 PPL Corporation $38.81 $1.58 5.09% 4.94% 4.79% 4.64% 4.50% 4.35% 4.20% 8.68%

23 Public Service Enterprise Group Incorporated $43.83 $1.72 2.39% 2.69% 2.99% 3.29% 3.60% 3.90% 4.20% 7.83%

24 SCANA Corporation $66.51 $2.45 4.39% 4.36% 4.33% 4.30% 4.26% 4.23% 4.20% 8.08%

25 Sempra Energy $113.57 $3.29 8.67% 7.93% 7.18% 6.44% 5.69% 4.95% 4.20% 8.20%

26 Vectren Corporation $59.99 $1.68 5.62% 5.39% 5.15% 4.91% 4.67% 4.44% 4.20% 7.39%

27 Xcel Energy Inc. $46.69 $1.44 5.41% 5.21% 5.01% 4.81% 4.60% 4.40% 4.20% 7.67%

28 Average $61.65 $1.98 5.57% 5.34% 5.11% 4.88% 4.66% 4.43% 4.20% 7.89%29 Median 7.80%

Sources:1 SNL Financial, Downloaded on August 8, 2017.2 The Value Line Investment Survey , May 19, June 16, and July 28, 2017.3 Exhibit AB-4.4 Blue Chip Financial Forecasts , June 1, 2017 at 14.


Multi-Stage Growth DCF Model

Second Stage Growth

Company




Common Stock Market/Book Ratio

1.000

1.500

2.000

2.500

Source:1980 - 2000: Mergent Public Utility Manual.2001 - 2015: AUS Utility Reports, multiple dates.2016 - 2017: Value Line Investment Survey, multiple dates.* Value Line Investment Survey Reports, May 19, June 2, June 16, and July 28, 2017.

0.000

0.500



Authorized 30 yr. Indicated Rolling RollingElectric Treasury Risk 5 - Year 10 - Year

Line Returns1 Bond Yield2 Premium Average Average(1) (2) (3) (4) (5)

1 1986 13.93% 7.80% 6.13%

2 1987 12.99% 8.58% 4.41%

3 1988 12.79% 8.96% 3.83%

4 1989 12.97% 8.45% 4.52%

5 1990 12.70% 8.61% 4.09% 4.60%

6 1991 12.55% 8.14% 4.41% 4.25%

7 1992 12.09% 7.67% 4.42% 4.26%

8 1993 11.41% 6.60% 4.81% 4.45%

9 1994 11.34% 7.37% 3.97% 4.34%

10 1995 11.55% 6.88% 4.67% 4.46% 4.53%

11 1996 11.39% 6.70% 4.69% 4.51% 4.38%

12 1997 11.40% 6.61% 4.79% 4.59% 4.42%

13 1998 11.66% 5.58% 6.08% 4.84% 4.65%

14 1999 10.77% 5.87% 4.90% 5.03% 4.68%

15 2000 11.43% 5.94% 5.49% 5.19% 4.82%

16 2001 11.09% 5.49% 5.60% 5.37% 4.94%

17 2002 11.16% 5.43% 5.73% 5.56% 5.07%

18 2003 10.97% 4.96% 6.01% 5.55% 5.19%

19 2004 10.75% 5.05% 5.70% 5.71% 5.37%

20 2005 10.54% 4.65% 5.89% 5.79% 5.49%

21 2006 10.34% 4.90% 5.44% 5.76% 5.56%

22 2007 10.31% 4.83% 5.48% 5.71% 5.63%

23 2008 10.37% 4.28% 6.09% 5.72% 5.63%

24 2009 10.52% 4.07% 6.45% 5.87% 5.79%

25 2010 10.29% 4.25% 6.04% 5.90% 5.84%

26 2011 10.19% 3.91% 6.28% 6.07% 5.91%

27 2012 10.01% 2.92% 7.09% 6.39% 6.05%

28 2013 9.81% 3.45% 6.36% 6.44% 6.08%

29 2014 9.75% 3.34% 6.41% 6.44% 6.15%

30 2015 9.60% 2.84% 6.76% 6.58% 6.24%

31 2016 9.60% 2.60% 7.00% 6.72% 6.40%

32 2017 3 9.61% 2.97% 6.64% 6.63% 6.51%

33 Average 11.12% 5.61% 5.51% 5.45% 5.45%

34 Minimum 4.25% 4.38%

35 Maximum 6.72% 6.51%

Sources: 1 Regulatory Research Associates, Inc ., Regulatory Focus, Major Rate Case Decisions, Jan. 1997 pg. 5, and Jan. 2011 pg. 3. S&P Global Market Intelligence , RRA Regulatory Focus, Major Rate Case Decisions, January-June 2017, July 26, 2017, p. 6. 2006 - 2017 Auhorized Returns exclude limited issue rider cases. 2 St. Louis Federal Reserve: Economic Research, http://research.stlouisfed.org/. The yields from 2002 to 2005 represent the 20-Year Treasury yields obtained from the Federal Reserve Bank. 3 Data includes January - June 2017.

Year


Equity Risk Premium - Treasury Bond



Authorized Average Indicated Rolling RollingElectric "A" Rated Utility Risk 5 - Year 10 - Year

Line Returns1 Bond Yield2 Premium Average Average(1) (2) (3) (4) (5)

1 1986 13.93% 9.58% 4.35%

2 1987 12.99% 10.10% 2.89%

3 1988 12.79% 10.49% 2.30%

4 1989 12.97% 9.77% 3.20%

5 1990 12.70% 9.86% 2.84% 3.12%

6 1991 12.55% 9.36% 3.19% 2.88%

7 1992 12.09% 8.69% 3.40% 2.99%

8 1993 11.41% 7.59% 3.82% 3.29%

9 1994 11.34% 8.31% 3.03% 3.26%

10 1995 11.55% 7.89% 3.66% 3.42% 3.27%

11 1996 11.39% 7.75% 3.64% 3.51% 3.20%

12 1997 11.40% 7.60% 3.80% 3.59% 3.29%

13 1998 11.66% 7.04% 4.62% 3.75% 3.52%

14 1999 10.77% 7.62% 3.15% 3.77% 3.52%

15 2000 11.43% 8.24% 3.19% 3.68% 3.55%

16 2001 11.09% 7.76% 3.33% 3.62% 3.56%

17 2002 11.16% 7.37% 3.79% 3.61% 3.60%

18 2003 10.97% 6.58% 4.39% 3.57% 3.66%

19 2004 10.75% 6.16% 4.59% 3.86% 3.82%

20 2005 10.54% 5.65% 4.89% 4.20% 3.94%

21 2006 10.34% 6.07% 4.27% 4.39% 4.00%

22 2007 10.31% 6.07% 4.24% 4.48% 4.04%

23 2008 10.37% 6.53% 3.84% 4.37% 3.97%

24 2009 10.52% 6.04% 4.48% 4.34% 4.10%

25 2010 10.29% 5.46% 4.83% 4.33% 4.26%

26 2011 10.19% 5.04% 5.15% 4.51% 4.45%

27 2012 10.01% 4.13% 5.88% 4.84% 4.66%

28 2013 9.81% 4.48% 5.33% 5.13% 4.75%

29 2014 9.75% 4.28% 5.47% 5.33% 4.84%

30 2015 9.60% 4.12% 5.48% 5.46% 4.90%

31 2016 9.60% 3.93% 5.67% 5.57% 5.04%

32 2017 3 9.61% 4.12% 5.49% 5.49% 5.16%

33 Average 11.12% 6.99% 4.13% 4.08% 4.05%

34 Minimum 2.88% 3.20%

35 Maximum 5.57% 5.16%

Sources: 1 Regulatory Research Associates, Inc ., Regulatory Focus, Major Rate Case Decisions, Jan. 1997 p. 5, and Jan. 2011 p. 3. S&P Global Market Intelligence , RRA Regulatory Focus, Major Rate Case Decisions, January-June 2017, July 26, 2017, p. 6 2006 - 2017 Auhorized Returns exclude limited issue rider cases. 2 Mergent Public Utility Manual, Mergent Weekly News Reports, 2003. The utility yields for the period 2001-2009 were obtained from the Mergent Bond Record. The utility yields from 2010-2017 were obtained from http://credittrends.moodys.com/.3 Data includes January - June 2017.


Equity Risk Premium - Utility Bond

Year



Line Year

T-Bond

Yield1 A2 Baa2A-T-Bond

SpreadBaa-T-Bond

Spread Aaa3 Baa3Aaa-T-Bond

SpreadBaa-T-Bond

SpreadBaa

SpreadA-AaaSpread

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1 1980 11.30% 13.34% 13.95% 2.04% 2.65% 11.94% 13.67% 0.64% 2.37% 0.28% 1.40%2 1981 13.44% 15.95% 16.60% 2.51% 3.16% 14.17% 16.04% 0.73% 2.60% 0.56% 1.78%3 1982 12.76% 15.86% 16.45% 3.10% 3.69% 13.79% 16.11% 1.03% 3.35% 0.34% 2.07%4 1983 11.18% 13.66% 14.20% 2.48% 3.02% 12.04% 13.55% 0.86% 2.38% 0.65% 1.62%5 1984 12.39% 14.03% 14.53% 1.64% 2.14% 12.71% 14.19% 0.32% 1.80% 0.34% 1.32%6 1985 10.79% 12.47% 12.96% 1.68% 2.17% 11.37% 12.72% 0.58% 1.93% 0.24% 1.10%7 1986 7.80% 9.58% 10.00% 1.78% 2.20% 9.02% 10.39% 1.22% 2.59% -0.39% 0.56%8 1987 8.58% 10.10% 10.53% 1.52% 1.95% 9.38% 10.58% 0.80% 2.00% -0.05% 0.72%9 1988 8.96% 10.49% 11.00% 1.53% 2.04% 9.71% 10.83% 0.75% 1.87% 0.17% 0.78%10 1989 8.45% 9.77% 9.97% 1.32% 1.52% 9.26% 10.18% 0.81% 1.73% -0.21% 0.51%11 1990 8.61% 9.86% 10.06% 1.25% 1.45% 9.32% 10.36% 0.71% 1.75% -0.30% 0.54%12 1991 8.14% 9.36% 9.55% 1.22% 1.41% 8.77% 9.80% 0.63% 1.67% -0.25% 0.59%13 1992 7.67% 8.69% 8.86% 1.02% 1.19% 8.14% 8.98% 0.47% 1.31% -0.12% 0.55%14 1993 6.60% 7.59% 7.91% 0.99% 1.31% 7.22% 7.93% 0.62% 1.33% -0.02% 0.37%15 1994 7.37% 8.31% 8.63% 0.94% 1.26% 7.96% 8.62% 0.59% 1.25% 0.01% 0.35%16 1995 6.88% 7.89% 8.29% 1.01% 1.41% 7.59% 8.20% 0.71% 1.32% 0.09% 0.30%17 1996 6.70% 7.75% 8.17% 1.05% 1.47% 7.37% 8.05% 0.67% 1.35% 0.12% 0.38%18 1997 6.61% 7.60% 7.95% 0.99% 1.34% 7.26% 7.86% 0.66% 1.26% 0.09% 0.34%19 1998 5.58% 7.04% 7.26% 1.46% 1.68% 6.53% 7.22% 0.95% 1.64% 0.04% 0.51%20 1999 5.87% 7.62% 7.88% 1.75% 2.01% 7.04% 7.87% 1.18% 2.01% 0.01% 0.58%21 2000 5.94% 8.24% 8.36% 2.30% 2.42% 7.62% 8.36% 1.68% 2.42% -0.01% 0.62%22 2001 5.49% 7.76% 8.03% 2.27% 2.54% 7.08% 7.95% 1.59% 2.45% 0.08% 0.68%23 2002 5.43% 7.37% 8.02% 1.94% 2.59% 6.49% 7.80% 1.06% 2.37% 0.22% 0.88%24 2003 4.96% 6.58% 6.84% 1.62% 1.89% 5.67% 6.77% 0.71% 1.81% 0.08% 0.91%25 2004 5.05% 6.16% 6.40% 1.11% 1.35% 5.63% 6.39% 0.58% 1.35% 0.00% 0.53%26 2005 4.65% 5.65% 5.93% 1.00% 1.28% 5.24% 6.06% 0.59% 1.42% -0.14% 0.41%27 2006 4.90% 6.07% 6.32% 1.17% 1.42% 5.59% 6.48% 0.69% 1.58% -0.16% 0.48%28 2007 4.83% 6.07% 6.33% 1.24% 1.50% 5.56% 6.48% 0.72% 1.65% -0.15% 0.52%29 2008 4.28% 6.53% 7.25% 2.25% 2.97% 5.63% 7.45% 1.35% 3.17% -0.20% 0.90%30 2009 4.07% 6.04% 7.06% 1.97% 2.99% 5.31% 7.30% 1.24% 3.23% -0.24% 0.73%31 2010 4.25% 5.46% 5.96% 1.21% 1.71% 4.95% 6.04% 0.70% 1.79% -0.08% 0.52%32 2011 3.91% 5.04% 5.56% 1.13% 1.65% 4.64% 5.67% 0.73% 1.76% -0.10% 0.40%33 2012 2.92% 4.13% 4.83% 1.21% 1.90% 3.67% 4.94% 0.75% 2.02% -0.11% 0.46%

Public Utility Bond Corporate Bond Utility to Corporate


Bond Yield Spreads

34 2013 3.45% 4.48% 4.98% 1.03% 1.53% 4.24% 5.10% 0.79% 1.65% -0.12% 0.24%35 2014 3.34% 4.28% 4.80% 0.94% 1.46% 4.16% 4.86% 0.82% 1.52% -0.06% 0.12%36 2015 2.84% 4.12% 5.03% 1.27% 2.19% 3.89% 5.00% 1.05% 2.16% 0.03% 0.23%37 2016 2.60% 3.93% 4.67% 1.33% 2.08% 3.66% 4.71% 1.07% 2.12% -0.04% 0.27%38 2017 4 2.97% 4.12% 4.52% 1.15% 1.55% 3.88% 4.58% 0.91% 1.61% -0.05% 0.24%

39 Average 6.62% 8.13% 8.57% 1.51% 1.95% 7.46% 8.55% 0.84% 1.94% 0.01% 0.67%

Sources:1 St. Louis Federal Reserve: Economic Research, http://research.stlouisfed.org/.2 The utility yields for the period 1980-2000 were obtained from Mergent Public Utility Manual, Mergent Weekly News Reports, 2003. The utility yields for the period 2001-2009 were obtained from the Mergent Bond Record. The utility yields for the period 2010-2017 were obtained from http://credittrends.moodys.com/.3 The corporate yields for the period 1980-2009 were obtained from the St. Louis Federal Reserve: Economic Research, http://research.stlouisfed.org/. The corporate yields from 2010-2017 were obtained from http://credittrends.moodys.com/.4 Data includes January - June 2017.

0.00%

0.50%

1.00%

1.50%

2.00%

2.50%

3.00%

3.50%

4.00%

1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Utility A - T-Bond Spread Utility Baa - T-Bond Spread

Corporate Aaa - T-Bond Spread Corporate Baa - T-Bond Spread

Yield SpreadsTreasury Vs. Corporate & Treasury Vs. Utility



Treasury "A" Rated Utility "Baa" Rated Utility

Line Date Bond Yield1 Bond Yield2 Bond Yield2

(1) (2) (3)

1 08/04/17 2.84% 3.90% 4.27%

2 07/28/17 2.89% 3.97% 4.32%

3 07/21/17 2.81% 3.91% 4.27%

4 07/14/17 2.91% 4.02% 4.40%

5 07/07/17 2.93% 4.06% 4.44%

6 06/30/17 2.84% 3.98% 4.36%

7 06/23/17 2.71% 3.86% 4.26%

8 06/16/17 2.78% 3.93% 4.31%

9 06/09/17 2.86% 4.00% 4.37%

10 06/02/17 2.80% 3.97% 4.34%

11 05/26/17 2.92% 4.07% 4.43%

12 05/19/17 2.90% 4.06% 4.44%

13 05/12/17 2.98% 4.15% 4.54%

14 Average 2.86% 3.99% 4.37%

15 Spread To Treasury 1.13% 1.51%

Sources:1 St. Louis Federal Reserve: Economic Research, http://research.stlouisfed.org.2 http://credittrends.moodys.com/.


Treasury and Utility Bond Yields


Witness: Christopher C. WaltersPage 2 of 3DTE Electric Company

Trends in Bond Yields

5.00%

6.00%

7.00%

8.00%

9.00%

10.00%

"Baa" Rated Utility Bond Yield

"A" Rated Utility Bond Yield

30‐Year Treasury Bond

__________Sources:Mergent Bond Record.www.moodys.com, Bond Yields and Key Indicators.St. Louis Federal Reserve: Economic Research, http://research.stlouisfed.org/

2.00%

3.00%

4.00%

5.00%


Witness: Christopher C. WaltersPage 3 of 3DTE Electric Company

Yield Spread Between Utility Bonds and 30-Year Treasury Bonds

2.00%

3.00%

4.00%

5.00%

6.00%

__________Sources:Mergent Bond Record.www.moodys.com, Bond Yields and Key Indicators.St. Louis Federal Reserve: Economic Research, http://research.stlouisfed.org/

0.00%

1.00%

2.00%

A Spread Baa Spread



Line Beta

1 ALLETE, Inc. 0.802 Alliant Energy Corporation 0.703 Ameren Corporation 0.654 American Electric Power Company, Inc. 0.655 Avangrid, Inc. NMF6 CenterPoint Energy, Inc. 0.85

7 CMS Energy Corporation 0.65

8 Consolidated Edison, Inc. 0.50

9 Dominion Resources, Inc. 0.65

10 DTE Energy Company 0.65

11 Edison International 0.60

12 El Paso Electric Company 0.75

13 Entergy Corporation 0.65

14 Eversource Energy 0.65

15 IDACORP, Inc. 0.70

16 OGE Energy Corp. 0.95

17 Otter Tail Corporation 0.90

18 PG&E Corporation 0.65

19 Pinnacle West Capital Corporation 0.65

20 PNM Resources, Inc. 0.75

21 Portland General Electric Company 0.70

22 PPL Corporation 0.70

23 Public Service Enterprise Group Incorporated 0.65

24 SCANA Corporation 0.65

25 Sempra Energy 0.80

26 Vectren Corporation 0.70

27 Xcel Energy Inc. 0.60

28 Average 0.70

Source:The Value Line Investment Survey,May 19, June 16, and July 28, 2017.


Value Line Beta

Company



High LowMarket Risk Market Risk

Line Premium Premium(1) (2)

1 Risk-Free Rate1 3.70% 3.70%

2 Risk Premium2 7.80% 6.00%

3 Beta3 0.70 0.70

4 CAPM 9.15% 7.89%

Sources:1 Blue Chip Financial Forecasts ; August 1, 2017, at 2.2 Duff & Phelps, 2017 SBBI Yearbook at 6-17 and 6-18, and Duff & Phelps, 2017 Valuation Handbook at 3-36 and 3-48.3 Exhibit AB-16.


CAPM Return

Description



Retail

Cost of ServiceLine Amount Intermediate Significant Aggressive Reference

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

1 Rate Base 15,391,337$ Exhibit A-8, Schedule A1.

2 Weighted Common Return 3.51% Page 2, Line 1, Col. 3.

3 Pre-Tax Rate of Return 7.38% Page 2, Line 6, Col. 4.

4 Income to Common 541,000$ Line 1 x Line 2.

5 EBIT 1,136,645$ Line 1 x Line 3.

6 Depreciation & Amortization 720,561$ Exhibit A-10, Schedule C1.

7 Imputed Amortization 70,000$ Response to ABATE 2.25.

8 Deferred Income Taxes & ITC 257,241$ Exhibit A-10, Schedule C9 - C11.

9 Funds from Operations (FFO) 1,588,802$ Sum of Line 4 and Lines 6 through 8.

10 Imputed & Capitalized Interest Expense 20,245$ Response to ABATE 2.24 and 2.25.

11 EBITDA 1,947,451$ Sum of Lines 5 through 7 and Line 10.

12 Total Adjusted Debt Ratio 49.3% Page 3, Line 3, Col. 2.

13 Debt to EBITDA 3.9x 2.5x - 3.5x 3.5x - 4.5x 4.5x - 5.5x (Line 1 x Line 12) / Line 11.

14 FFO to Total Debt 20.9% 23% - 35% 13% - 23% 9% - 13% Line 9 / (Line 1 x Line 12).

Sources:1 Standard & Poor's: "Criteria: Corporate Methodology," November 19, 2013.2 Ratings Direct: "Summary: DTE Electric Co.," December 22, 2016.

Note:Based on the December 2016 S&P report, DTE has an "Excellent" business profile and a "Significant" financial profile,and falls under the 'Medial Volatility' matrix.

Description


Standard & Poor's Credit Metrics

S&P Benchmark (Medial Volatility)1/2



Pre-TaxWeighted Weighted

Line Weight1Cost Cost Cost

(1) (2) (3) (4)

1 Common Equity 37.59% 9.35% 3.51% 5.76%

2 Long-Term Debt 36.09% 4.42% 1.60% 1.60%

3 Short-Term Debt 1.31% 1.85% 0.02% 0.02%

4 Deferred Income Taxes 24.96% 0.00% 0.00% 0.00%

5 Investment Tax Credit 0.05% 6.94% 0.00% 0.00%

6 Total 100.00% 5.14% 7.38%

7 Tax Conversion Factor21.6393

Sources:1Exhibit AB-1.2Exhibit A-8, Schedule A1.


Standard & Poor's Credit Metrics(Pre-Tax Rate of Return)

Description



Line Description Amount1 Weight(1) (2)

1 Long-Term Debt 5,554,238$ 48.6%

2 Off-Balance Sheet Debt2 82,000$ 0.7%

3 Total Long-Term Debt 5,636,238$ 49.3%

4 Common Equity 5,786,095$ 50.7%

5 Total 11,422,333$ 100.0%

Sources:1Exhibit AB-1.2Response to ABATE 2.25.


Standard & Poor's Credit Metrics(Financial Capital Structure)



Line Rating Count Average Median High Low < 50 50 to 55 > 55(1) (2) (3) (4) (5) (6) (7) (8)

1 AA- 1 42.58 42.58 42.58 42.58 100% 0% 0%2 A 7 49.08 50.02 52.31 39.77 43% 57% 0%3 A- 44 51.44 52.40 63.90 39.36 34% 41% 25%4 BBB+ 23 52.01 52.24 60.33 37.53 26% 39% 35%5 BBB 8 52.70 53.18 57.03 47.22 25% 38% 38%6 BBB- 10 55.29 54.86 59.62 50.66 0% 50% 50%7 BB 0 - -

8 Total 939 Average 50.51 50.88 47.97 36.73

Line Rating Count Average Median High Low < 50 50 to 55 > 55(1) (2) (3) (4) (5) (6) (7) (8)

10 AA- 12 42.58 42.70 44.98 40.78 100% 0% 0%11 A 75 50.35 50.67 57.10 38.99 40% 55% 5%12 A- 525 51.46 52.39 64.53 31.05 38% 34% 28%13 BBB+ 289 52.17 52.53 61.78 35.62 27% 42% 31%14 BBB 101 52.71 53.00 60.01 44.64 30% 39% 32%15 BBB- 125 55.28 54.56 67.82 41.38 10% 42% 48%16 BB - - - - -

17 Total 112718 Average 50.76 50.98 50.89 33.21

Source:Standard and Poors Global Credit Portal, downloaded June 1, 2017.

% Distribution of Quarterly Average


S&P Adjusted Debt Ratio(Operating Subsidiaries)

13 Quarter Average

Quarter Results - 2013Q4 through 2016Q4% Distribution of Quarterly Average



Actual Yield Projected YieldPrior Quarter Projected Projected in Projected Higher (Lower)

Line Date Actual Yield Yield Quarter Quarter Than Actual Yield*(1) (2) (3) (4) (5)

1 Dec-00 5.8% 5.8% 1Q, 02 5.6% 0.2%2 Mar-01 5.7% 5.6% 2Q, 02 5.8% -0.2%3 Jun-01 5.4% 5.8% 3Q, 02 5.2% 0.6%4 Sep-01 5.7% 5.9% 4Q, 02 5.1% 0.8%5 Dec-01 5.5% 5.7% 1Q, 03 5.0% 0.7%6 Mar-02 5.3% 5.9% 2Q, 03 4.7% 1.2%7 Jun-02 5.6% 6.2% 3Q, 03 5.2% 1.0%8 Sep-02 5.8% 5.9% 4Q, 03 5.2% 0.7%9 Dec-02 5.2% 5.7% 1Q, 04 4.9% 0.8%10 Mar-03 5.1% 5.7% 2Q, 04 5.4% 0.3%11 Jun-03 5.0% 5.4% 3Q, 04 5.1% 0.3%12 Sep-03 4.7% 5.8% 4Q, 04 4.9% 0.9%13 Dec-03 5.2% 5.9% 1Q, 05 4.8% 1.1%14 Mar-04 5.2% 5.9% 2Q, 05 4.6% 1.4%15 Jun-04 4.9% 6.2% 3Q, 05 4.5% 1.7%16 Sep-04 5.4% 6.0% 4Q, 05 4.8% 1.2%17 Dec-04 5.1% 5.8% 1Q, 06 4.6% 1.2%18 Mar-05 4.9% 5.6% 2Q, 06 5.1% 0.5%19 Jun-05 4.8% 5.5% 3Q, 06 5.0% 0.5%20 Sep-05 4.6% 5.2% 4Q, 06 4.7% 0.5%21 Dec-05 4.5% 5.3% 1Q, 07 4.8% 0.5%22 Mar-06 4.8% 5.1% 2Q, 07 5.0% 0.1%23 Jun-06 4.6% 5.3% 3Q, 07 4.9% 0.4%24 Sep-06 5.1% 5.2% 4Q, 07 4.6% 0.6%25 Dec-06 5.0% 5.0% 1Q, 08 4.4% 0.6%26 Mar-07 4.7% 5.1% 2Q, 08 4.6% 0.5%27 Jun-07 4.8% 5.1% 3Q, 08 4.5% 0.7%28 Sep-07 5.0% 5.2% 4Q, 08 3.7% 1.5%29 Dec-07 4.9% 4.8% 1Q, 09 3.5% 1.4%30 Mar-08 4.6% 4.8% 2Q, 09 4.0% 0.8%31 Jun-08 4.4% 4.9% 3Q, 09 4.3% 0.6%32 Sep-08 4.6% 5.1% 4Q, 09 4.3% 0.8%33 Dec-08 4.5% 4.6% 1Q, 10 4.6% 0.0%34 Mar-09 3.7% 4.1% 2Q, 10 4.4% -0.3%35 Jun-09 3.5% 4.6% 3Q, 10 3.9% 0.8%36 Sep-09 4.0% 5.0% 4Q, 10 4.2% 0.8%37 Dec-09 4.3% 5.0% 1Q, 11 4.6% 0.4%38 Mar-10 4.3% 5.2% 2Q, 11 4.3% 0.9%39 Jun-10 4.6% 5.2% 3Q, 11 3.7% 1.5%40 Sep-10 4.4% 4.7% 4Q, 11 3.0% 1.7%41 Dec-10 3.9% 4.6% 1Q, 12 3.1% 1.5%42 Mar-11 4.2% 5.1% 2Q, 12 2.9% 2.2%43 Jun-11 4.6% 5.2% 3Q, 12 2.8% 2.5%44 Sep-11 4.3% 4.2% 4Q, 12 2.9% 1.3%


Accuracy of Interest Rate Forecasts(Long-Term Treasury Bond Yields - Projected Vs. Actual)

Publication Data

45 Dec-11 3.7% 3.8% 1Q, 13 3.1% 0.7%46 Mar-12 3.0% 3.8% 2Q, 13 3.2% 0.7%47 Jun-12 3.1% 3.7% 3Q, 13 3.7% 0.0%48 Sep-12 2.9% 3.4% 4Q, 13 3.8% -0.4%49 Dec-12 2.8% 3.4% 1Q, 14 3.7% -0.3%50 Mar-13 2.9% 3.6% 2Q, 14 3.4% 0.2%51 Jun-13 3.1% 3.7% 3Q, 14 3.3% 0.4%52 Sep-13 3.2% 4.2% 4Q, 14 3.0% 1.2%53 Dec-13 3.7% 4.2% 1Q, 15 2.6% 1.7%54 Mar-14 3.8% 4.4% 2Q 15 2.9% 1.5%55 Jun-14 3.7% 4.3% 3Q 15 2.8% 1.5%56 Sep-14 3.4% 4.3% 4Q 15 3.0% 1.3%57 Dec-14 3.3% 4.0% 1Q 16 2.7% 1.3%58 Mar-15 3.0% 3.7% 2Q 16 2.6% 1.1%59 Jun-15 2.6% 3.7% 3Q 16 2.3% 1.4%60 Sep-15 2.9% 3.8% 4Q 16 2.8% 1.0%61 Dec-15 2.8% 3.7% 1Q 17 3.0% 0.7%62 Mar-16 3.0% 3.5% 2Q 17 2.9% 0.6%63 Apr-16 2.7% 3.6% 3Q 1764 May-16 2.7% 3.5% 3Q 1765 Jun-16 2.7% 3.4% 3Q 1766 Jul-16 2.7% 3.4% 4Q 1767 Aug-16 2.6% 3.1% 4Q 1768 Sep-16 2.6% 3.1% 4Q 1769 Oct-16 2.3% 3.1% 1Q 1870 Nov-16 2.3% 3.1% 1Q 1871 Dec-16 2.3% 3.4% 1Q 1872 Jan-17 2.8% 3.7% 2Q 1873 Feb-17 2.8% 3.7% 2Q 1874 Mar-17 2.8% 3.7% 2Q 1875 Apr-17 3.1% 3.8% 3Q 1876 May-17 3.0% 3.7% 3Q 1877 Jun-17 3.0% 3.7% 3Q 1878 Jul-17 2.9% 3.7% 4Q 1879 Aug-17 2.9% 3.7% 4Q 18

Source:Blue Chip Financial Forecasts, Various Dates.* Col. 2 - Col. 4.

STATE OF MICHIGAN



))))))))))

Case No. U-18255

Direct Testimony and Exhibits of

James R. Dauphinais

On behalf of

Association of Businesses Advocating Tariff Equity

August 29, 2017

Project 10427

James R. Dauphinais Table of Contents


STATE OF MICHIGAN



))))))))))

Case No. U-18255

Table of Contents for the Direct Testimony of James R. Dauphinais

I. Introduction and Summary ........................................................................................................ 1 II. Class Cost of Service ............................................................................................................... 6

A. Background .................................................................................................................. 6 B. Modeling of Rider R3 Standby Service Class .............................................................. 9

III. Rate Design .......................................................................................................................... 16

A. Rider R3 Standby Service ......................................................................................... 16 B. Rate D11 Demand Charge Voltage Level Discounts ................................................. 36 C. Collection of Transmission Expenses from Rate D11 Customers ............................. 40

IV. Interaction Between Case Nos. U-18255 and U-18248 ....................................................... 44 V. Conclusions and Recommendations ..................................................................................... 46

James R. Dauphinais Page 1


STATE OF MICHIGAN



))))))))))

Case No. U-18255

Direct Testimony of James R. Dauphinais

I. Introduction and Summary 1

Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 2

A James R. Dauphinais. My business address is 16690 Swingley Ridge Road, 3


Q WHAT IS YOUR OCCUPATION? 5

A I am a consultant in the field of public utility regulation and a Managing Principal with 6

the firm of Brubaker & Associates, Inc. (“BAI”), energy, economic and regulatory 7

consultants. 8

Q PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE. 9

A I hold an Associate’s Degree in Electric Engineering Technology from Hartford State 10

Technical College, a Bachelor’s Degree in Electrical Engineering from the University 11

of Hartford, and have completed graduate level courses in the study of power system 12

transients and power system protection through the Engineering Outreach Program 13



of the University of Idaho. For the first 12 years of my career, I was employed in the 1

Transmission Planning Department of the Northeast Utilities Service Company (“NU,” 2

now “Eversource”), where I was extensively involved with transmission planning, 3

transmission operation and transmission open access issues. 4

For the past 20 years I have been employed by Brubaker & Associates Inc. 5

During these 20 years I have been engaged with respect to resource planning, 6

transmission planning, wholesale power market structure, market power, transmission 7

access, transmission line routing, fuel cost, power procurement and rate issues 8

throughout the United States and Canada. For at least 18 of these 20 years, I have 9

participated in the Midcontinent Independent System Operator, Inc. (“MISO”) 10

stakeholder process on behalf of various large end-use customer groups. This work 11

has included, but not been limited to, providing extensive feedback to MISO and other 12

MISO stakeholders regarding the design of MISO’s day-ahead and real-time energy 13

markets and MISO’s current Resource Adequacy Requirements (“RAR”) construct, 14

including its annual prompt Planning Resource Auction (“PRA”) for capacity. This 15

work has included active participation in the MISO Resource Adequacy 16

Subcommittee [including its predecessor, the MISO Supply Adequacy Working Group 17

(“SAWG”), and the MISO Loss of Load Expectation Working Group (“LOLEWG”). I 18

have testified before the Federal Energy Regulatory Commission (“FERC”) as well as 19

many state and provincial regulatory commissions. Appendix A to my testimony 20

provides additional information on my background and experience. 21



Q ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING? 1

A I am appearing on behalf of the Association of Businesses Advocating Tariff Equity 2

(“ABATE”). ABATE’s members are customers of DTE Electric Company (“DTE” or 3

“Company”). 4

Q HAVE YOU PRESENTED TESTIMONY IN PRIOR ELECTRIC REGULATORY 5

PROCEEDINGS BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION 6

(“COMMISSION”)? 7

A Yes. Over the past 20 years, I have provided testimony to the Commission on 8

several occasions regarding issues that include, but are not limited to, electric rate 9

design, class cost of service, power supply cost recovery, standby service rates, 10

transmission planning and transmission line routing. Of particular relevance to this 11

proceeding, I have provided testimony on behalf of ABATE in both DTE’s most recent 12

previous general rate case (Case No. U-18014) and in DTE’s Section 6w Capacity 13

Charge proceeding (Case No. U-18248). 14

Q WHAT IS THE SUBJECT MATTER OF YOUR TESTIMONY? 15

A I address the following issues: 16

DTE’s proposed class cost of service (“CCOS”) study as it relates to its modeling 17 of the Rider 3 (“R3”) standby service customer class; 18

DTE’s proposed rate design for R3; 19 DTE’s proposed Rate D11 (“D11”) voltage level demand charge discounts; 20 DTE’s proposed collection of transmission expenses from D11 customers through 21

energy charges; and 22 The interaction between this general rate case and DTE’s Section 6w State 23

Reliability Mechanism (“SRM”) capacity charge case (Case No. U-18248). 24



My colleague, Mr. Christopher C. Walters, is separately filing testimony in this 1

proceeding on behalf of ABATE with respect to DTE’s proposed authorized Return on 2

Equity (“ROE”) and capital structure. 3

Note that my CCOS and rate design numbers in this testimony are for 4

illustrative purposes only. They are based on DTE’s proposed revenue requirement 5

and its proposed split of costs between capacity and non-capacity related charges. 6

They should not be interpreted as an endorsement of DTE’s proposed revenue 7

requirement or its proposed split between capacity and non-capacity related charges. 8

They do not reflect the impact on DTE’s proposed revenue requirement of Mr. 9

Walters’ recommendations. Nor do they reflect the impact of any other revenue 10

requirement adjustment recommendations that may be made in direct testimony by 11

the Commission Staff or other intervenors in this proceeding. Finally, they do not 12

reflect my recommendations in Case No. U-18255 with respect to the split of DTE’s 13

costs between capacity and non-capacity related costs. 14

My silence in this testimony with regard to any issue should not be construed 15

as an endorsement of DTE’s position on that issue. 16

Q PLEASE BRIEFLY SUMMARIZE YOUR CONCLUSIONS AND 17

RECOMMENDATIONS IN THIS PROCEEDING. 18

A My conclusions and recommendations are as follows: 19

1. DTE’s proposed CCOS is seriously flawed with respect to the R3 class and 20 should be modified as proposed in the body of my testimony. This lowers the 21 power supply CCOS revenue target of the R3 class from approximately 22 $13.58 million to approximately $6.31 million. 23



2. When DTE’s proposed rate design R3 power supply revenue target of 1 $9.69 million1 is lowered to ABATE’s CCOS R3 power supply revenue target of 2 $6.31 million, DTE’s proposed power supply reservation and demand charge 3 rate design would over-collect revenue from R3 customers by $3.38 million 4 (53.6%). To address this issue and bring R3 in line with cost of service, DTE’s 5 proposed reservation and demand charge rate design for power supply should 6 be replaced with: (i) a monthly power supply reservation charge that 7 accommodates the forced outage rate of the best performing generation of R3 8 customers, (ii) an on-peak daily power supply demand charge based on an 9 on-peak day pro ration of the full service D11 monthly power supply demand 10 charge and (iii) a maintenance on-peak daily demand charge set at 50% of the 11 normal on-peak daily power supply demand charge . 12

3. DTE’s proposed Rate D11 demand charge voltage level discounts of $0.50 per 13 kW-month for transmission and $1.13 per kW-month for subtransmission are 14 inconsistent with cost of service in that the transmission level discount is smaller 15 than the subtransmission level discount. The proposed demand charge voltage 16 level discounts should be replaced with ABATE’s proposed discounts of 17 $0.95 per kW-month for transmission and $0.63 per kW-month for 18 subtransmission as detailed in the body of my testimony. 19

4. While DTE correctly allocates its transmission expenses in its CCOS study to 20 D11 customers as a whole on the basis of 12-CP demand, it inappropriately 21 collects these demand-related expenses from individual D11 customers on the 22 basis of energy consumption. These transmission expenses should instead be 23 recovered from individual D11 customers through a non-capacity related power 24 supply demand charge as detailed in the body of my testimony. 25

5. The split of power supply costs between capacity-related and non-capacity 26 related charges in this proceeding should be dictated by the outcome of Case 27 No. U-18248, which is specifically addressing that split. However, as I have 28 recommended on behalf of ABATE in Case No. U-18248, regardless of how the 29 Commission decides to make that split, no less that 75% of total fixed production 30 costs should continue to be allocated to bundled retail customer classes on the 31 basis of 4-CP demand assuming the Commission adopts DTE’s proposed 75-0-32 25 allocation method for fixed production costs. In addition, as I have also 33 recommended in Case No. U-18248, the Commission should require DTE to 34 make a filing after: (i) the February 2018 SRM Capacity Demonstrations by 35 Alternative Electric Suppliers (“AESs”) and (ii) the conclusion of this current 36 proceeding. The filing should update DTE’s final SRM Capacity Charge to 37 reflect the additional capacity costs DTE has incurred to supply capacity to ROA 38 customers paying the SRM Capacity Charge and those ROA customers that 39 have returned to bundled service. In addition, the filing should update the SRM 40 Capacity Charge to reflect the billing units of the customers that are being 41 supplied with this additional capacity. 42

1While DTE’s proposed CCOS R3 power supply revenue target is $13.58 million, in its rate design it is proposing to discard those CCOS results and instead use a power supply revenue target of $9.69 million by continuing to sub-allocate a portion of the total D11/Other CCOS revenue target of $840 million to R3 based on historical R3 power supply revenues as it has in the past.



II. Class Cost of Service 1

A. Background 2

Q WHAT IS THE BASIC PURPOSE OF A CCOS STUDY? 3

A After determining the total cost to serve or revenue requirement, a CCOS study is 4

used to allocate the revenue requirement or cost responsibility among the customer 5

rate classes. A CCOS study compares the cost that each customer rate class 6

imposes on the system to the revenues each rate contributes. For example, when a 7

rate class produces the same rate of return as the total system rate of return, it is 8

paying revenue to the utility just sufficient to cover the costs incurred to serve that 9

class. If a rate class produces a below-average rate of return, it may be concluded 10

that the revenues provided by that class are insufficient to cover all relevant costs to 11

serve that class. On the other hand, if a class produces a rate of return above the 12

system average, it is not only paying revenues sufficient to cover the cost attributable 13

to it but, in addition, it is paying part of the cost attributable to other classes who 14

produce a below-system average rate of return. 15

Q WHY IS A CCOS STUDY IMPORTANT? 16

A It is a widely held principle that costs should be shared among customer rate classes 17

on the basis of cost-causation. That principle is perhaps the most universally 18

accepted principle of regulatory rate design. 19

Cost-based rates are not only fair and reasonable, but further the cause of 20

stability, conservation and efficiency. When customers are presented with price 21

signals that convey the consequences of their consumption decisions (i.e., how much 22

energy to consume, at what rate and when), they tend to take actions which not only 23

minimize their own costs but those of the utility as well. 24



The fundamental starting point and guideline for setting rates should be the 1

actual cost of serving each customer class, which is required by Michigan law and will 2

enhance Michigan’s business climate. 3

Q CAN YOU PLEASE EXPLAIN WHY COST OF SERVICE IS AN IMPORTANT 4

STARTING POINT IN DESIGNING RATES? 5

A ABATE has always been a staunch advocate of rates based upon the cost of 6

providing service because this method is the most fair and results in rates sending 7

the proper economic signals to customers. For example, basic economic theory is 8

that customers will respond to price signals and consume less as the prices increase 9

and consume more as the prices decrease. Accordingly, if the actual cost of 10

production rises during the peak periods during the summer and rates are not 11

designed to recover those costs based on that characteristic, then customers will 12

over-consume power during peak periods and place pressure on utilities to either 13

contract for or build incremental resources to produce the energy needed. This, in 14

turn, has cost implications for customers who will have to pay rates to support an 15

increased rate base. 16

Q IN DEVELOPING ITS PROPOSED POWER SUPPLY RATES, WHAT COST 17

ALLOCATION METHODS HAS DTE UTILIZED TO ALLOCATE ITS FIXED 18

PRODUCTION COSTS AND TRANSMISSION COSTS TO CUSTOMER CLASSES? 19

A To allocate fixed production costs, DTE used what is referred to as the 75-0-25 20

methodology. It allocates 75% of these costs to customer classes on an average of 21

4-CP demand basis and 25% on an annual energy consumption basis. To allocate 22

transmission expenses, DTE used an average of 12-CP demand method. 23



Q WOULD YOU PLEASE EXPLAIN WHAT IS MEANT BY THE AVERAGE OF 4-CP 1

DEMAND? 2

A The 4-CP allocation factor is based on class contributions to DTE’s highest four 3

monthly summer coincident peaks in each of the four summer months, which are 4

June through September. Under this method, the coincident demand at the time of 5

each of the four monthly summer peaks is used to allocate the production fixed costs. 6

The 12-CP allocation factor used for transmission expenses is similar except in that it 7

is based on the highest monthly coincident peaks in each of the 12 months of the 8

year. 9

Q DO YOU AGREE THAT THE 75-0-25 METHOD IS THE MOST APPROPRIATE 10

WAY TO ALLOCATE FIXED PRODUCTION COSTS TO CUSTOMER CLASSES? 11

A No. In DTE’s most recent previous general rate case, Case No. U-18014, I presented 12

detailed testimony on why DTE’s fixed production costs should instead be allocated 13

to customer classes using a 100-0-0 (i.e., 100% 4-CP demand) method. 14

I still believe a 100-0-0 method would be the most appropriate method to 15

allocate these costs. However, given the very recent nature of the Commission’s 16

decision in Case No. U-18014, the fact that the makeup of the Commission has not 17

changed since that decision and the fact I have no new evidence to present on the 18

issue at this time, I am not in this proceeding actively contesting DTE’s proposed use 19

of a 75-0-25 method to allocate fixed production costs to customer classes. However, 20

I reserve the right to pursue the issue in future proceedings. 21



B. Modeling of Rider R3 Standby Service Class 1

Q PUTTING ASIDE THE CONCERNS YOU HAVE WITH USING THE 75-0-25 2

METHOD TO ALLOCATE FIXED PRODUCTION COSTS, DO YOU HAVE ANY 3

ISSUES WITH RESPECT TO DTE’S PROPOSED CCOS STUDY? 4

A Yes. In response to Paragraph N of the ordering paragraphs of the Commission’s 5

Final Order in Case No. U-18014, DTE has provided a version of its proposed CCOS 6

study that treats the R3 customers as a separate customer class rather than a 7

subsidiary rate class to D11. There is a serious flaw with respect to modeling the 8

4-CP demand, 12-CP demand and annual energy consumption of the R3 class in this 9

CCOS study. 10

Q PLEASE EXPLAIN THIS FLAW. 11

A The flaw greatly overstates the 4-CP demand, 12-CP demand and annual energy 12

consumption of the R3 class in the CCOS study. DTE witness Farrell’s workpapers 13

show that for the R3 class DTE used a 4-CP demand of 25.21 MW, a 12-CP demand 14

of 23.72 MW and annual energy consumption at the generation level of 15

235,349 MWh. (See DTE Workpaper WPA-16 (Revised) at pages 3, 4 and 5). 16

However, when I performed an analysis of the historical hourly energy consumption 17

of the R3 class from 2007 through 2016 that was provided by DTE in response to 18

Staff Audit Data Request NMR-6.3, I found that the 4-CP demand, 12-CP demand 19

and annual energy consumption at the generation level values that DTE used in its 20

proposed CCOS study are much higher than the historical 4-CP demand, 12-CP 21

demand and annual energy consumption of the R3 class. Table JRD-1, below, 22

summarizes the results of my analysis. 23



TABLE JRD-1

R3 Loss Adjusted Contribution to Peak Load

Year

Average 4-CP (MW)

Average 12-CP (MW)

Annual Energy (MWh)

2007 7.72 10.35 171,950 2008 13.35 14.24 210,513 2009 15.89 13.11 126,632 2010 5.88 6.90 102,888 2011 5.15 6.85 86,847 2012 14.86 12.52 137,653 2013 7.35 7.53 107,188 2014 5.61 8.69 123,314 2015 13.85 16.33 146,948 2016 9.97 12.07 144,383

3-Year Average 9.81 12.36 138,215 5-Year Average 10.33 11.43 131,897

10-Year Average 9.96 10.86 135,832

DTE Proposed 25.21 23.72 235,349

As can seen from the table above, the historical 4-CP demand for R3 1

(adjusted for losses up to the generation level) was 9.97 MW in 2016, an average of 2

9.81 MW for the three-year period ending in 2016, an average of 10.33 MW for the 3

five-year period ending in 2016 and 9.96 MW for the ten-year period ending in 2016. 4

The 25.21 MW 4-CP value used by DTE for R3 in its proposed CCOS is 144% to 5

157% higher than these historical 4-CP values. Similarly, the 23.72 MW 12-CP value 6

used by DTE for R3 in its proposed CCOS is 92% to 118% higher than the historical 7

2016 12-CP value and the three, five and ten year average historical 12-CP values. 8

Finally, the 235,349 MWh annual energy consumption at the generation level value 9

used by DTE for R3 in its proposed CCOS is 63% to 78% higher than the historical 10



2016 annual energy consumption at general level value and the three, five and ten 1

year average historical annual energy consumption at the generation level values. 2

Q WHAT IS THE IMPACT OF THIS FLAW? 3

A Since fixed production costs are allocated to classes in DTE CCOS study 75% based 4

on 4-CP demand and 25% annual energy consumption and transmission costs are 5

allocated 100% based on 12-CP demand, the grossly inflated 4-CP, 12-CP and 6

annual energy consumption values used by DTE in its CCOS study greatly overstate 7

the CCOS power supply (i.e., production and transmission) revenue target for R3 that 8

would be necessary to meet cost of service. Specifically, the $13.58 million power 9

supply revenue target identified for R3 in the version of DTE’s proposed CCOS study 10

that models R3 separate from Rate D11 (Exhibit A-13 REVISED, Schedule F1.4, 11

Page 3, Line 27, column (n)) is greatly overstated. As I will discuss in detail later, 12

when this flaw is corrected, the power supply revenue target for R3 drops to 13

$6.311 million. 14

Q HAS DTE PROVIDED EXPLANATION WITH RESPECT TO WHY THE 4-CP, 12-CP 15

AND ANNUAL ENERGY CONSUMPTION AT GENERATION LEVEL VALUES IT 16

USED FOR THE R3 CLASS ARE SO MUCH HIGHER THAN THE HISTORICAL 17

VALUES FOR THOSE AMOUNTS FOR THE R3 CLASS? 18

A Yes. DTE witness Timothy Bloch indicates in his direct testimony he instructed DTE 19

witness Keegan Farrell “to use the maximum 30-minute generator output for internal 20

load during 2016 as the demand level for indentifying standby service and 21

determining allocations schedules for the Rider 3 cost of service class” (Bloch Direct 22

at 18). In doing so, this shifted hourly energy consumption that has historically been 23



classified as supplemental service to being classified as standby service. DTE’s 1

justification for doing so is based on its position that all power provided to a customer 2

up to the maximum capability of the customer’s generation when its generation is not 3

running at full output is standby service even if a portion of it has been historically 4

classified as supplemental service (Bloch Direct at 18-19). 5

Q IS DTE’S EXPLANATION REASONABLE? 6

A No. Appropriately, under DTE’s current retail electric rates, power provided to a 7

customer when its generation is not operating at full output is not standby service 8

power to the extent it is below the maximum monthly on-peak supplemental service 9

demand of that customer. (See DTE Tariff at Sheet D-69.00 at “Demand Charges” or 10

“Daily Demand Charges”). The reason for this is that the customer has already paid 11

for DTE’s fixed production costs and transmission costs up to its maximum monthly 12

on-peak supplemental service demand. So, to the extent the customer’s total power 13

demand when its generation is not operating at full output is below the customer’s 14

maximum monthly on-peak supplemental service demand, it does not cause DTE to 15

incur additional fixed production and transmission costs to serve that customer. Only 16

when the customer’s total power demand is in excess of its maximum monthly on-17

peak supplemental demand is the customer causing DTE to incur additional fixed 18

production and transmission costs. DTE’s historical hourly energy consumption 19

provided by DTE in response to Staff Audit Data Request NMR-6.3 reflects this 20

classification of what is standby service and what is supplemental service. 21



Q DOES THE MODELING OF THE R3 CLASS AS A SEPARATE RATE CLASS IN 1

THE CCOS STUDY REQUIRE THE RECLASSIFICATION OF A PORTION OF 2

HISTORICAL SUPPLEMENTAL SERVICE AS STANDBY SERVICE AS 3

PROPOSED BY DTE? 4

A No. The purpose of modeling R3 as a separate rate class is to provide a cost of 5

service basis for the revenue target for R3. As I will discuss further later in my 6

testimony, the original revenue target used for the rate design for R3 was based on 7

an arbitrary allocation of the overall Rate D11/Other revenue target. This non-cost of 8

service based revenue allocation has been perpetuated over the years in DTE’s 9

subsequent general rate cases by setting the R3 revenue target based on the 10

historical ratio of R3 revenues to total D11/Other revenues. 11

To break this cycle, a cost of service basis for allocating a portion of the 12

overall D11/Other revenue target to R3 needs to be applied. However, this does not 13

require that electric service that is currently properly classified as supplemental 14

service be reclassified as standby service. It only requires that the historical 4-CP 15

demand, 12-CP demand and annual energy consumption associated with the portion 16

of the overall D11/Other revenue target that has been assigned to R3 be broken out 17

from the overall D11/Other 4-CP, 12-CP and annual energy consumption values in 18

the CCOS study. This essentially has the effect of keeping R3 in the overall 19

D11/Other class together even though the two classes are modeled separately in the 20

CCOS study. This is because this approach simply involves breaking the overall 21

D11/Other class 4-CP, 12-CP and annual energy consumption amounts into R3 and 22

non-R3 amounts. As a result, the sum of the new D11/Other (i.e., non-R3) and R3 23

revenues targets will be equal to the revenue target of the old D11/Other class that 24

included R3. 25



Q ON PAGE 18 OF HIS DIRECT TESTIMONY, MR. BLOCH INDICATES ASSIGNING 1

POWER SUPPLY COSTS BASED ON 4-CP DEMAND TO THE STANDBY 2

SERVICE CLASS WHERE LOADS CAN BE VERY IRREGULAR AND CAN VARY 3

SIGNIFICANTLY DOES NOT FOLLOW PROPER COST ALLOCATION 4

PRINCIPLES (BLOCH DIRECT AT 18). HOW DO YOU RESPOND? 5

A I disagree with Mr. Bloch’s conclusion. I agree that standby service is more variable, 6

which could potentially cause 4-CP and 12-CP demand values to fluctuate from year 7

to year much more than for other rate classes. However, this can be addressed by 8

using a larger number of years to produce normalized 4-CP and 12-CP demand 9

values. As I noted earlier, DTE in discovery has produced ten years of historical 10

hourly energy consumption data for R3 standby service. Earlier in my testimony, I 11

also tabulated the annual 4-CP, 12-CP and annual energy consumption values 12

grossed up for losses to the generation level (See Table JRD-1). While that data 13

showed there is significant year-to-year variation, it is important to note that the three, 14

five and ten year 4-CP, 12-CP and annual energy consumption averages from that 15

data are fairly consistent. This, combined with no discernible growth in the use of 16

standby service over the ten-year period, supports the reasonableness of using a ten-17

year average to produce normalized historical 4-CP demand, 12-CP demand and 18

annual energy consumption values at the generation level for the R3 class despite 19

the year-to-year variation in those values. 20



Q HAVE YOU CORRECTED DTE’S CCOS STUDY TO REFLECT HISTORICAL R3 1

4-CP DEMAND, 12-CP DEMAND AND ANNUAL ENERGY CONSUMPTION AT 2

GENERATION LEVEL RATHER THAN THE UNREASONABLY INFLATED 3

VALUES USED BY DTE? 4

A Yes. I have done so by applying the ten-year normalized historical 4-CP, 12-CP and 5

annual energy consumption at the generation level values for R3 that I developed 6

above to segregate R3 from the overall D11/Other class. As a result, in my corrected 7

version of DTE’s CCOS study with R3 broken out, the sum of the 4-CP demand, 8

12-CP demand and annual energy consumption at the generation level values for R3 9

and D11/Other combined are the same as for the D11/Other class in the version of 10

DTE proposed CCOS study that does not break out R3. This ensures that the 11

separate modeling of R3 in the CCOS study does not cause revenues shifts between 12

the overall D11/Other class and the other rate classes. In other words, the revenue 13

targets for the non-R3 and non-D11/Other classes are exactly the same in both my 14

corrected version of DTE’s proposed CCOS study with R3 broken out and in DTE’s 15

proposed CCOS study that does not break out R3. The results of my corrected 16

CCOS study with R3 broken out are summarized in Exhibit AB-20. My CCOS study 17

identifies a cost of service based power supply revenue target of approximately 18

$6.31 million for R3, which is $7.27 million less than the $13.48 million power supply 19

revenue target that resulted from DTE’s proposed CCOS study with R3 broken out 20

that is based on DTE’s grossly inflated and unreasonable 4-CP demand, 12-CP 21

demand and annual energy consumption values for R3. 22



III. Rate Design 1

A. Rider R3 Standby Service 2

Q WHAT IS SELF-SERVICE POWER? 3

A Subsection (12) of MCL§460.10a defines Self-Service Power as any of the following: 4

(a) Electricity generated and consumed at an industrial site or contiguous industrial 5 site or single commercial establishment or single residence without the use of 6 an electric utility’s transmission and distribution system. 7

(b) Electricity generated primarily by the use of by-product fuels, including waste 8

water solids, which electricity is consumed as part of a contiguous facility, with 9 the use of an electric utility’s transmission and distribution system, but only if the 10 point or points of receipt of the power within the facility are not greater than 11 three miles distant from the point of generation. 12

(c) A site or facility with load existing on June 5, 2000 that is divided by an inland 13

body of water or by a public highway, road, or street but that otherwise meets 14 this definition meets the contiguous requirement of this subdivision regardless of 15 whether self-service power was being generated on June 5, 2000. 16

(d) A commercial or industrial facility or single residence that meets the 17

requirements of subdivision (a) or (b) meets this definition whether or not the 18 generation facility is owned by an entity different from the owner of the 19 commercial or industrial site or single residence. 20

Self-service power often involves the use of combined heat and power 21

(“CHP”) facilities that provide both useful electric and thermal energy from a single 22

fuel source at or immediately adjacent to the customer’s site. This is a much more 23

efficient way to provide both electricity and thermal energy than traditional utility 24

service. This improved efficiency reduces environmental impacts, lowers the 25

customer’s costs (making the customer more competitive) and incents electric utilities 26

to improve their own cost efficiency in order for their regulated electric service rates to 27

become more competitive (lowering costs for all of the electric utility’s customers). 28

It is important to note self-service power long predates the existence of retail 29

access in Michigan through alternative electric supply. Furthermore, Subsection (12) 30

of MCL§460.10a clearly defines self-service power as separate and apart from 31



alternative electric supply service. The act of a customer taking self-service power 1

does not involve purchasing power under retail access from an AES. 2

Q WHAT IS STANDBY SERVICE AND WHY IS IT OF SUCH VITAL IMPORTANCE 3

TO SELF-SERVICE POWER CUSTOMERS? 4

A Standby Service (a/k/a backup and maintenance service) is electric service provided 5

when a customer’s self-service power is partially or fully curtailed due to a planned or 6

unplanned deration or outage. While self-service power is highly reliable, just like 7

with utility generation, there will be limited times when self-service power will be 8

partially or fully unavailable due to deration or outages. If self-service power 9

customers were required to: (i) curtail their electric consumption during these 10

occasional deration and outages; (ii) take firm full requirements service from their 11

electric utility to cover these occasional deration and outages; or (iii) build sufficient 12

redundancy in their self-service power to cover these durations and outages 13

themselves, the economics and/or reliability of the self-service power option would be 14

destroyed and the benefits to customers and the public of CHP and other types of 15

self-service power would be lost. 16

As a result, electric utilities are generally required to offer bundled retail 17

standby power to self-service power customers based on the utility’s cost to provide 18

that standby power, which is appreciably less than the utility’s cost to provide firm full 19

requirements service to those same customers. To meet this requirement, DTE 20

currently provides bundled retail standby service to its self-service power customers 21

under its Standard Contract Rider No. 3 (“Rider R3” or “R3”). 22



Q WHAT IS BACKUP SERVICE? 1

A Backup Service is the provision of standby electric energy and capacity to replace 2

energy, ordinarily generated by a customer’s own generation equipment, during an 3

unscheduled (or forced) deration or outage of the customer’s generation equipment. 4

Q WHAT IS MAINTENANCE SERVICE? 5

A Maintenance Service is the provision of standby electric energy and capacity to 6

replace energy, ordinarily generated by a customer’s own generation equipment, 7

during a scheduled (or planned) outage of the customer’s generation equipment. 8

Q WHAT IS SUPPLEMENTAL POWER? 9

A Supplemental Power is power that is purchased in addition to standby service. It is 10

similar in character to the full service provided to non self-service customers. 11

Q CAN YOU ILLUSTRATE THE DIFFERENCES BETWEEN SUPPLEMENTAL, 12

BACKUP, AND MAINTENANCE POWER? 13

A Yes. The following diagram illustrates the relationship between supplemental, 14

backup, and maintenance power. The solid line curve at the top represents total 15

electricity requirement of a self-service customer. The dashed line represents the 16

electricity normally generated by the self-service customer’s own facilities. When 17

generating units are operational and fully available, a self-service customer only 18

requires supplemental power, as indicated by the grey shaded area. Furthermore, as 19

I discussed earlier in my testimony (when addressing the historical split between 20

supplemental and standby service) and as shown in the middle of the diagram below, 21

even when the generating units are completely shut down, the self-service customer 22



may still be purchasing only supplemental power assuming that there is a 1

corresponding load reduction associated with the equipment outages. 2

Backup and maintenance power are depicted in the slashed areas. (The time 3

scale has been exaggerated to illustrate the concepts.) They are required only when 4

a self-service customer needs to purchase electricity to replace power and energy 5

that is normally self-generated. Backup power is purchased during forced derations 6

and outages, while maintenance power is purchased during scheduled derations and 7

outages, which are planned in advance. 8

Q IS DTE REQUIRED TO PROVIDE BACKUP AND MAINTENANCE POWER TO ITS 9

CUSTOMERS? 10

A Yes. Pursuant to the Public Utility Regulatory Policy Act (“PURPA”), DTE is required 11

to offer Backup and Maintenance Service to Cogeneration and Small Power 12

Production Facilities, what are collectively called “Qualifying Facilities” (“QFs”) under 13



FERC regulations, in order to support customer operations that utilize power 1

generated by a QF. As I have noted, DTE currently does so pursuant to its Rider R3. 2

Q CAN YOU PLEASE PROVIDE SOME BRIEF BACKGROUND IN REGARD TO 3

PURPA? 4

A Yes. PURPA was enacted in 1978 and subsequently amended by the Energy Policy 5

Act of 2005. PURPA is intended to encourage conservation and efficient use of 6

energy resources. This included the encouragement of the development and use of 7

Cogeneration and Small Power Production Facilities, including CHP. 8

The encouragement of these types of facilities reduces the amount of capacity 9

the utilities such as DTE require to serve their customers, and is generally more 10

environmentally friendly due to their very high efficiency, particularly in the case of 11

cogeneration facilities. 12

PURPA generally requires electric utilities to sell electric energy to QFs. 13

PURPA also generally requires electric utilities to purchase excess electric energy 14

from QFs. PURPA requires that the FERC establish rules for the rates at which sales 15

are made to QFs such that they are just and reasonable, in the public interest and do 16

not discriminate against QFs. Similarly, it requires FERC to establish rules for the 17

rates at which purchases are made from QFs such that they are just and reasonable 18

to electric consumers of the electric utility, in the public interest, and do not 19

discriminate against QFs. The FERC’s current rules for QFs are contained in 20

Part 292 of 18 CFR Ch. I. 21

The FERC rules, among other things, require the purchase of electric energy 22

and capacity from QFs at a rate no greater than the cost the electric utility avoids by 23

making the purchase. This ensures electric consumers do not subsidize QFs. As a 24



result, electric consumers do not pay more for electricity than they would have if the 1

utility had purchased the power elsewhere or generated the power in its own 2

facilities. The FERC rules also require that the rates for Backup and 3

Maintenance Power for QFs reflect the cost of service to provide such power. 4

This includes reflecting the non-simultaneous nature of QF forced outages and the 5

low likelihood of such outages during the electric utility’s system peak. It also 6

includes the recognition of the coordination of QF scheduled maintenance outages 7

with the scheduled outages of the electric utility’s own facilities. All of this helps to 8

ensure that these rates are: (i) just and reasonable; and (ii) do not result in electric 9

consumers subsidizing QFs. 10

Q DO POLICY REASONS SUPPORT THE PROVISION OF BACKUP AND 11

MAINTENANCE POWER TO FACILITIES OTHER THAN QFs? 12

A Yes. As noted above, the purpose of PURPA is to encourage the development of 13

non-utility owned generation as a means of promoting the efficient use of energy 14

resources. The provision of backup and maintenance power on non-discriminatory 15

terms to customers utilizing such resources is a key provision in PURPA, as it allows 16

customers to rely on such resources without fear that their businesses will grind to a 17

halt if generation equipment needs to shut down. There is no fundamental reason 18

that the provision of backup and maintenance power to facilities that efficiently meet 19

the energy needs of customers should not have access to the same protection as 20

QFs. 21



Q CAN YOU PLEASE DESCRIBE THE FERC PURPA RULES FOR BACKUP AND 1

MAINTENANCE POWER? 2

A Yes. FERC defines Backup Power as: 3

“Electric energy or capacity supplied by an electric utility to replace 4 energy ordinarily generated by a facility’s own generation equipment 5 during an unscheduled outage of the facility.” (18 CFR Ch. I, 6 829.101(b)(9).) 7

FERC defines Maintenance Power as: 8

“Electric energy or capacity supplied by an electric utility during 9 scheduled outages of the qualifying facility.” (Id. at (b)(11).) 10

The FERC’s rules require that the rate for sales of Backup Power or Maintenance 11

Power to QFs: 12

“(1) Shall not be based upon an assumption (unless supported by 13 factual data) that forced outages or other reductions in electric output 14 by all qualifying facilities on an electric utility’s system will occur 15 simultaneously, or during the system peak, or both; and (2) Shall take 16 into account the extent to which scheduled outages of the qualifying 17 facilities can be usefully coordinated with scheduled outages of the 18 utility’s facilities.” (18 CFR Ch. I, § 292.305 (c).) 19

Q HAS THE COMMISSION STAFF PROVIDED RECOMMENDATIONS ON THE 20

PROVISION OF STANDBY SERVICE? 21

A Yes. They were provided on page 23 of the Staff’s June 2017 Standby Rate Working 22

Group Supplemental Report in Case No. U-17735. I have attached a copy of this 23

report as Exhibit AB-21 of my testimony. ABATE generally supports the 24

recommendations of the Staff in this report and I was an active participant in the 25

Standby Working Group on behalf of ABATE. My recommendations in this testimony 26

address many of the Staff’s recommendations with regard to DTE’s provision of 27

standby service including the use of a cost of service basis for the rate, recognition of 28

the demand interactions between supplemental and standby service, review of 29



reservation and daily demand charges, and provision of a reasonable capacity price 1

differential to encourage scheduled maintenance. 2

Q DO CHP AND PROPERLY DESIGNED STANDBY SERVICE TARIFFS PROVIDE 3

ECONOMIC BENEFITS TO THE STATE OF MICHIGAN? 4

A Absolutely. There are two distinct benefits that properly designed standby service 5

tariffs for CHP can offer to the state of Michigan: economic retention and economic 6

growth. First, the economic retention value applies to customers and industries that 7

operate on the margin with respect to the cost of electricity. For these customers, 8

electricity accounts for a major portion of their operating expenses. A properly 9

designed standby service tariff for CHP will provide these customers with an 10

opportunity to lower cost and continue to operate in the state of Michigan. These 11

same characteristics would also be attractive to new business and foster an 12

environment of economic growth in a climate of rising electric rates. 13

Q DOES CHP PROVIDE VALUE TO DTE? 14

A Yes. DTE’s resource planning does not have to account for the large majority of the 15

load served by self-service customers. Because of the high reliability of CHP, DTE 16

only has to plan its resources to meet the expected value of this load at the time of 17

DTE’s system peak. The expected value of this type of load is calculated by 18

multiplying the capacity of the CHP facility by its equivalent forced outage rate 19

(“EFOR”). As I will discuss in more detail later in my testimony, EFORs for CHP are 20

typically less than 10%. Therefore, in order to meet its peak demand, DTE would 21

typically need to plan for less than 10% of the load that takes service under Rider R3. 22



In addition, DTE has proposed to retire 3,306 MW of coal generation by 1

2023.2 If DTE has a properly designed standby service rate to attract existing 2

customers to build CHP, and this leads to greater use of CHP, then DTE will not be 3

required to replace as much of this retired capacity due to more load being served by 4

on-site facilities. 5

Q HOW DOES CHP IMPROVE EFFICIENCY? 6

A As I noted earlier, by simultaneously producing useful electric and thermal energy 7

from a single fuel source at a customer’s site, CHP enhances efficiency, improves 8

environmental quality, and makes businesses more competitive. In addition, since a 9

majority of the customer’s electricity needs are generated on-site, there are virtually 10

no transmission or distribution losses, thus reducing the amount of fossil fuel that 11

must be burned to generate electricity to cover the customer’s load. Most importantly, 12

CHP applies heat energy to a useful purpose that would have otherwise been 13

wasted. 14

Q ARE YOU ADVOCATING FOR ANY SUBSIDIES FOR THE SELF-SERVICE 15

CUSTOMERS? 16

A No, I am only advocating that the self-service customers taking service under 17

Rider R3 pay power supply rates that are reflective of the cost of service for the 18

standby service that is being provided. 19

2Megawatt Daily, June 9, 2016, S&P Global.



Q HAVE YOU PERFORMED ANY REVIEW OF STRUCTURE AND COST OF DTE’S 1

R3 STANDBY SERVICE RATE VERSUS THAT OF OTHER UTILITIES IN THE 2

MIDWEST? 3

A Yes. I did so in February 2017 as part of my participation in the Commission’s 4

Standby Rate Working Group on behalf of ABATE. I have included that comparison 5

as Exhibit AB-22 of my testimony and I have summarized it below in my Table JRD-2. 6

TABLE JRD-2

Comparison of Monthly All-In Utility Standby Service Tariff Charges Under Various Generation Full Outage Scenarios

For 20 MW, Transmission Level Standby Service Customer

As of February 4, 2017

Outage Scenario

Consumers Energy

Company GSG-2

DTE R3

Northern Indiana Public Service

Company Rider 776

AmerenMissouri

Rider SSR

No Outage $12,501 $53,018 $0 $14,466Scheduled Outage 16 Hours Off-Peak $23,338 $65,810 $34,540 $33,212Scheduled Outage 16 Hours On-Peak $51,295 $135,770 $34,540 $41,079Scheduled Outage 8 Hours On-Peak, 8 Hours Off-Peak $37,317 $83,290 $34,540 $37,146Scheduled Outage 32 Hours On-Peak $90,090 $253,523 $69,080 $67,692Unscheduled Outage 8 Hours On-Peak, 8 Hours Off-Peak $37,317 $124,690 $33,439 $49,224

The comparison was performed for a 20 MW transmission level standby service 7

customer under various generation outage scenarios3 for the then-current standby 8

service rates of DTE, Consumers Energy Company, Northern Indiana Public Service 9

Company (“NIPSCO”) and Ameren Missouri. I included NIPSCO because its Rider 10

776 standby service tariff was originally designed within the last decade as part of an 11

overall settlement of NIPSCO’s electric rates and is the product of a negotiations 12

3The outage scenarios were originally developed by 5 Lakes Energy as part of its participation in the Commission’s Standby Rate Working Group.



between NIPSCO, the Indiana Office of Utility Consumers Counsel (“OUCC”) and the 1

NIPSCO Industrial Group. It was recently subject to additional scrutiny in NIPSCO’s 2

last base rate case in Indiana. It is also a good choice for comparison because 3

Michigan and Indiana compete against each other with respect to economic retention 4

and economic development. I included Ameren Missouri’s standby service rider 5

(Rider SSR, as proposed by Ameren Missouri as of February 2017) because it was a 6

recent proposal that had extensive stakeholder input into it prior to being filed with the 7

Missouri Public Service Commission. As can be seen from my summary in Table 8

JRD-2 above, my comparison shows that, under all six of the outage scenarios I 9

examined, the total monthly charges for standby service for DTE are much higher 10

than those of Consumers Energy Company, NIPSCO and Ameren Missouri. 11

As part of my comparison, I also examined the standby service daily demand 12

charges of each of these utilities as a percentage of the monthly demand charge of 13

that utility’s applicable full service rate. This showed that DTE’s standby service daily 14

demand charges as a percentage of the full service monthly demand charge are 15

much higher than for Consumers, NIPSCO or Ameren Missouri. For DTE the 16

percentage ranged from 18% to 32% of the full service monthly demand charge (See 17

Exhibit AB-22 at page 2). For Consumers Energy Company, NIPSCO and Ameren 18

Missouri, the percentage was much lower -- roughly in the range of 2% to 5% of the 19

full service monthly demand charge (Id.). This suggests that DTE’s very high standby 20

service rate is not a product of DTE’s revenue requirement being much higher than 21

that of the other three utilities and is instead related to poor rate design. 22



Q HAVE YOU IDENTIFIED THE UNDERLYING DRIVERS OF DTE’S MUCH HIGHER 1

STANDBY SERVICE CHARGES? 2

A Yes. They are caused by a combination of the revenue target used in the rate design 3

for DTE’s Rider R3 along with the characteristics of the R3 rate design. With respect 4

to the revenue target for rate design, while I was participating in the Commission’s 5

Standby Rate Working Group, it came to light in discussions with DTE that the 6

revenue target for R3 was originally established as roughly 1% of the overall 7

D11/Other revenue target. As I discussed earlier in my testimony, this arbitrary 8

allocation of revenue has continually been perpetuated over the years since R3 has 9

been treated as a subsidiary class to D11/Other. As a subsidiary class, R3 has had 10

its revenue target for revenue design set based on its historical revenues versus that 11

of the D11 rate class as a whole (See Exhibit AB-21 at 6). Thus, DTE’s revenue 12

target for R3 has not been based on the cost of service to provide R3 service. 13

In addition, DTE’s reservation and demand charge rate design structure is 14

highly punitive and creates intra-class subsidies between individual R3 customers. 15

First, if there is a reservation fee, it should be based on the forced outage rate of the 16

best performing customers, so as not to require those customers to pay more than 17

their own cost of service. As proposed by DTE, the reservation fee represents 18

16.1%4 of the Rate D11 demand rate, which would assume that all customers in this 19

class would experience, on average, approximately 4.9 outage days per month.5 20

Distributed Generation (“DG”) and CHP generation facilities can be very 21

reliable, with forced outage characteristics comparable to that of the latest utility 22

combined-cycle gas turbine generation facilities. For example, in Exhibit AB-23 I 23

have included a copy of a January 2004 Executive Summary Report titled “Distributed 24

4$2.74 ÷ $17.01 = 16.1%; See Exhibit A-14 Revised, Schedule F3 at page 35). 54.9 outage days per month = 16.1% x 365 days per year ÷ 12 months per year.



Generating Operational Reliability and Availability Database” prepared on behalf of 1

Oak Ridge National Laboratory and other parties by Energy and Environmental 2

Analysis, Inc. The team that prepared the report collected data on 121 DG and CHP 3

facilities (Exhibit AB-23 at 3-4). It found that DG and CHP based on reciprocating 4

engines, gas turbines and/or steam turbines all had forced outage rates that all 5

average under 3% (Id. at 6-7). It also compared this to the average forced outage 6

rate of utility and independent power producer combined-cycle gas turbine generation 7

facilities in the 1997-2001 timeframe, which was 3.24%. For further comparison, 8

MISO has reported that the class average forced outage rate for combined-cycle 9

generation in the MISO footprint is only 3.61%6 or, on average, approximately 10

1.1 outage days per month.7 Given all of this data, the best performing Rider R3 11

customers would be expected to experience, on average, no more than one forced 12

outage per month, not, on average, approximately 4.9 per month. 13

Similarly, Rider R3’s current and proposed daily on-peak demand charges are 14

excessive. The proposed daily on-peak backup demand charge is equal to 42.2% of 15

the Rate D11 demand charge.8 This essentially assumes there are only 2.37,9 rather 16

than 20, on-peak days in a month and that Rider R3 customers should pay the full 17

Rate D11 power supply demand charge once they have experienced three 18

(3) on-peak forced outage days in a month (a forced outage rate of 33%). Given the 19

random nature of forced generation durations and outages, it is much more 20

appropriate and reflective of cost of service if the Rate D11 power supply on-peak 21

daily backup demand rate is instead divided by the number of on-peak days per 22

6See Slide 5 of MISO Presentation “2017 LOLE Model Input Capacity,” Loss of Load

Expectation Working Group (“LOLEWG”), June 1, 2016: https://www.misoenergy.org/_layouts/MISO/ECM/Redirect.aspx?ID=225595 71.1 outage days per month = 3.61% x 365 days per year ÷ 12 months per year. 842.2% = $7.18 ÷ $17.01; See Exhibit A-14 Revised, Schedule F3 at page 35. 92.37 = 1 ÷ 42.2%.



month (approximately 20 days). This would be an on-peak daily demand charge that 1

is set at 5% (1/20th) of the D11 monthly demand charge. This would also bring DTE 2

in line with Consumers Energy Company, NIPSCO and Ameren Missouri. As I noted 3

earlier, these utilities each have standby service daily demand charges roughly in the 4

range of 2 to 6% of their respective full service rate monthly demand charges. 5

In summary, it is the combination of the revenue target for the rate not being 6

based on cost of service and a poor rate design structure that causes DTE’s R3 7

standby service to be much higher than those of the other utilities in the Midwest that 8

were included in my comparison. DTE’s current and proposed R3 rates are 9

unreasonable and need to be corrected in this proceeding. 10

Q HOW CAN THE REVENUE TARGET ISSUE BE RESOLVED FOR R3? 11

A It is resolvable by properly modeling R3 as a separate rate class in DTE’s CCOS 12

study. If there is sufficient data and it is properly captured in the CCOS study, the 13

CCOS study will identify the revenue target necessary for R3 to collect the cost for 14

service to provide it. Both the Commission Staff and ABATE advocated in DTE’s 15

most recent previous general rate case that this be explored by DTE. As a result, the 16

Commission in Paragraph N of its ordering paragraphs in its Final Order in that 17

proceeding required DTE to provide a CCOS study in this proceeding that treated R3 18

as a separate rate class. However, as I have discussed earlier in my testimony, there 19

are serious flaws in the CCOS study that DTE proposed in this proceeding that treats 20

R3 as a separate rate class. However, as I have also previously discussed, I was 21

able to rectify those shortcomings by using the ten years of historical hourly energy 22

consumption date that DTE provided in response to discovery. That resulted in a 23

revenue target of $6.311 million for R3 versus the $13.578 million amount in DTE’s 24



CCOS study and the $9.694 million amount that DTE actually used in its proposed 1

rate design for R3. I recommend that the R3 rates be designed using this 2

$6.311 million revenue target for R3 rather than the $9.694 million target that DTE 3

used in its proposed R3 rate design. 4

Q IF DTE’S PROPOSED RATE DESIGN STRUCTURE IS MAINTAINED, HOW MUST 5

THE RATES CHANGE IN ORDER TO MEET YOUR RECOMMENDED REVENUE 6

TARGET OF $6.311 MILLION? 7

A If the R3 power supply demand rate structure10 is to be retained and the power supply 8

revenue target is set at $6.311 million, then significant reductions to the power supply 9

demand charges would be required. I have calculated that a scaling factor of 28.8% 10

would be needed to reduce all of the power supply reservation and demand charges 11

including the monthly cap on R3 daily demand charges (i.e., the monthly cap on R3 12

daily demand charges would be set at 28.8% of the D11 monthly power supply 13

demand charge rather than at 100% of the D11 monthly power supply demand 14

charge). My calculations are summarized in Exhibit AB-24. 15

This scaled down rate design highlights a significant problem with DTE’s 16

proposed rate design. The billing units that DTE has assembled for its R3 rate design 17

are only applicable to DTE’s present rate design, in which the power supply demand 18

charges reach and are capped at the monthly D11 power supply demand rate after 19

only three days of on-peak outages. As a result, this scaled down demand charge 20

version of R3 would need to have a maximum monthly power supply demand rate of 21

$4.90/kW, which is only 28.8% of the full service D11 monthly power supply demand 22

rate in order to prevent the R3 rates from greatly over-collecting their revenue target. 23

10The R3 demand rates I am referring to are the Generation Reservation Fee, Daily Demand, Maintenance Demand, and Maximum Billing Demand, as well as the voltage level discounts for subtransmission and transmission voltage customers.



Note that this 28.8% scaling factor for the R3 power supply reservation and demand 1

charges is based on DTE’s filed revenue requirement, capacity-related cost split and 2

proposed rate design for D11. To the extent any of the forgoing change, the scaling 3

factor may need to be adjusted to prevent over or under-recovery of the R3 revenue 4

target. 5

Q ARE YOU RECOMMENDING THE COMMISSION ADOPT THIS SCALED DOWN 6

POWER SUPPLY DEMAND CHARGE VERSION OF THE R3 RATE DESIGN? 7

A As I discuss later in my testimony, I am only recommending its adoption if the 8

Commission does not adopt the R3 rate design I propose below. 9

Q WHAT IS YOUR RECOMMENDED RATE DESIGN FOR R3? 10

A As I have alluded to at the outset of my testimony, I recommend the Commission 11

discard DTE’s proposed power supply reservation and demand charge rate design 12

structure for R3 and replace it with one which has: (i) a monthly power supply 13

reservation charge that reasonably accommodates the forced outage rates of the 14

best performing generators of R3 customers, (ii) an on-peak daily power supply 15

demand charge based on an on-peak day pro ration of the full service D11 monthly 16

power supply demand charge and (iii) a maintenance on-peak demand charge set at 17

50% on the on-peak daily power supply demand charge. 18

Specifically, I propose the monthly power supply reservation charge be set 19

based on 1/20th or 5% of the monthly D11 power supply demand charge. 5% is much 20

closer than DTE’s proposed 16.1%11 to the 2% to 4% average forced outage rate of 21

reciprocating engine, gas turbine and steam turbine DG and CHP generation that I 22

11As noted earlier in my testimony, DTE’s proposed R3 power supply reservation charge is

16.1% of the monthly D11 power supply demand charge.



identified earlier in my testimony. By setting this reservation charge much closer to 1

2 to 4% of the D11 monthly power supply demand charge, it would reduce the 2

payment of subsidies from R3 customers with better performing generation to R3 3

customers with poorer performing generation facilities. For illustration purposes, this 4

monthly charge would be $1.03 per kW-month at the primary voltage level assuming 5

a total D11 monthly power supply demand charge of $20.60 per kW-month.12 6

The prorated daily on-peak power supply demand charge would be set at 7

1/20th (or 5%) of the of the monthly D11 power supply demand charge. This pro 8

ration approach, which is broadly similar in concept to Consumers Energy Company’s 9

on-peak daily demand charge structure, would have R3 customers pay on-peak daily 10

power supply demand change in proportion to the amount they use standby service 11

during a given month. It would still cap out at the D11 monthly power supply demand 12

charge, but only when 20 on-peak days of outage occur. This would eliminate the 13

current punitive application of the D11 monthly power supply demand charge after 14

just 3 on-peak days of generation outage. In addition, it is a critical component 15

necessary to eliminate the over-recovery of the R3 power revenue target that would 16

exist under DTE’s current R3 rate design structure unless DTE’s reservation and 17

demand charges are scaled down to 28.8% of what DTE proposed for those charges. 18

For illustration purposes, my proposed on-peak daily power supply demand rate 19

would be $1.03 per kW-day at the primary voltage level assuming a total D11 monthly 20

power supply demand charge of $20.60 per kW-month. 21

Finally, a maintenance on-peak daily power supply demand charge would be 22

retained, but set at 50% of my proposed on-peak daily power supply demand charge. 23

12$20.60 per kW-month is the sum of the illustrative capacity and non-capacity related demand

charges for D11 primary voltage customers shown in Exhibit AB-26, which reflects the recovery of transmission expenses in D11 demand charges as I propose later in this testimony.



This charge would be $0.515 per kW-day at the primary voltage level assuming a 1

total D11 monthly power supply demand charge of $20.60 per kW-month. 2

Q DTE’S CURRENT AND PROPOSED R3 ONLY HAS A CUSTOMER PAY THE 3

HIGHER OF THE MONTHLY RESERVATION CHARGE OR THE SUM OF DAILY 4

DEMAND CHARGES FOR THAT MONTH (DTE TARIFF SHEET NO. D-70.00). 5

DOES YOUR PROPOSED RATE DESIGN CONTINUE THAT FEATURE? 6

A Yes. Under my proposed rate design for R3, customers would continue to pay only 7

the higher of the monthly reservation charge or the total daily demand charges for 8

that month. This is an important feature that recognizes that the reservation charge 9

has the customer effectively pre-pay for a limited amount of standby service daily 10

demand charges on a take-or-pay basis. The feature effectively credits the customer 11

for its pre-paid reservation charge prior to having to pay daily demand charges. 12

Q HOW WOULD THESE PROPOSED R3 RATES COMPARE TO CONSUMERS 13

ENERGY COMPANY’S, NIPSCO’S AND AMEREN MISSOURI’S STANDBY 14

SERVICE RATES AS THOSE RATES EXISTED IN FEBRUARY 2017? 15

A In Exhibit AB-25 I have updated my comparison of these standby service rates under 16

various operating scenarios to reflect my proposed R3 rate design for DTE. In 17

addition, I have summarized that update comparison in my Table JRD-3 below. 18



TABLE JRD-3

Comparison of Monthly All-In Utility Standby Service Tariff Charges

Under Various Generation Full Outage Scenarios For 20 MW, Transmission Level Standby Service Customer

As of February 4, 2017

Outage Scenario

Consumers Energy

Company GSG-2

ABATE Proposed

DTE R3

Northern Indiana Public Service

Company Rider 776

AmerenMissouri

Rider SSR

No Outage $12,501 $35,068 $0 $14,466Scheduled Outage 16 Hours Off-Peak $23,338 $44,731 $34,540 $33,212Scheduled Outage 16 Hours On-Peak $51,295 $47,931 $34,540 $41,079Scheduled Outage 8 Hours On-Peak, 8 Hours Off-Peak $37,317 $46,331 $34,540 $37,146Scheduled Outage 32 Hours On-Peak $90,090 $80,243 $69,080 $67,692Unscheduled Outage 8 Hours On-Peak, 8 Hours Off-Peak $37,317 $46,331 $33,439 $49,224

As can be seen from my Table JRD-3 above, my proposed R3 rate design produces 1

monthly standby service charges much more comparable to those under the standby service 2

rates for Consumers Energy Company, NIPSCO and Ameren Missouri. As a result, my 3

recommended R3 rate design would eliminate the large disparity between standby service 4

costs that currently exists between DTE and these three utilities. 5



Q CAN YOU PROVIDE A REVENUE PROOF THAT DEMONSTRATES YOUR 1

PROPOSED R3 RATE DESIGN WOULD BE EXPECTED TO COLLECT YOUR 2

RECOMMENDED R3 REVENUE TARGET? 3

A I cannot provide a rigorous revenue proof since DTE has not collected its R3 on-peak 4

daily demand billing units without application of its monthly D11 power supply 5

demand charge cap on R3 on-peak daily power supply demand charges. However, 6

my comparison of my proposed R3 rate design to the standby service rates of 7

Consumers Energy Company, NIPSCO and Ameren Missouri in Exhibit AB-2 and 8

Table JRD-3 demonstrates that my proposal produces monthly charges reasonably 9

comparable to those of the other three utilities. Furthermore, a comparison of the 10

monthly charges collected under my proposed R3 rate in Table JRD-3 versus that 11

collected under the current R3 rate in Table JRD-2 strongly suggests that my 12

proposed R3 rate will provide enough revenue to meet my recommended R3 revenue 13

target of $6.311 million. Specifically, for every outage scenario presented in Tables 14

JRD-2 and JRD-3, my proposed R3 rate produces monthly R3 revenue of between 15

32% and 68% of DTE’s current R3 rate. This is above the 28.8% scaling factor that 16

would be applied under my alternative R3 recommendation of a scaled down version 17

of DTE’ proposed R3 rate design. Finally, once my recommended R3 rate design is 18

in place, DTE would be able to start collecting billing units under my proposed rate 19

design and the R3 rates under the rate design could be adjusted as necessary on a 20

going forward basis through a revenue proof in DTE’s next general rate case 21

proceeding. In conclusion, R3 customers should not continue to be subject to a 22

punitive standby service rate design simply because DTE has not assembled the 23

billing unit information necessary to perform a rigorous revenue proof at this time. 24



Q WHAT DO YOU RECOMMEND TO THE COMMISSION IF, DESPITE YOUR 1

RECOMMENDATION, THE COMMISSION CHOOSES NOT TO ADOPT YOUR 2

RECOMMENDED RATE DESIGN FOR R3? 3

A If despite my recommendation the Commission does not adopt my recommended R3 4

rate design, I recommend it instead for this proceeding adopt my scaled down DTE 5

R3 power supply reservation and demand charges that would be set at 28.8%13 of the 6

charges that were proposed by DTE. This would at least ensure DTE is not 7

recovering power supply revenues from R3 customers well in excess of my 8

recommended CCOS study power supply revenue target of $6.311 million for R3. As 9

I noted earlier, DTE’s proposed R3 rates would over recover the R3 power supply 10

revenue target by approximately 54%. The Commission should also require DTE to 11

maintain a record of the billing determinants for R3, such that the historical 12

reservation charge, on-peak daily demand charge and maintenance on-peak daily 13

demand charge billing units are accumulated without the D11 monthly power supply 14

demand charge cap applied. This would allow the accumulation of the billing units 15

necessary to perform a rigorous revenue proof of my recommended R3 rate design in 16

the next general rate case even if the Commission does not adopt my recommended 17

R3 rate design in this current case. 18

B. Rate D11 Demand Charge Voltage Level Discounts 19

Q PLEASE DESCRIBE THE RATE DESIGN CHANGES THAT DTE HAS PROPOSED 20

TO RATE D11? 21

A In response to Paragraph M of the ordering paragraphs of the Commission’s Final 22

Order in Case No. U-18014, DTE has changed the manner in which it has calculated 23

13Again, this scaling factor is only illustrative of DTE’s proposed total revenue requirement

issue, capacity-related cost split and proposed rate design for D11.



the voltage level discounts. For the first time, DTE is proposing both an energy 1

charge discount and a demand charge discount for Subtransmission and 2

Transmission voltage level customers. 3

For the Energy Charge Discount, DTE has calculated the discount in a 4

manner consistent with ABATE’s past recommendations. This procedure is to 5

allocate the costs to each voltage level within the class by using the losses-adjusted 6

billing units. Those allocated costs are then divided by the billing units to arrive at the 7

energy rate for each class.14 This procedure ensures that the transmission customers 8

pay a lower rate than the subtransmission customers who pay a lower rate than the 9

primary voltage customers. 10

For the Demand Charge Discount, DTE has proposed a different methodology 11

than for the energy rate. This procedure allocates the cost to each voltage level 12

within the class by the 4-CP demands. Those allocated costs are then divided by the 13

test year billing units to arrive at the tariff rate for each voltage level.15 By using this 14

procedure, there is no way to ensure that higher voltage customers pay lower rates 15

than lower voltage customers, as the 4-CP demands from a historical period do not 16

necessarily reflect the test year billing determinants 17

Q DOES ABATE HAVE CONCERNS WITH THESE CHANGES? 18

A Yes. ABATE has concerns with DTE’s proposed voltage level discounts for the 19

demand charges. The procedure DTE is utilizing is significantly flawed and does not 20

determine rates that are based on cost-causation principles. This procedure is 21

14There is a single rate for all customers, but the transmission and subtransmission customers

receive a discount. 15There is a single rate for each voltage level, but the transmission and subtransmission

customers receive a discount relative to primary.



incorrect, and the methodology used for the energy charge discount should instead 1

be used for the demand charge discount. 2

Q HOW DO YOU KNOW THAT THE IMPLEMENTED RATE DESIGN CHANGE FOR 3

THE DEMAND RATES IS INCORRECT? 4

A DTE’s proposed voltage discount for the subtransmission customers is $1.13/kW, but 5

for the transmission level customers, the demand discount is only $0.50/kW. This is a 6

clear indication that DTE’s proposal is flawed. It is less expensive to provide service 7

to higher voltage level customers, which is why transmission level customers should 8

pay rates that are lower than subtransmission customers. 9

Q WHY DO YOU STATE THAT IT IS LESS EXPENSIVE TO PROVIDE SERVICE TO 10

A TRANSMISSION LEVEL CUSTOMER THAN ANY CUSTOMER SERVED AT A 11

HIGHER VOLTAGE? 12

A A transmission customer takes service at the transmission level of the electric grid. 13

DTE’s own loss factors prove that it is less expensive to serve the transmission level 14

customer.16 In order for a single MW of demand to be delivered to the transmission 15

customer, DTE must generate or purchase 1.03 MW to account for the losses. 16

Contrast this with a subtransmission customer that would require DTE to generate 17

1.05 MW to provide a single MW or a primary customer that would require 1.09 MW 18

at the generator to provide the single MW at the primary customer meter. The 19

transmission level customer utilizes less infrastructure and creates fewer losses than 20

the subtransmission customer; therefore it is less expensive to provide service. 21

16WP KOF-2.



Q ARE YOU AWARE OF ANY OTHER ELECTRIC UTILITY THAT CHARGES A 1

TRANSMISSION VOLTAGE A HIGHER DEMAND CHARGE THAN CUSTOMERS 2

SERVED AT LOWER VOLTAGES? 3

A No. I am not currently aware of such an example. 4

Q HOW DO YOU SUGGEST THIS ISSUE BE REMEDIED? 5

A ABATE recommends that the demand level discounts be calculated using the same 6

procedure as the energy charge discount. This procedure is consistent with ABATE’s 7

past recommendations and is consistent with cost-causation principles. 8

Q HAVE YOU PERFORMED A CALCULATION OF DEMAND RATES DONE IN THE 9

SAME MANNER AS DTE PROPOSED TO CALCULATE THE ENERGY RATE 10

DISCOUNTS? 11

A Yes. Table JRD-4 shows ABATE’s proposed voltage discounts for the D11 demand 12

charge. These rates were calculated on the assumption that the D11 demand rates 13

should recover $390.859 million, and are provided for illustrative purposes to show 14

the impact of the change of methodology. 15

TABLE JRD-4

Voltage Level

DTE Proposed Rate/ Discount

ABATE Proposed Rate/Discount

Delta

Demand Rate $17.01 $17.07 +$0.06 Subtransmission Discount ($1.13) ($0.63) +$0.50 Transmission Discount ($0.50) ($0.95) ($0.45)

As can be seen in this table, the transmission level discount is larger than the 16

subtransmission discount. ABATE’s proposed demand voltage discounts will allow 17



DTE to recover the same $390.859 million from D11, but will collect these costs from 1

customers in a way more reflective of cost of service principles. 2

C. Collection of Transmission Expenses from Rate D11 Customers 3

Q WHAT TRANSMISSION COST OR EXPENSE DOES DTE INCUR IN ORDER TO 4

PROVIDE TRANSMISSION SERVICE TO ITS BUNDLED SERVICE RETAIL 5

CUSTOMERS? 6

A DTE does not own its own transmission system and instead purchases transmission 7

service from International Transmission Company (“ITC”) and other MISO 8

transmission owners under MISO’s FERC-filed tariff. These expenses are principally 9

billed to DTE on a 12-CP load ratio share, or the DTE system total load at the time of 10

the ITC total coincident peaks each month of the planning year.17 11

Q HOW DOES DTE ALLOCATE THE TEST YEAR TRANSMISSION EXPENSE 12

ACROSS RETAIL CUSTOMER CLASSES? 13

A DTE’s proposal is to continue the Commission-approved 100% 12-CP allocation 14

method.18 I do not take issue with DTE’s proposed cost allocation for transmission 15

expenses. 16

Q HOW DOES DTE PROPOSE TO RECOVER THE TRANSMISSION EXPENSE 17

ALLOCATED TO THE D11 CLASS FROM D11 CUSTOMERS? 18

A Based on my review of the Company’s filing, I have concluded that DTE proposes 19

using a non-capacity energy charge to recover the allocated transmission expense. 20

17Lacey Direct at 18. 18Id.



Q DO YOU SUPPORT DTE’S PROPOSED TRANSMISSION COST RECOVERY 1

METHOD FOR D11 CUSTOMERS? 2

A No. DTE’s proposal to recover the demand-related transmission expense from D11 3

customers on an energy basis is illogical and does not follow sound cost of service 4

principles. This argument holds true for any other DTE retail customer rate for which 5

DTE proposes recovery of transmission expense through an energy charge, but I am 6

presenting testimony in this proceeding supporting only at this time proposing a 7

change in Rate D11 recovery of transmission expenses. 8

Q PLEASE DESCRIBE HOW YOU CAME TO THE CONCLUSION THAT DTE 9

PROPOSES TO RECOVER TRANSMISSION EXPENSE THROUGH AN ENERGY 10

CHARGE FOR RATE D11 CUSTOMERS. 11

A Mr. Lacey calculates DTE’s proposed total capacity-related power supply revenue 12

requirement for each class on his Exhibit A-3, Schedule F1.5, line 7. Transmission 13

revenues are not explicitly shown on this Exhibit A-3, Schedule F1.5, but a review of 14

the COSS workpapers in Excel format indicate that they are included within Fuel 15

shown on line 3. In other words, DTE has appropriately classified the transmission 16

expense as non-capacity related, but has inaccurately lumped the transmission 17

expense into the same category as fuel costs. 18

In addition, Mr. Bloch describes at page 10 of his testimony that he uses the 19

capacity-related class revenue requirement calculated by Mr. Lacey to determine the 20

appropriate capacity demand and energy charges for primary service customers, 21

which includes Rate D11 customers. Looking at Exhibit A-14, Schedule F3, page 24, 22

one can see that this demand charge for recovery of fixed capacity-related revenue 23

requirement is the only demand charge billed to Rate D11 customers, save for 24



distribution demand charges which are calculated separate and apart from the power 1

supply charges. DTE accounts for transmission expense as a power supply expense. 2

Lastly, a comparison of the capacity-related $535.604 million figure on 3

Exhibit A-3, Schedule F1.5, line 7, column n for Rate D11 customers to the 4

$528.068 million figure on Exhibit A-14, Schedule F3, page 24 shows that DTE is 5

recovering only what it calculates to be capacity-related power supply revenues 6

through the capacity-related demand and energy charges.19 All other non-capacity 7

related power supply charges are recovered through the non-capacity energy charge 8

shown on Exhibit A-14, Schedule F3, page 24. 9

Q WHAT IS YOUR RECOMMENDATION CONCERNING RECOVERY OF 10

TRANSMISSION EXPENSE FROM RATE D11 CUSTOMERS? 11

A I recommend that these demand-related power supply expenses be recovered from 12

Rate D11 customers through a base rate demand charge, structured similarly to 13

DTE’s proposed capacity-related base rate demand charges, where customers at 14

higher voltage levels receive the appropriate voltage level credit off of the baseline 15

transmission charge rate. To illustrate my proposal, I have developed transmission 16

demand charges for Rate D11 customers, shown in Exhibit AB-26, and have also 17

calculated the reduced power supply non-capacity energy charges that no longer 18

need to recover transmission expense. Exhibit AB-26 also reflects the changes in the 19

D11 power supply revenue targets that result from my testimony with respect to R3. I 20

recommend the Commission approve this revised D11 rate design with respect to the 21

recovery of transmission expenses, illustratively summarized below in Table JRD-5, 22

19The difference of $7.537 million is the amount of capacity-related revenue allocated to

Rate D11 non-firm customers taking standby or interruptible service. This allocation is performed within Mr. Bloch’s rate design workpapers in Excel.



in order to appropriately recover transmission expenses from D11 customers through 1

a demand charge. 2

Q PLEASE DESCRIBE HOW YOU CALCULATED YOUR PROPOSED 3

TRANSMISSION DEMAND CHARGES. 4

A Using the allocated transmission expense for Rate D11 customers in my corrected 5

COSS, I allocate that total to Rate D11 firm service customers using the same 6

method DTE has employed in its rate design workpapers for allocating the other 7

demand-related power supply expenses. I further allocate the Rate D11 firm service 8

expense amount to the various service voltage level subclasses, based on the loss 9

adjusted demand billing units. Finally, I divide the allocated transmission expense by 10

the monthly billing demands shown on Exhibit A-14, Schedule F3, page 24 for 11

capacity-related revenue for customers under each voltage level to determine the 12

DTE ABATERate Component Proposed Proposed

Non-CapacityTransmission Demand Charge n/a 3.39$

Voltage Level DiscountSubtransmission n/a (0.13)$ Transmission n/a (0.19)$

Energy 0.02477$ 0.01863$

Voltage Level DiscountSubtransmission (0.00710)$ (0.00710)$ Transmission (0.00122)$ (0.00122)$

Proposed D11 Transmission and Non-Capacity Rate Design

TABLE JRD-5

ABATE



final proposed transmission rate. I recommend that the transmission demand charge 1

be billed on the same 12 month peak demands used for billing capacity demand 2

charges to Rate D11 customers.20 3

The result is my proposed transmission demand rate for Primary, 4

Subtransmission, and Transmission voltage level Rate D11 customers, illustratively 5

shown on lines 17 through 20 of Exhibit AB-26. Because I recommend a new line 6

item charge for Rate D11 customers, I calculate as well the commensurate reduction 7

in the non-capacity energy charges proposed by Rate D11 by reducing the energy 8

charge by the appropriate amount. This resulting non-capacity energy charges are 9

illustratively shown on line 22 of Exhibit AB-26. My transmission rate proposal does 10

not result in a shift of transmission revenue requirements among customer classes. It 11

only changes how the total transmission expense allocation to the D11 class is 12

recovered from D11 customers. 13

IV. Interaction Between Case Nos. U-18255 and U-18248 14

Q HOW DO THE ISSUES BEFORE THE MPSC IN DTE’S 6W PROCEEDING CASE 15

NO. U-18248 INTERACT WITH THE ISSUES BEFORE THE MPSC IN THE 16

INSTANT PROCEEDING, DTE’S BASE RATE CASE? 17

A The primary question before the MPSC in Case No. U-18248 is the determination of 18

the appropriate capacity-related component of DTE’s embedded cost of service total 19

revenue requirement. I recommend that the outcome of that case, specifically the 20

MPSC’s determination of the appropriate capacity-related versus non-capacity related 21

20Although this billing determinant is not equal to the true billing determinant that DTE is billed for transmission expense – DTE is billed on the 12-CP basis – the on-peak demand is a usable proxy while this transmission billing method is first beginning. In future cases, it would be appropriate to review the correlation between Rate D11 customers’ monthly on-peak demands and their demands at the time of the 12 ITC system coincident peaks, with sufficient data to unearth whether an appropriate pattern can be discerned, and a better price signal sent to Rate D11 customers in the form of adjusted billing determinants for transmission rates.



power supply costs, be used and coordinated in the instant proceeding when 1

determining the appropriate capacity-related charges ultimately approved for each 2

retail class. 3

Q SHOULD THE MPSC DECISION IN CASE NO. U-18248 BE USED TO DETERMINE 4

THE APPROPRIATE CAPACITY-RELATED DEMAND CHARGE ULTIMATELY 5

AUTHORIZED FOR RATE D11 CUSTOMERS IN THE INSTANT PROCEEDING? 6

A Yes. MPSC should order the appropriate calculation methodology for 7

capacity-related costs allocated to the bundled retail service customers in Case 8

No. U-18248, and such methodology should carry over to the instant base rate 9

proceeding. However, I echo my recommendation raised in Case No. U-18248 in my 10

Direct Testimony at page 21-24 for a filing by DTE after the February 2018 AES SRM 11

capacity demonstrations are made to reflect actual billing units for the period June 1, 12

2018 - May 31, 2019 of ROA customers purchasing capacity from DTE. Actualizing 13

these billing units for the upcoming planning year period will allow for proper cost 14

recovery from all retail customers. 15

Q DO YOU AGREE WITH OTHER PARTIES’ PROPOSALS IN CASE NO. U-18248 16

THAT ALL NON-CAPACITY RELATED FIXED PRODUCTION COSTS ARE 17

ENERGY-RELATED? 18

A No. As I have proven previously in Section IV D of this testimony, transmission 19

expense is one obvious example of non-capacity related costs that are not 20

energy-related. Therefore, in the event MPSC determines in Case No. U-18248 the 21

appropriate capacity-related power supply cost to be recovered from retail customers, 22

I do not believe it will be as simple as taking the remaining power supply costs 23



designated as non-capacity related and allocating or collecting those costs through 1

an energy charge. The remaining non-capacity related power supply charges must 2

be appropriately assigned as being demand-related or energy-related as they would 3

be in any proper cost of service study, and, thereafter, recovered from customers in 4

the appropriate manner. 5

Regardless of how the Commission decides to split fixed production costs 6

between capacity and non-capacity costs in Case No. U-18248 and here in this 7

proceeding and assuming the Commission adopts DTE’s proposed 75-0-25 allocation 8

method for fixed production costs, no less than 75% of total fixed production costs 9

should continue to be allocated to bundled retail customer classes on the basis of 10

4-CP demand. Since non-capacity related fixed production costs are not necessarily 11

energy-related, the allocation of total fixed production costs bundled to retail 12

customers should not be changed simply due to segregating them between 13

capacity-related and non-capacity related costs. While I believe all fixed production 14

costs, whether capacity-related or not, should be allocated to bundled retail 15

customers 100% on a 4-CP demand basis (i.e., using 100-0-0 method), to the extent 16

the Commission deems any portion of non-capacity related fixed production costs 17

should be allocated on the basis of annual energy consumption, the costs allocated in 18

that way should not exceed 25% of DTE’s total fixed production costs consistent with 19

the 75-0-25 method. 20

V. Conclusions and Recommendations 21

Q PLEASE SUMMARIZE YOUR CONCLUSIONS AND RECOMMENDATIONS IN 22

THIS PROCEEDING. 23

A My conclusions and recommendations are as follows: 24



1. DTE’s proposed CCOS is seriously flawed with respect to the R3 class and 1 should be modified as proposed in the body of my testimony. This lowers the 2 power supply CCOS revenue target of the R3 class from approximately 3 $13.58 million to approximately $6.31 million. 4

2. When DTE’s proposed rate design R3 power supply revenue target of 5 $9.69 million21 is lowered to ABATE’s CCOS R3 power supply revenue target of 6 $6.31 million, DTE’s proposed power supply reservation and demand charge 7 rate design would over-collect revenue from R3 customers by $3.38 million 8 (53.6%). To address this issue and bring R3 in line with cost of service, DTE’s 9 proposed reservation and demand charge rate design for power supply should 10 be replaced with: (i) a monthly power supply reservation charge that 11 accommodates the forced outage rate of the best performing generation of R3 12 customers, (ii) an on-peak daily power supply demand charge based on an 13 on-peak day pro ration of the full service D11 monthly power supply demand 14 charge and (iii) a maintenance on-peak daily demand charge set at 50% of the 15 normal on-peak daily power supply demand charge . 16

3. DTE’s proposed Rate D11 demand charges voltage level discounts of $0.50 per 17 kW-month for transmission and $1.13 per kW-month for subtransmission are 18 inconsistent with cost of service in that the transmission level discount is smaller 19 than the subtransmission level discount. The proposed demand charge voltage 20 level discounts should be replaced with ABATE’s proposed discounts of 21 $0.95 per kW-month for transmission and $0.63 per kW-month for 22 subtransmission as detailed in the body of my testimony. 23

4. While DTE allocates its transmission expenses in its CCOS study to D11 24 customers as a whole on the basis of 12-CP demand, it inappropriately collects 25 these demand-related expenses from individual D11 customers on the basis of 26 energy consumption. These transmission expenses should instead be 27 recovered from individual D11 customers through a non-capacity related power 28 supply demand charge as detailed in the body of my testimony. 29

5. The split of power supply costs between capacity-related and non-capacity 30 related charges in this proceeding should be dictated by the outcome of Case 31 No. U-18248, which is specifically addressing how that split should be made. 32 However, as I have recommended on behalf of ABATE in Case No. U-18248, 33 regardless of how the Commission decides to make that split, , no less that 75% 34 of total fixed production costs should continue to be allocated to bundled retail 35 customer classes on the basis of 4-CP demand assuming the Commission 36 adopts DTE’s proposed 75-0-25 allocation method for fixed production costs. In 37 addition, as I have also recommended in Case No. U-18248, the Commission 38 should require DTE to make a filing after: (i) the February 2018 SRM Capacity 39 Demonstrations by Alternative Electric Suppliers (“AESs”) and (ii) the conclusion 40 of this current proceeding. The filing should update DTE’s final SRM Capacity 41 Charge to reflect the additional capacity costs DTE has incurred to supply 42

21While DTE’s proposed CCOS R3 power supply revenue target is $13.58 million, in its rate

design it is proposing to discard those CCOS results and instead use a power supply revenue target of $9.69 million by continuing to sub-allocate a portion of the total D11/Other CCOS revenue target of $840 million to R3 based on historical R3 power supply revenues as it has in the past.



capacity to ROA customers paying the SRM Capacity Charge and those ROA 1 customers that have returned to bundled service. In addition, the filing should 2 update the SRM Capacity Charge to reflect the billing units of the customers 3 that are being supplied with this additional capacity. 4

Q DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 5

A Yes, it does. 6

Appendix A James R. Dauphinais

Page 1


Qualifications of James R. Dauphinais 1 Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 2

A James R. Dauphinais. My business address is 16690 Swingley Ridge Road, 3

Suite 140, Chesterfield, MO 63017, USA. 4

Q PLEASE STATE YOUR OCCUPATION. 5

A I am a consultant in the field of public utility regulation and a Managing Principal with 6

the firm of Brubaker & Associates, Inc. (“BAI”), energy, economic and regulatory 7

consultants. 8

Q PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND 9

EXPERIENCE. 10

A I graduated from Hartford State Technical College in 1983 with an Associate's Degree 11

in Electrical Engineering Technology. Subsequent to graduation I was employed by 12

the Transmission Planning Department of the Northeast Utilities Service Company1 13

as an Engineering Technician. 14

While employed as an Engineering Technician, I completed undergraduate 15

studies at the University of Hartford. I graduated in 1990 with a Bachelor's Degree in 16

Electrical Engineering. Subsequent to graduation, I was promoted to the position of 17

Associate Engineer. Between 1993 and 1994, I completed graduate level courses in 18

the study of power system transients and power system protection through the 19

Engineering Outreach Program of the University of Idaho. By 1996 I had been 20

promoted to the position of Senior Engineer. 21

1In 2015, Northeast Utilities changed its name to Eversource Energy.


Page 2


In the employment of the Northeast Utilities Service Company, I was 1

responsible for conducting thermal, voltage and stability analyses of the Northeast 2

Utilities' transmission system to support planning and operating decisions. This 3

involved the use of load flow, power system stability and production cost computer 4

simulations. It also involved examination of potential solutions to operational and 5

planning problems including, but not limited to, transmission line solutions and the 6

routes that might be utilized by such transmission line solutions. Among the most 7

notable achievements I had in this area include the solution of a transient stability 8

problem near Millstone Nuclear Power Station, and the solution of a small signal (or 9

dynamic) stability problem near Seabrook Nuclear Power Station. In 1993 I was 10

awarded the Chairman's Award, Northeast Utilities’ highest employee award, for my 11

work involving stability analysis in the vicinity of Millstone Nuclear Power Station. 12

From 1990 to 1996, I represented Northeast Utilities on the New England 13

Power Pool Stability Task Force. I also represented Northeast Utilities on several 14

other technical working groups within the New England Power Pool (“NEPOOL”) and 15

the Northeast Power Coordinating Council (“NPCC”), including the 1992-1996 New 16

York-New England Transmission Working Group, the Southeastern 17

Massachusetts/Rhode Island Transmission Working Group, the NPCC CPSS-2 18

Working Group on Extreme Disturbances and the NPCC SS-38 Working Group on 19

Interarea Dynamic Analysis. This latter working group also included participation 20

from a number of ECAR, PJM and VACAR utilities. 21

From 1990 to 1995, I also acted as an internal consultant to the Nuclear 22

Electrical Engineering Department of Northeast Utilities. This included interactions 23

with the electrical engineering personnel of the Connecticut Yankee, Millstone and 24


Page 3


Seabrook nuclear generation stations and inspectors from the Nuclear Regulatory 1

Commission (“NRC”). 2

In addition to my technical responsibilities, from 1995 to 1997, I was also 3

responsible for oversight of the day-to-day administration of Northeast Utilities' Open 4

Access Transmission Tariff. This included the creation of Northeast Utilities' pre-5

FERC Order No. 889 transmission electronic bulletin board and the coordination of 6

Northeast Utilities' transmission tariff filings prior to and after the issuance of Federal 7

Energy Regulatory Commission (“FERC” or “Commission”) FERC Order No. 888. I 8

was also responsible for spearheading the implementation of Northeast Utilities' Open 9

Access Same-Time Information System and Northeast Utilities’ Standard of Conduct 10

under FERC Order No. 889. During this time I represented Northeast Utilities on the 11

Federal Energy Regulatory Commission's "What" Working Group on Real-Time 12

Information Networks. Later I served as Vice Chairman of the NEPOOL OASIS 13

Working Group and Co-Chair of the Joint Transmission Services Information Network 14

Functional Process Committee. I also served for a brief time on the Electric Power 15

Research Institute facilitated "How" Working Group on OASIS and the North 16

American Electric Reliability Council facilitated Commercial Practices Working Group. 17

In 1997 I joined the firm of Brubaker & Associates, Inc. The firm includes 18

consultants with backgrounds in accounting, engineering, economics, mathematics, 19

computer science and business. Since my employment with the firm, I have filed or 20

presented testimony before the Federal Energy Regulatory Commission in 21

Consumers Energy Company, Docket No. OA96-77-000; Midwest Independent 22

Transmission System Operator, Inc., Docket No. ER98-1438-000; Montana Power 23

Company, Docket No. ER98-2382-000; Inquiry Concerning the Commission’s Policy 24

on Independent System Operators, Docket No. PL98-5-003; SkyGen Energy LLC v. 25


Page 4


Southern Company Services, Inc., Docket No. EL00-77-000; Alliance Companies, et 1

al., Docket No. EL02-65-000, et al.; Entergy Services, Inc., Docket No. 2

ER01-2201-000; Remedying Undue Discrimination through Open Access 3

Transmission Service, Standard Electricity Market Design, Docket No. RM01-12-000; 4

Midwest Independent Transmission System Operator, Inc., Docket No. ER10-1791-5

000; NorthWestern Corporation, Docket No. ER10-1138-001, et al.; Illinois Industrial 6

Energy Consumers v. Midcontinent Independent System Operator, Inc., Docket No. 7

EL15-82-000; Midcontinent Independent System Operator, Inc., Docket No. ER16-8

833-000; and Midcontinent Independent System Operator, Inc., Docket No. ER17-9

284-000. I have also filed or presented testimony before the Alberta Utilities 10

Commission, Colorado Public Utilities Commission, Connecticut Department of Public 11

Utility Control, the Florida Public Service Commission, Illinois Commerce 12

Commission, the Indiana Utility Regulatory Commission, the Iowa Utilities Board, the 13

Kentucky Public Service Commission, the Louisiana Public Service Commission, the 14

Michigan Public Service Commission, the Missouri Public Service Commission, the 15

Montana Public Service Commission, the New Mexico Public Regulation 16

Commission, the Council of the City of New Orleans, the Oklahoma Corporation 17

Commission, the Public Utility Commission of Texas, the Wisconsin Public Service 18

Commission and various committees of the Missouri State Legislature. This 19

testimony has been given regarding a wide variety of issues including, but not limited 20

to, ancillary service rates, avoided cost calculations, certification of public 21

convenience and necessity, cost allocation, fuel adjustment clauses, fuel costs, 22

generation interconnection, interruptible rates, market power, market structure, 23

off-system sales, prudency, purchased power costs, resource planning, rate design, 24


Page 5


retail open access, standby rates, transmission losses, transmission planning and 1

transmission line routing. 2

I have also participated on behalf of clients in the Southwest Power Pool 3

Congestion Management System Working Group, the Alliance Market Development 4

Advisory Group and several committees and working groups of the Midcontinent 5

Independent System Operator, Inc. (“MISO”), including the Congestion Management 6

Working Group, Economic Planning Users Group, Loss of Load Expectation Working 7

Group, Regional Expansion, Criteria and Benefits Working Group and Resource 8

Adequacy Subcommittee (formerly the Supply Adequacy Working Group). I am 9

currently a member of the MISO Advisory Committee in the end-use customer sector 10

on behalf of a group of industrial end-use customers in Illinois and a group of 11

industrial end-use customers in Texas. I am also the past Chairman of the 12

Issues/Solutions Subgroup of the MISO Revenue Sufficiency Guarantee (“RSG”) 13

Task Force. 14

In 2009, I completed the University of Wisconsin-Madison High Voltage Direct 15

Current (“HVDC”) Transmission course for Planners that was sponsored by MISO. I 16

am a member of the Power and Energy Society (“PES”) of the Institute of Electrical 17

and Electronics Engineers (“IEEE”). 18

In addition to our main office in St. Louis, the firm also has branch offices in 19

Phoenix, Arizona and Corpus Christi, Texas. 20

\\Doc\Shares\ProlawDocs\MED\10427\Testimony-BAI\327516.docx

21

ABATE Cost of Service Study

75-0-25

Production Costs

Case No.: U-18255

Exhibit: AB-20

Witness: J.R. Dauphinais

Date: August 29, 2017

Page 1 of 4

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

Total E-1 St Lgt

Total Total Commercial Total D9 OPL

Electric Residential Secondary Primary E-2 Signals

1 Rate Base 8,635,608 3,845,152 2,173,753 2,593,653 23,074

2 Revenue 3,099,399 1,285,903 751,860 1,040,382 21,255

3 Expenses:

4 Fuel 1,097,531 439,233 273,062 379,217 6,018

5 Purchased Power 290,538 116,411 62,784 111,093 250

6 O & M Expense 703,424 284,386 172,760 243,055 3,224

7 Depreciation 312,456 140,782 78,890 92,084 701

8 Other (Reg Assets, etc) 0 0 0 0 0

9 Remove Reg Assets 0 0 0 0 0

10 Accretion of Loss/ Gain on Sale 0 0 0 0 0

11 Other Taxes 142,261 62,913 35,727 43,226 395

12 Income Taxes 167,647 73,393 38,984 52,037 3,232

13 Amortizations - - - - -

14 Total Expenses 2,713,857 1,117,119 662,207 920,711 13,822

15 Net Oper Income 385,542 168,784 89,653 119,670 7,433

16 AFUDC & Other 22,378 10,092 5,651 6,585 50

17 Net Adjustments 0 - 0 0 0

18 Adj Net Oper Income 407,921 178,876 95,305 126,255 7,483

19 Rate of Return 4.72% 4.69% 4.38% 4.87% 32.43%

20 Return @ 5.5715 % 481,133 214,233 121,111 144,505 1,286

21 Income Deficiency 73,212 35,356 25,806 18,250 (6,197)

22 Base Revenue Def / (Sufficiency) 120,015 57,959 42,303 29,917 (10,159)

23 Additional Rev Req 0 - - - -

24 Total Revenue Def/ (Sufficiency) 120,015 57,959 42,303 29,917 (10,159)

25 Revenue Requirement 3,219,414 1,343,861 794,163 1,070,298 11,096

26 Misc Revenue 36,760 27,294 5,215 4,159 91

27 Rev Req Excl Misc Rev & Nuc Decomm 3,182,654 1,316,567 788,948 1,066,139 11,005


75-0-25

Production Costs

Case No.: U-18255

Exhibit: AB-20



Page 2 of 4

(f) (g) (h) (i) (j) (k) (l) (m)

D-1/Other D-1.2 D-2 D-3/Other D-3.2 D-4 Total

Residential TOU Residential Total General Secondary Lg Genl Commercial

Service - Space Ht Residential Service Schools Service Secondary

1 Rate Base 3,761,315 33,812 50,025 3,845,152 1,686,747 29,045 457,961 2,173,753

2 Revenue 1,256,801 9,265 19,837 1,285,903 571,620 11,251 168,989 751,860

3 Expenses:

4 Fuel 427,399 4,155 7,679 439,233 208,325 4,487 60,250 273,062

5 Purchased Power 114,126 991 1,294 116,411 49,235 732 12,817 62,784

6 O & M Expense 277,141 2,693 4,552 284,386 132,186 2,742 37,832 172,760

7 Depreciation 137,764 1,240 1,777 140,782 61,361 1,032 16,497 78,890

8 Other (Reg Assets, etc) 0 0 0 0 0 0 0 0

8 Other (Reg Assets, etc) 0 0 0 0 0 0 0 0

10 Accretion of Loss/ Gain on Sale 0 0 0 0 0 0 0 0

11 Other Taxes 61,528 556 829 62,913 27,698 484 7,545 35,727

12 Income Taxes 72,383 (112) 1,123 73,393 28,128 538 10,319 38,984

13 Amortizations - - - - - - - -

14 Total Expenses 1,090,341 9,523 17,254 1,117,119 506,933 10,015 145,259 662,207

15 Net Oper Income 166,460 (258) 2,582 168,784 64,687 1,236 23,730 89,653

16 AFUDC & Other 9,876 89 127 10,092 4,396 74 1,181 5,651

17 Net Adjustments 0 0 0 0 0 0 0 0

18 Adj Net Oper Income 176,336 (170) 2,709 178,876 69,083 1,310 24,911 95,305

19 Rate of Return 4.69% -0.50% 5.42% 4.65% 4.10% 4.51% 5.44% 4.38%

20 Return @ 5.5715 % 209,562 1,884 2,787 214,233 93,977 1,618 25,515 121,111

21 Income Deficiency 33,225 2,053 78 35,356 24,894 308 604 25,806

22 Base Revenue Def / (Sufficiency) 54,465 3,366 127 57,959 40,808 505 990 42,303

23 Additional Rev Req - - - - - - - -

24 Total Revenue Def/ (Sufficiency) 54,465 3,366 127 57,959 40,808 505 990 42,303

25 Revenue Requirement 1,311,266 12,631 19,964 1,343,861 612,428 11,756 169,979 794,163

26 Misc Revenue 26,738 133 423 27,294 4,392 64 759 5,215

27 Rev Req Excl Misc Rev & Nuc Decomm 1,284,529 12,498 19,541 1,316,567 608,035 11,692 169,220 788,948


75-0-25

Production Costs

Case No.: U-18255

Exhibit: AB-20



Page 3 of 4

(n) - (o) (p) (q) (r) (s)

D-11/Other Rider 3 D-6.2 D-8 R-1.1/R-1.2 R-10

- Primary Interrupt Metal Melt Interrupt Total

Primary Primary Schools Supply Process Heat Supply Primary

1 Rate Base 2,155,335 15,224 165,482 95,777 67,148 94,688 2,593,653

2 Revenue 815,554 9,448 58,475 40,279 30,401 86,223 1,040,382

3 Expenses:

4 Fuel 312,399 2,779 20,741 16,852 13,478 12,967 379,217

5 Purchased Power 56,478 454 4,731 2,225 1,392 45,814 111,093

6 O & M Expense 193,839 1,702 13,329 9,723 7,468 16,995 243,055

7 Depreciation 76,850 507 5,993 3,344 2,303 3,086 92,084

8 Other (Reg Assets, etc) 0 0 0 0 0 0 0

8 Other (Reg Assets, etc) 0 0 0 0 0 0 0

10 Accretion of Loss/ Gain on Sale 0 0 0 0 0 0 0

11 Other Taxes 35,717 256 2,723 1,601 1,130 1,798 43,226

12 Income Taxes 42,599 1,047 3,321 1,980 1,403 1,686 52,037

13 Amortizations - - - - - - -

14 Total Expenses 717,882 6,745 50,838 35,725 27,175 82,346 920,711

15 Net Oper Income 97,672 2,703 7,637 4,554 3,227 3,878 119,670

16 AFUDC & Other 5,498 36 429 239 164 218 6,585

17 Net Adjustments 0 0 0 0 0 0 0

18 Adj Net Oper Income 103,170 2,739 8,066 4,793 3,391 4,096 6,585

19 Rate of Return 4.79% 17.99% 4.87% 5.00% 5.05% 4.33% 0.25%

20 Return @ 5.5715 % 120,084 848 9,220 5,336 3,741 5,276 144,505

21 Income Deficiency 16,914 (1,891) 1,154 543 350 1,180 18,250

22 Base Revenue Def / (Sufficiency) 27,727 (3,100) 1,891 891 574 1,934 29,917

23 Additional Rev Req - - - - - - -

24 Total Revenue Def/ (Sufficiency) 27,727 (3,100) 1,891 891 574 1,934 29,917

25 Revenue Requirement 843,282 6,348 60,366 41,170 30,975 88,157 1,070,298

26 Misc Revenue 3,251 37 229 164 124 355 4,159

27 Rev Req Excl Misc Rev & Nuc Decomm 840,030 6,311 60,137 41,006 30,852 87,802 1,066,139


75-0-25

Production Costs

Case No.: U-18255

Exhibit: AB-20



Page 4 of 4

(t) (u) (v) (w)

D-9 OPL D-9 OPL

Residential Commercial E-1 St Lght E-2 Signals

1 Rate Base 536 1,910 12,112 8,516

2 Revenue 611 1,736 17,576 1,331

3 Expenses:

4 Fuel 181 668 3,737 1,432

5 Purchased Power 2 6 33 210

6 O & M Expense 90 332 1,929 873

7 Depreciation 15 55 322 309

8 Other (Reg Assets, etc) 0 0 0 0

8 Other (Reg Assets, etc) 0 0 0 0

10 Accretion of Loss/ Gain on Sale 0 0 0 0

11 Other Taxes 9 34 210 143

12 Income Taxes 95 194 3,438 (496)

13 Amortizations - - - -

14 Total Expenses 392 1,290 9,669 2,471

15 Net Oper Income 219 447 7,908 (1,140)

16 AFUDC & Other 1 4 23 22

17 Net Adjustments 0 0 0 0

18 Adj Net Oper Income 220 451 7,930 (1,118)

19 Rate of Return 41.01% 23.61% 65.47% -13.13%

20 Return @ 5.5715 % 30 106 675 474

21 Income Deficiency (190) (344) (7,255) 1,593

22 Base Revenue Def / (Sufficiency) (311) (565) (11,894) 2,611

23 Additional Rev Req - - - -

24 Total Revenue Def/ (Sufficiency) (311) (565) (11,894) 2,611

25 Revenue Requirement 299 1,172 5,683 3,942

26 Misc Revenue 2 7 75 7

27 Rev Req Excl Misc Rev & Nuc Decomm 297 1,165 5,608 3,935

Standby Rate

Working Group Supplemental

Report

PREPARED BY: MICHIGAN PUBLIC SERVICE

COMMISSION STAFF

MPSC Case No. U-17735

June 2017

Case No.: U-18255 Exhibit: AB-21

Witness: J. R. Dauphinais Date: August 29, 2017

Page 1 of 81

Page | 1

Introduction

To satisfy the need for electric reliability, self-generation customers rely on utility services

for backup, supplemental and maintenance power.1 These utility services are generally referred to

as standby service2 and the rates are based on the utility’s costs for being ready to serve a load that

is otherwise supplied by a customer’s generator as well as the cost of any energy actually delivered

by the utility to the customer pursuant to standby service. Michigan Public Service Commission

staff (staff) issued a report on standby service and the activities of the Standby Rate Working Group

(SRWG) on August 19, 2016. The report was primarily focused on how Consumers Energy’s

(Consumers) and DTE Electric’s (DTE) standby rates function with a primary focus on solar self-

generation. 3 This supplemental report will highlight the SRWG’s findings related to non-

intermittent standby service tariff design and present staff’s recommendations on standby service

tariffs for both combined heat and power (CHP) and solar self-generation.

The overarching goal of the SRWG is to ensure that any resulting standby service tariffs are

based on the cost to serve self-generation standby customers and to increase transparency of the

tariffs. Standby service tariff transparency doesn’t necessarily mean that the tariffs must be

simplified, but the tariffs must include clear and concise definitions of the terms and billing

determinants used within the tariff and all of the rate information necessary to calculate a monthly

bill must be clearly shown. While actual changes to the standby service tariffs can only be

accomplished through the Commission’s rate case process, this report will provide information on

1 1 Backup power means electric energy or capacity supplied by an electric utility to replace energy ordinarily generated by a facility's own generation equipment during an unscheduled outage of the facility. Supplemental power means electric energy or capacity supplied by an electric utility, regularly used by a qualifying facility in addition to that which the facility generates itself. Maintenance power means electric energy or capacity supplied by an electric utility during scheduled outages of the qualifying facility. (From PURPA) 2 Also referred to as partial requirements service. 3 Detailed explanations of current standby service tariffs for both Consumers and DTE are included in the August 19th Report.



Page 2 of 81

Page | 2

the SRWG’s investigation (primarily focused on Consumers and DTE tariffs with some limited

discussion of Upper Michigan Energy Resource Company (UMERC) and Upper Peninsula Power

Company (UPPCo) tariffs) into how existing standby service tariffs function and issues explored by

the group. Staff’s recommendations are presented in the conclusion and recommendations section

of the report.

To help staff prepare this report, in addition to the five in-person workgroup meetings held,

the SRWG provided comments to highlight important aspects of the SRWG’s activities. Comments

were received from the following:4

1. Alliance for Industrial Efficiency

2. Association of Businesses Advocating Tariff Equity (ABATE)

3. Consumers Energy (Consumers)

4. DTE Electric (DTE)

5. Electricity Users Resource Council

6. Michigan Energy Innovation Business Council (MIEIBC)

7. Midwest Cogeneration Association and the Great Plains Institute (MCA/GPI)

A draft version of this report was provided to the SRWG in May 2017. Comments were received

from ABATE, Consumers, DTE, MCA/GPI and MIEIBC. Copies of all comments on the draft

report are included as Appendix D.

Staff thanks all of the commenters and finds the information provided helpful in

understanding the different CHP perspectives and notes that this report draws on many of the

comments provided.

Currently effective standby service tariffs are provided in Appendix A:

4 SRWG comments submitted prior to the draft report preparation are provided on the workgroup website: http://www.michigan.gov/mpsc/0,4639,7-159-16377_47107-376753--,00.html



Page 3 of 81

Page | 3

Consumers: General Service Self Generation Rate - GSG-2

DTE: Rider 3

UMERC (WPSC Rate Zone): Large Commercial & Industrial Service Cp-1M

(Standby Provision)

UPPCo: Large Commercial & Industrial Service Cp-U (Standby Provision)

Cost of Service Rate Class

A question that arose during the SRWG discussions was whether it was more appropriate to

assign baseload-type, non-intermittent, standby service customers to a separate rate class for

purposes of determining the cost of service rather than including such customers in their

supplemental service rate class for ratemaking purposes. Once the costs are assigned to the cost of

service rate class, rate design within the cost of service class is used to develop the standby service

tariffs and prevent intra-class subsidies. Figure 1 depicts the traditional ratemaking process.



Page 4 of 81

Page | 4

Figure 1

Source: MPSC Staff, Cost of Service Ratemaking Presentation to the Solar Working Group, March 18, 2017

http://www.michigan.gov//documents/mpsc/2014marchMPSC_450649_7.pdf

One factor to consider when deciding whether to establish a new cost of service rate class is

the number of customers expected to be in the class. Currently, both Consumers and DTE have

very few customers taking standby service. Figures 2 and 3 show the number of customers taking

standby service and the generator types from both utilities. It might be desirable to promote

homogeneity within any new standby cost of service rate class by including only non-intermittent

generator types such as biomass, waste-to-energy, hydroelectric, and cogeneration.



Page 5 of 81

Page | 5

Figure 2: Consumers GSG-2 Summary Data

Figure 3 – DTE Rider 3 Summary Data

‐ 40



Page 6 of 81

Page | 6

The SRWG discussed DTE’s power supply cost of service model which includes a class

called “D11 and Other” that includes Rider 3 customers. Rate D11 is the supplemental service rate

for nearly all DTE standby service customers. Based on previous revenue allocations, historically

99% of the cost of service has typically been assigned to D11 and 1% to Rider 3. Several SRWG

participants expressed interest in reviewing this allocation and making any necessary adjustments to

update the allocation mechanism.

Standby service customers have historically been kept within a larger rate class for the cost

of service study as the characteristics of standby customers are similar to the larger class and there

may not be enough standby service customers to warrant a separate class. DTE’s standby rate is a

rider that has rates coordinated with the supplemental service rate. An example given by DTE in

the rate case is that “…the amount by which a customer’s supplemental demand on Rate D11 is

below their maximum D11 on-peak supplemental demand, reduces the customer’s Rider 3 daily on-

peak demand. This rate interaction lowers the customer’s daily demand charges and is just one

example of why Rider 3 and Rate D11 should be viewed together as one cost of service class.”5 In

almost all cases, DTE standby service rate customers with large cogeneration facilities take

supplemental service under Rate D11.

Several SRWG participants commented that standby service customers should be studied in

their own separate cost of service class so that the load and capacity and energy coincidence factors

can be recognized and factored into the rates.

In the first quarter of 2017, the Commission issued rate case orders for both Consumers and

DTE. 6 DTE is directed to treat its standby service customers as a separate rate class for the

5 See DTE’s Exceptions in U-18014 http://efile.mpsc.state.mi.us/efile/docs/18014/0280.pdf page 102 6 Consumers Energy February 28, 2017 U-17990 rate case order and DTE Electric January 31, 2017 U-18014 rate case order.



Page 7 of 81

Page | 7

purposes of the cost of service study in the next rate case, though this does not mean these

customers should be in a separate rate class for the rate design. Consumers is directed to file a

study that compares power supply revenue from Rate GSG-2 (standby service) customers to power

supply costs caused by these customers, in order to determine whether current demand charges

reflect the cost to serve standby customers. Establishing that the costs allocated to standby

customers are cost of service-based will build the foundation for developing an effective rate design

and standby service tariff. Rate design will parse out differences in costs imposed by individual

customers such as those with CHP systems.

5 Lakes Energy – ConEd CHP Data Analysis

MCA/GPI asked 5 Lakes Energy to undertake an analysis of typical cogeneration customer

standby service coincidence utilizing the continuous operating data collected by the New York State

Energy Development Agency (NYSERDA) in its unique, long-standing cogeneration database. 5

Lakes Energy analyzed two years of 8760 hourly NYSERDA CHP data from the ConEd program

for 19 CHP projects which included health care, industrial, multi-family residential, retail, and

educational customers. On October 20, 2016, 5 Lakes Energy presented a summary of the analysis

results and findings, including demand coincidence and recommendations for billing determinant

accuracy. The summary slide from the presentation is shown in Figure 4. One of the key findings

of the 5 Lakes Energy NYSERDA analysis was that the standby users’ demand variation was

inconsequential based on ConEd’s overall load diversity. 5 Lakes Energy’s recommendation from

that data was that no distinction between standby and supplemental power appears warranted.

SRWG participants discussed the analysis, but did not reach consensus on the issue.



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Figure 4: Summary of 5 Lakes Energy – ConEd CHP Data Analysis7

Rate Design - Key Elements of a Standby Service Tariff

The primary rate design elements typically included in a standby service tariff are Customer

Charge, Generation Reservation Fee, Power Supply Demand Charge, Power Supply Energy Charge,

Delivery Demand Charge, and Delivery Energy Charge. Each rate design element will be discussed

below. The discussion will focus on Consumers’ and DTE’s current standby service tariffs.

However, the analysis conducted by the SRWG is based on the previous versions that were in effect

until the most recent rate case orders were issued.

Customer Charge

Self-generation customers taking standby service may also be taking supplemental service

under their normal rate schedule. A customer’s normal rate schedule will include a monthly

customer charge. Costs recovered via a monthly customer charge are based on longstanding

7 See Jester October 20, 2016 presentation to SRWG, slide 14 http://www.michigan.gov/documents/mpsc/SBRWG_Presentation_of_NYSERDA_CHP_538291_7.pdf



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Commission precedent and are directly related to the costs of attaching a customer to the system.

Such costs include the meter, overhead and underground services, customer accounting costs, and

customer service expenses. A utility may experience additional metering and administrative costs

in the course of providing standby service, potentially making it appropriate to include a separate

customer charge on the standby service tariff. DTE’s Rider 3 includes an additional customer

charge which varies from $95 to $375 per month based on the service voltage. The supplemental

rate most often paired with Rider 3 is D11 which has a customer charge of $275 or $375 based on

the service voltage level (levels 1-3). Consumers’ GSG-2 tariff features a $100 system access

charge for projects where the generator does not meet or exceed load and $200 for all others. In

addition, the normal rate schedule for most GSG-2 customers is GPD which has a system access

charge of $200. Staff recommends that customer charge amounts be reviewed by interested parties

in the next rate cases.

Generation Reservation Fee

A generation reservation fee (also called a capacity reservation charge) is used in rate design

on some standby service tariffs. A generation reservation fee is a charge to compensate the utility

for the capacity that the utility must have available to serve a customer during an unscheduled

outage of the customer’s self- generation unit.8 Standby service tariffs without a generation

reservation fee are designed to recover capacity costs through the use of a demand charge. It may

be appropriate to design the generation reservation fee so that it incorporates the forced outage rate

of the generator.9 One way to do this is to base the fee on the forced outage rate of the highest

8 See Standby Rates for Combined Heat and Power Systems, Prepared by Brubaker & Associates, Inc. and the Regulatory Assistance Project for Oak Ridge national Laboratory, 2014. 9 Forced outage rate is the percent of time a generation unit is unavailable due to unplanned outages. See 21st Century Energy Plan Appendix II.



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performing generators taking standby service. ABATE commented that it is best to not have a

reservation charge at all, but if there is, it should be based on no more than one day’s, or one on-

peak day’s, worth of daily or on-peak daily demand charges.

The Rate D11 Primary Supply Rate Power Supply Demand Charge is $15.79 per kW of on-

peak billing demand (based on the highest 30 minute on-peak billing demand, must be at least 65%

of the previous June – October billing demand). Rider 3, DTE’s standby service tariff, has a

Monthly Generation Reservation Fee of $1.94 which is multiplied by the standby contract capacity

in kW. Standby Contract Capacity has a lengthy definition in the tariff (attached as Attachment A).

(To reduce complexity for this discussion, the nameplate capacity of the generator multiplied by the

forced outage rate is assumed.)

The monthly generation reservation fee is 12% of the Rate D11 on-peak power supply

demand rate ($1.94/$15.79). Excluding off-peak days which are weekends and holidays, each

month has roughly 20 on-peak days. Twelve percent of 20 on-peak days is 2.4 days. Under Rider

3, at a minimum, the rate is designed to ensure that standby customers are paying for 2.4 days of on-

peak capacity during a month when they have no generator outages. MCA/GPI point out that DTE’s

reservation fee results in a minimum charge which is equivalent to a 12% outage rate, while the

2004 Oak Ridge National Laboratory Report10 MCA provided to the SRWG found that

cogeneration systems, at the time of the report data collection, averaged a 5% forced outage rate.

DTE is not necessarily over-recovering costs because the rate is designed so that the total capacity

costs to be recovered are spread between the generation reservation fee and the capacity demand

charge. The SRWG discussed what contribution to capacity standby customers should make during

a month with no outages. No consensus was reached. Some participants said that standby rates

10 See https://energy.gov/sites/prod/files/2013/11/f4/dg_operational_final_report.pdf.



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should be set up to incentivize standby customers to maintain and operate their generators to

minimize outages by not having a generator reservation fee or setting the fee equal to one day’s on-

peak usage. They point out that all necessary costs can be recovered from standby customers by

increasing the standby capacity demand charge which would result in customers with lower

performing generators paying more, and customers with higher performing generators paying less.

Some SRWG participants said that a generation reservation fee equivalent to more than one day’s

outage creates a subsidy from higher performing generators to lower performing generators.

However, a question that arose from the SRWG discussion was whether the value of incentivizing

standby customers to operate their generators as efficiently as possible made it appropriate for the

standby service tariff to be designed such that customers with high performing generators make no

contribution to capacity costs during a month when no standby service is taken. Consumers’ GSG-

2 standby service tariff does not include a generation reservation fee.

Power Supply Standby Charges - Demand

Power supply standby charges are paid by standby customers when they take standby

service. These charges typically have on-peak demand (based on kW). The purpose of this charge

is to recover costs for the capacity used by the customer.

DTE’s Rider 3 has a Power Supply Demand Charge equal to $5.09 per kW per day based on

the highest 30 minute period on an on-peak day when standby service is taken.11 For comparison

purposes, the full service tariff, D11 has a Power Supply Demand Charge of $15.79 per kW of

monthly maximum on-peak billing demand. There are several waivers on the tariff that cap the

demand charge according to the scenario:12 Standby Power is defined in the tariff:

Standby Demand is electric capacity provided by the Company to serve the 11 The rate is reduced to $2.88 per kW per day during pre-scheduled maintenance periods provided for in the tariff. 12 See DTE’s March 14, 2016 presentation to the Standby Rate Working Group, slides 16 & 17. Rates shown have been updated in a subsequent rate case.



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customer’s total internal load which would have been provided by the customer’s generation had it operated at its contract capacity less any reduction the customer can accomplish by reducing the supplemental demand at the time of the daily on-peak standby demand below the maximum monthly on-peak supplemental demand but not less than zero.

This option to reduce supplemental demand provides flexibility by enabling the customer to manage

their monthly bill by reducing their total demand and the impact on the utility’s capacity during a

generator outage.



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Figure 5: DTE Rider 3 Standby Capacity Charge Calculation13

13 DTE presentation to SRWG on March 14, 2016, slides 15-17, http://www.michigan.gov/documents/mpsc/DTE_Standby_Presentation_SWG_517636_7.pdf

Standby Capacity Charges recover DTE’s costs of having generating resources available to serve load that is normally served by the customer’s generator. There are three standby capacity calculations performed to determine the monthly capacity charge for customers on demand rates; 1) the monthly generation reservation fee; 2) the sum of the daily demand charges, and; 3) the daily demand cap. The monthly generation reservation fee is the minimum charge amount and the daily demand cap is the maximum charge amount. The current monthly generation reservation fee is $1.75/kW/month applied to Standby Contract Capacity.

Daily demands are determined based on the daily standby demand coincident with the highest 30-minute on-peak DTE Supply demand to the site. The current daily on-peak demand charge of $4.67/kW/day (or $2.60/kW/day during approved maintenance periods) is applied to each daily demand. The sum of the daily demand charges are compared to the minimum and maximum charge amounts to determine what charge to apply.

The daily demand cap is determined as the D11 Power Supply Demand Charge of $14.65/kW times the maximum standby capacity utilized, plus the Generation Reservation charge times the difference between the total standby contract capacity and the maximum standby utilized. Example: Customer’s generator with a SCC of 1,000kW was down for five on-peak days during month (unscheduled outage) a) Generation Reservation Fee = 1,000kW x 1.75/kW/month = $1,750 b) Sum of the Daily Demands = 1,000kW x $4.67/kW/day x 5 days = $23,350 c) Daily Demand Cap = 1,000kW x $14.65 = $14,650 For this month the customer is billed the Daily Demand Cap



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The group discussed that the Rider 3 daily on-peak backup demand charge is $5.09 per kW per day

which is 32% of the full service power supply demand charge of $15.79. After three full, on-peak

outages during the month, the standby customer is paying the full service rate power supply demand

charge. There is not agreement among the group about the appropriate ratio of daily demand cap to

daily demand. Some members of the SRWG recommended prorating the full-service demand

charge by the number of on-peak days (or to reduce complexity, 20 on-peak days in every month

could be assumed as previously discussed) in the month and making the charge a daily demand

charge.

Consumers’ GSG-2 standby service tariff bases the power supply standby capacity charge

on the “…highest contracted capacity purchased by the Company in that month, plus allocated

transmission and ancillaries.” The contract setting this rate is currently the Company’s power

purchase agreement with the Palisades nuclear plant. The actual capacity rate is not easily

obtainable as the contract terms are redacted and its use is less transparent than if the rate was based

on a source that could be shown on the tariff. Consumers correctly points out that there are only

eight customers on the GSG-2 tariff and that there has been limited interest by potential customers.

The capacity charge is prorated by the number of on-peak days in the month. In effect, Consumers’

tariff provides a daily demand charge for capacity. The company has proposed basing the power

supply capacity charge on its embedded costs in the currently pending rate case.

If a customer has contracted for a specific amount of supplemental service, it is a benefit to

the distribution system if the customer is able to reduce their load. Staff recommends that this

customer load reduction should be incentivized by charging the customer for standby service only

for the incremental load above the supplemental contracted amount or the largest net demand the

customer places on the system. Staff acknowledges the complexity of doing this.



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Power Supply Standby Charges – Energy

The energy charge is based on the number of kWh taken by the customer under standby

service. DTE’s Rider 3 customers taking supplemental service under D11 pay the D11 energy

charges for kWh taken during the month. In the past, for a limited time period, DTE Rider 3

customers had the option to pay for energy based on the MISO wholesale market. This option was

discontinued due to a lack of cost justification in a previous rate case order issued on December 15,

2015 in Case No. U-17767.

Under Consumers’ GSG-2 standby service tariff, customers pay for energy according to the

MISO Real-Time Locational Marginal Price for the Company’s load node plus a market settlement

fee of $0.002/kwh. Consumers commented that this rate cannot be known in advance and reduces

the transparency of the standby service tariff. In a future rate case, the Company commented it will

propose an energy rate that is reflective of the cost to provide service and also easy for the customer

to understand.

Delivery Standby Charges

Delivery charges are meant to recover the utility’s cost of the distribution system and other

delivery-related costs not included in the monthly customer charge. These costs are allocated to the

class based on the non-coincident class peak.14 For Consumers’ standby customers, delivery

demand charges are generally based on the highest output of the generator with the generator

nameplate capacity setting the maximum limit. Presumably, the amount can never be more than the

customer’s peak load without the generator, although this is not stated in the tariff. It is not clear on

the tariff how this amount would be established for a solar generator.

The delivery standby charges for DTE Rider 3 customers are based on the standby contract

14 Non-coincident class peak is the peak of the rate class (D11 & Other rate class for example) and not related to the utility’s overall system peak or customer’s individual peak.



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capacity which is set according to 4 options. Generally, generators that operate on-peak as base

load, have standby contract capacity based on the 1001st highest ½ hour of operation during June

through October. Standby contract capacity for thermal load following generators or a solar

generator would be set by mutual agreement between the Company and customer.

The Electricity Consumers Resource Council commented that the delivery demand charge

should be based on the largest net demand, comprised of supplemental and standby demand, the

customer places on the system.

Now that more information is known about solar generation profiles on a seasonal and daily

basis, the Company may be able to provide more information about how solar standby contract

capacity might be determined on the tariff.

2016 Public Act 341

Section 6v of PA 341 addresses the Public Utility Policies Act of 1978 and Michigan’s

implementation. The new law directs the Commission to issue an order every five years that does

the following:

(4) An order issued by the commission under subsection (1) shall do all of the following:

(a) Ensure that the rates for purchases by an electric utility from, and rates for sales to, a qualifying facility shall, over the term of a contract, be just and reasonable and in the public interest, as defined by PURPA.

(b) Ensure that an electric utility does not discriminate against a qualifying facility with respect to the conditions or price for provision of maintenance power, backup power, interruptible power, and supplementary power or for any other service. (c) Require that any prices charged by an electric utility for maintenance power, backup power, interruptible power, and supplementary power and all other such services are cost-based and just and reasonable.

Staff recommends that standby service tariffs be addressed in a rate case wherever possible.

For utilities that do not have rate cases within a five year time span, the Commission would



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have the option to combine the standby service tariff review activity with the avoided cost

review.

Standby Service Tariff Complexity

At the beginning of the process, one of the staff goals was to simplify the standby service

tariffs and make it easier for current standby service customers to understand the billing calculations

and how their bills could be reduced. Another goal is for potential standby service customers to be

able to fully evaluate how their utility rates will change if they undertake a self-service generation

project. Transparency in rates is frequently mentioned by SRWG participants. Staff defines rate

transparency as a tariff that is reasonably understandable and includes information needed to

calculate a customer bill. Standby service tariffs are very complex, and staff realized early in the

SRWG process that a cost of service based standby service tariff can only be simplified to a certain

point. The MIEIBC commented that it is important that the rates are transparent in order to

facilitate the ability of companies to determine whether CHP is appropriate. MIEIBC’s comments

included the following “…in the absence of transparency around rates, many potential applications

never even get serious consideration…The integrated resource planning (IRP) process under Public

Act 341 requires consideration of projected energy and capacity purchased from a cogeneration

resource…In order to accurately assess contributions of CHP in an IRP process, transparency in

standby rates is essential.”

The Alliance for Industrial Efficiency pointed out that Michigan has 87 CHP sites, with a

total capacity of 3,389 MW.15

The Department of Energy estimates the state has 4,987 MW of remaining CHP and WHP technical potential capacity (identified at 10,370 sites), with 2,170

15 U.S. DOE Combined Heat and Power Installation Database, (https://doe.icfwebservices.com/chpdb/state/MI)



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MW of remaining onsite technical potential in the industrial sector alone.16 A 2016 report from the Alliance for Industrial Efficiency found that if an economically-viable portion of the state’s CHP and WHP was deployed,17 Michigan industrial sector customers would save $2.27 billion on electricity costs from years 2016 to 2030. These cost savings result from increasing CHP and WHP deployment alone, demonstrating the importance of CHP to increasing manufacturing competitiveness.18

The MCA/GPI take the position that standby service tariffs should be unbundled but need

not be overly complex and provided a conceptual Model Tariff for discussion which is attached as

Appendix B. MCA/GPI’s Model Tariff includes four key elements: Customer Charge,

Reservation Fee, Demand Charge and Energy Charge. (Michigan utilities may have demand

charges for both power supply and delivery.) The Model Tariff describes MCA/GPI’s best practice

approaches for these key tariff elements. MCA/GPI recommended that the Commission require

each utility to translate their tariff charges into a one-page “Summary of Charges” table clearly

showing the tariff rates for each key element of the tariff. In the SRWG process, MCA/GPI offered

two examples of such a table in Ameren Missouri’s standby rider and Otter Tail Power’s

‘standalone’ standby tariff.

During the course of the SRWG, both Consumers and DTE refined their processes for

working with customers interested in self-generation. DTE’s process includes the customer

contacting their account representative for guidance. The company said that several customers have

recently availed themselves of this service. Consumers commented that, during 2016, it has worked

closely with more than a dozen customers who are evaluating self-generation projects. Staff has

participated in several calls with an interested customer’s project developer and the utility as part of

16 U.S. Department of Energy, Mar. 2016, “Combined Heat and Power (CHP) Technical Potential in the United States” (http://energy.gov/sites/prod/files/2016/03/f30/CHP%20Technical%20Potential%20Study%203-18-2016%20Final.pd). 17 Percentage of Michigan’s technical potential for CHP with less than 10-year payback period. 18 Alliance for Industrial Efficiency comments, page 2.



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this process. While these processes involving a customer account representative are helpful,

especially when a project is further in the development process, CHP project developers need to be

able to understand the standby service tariff well enough to run some initial economic evaluations

to determine whether the customer is a reasonable candidate for a project. Increased transparency

in the tariff will be helpful for these early screening analyses.

Both Consumers and DTE are supportive of making standby service tariffs easier to

understand by providing more descriptive information on the tariff and also adding sample

calculations on their websites.

Standby Service Tariff Fairness

The primary impetus for the SRWG was to research whether the standby service tariffs are

fair. Fairness has been defined as basing the standby service tariff on cost of service principles and

incorporating rate design to send appropriate price signals for customers to operate their generators

efficiently. One fairness concept that was brought up consistently was whether the standby service

tariffs are designed with the assumption that all generators are experiencing an outage at one time.

Making this assumption would mean that standby customers are paying for standby capacity based

on the full amount of contracted standby capacity for the entire class of standby service customers

(the highest expected output of the generator in cases where the generator size is less than the site

load). DTE commented that Consumers’ and DTE’s standby service tariffs are not designed that

way and doing so would be a violation of PURPA. Consumers explained they use the historical

contribution of the standby service customers to assign cost and design rates for standby service

customers. Doing so provides the benefit of generator diversity and does not base the costs on the

assumption that all generators are experiencing an outage at once. DTE has a different approach



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which relies on previous revenue allocations, historically 99% of the “D11 and Other” rate class

cost of service has typically been assigned to D11 and 1% to Rider 3. The appropriateness of this

cost split is expected to be addressed in DTE’s current rate case (U-18255). The fairness of

standby service tariffs should be reviewed and considered in future rate cases.

Standby Service Tariff Comparisons

The Midwest Cogeneration Association completed a study comparing standby service tariffs

for seven Midwestern utilities, Consumers and DTE. The study included five scenarios evaluated

on a single-month basis:

no generator outage one scheduled outage 16 hours on-peak two scheduled outages 8 hours on-peak and 8 hours off-peak one scheduled outage 32 hours on-peak one unscheduled outage 16 hours (8 on-peak, 8 off-peak)

The full results of the study are presented in Appendix C and a summary is shown in Table 1. It is

difficult to compare standby service tariff charges because the tariffs are complex and the selected

scenarios may not reflect actual operating characteristics of generators taking service under the

standby service tariff on the utility’s system and differences between utility customer composition,

average customer usage and average cost per kWh. Nevertheless, staff believes there is value in

this type of comparison study. For the study to have maximum value, the data and inputs were

vetted by the SRWG. When the study results were first reviewed, there was concern that the

comparison might not be incorporating all of the nuances of the tariffs. Specifically, some states or

utilities may have goals other than achieving cost of service based rates, such as incentivizing

certain types of distributed generation. As an example of a tariff nuance, DTE pointed out that

while a generator’s nameplate capacity was used in each of the tariff scenarios, their tariff is based



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on the 1001st highest half-hourly kW output towards internal load which could be 30% less than

nameplate. The MCA fine-tuned the study and presented the results to the SRWG. Both

Consumers and DTE commented that this type of benchmarking is important, but more research is

needed to determine whether the comparisons are truly on an “apples-to-apples” basis. They point

out that some state jurisdictions may have policy goals that might impact whether the standby

service tariff is structured to fully collect costs from each rate class. Factors identified include

whether the rate is a negotiated rate, subsidized, includes interruptible components or whether

certain charges are recovered as part of the supplemental rate.

After the SRWG’s final in-person meeting, 5 Lakes Energy worked with two Upper

Peninsula utilities, UMERC and UPPCo, to add their standby service tariffs to the comparison. Due

to the timing of the UMERC and UPPCo standby calculations, the SRWG did not have the

opportunity to vet the UMERC and UPPCo data, but the calculations are included in Table 1.

Table 1: Comparison of Standby Service Tariff Rates for Four Michigan Utilities19,20

Scenario Description Consumers DTE UMERC UPPCO

No Outage 8,300 10,535 0 0

Scheduled Outage 16 Hours Off-Peak 9,246 11,657 2,218 2,911

Scheduled Outage 16 Hours On-Peak 11,645 18,653 3,098 3,883

Scheduled Outage 8 Hours On-Peak, 8 Hours Off-Peak 11,191 13,405 2,658 3,397

Scheduled Generator Outage 32 Hours On-Peak 14,833 30,272 6,196 7,766

Unscheduled Outage 8 Hours On-Peak, 8 Hours Off-Peak 11,191 17,545 30,536 31,631

19 Based on 2,000 kW standby contract capacity with customer served at primary voltage level. 20 Details about each calculation for Consumers Energy and DTE Electric are available in the comments provided by MCA/GPI. UMERC and UPPCo calculation details are available in 5 Lakes Energy’s additional analysis.



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Table 1 highlights the dramatic differences in standby service costs across the four studied utilities.

Both UMERC and UPPCo have pro-rated demand charges for months where the customer

experiences a scheduled outage. The scenario with the unscheduled 8 hour on-peak outage shows

both UMERC and UPPCo with significantly higher monthly bills due to the fact that for

unscheduled outages, the demand charges are not prorated and the customer pays a monthly

“ratcheted” standby capacity demand charge. Both Consumers and DTE have pro-rated standby

capacity demand charges. DTE has a higher daily on-peak demand charge for unscheduled outages.

UMERC and UPPCo have no standby charges during the no-outage scenario while

Consumers and DTE bill for standby capacity and distribution costs. Neither standby rate

information nor the appropriateness of the standby service tariffs for UMERC and UPPCo were

discussed by the SRWG.

Conclusion & Recommendations

The Standby Rate Working Group had the overarching goal to investigate standby service

tariff rates. As a result of the group’s collaboration, we have developed a deeper understanding in

the operation of the tariffs which has allowed staff to identify the recommendations provided in this

report. Standby rate working group participants approach these rates from different perspectives,

which contributed to a lack of consensus on recommendations. After reviewing meeting notes,

presentations and comments provided by participants, staff developed a list of recommendations.

Staff is greatly appreciative of the time and effort put into the SRWG collaborative process by all of

the participants. Staff looks forward to a thoughtful and detailed review of all aspects of standby

service tariffs by all interested parties as part of future utility rate cases.



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Staff Recommendations

1. To assist with standby service tariff transparency, a clear and concise description of the tariff structure and each term used should be included with the tariff. Utilities should work with staff and stakeholders to ensure a good understanding of 1) the standby service tariff; 2) information available on the company’s website; and 3) the company’s preferred process for developers and customers to get standby service questions answered.

2. Table 1 highlights the inconsistency in standby service tariffs across the state. Staff recommends that the Commission develop a cost-of-service-based, standardized framework for standby service tariffs where possible. Staff recognizes there may be reason to deviate from the standard. Any differences should be justified and supported by the company.

3. For customers taking both supplemental and standby service, the standby service tariff should be structured to allow the standby capacity and delivery demand charges to be structured to recognize the demand interactions between supplemental and standby service (net load).

4. Standby service tariffs, including the monthly customer charges, should be reviewed and, if necessary, updated in each utility’s rate case to ensure they are based on the most up-to-date cost of service principles. Daily capacity demand charges and the use of generator reservation fees and how the fee relates to the daily demand charge/pro-rated daily demand charges should be considered and discussed by the parties.

5. Standby service tariffs should include a reasonable capacity price differential to encourage scheduled maintenance, which in turn may reduce unscheduled outages. Limiting options to only off-peak time periods may not result in least cost to the utility.

6. Time of use charges for capacity and energy should be an available option for standby service customers.

7. The method for determining the solar standby tariff billing criteria should be made clear on the tariff. Customers with solar generators should have the option to stay on their supplemental service rate schedule provided it has a demand charge for delivery services. A time of use charge for capacity and energy should be considered for these customers.



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Appendix A-Current Standby Service Tariffs



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M.P.S.C. No. 13 - Electric Fifth Revised Sheet No. D-42.00Consumers Energy Company Cancels Fourth Revised Sheet No. D-42.00(To update provision)

GENERAL SERVICE SELF GENERATION RATE GSG-2Availability:

Subject to any restrictions, this rate is available to any Full Service Customer with a generating installation greater than 550kW, which may employ cogeneration or small power production technology. A customer who meets the Federal Energy Regulatory Commission’s (FERC) criteria for a Qualifying Facility may elect to take standby service under this rate and may elect to sell energy to the Company. The Company has the right to refuse to contract for the purchase of energy , should it be determined to adversely impact economic or reliable operation of the Company’s electric system . An eligible customer may elect to take service under this General Service Self Generation Rate GSG-2 or under Rule C11., NetMetering Program.

“Standby” service is defined as that electric service used in place of the customer's generation other than Company supplied firm service.

"Standby Capacity" is defined as the contracted kW capacity the Company is expected to provide to the customer on an occasional basis due to outages of the customer’s generating unit(s). The Standby Capacity shall not exceed the generator 's capability as designated in the interconnection agreement and as determined by the Company .

“Standby Demand” is defined as the greater of the (i) highest 15 minute kW demand the Company supplies the customer for Standby Service during the current month or (ii) highest Standby Demand from the previous 11 months. The Company shall determine the amount of monthly Standby Demand supplied to the customer based upon the total amount of power supplied to the customer, their contract Standby Capacity and generator output .

The Company shall not be required to supply standby power to the customer in excess of their contracted Standby Capacity. However, the Company may, at the written request of the customer made at least thirty days in advance , permit an increase in Standby Capacity provided the Company has facilities and generating capacity available .

Self-generation customers who require Company delivery service for any portion of the load that has been self -generated will be charged as described under the Delivery Standby Charges as shown on this Rate Schedule for the service provided and charged for any Power Supply provided by the Company as described under Power Supply Standby Charges on this rate schedule.

This rate is not available to Retail Open Access.

Nature of Service:

All facilities operated in parallel with the Company’s system must meet the Parallel Operation Requirements set forth in Rule C1.6 B. The Company shall own, operate and maintain all metering and auxiliary devices (including telecommunication links) at the customer's expense. Meters furnished, installed and maintained by the Company shall meter all generation equipment. No refund shall be made for any customer contribution required under this Rate Schedule .

Interval Data Meters are required on all generators. Meter reading will be accomplished electronically through telecommunication links or other electronic data methods able to provide the Company with the metering data /billing determinants necessary for billing.

Energy delivered to the Company shall be alternating current , 60-hertz, single-phase or three-phase (as governed by Rule B8., Electric Interconnection and Net Metering Standards) Primary Voltage service. The Company will determine the particular nature of the voltage in each case.

The Company may discontinue purchases during system emergencies, maintenance and other operational circumstances.

Where service is supplied at a nominal voltage of 25,000 volts or less but equal to or greater than 2,400 volts, the customer shall furnish, install and maintain all necessary transforming, controlling and protective equipment.

(Continued on Sheet No. D-43.00)

Issued June 19, 2012 by Effective for service rendered onJ. G. Russell, and after June 8, 2012President and Chief Executive Officer,Jackson, Michigan Issued under authority of the

Michigan Public Service Commissiondated June 7, 2012in Case No. U-16794

Michigan Public Service Commission

Filed _______________

June 25, 2012



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M.P.S.C. No. 13 - Electric Ninth Revised Sheet No. D-43.00 Consumers Energy Company Cancels Eighth Revised Sheet No. D-43.00 (To update prices and the Power Supply Standby Charges)

GENERAL SERVICE SELF GENERATION RATE GSG-2 (Continued From Sheet No. D-42.00)

Nature of Service (Contd)

Where service is supplied at a nominal voltage equal to or greater than 2,400 volts and the Company elects to measure the service at a nominal voltage above 25,000 volts, 1% shall be deducted for billing purposes, from the demand and energy measurements thus made.

Where service is supplied at a nominal voltage equal to or greater than 2,400 volts and the Company elects to measure the service at a nominal voltage of less than 2,400 volts, 3% shall be added for billing purposes, to the demand and energy measurements thus made.

Where service is supplied at a nominal voltage less than 2,400 volts and the Company elects to measure the service at a nominal voltage equal to or greater than 2,400 volts, 3% shall be deducted for billing purposes from the energy measurements thus made.

There shall be no double billing of demand under the base rate and Rate GSG-2.

Monthly Rate

Standby Charges

Power Supply Standby Charges

For all standby energy supplied by the Company, the customer shall be responsible for the MISO Real-Time Locational Market Price (LMP) for the Company's load node (designated as "CONS.CETR" as of the date of this Rate Schedule), multiplied by the customer’s consumption (kWh), plus the Market Settlement Fee of $0.002/kWh. In addition capacity charges will be assessed monthly, calculated using the highest 15 minute kW demand associated with Standby Service occurring during the Company's On-Peak billing hours will be multiplied by the highest contracted capacity purchased by the Company in that month, plus allocated transmission and ancillaries. The capacity charges will be prorated based on the number of On-Peak days that Standby Service was used during the billing month.

A customer with a generator(s) nameplate rating more than 550 kW must provide written notice to the Company by December 1 if they desire standby service in the succeeding calendar months of June through September. Written notice shall be submitted on Company Form 500. If the customer fails to meet this written notice requirement, the LMP shall be increased by applying a 10% adder.

Delivery Standby Charges

System Access Charge:

Generator that does not meet or exceed load: $100.00 per generator installation per month Generator that meets or exceeds load: $200.00 per generator installation per month

Charges for Customer Voltage Level 3 (CVL 3)

Capacity Charge: $4.92 per kW of Standby Demand





This rate is subject to the Surcharges shown on Sheet Nos. D-2.00 through D-3.10 and the Securitization Charges shown on Sheet Nos. D-5.00 and D-5.10.

(Continued on Sheet No. D-44.00) Issued March 10, 2017 by Effective for service rendered on Patti Poppe, and after March 7, 2017 President and Chief Executive Officer, Jackson, Michigan Issued under authority of the Michigan Public Service Commission dated February 28, 2017 in Case No. U-17990


Filed _______________

March 14, 2017



Page 27 of 81

M.P.S.C. No. 13 - Electric Sixth Revised Sheet No. D-44.00 Consumers Energy Company Cancels Fifth Revised Sheet No. D-44.00 (To update prices, Adjustment for Power Factor, and Substation Ownership Credit)


Monthly Rate (Contd)

Standby Charges (Contd)

Adjustment for Power Factor

This rate requires a determination of the average Power Factor maintained by the customer during the billing period. Such average Power Factor shall be determined through metering of lagging Kilovar-hours and Kilowatt-hours during the billing period. The calculated ratio of lagging Kilovar-hours to Kilowatt-hours shall then be converted to the average Power Factor for the billing period by using the appropriate conversion factor. Whenever the average Power Factor during the billing period is above .899 or below .850, the customer bill shall be adjusted as follows:

(a) If the average Power Factor during the billing period is .900 or higher, a 0.50% credit will be applied to all metered-based charges, excluding surcharges. This credit shall not in any case be used to reduce the prescribed Minimum Charge.

(b) If the average Power Factor during the billing period is less than .850, a penalty will be applied to all metered-based charges, excluding surcharges, in accordance with the following table:

Power Factor Penalty 0.800 to 0.849 0.50% 0.750 to 0.799 1.00% 0.700 to 0.749 2.00% Below 0.700 3% first 2 months

(c) A Power Factor less than 0.700 is not permitted and necessary corrective equipment must be installed by the customer. A 15% penalty will be applied to any metered-based charges, excluding surcharges, after two consecutive months below 0.700 Power Factor and will continue as long as the Power Factor remains below 0.700.Once the customer's Power Factor exceeds 0.700, it is necessary to complete two consecutive months below 0.700 before the 15%penalty applies again.

Substation Ownership Credit

Where service is supplied at a nominal voltage of more than 25,000 volts, energy is measured through an Interval Data Meter, and the customer provides all of the necessary transforming, controlling and protective equipment for all of the service there shall be deducted from the bill a monthly credit. For those customers, part of whose load is served through customer-owned equipment, the credit shall be based on the billed Standby Demand.

The monthly credit for the substation ownership shall be applied as follows:

Delivery Charges


Substation Ownership Credit: $(0.64) per kW of Maximum Demand

Charges for Customer Voltage Level 1 (CVL 1) Substation Ownership Credit: $(0.44) per kW of Maximum Demand

For those customers served by more than one substation where one or more of the substations is owned by the customer, the credit will be applied to the customer's coincident Maximum Demand for those substations owned by the customer. This credit shall not operate to reduce the customer’s billing below the prescribed minimum charges included in the rate. The credit shall be based on the kW after the 1% deduction or 3% addition has been applied to the metered kW.

Transmission Interconnect Credit

Where standby service is provided to a non-utility electric generator located within the Company's service territory and taking power through its transmission interconnect, where the Company has no owned infrastructure other than metering, including billing grade current transformers and potential transformers, telemetry facilities and associated wiring, the following monthly credit shall be applied to the bill:

Delivery Charges Transmission Interconnect Credit: $(1.25) per kW of Standby Demand

This credit shall be based on the kW after the 1% deduction has been applied to the metered kW. The credit supersedes any applicable substation ownership credit.


Issued March 10, 2017 by Effective for service rendered on Patti Poppe, and after March 7, 2017 President and Chief Executive Officer, Jackson, Michigan Issued under authority of the Michigan Public Service Commission dated February 28, 2017 in Case No. U-17990


Filed _______________

March 14, 2017



Page 28 of 81

M.P.S.C. No. 13 - Electric Fifth Revised Sheet No. D-45.00 Consumers Energy Company Cancels Fourth Revised Sheet No. D-45.00 (To update Energy Purchase and reformat rate book)


Monthly Rate(Contd) Sales of Energy to the Company Administrative Cost Charge Generation installation with a capacity of over 550 kW but less than or equal to 2,000 kW As negotiated or $0.0010 per kWh purchased, at the option of the customer Generation installation with a capacity of over 2,000 kW As negotiated Energy Purchase: An energy purchase by the Company shall be bought at the Midcontinent Independent System Operator's

Inc. (MISO) real-time Locational Marginal Price (LMP) for the Company's load node (designated as "CONS.CETR" as of the date of this Rate Schedule).

General Terms This rate is subject to all general terms and conditions shown on Sheet No. D-1.00. Green Generation Program Customer contracts for participation in the Green Generation Program shall be available to any eligible customer as

described in Rule C10.2, Green Generation Program. A customer who participates in the Green Generation Program is subject to the provisions contained in Rule C10.2, Green

Generation Program. Minimum Charge The System Access Charge included in this Rate Schedule in addition to the customer's contracted Standby Capacity

multiplied by the net of any Substation Ownership Credit and Delivery Capacity Charges of this Rate Schedule. Due Date and Late Payment Charge

The due date of the customer bill shall be 21 days from the date of mailing. A late payment charge of 2% of the unpaid balance, net of taxes, shall be assessed to any bill which is not paid on or before the due date shown thereon.

Term and Form of Contract Standby service and/or sales of energy to the Company under this rate shall require a written contract with a minimum term

of one year. _________________________________________________________________________________________________ Issued March 10, 2017 by Effective for service rendered on Patti Poppe, and after March 7, 2017 President and Chief Executive Officer, Jackson, Michigan Issued under authority of the Michigan Public Service Commission dated February 28, 2017 in Case No. U-17990


Filed _______________

March 14, 2017



Page 29 of 81

M.P.S.C. No. 1 - Electric Second Revised Sheet No. D-67.00DTE Electric Company Cancels First Revised Sheet No. D-67.00(Add Station Power Standby Service Provision)

STANDARD CONTRACT RIDER NO. 3 PARALLEL OPERATION AND STANDBY SERVICE ANDSTATION POWER STANDBY SERVICE

There are two categories of standby service provided under this rider, “STANDBY SERVICE” AND “STATION POWER STANDBY SERVICE”. STANDBY SERVICE applies to customers with generation facilities that are located within the Company’s retail service territory and directly interconnected with the Company. STATION POWER STANDBY SERVICE applies to customers with generation facilities that are located within the Company’s retail service territory and that are directly interconnected to ITC Transmission.

STANDBY SERVICE

STANDBY SERVICE: Available to customers with generation facilities that are located within the Company’s retail service territory and directly interconnected with the Company. Customers who desire the Company to serve the power supply requirements of load that is normally served by the customer’s generator or prime mover must take standby service under the provisions of this rider unless otherwise exempted by order of the Michigan Public Service Commission or by the provisions set forth below and must take supplemental service on one of the applicable filed rates listed below.

Customers purchasing their entire energy requirements from the Company with generators or prime movers installed for use only in emergency will not be considered as taking standby service.

Customers with generators or prime movers installed solely for use to provide a load for testing equipment such as regenerative dynamometers may elect not to purchase standby energy service for that equipment under this rider, must meet the applicable parallel operation requirement, must purchase power that would, absent this provision, be considered standby on another rate schedule and must take standby for any additional generating equipment normally site load.

APPLICABLE TO: General Service Rate Schedule Designation D3Secondary Educational Institution Rate Schedule Designation D3.2Interruptible General Service Rate Schedule Designation D3.3Large General Service Rate Schedule Designation D4Primary Educational Institution Rate Schedule Designation D6.2Interruptible Supply Rate Schedule Designation D8Primary Supply Rate Schedule Designation D11

PARALLEL OPERATION: The customer must meet the interconnection requirements of the Company specified in "The Michigan Electric Utility Generator Interconnection Requirements” as approved by the Commission, and must enter into an Interconnection and Operating Agreement with the Company before parallel operation will be permitted. Operating in parallel with the Company's system without written approval by the Company of the interconnection and any subsequent changes to the interconnection will make the customer subject to disconnection.

INDEMNIFICATION AND INSURANCE: Except for the acts or omissions of the Company's employees or agents which occur on the Customer's side of the point of interconnection the customer shall indemnify, defend and hold the Company and its officers, agents and employees harmless from any liabilities, claims, losses,


Issued July 9, 2015 Effective for service rendered onD. M. Stanczak and after July 1, 2015Vice PresidentRegulatory Affairs Issued under authority of the

Michigan Public Service CommissionDetroit, Michigan dated June 30, 2015 in Case No. U-17689


Filed _______________

July 15, 2015



Page 30 of 81

M.P.S.C. No. 1 - Electric First Revised Sheet No. D-68.00DTE Electric Company Cancels Original Sheet No. D-68.00(Add Station Power Standby Service Provision)

(Continued from Sheet No. D-67.00)

STANDARD CONTRACT RIDER NO. 3 (Contd.) PARALLEL OPERATION AND STANDBY SERVICE ANDSTATION POWER STANDBY SERVICE

demands, costs, damages or damage which (i) occur on the Customer's side of the point of interconnection resulting from the installation, maintenance, possession or operation of the Facility, or (ii) occur on theCompany's side of the point of interconnection up to the first point of the Company's General Facility Protection if at the time of the injury or damage, the Company is not providing electric energy to the customer and the injury or damage was caused by the customer's intentional defeat of the protective relays.

The Company shall indemnify, defend and hold the Customer and its officers, agents and employees harmless from any liabilities, claims, losses, demands, costs, damages or judgments, including reasonable attorneys' fees, arising out of all personal injuries or property damages which occur on the Company's side of the point of interconnection resulting from the installation, maintenance, possession or operation of the Company's General

Facilities; (i) except for the acts or omissions of the Customer's employees or agents which occur on the Company's side of the point of interconnection; and (ii)except for those injuries or damages for which the Customer is to indemnify the Company pursuant to the preceding paragraph.

The Customer taking service under this rider shall maintain and furnish current evidence of comprehensive general liability insurance in the amount of $2,500,000 per occurrence. This insurance can be a combination of primary and excess insurance. The Company shall be named as an additional insured under the customer's policy. The customer need not provide insurance if it can demonstrate that its Tangible Net Worth as defined by GAAP is $8,000,000 or more and provides an affidavit to that effect signed by an authorized agent of the Company.. If the customer fails to provide insurance or does not meet the requirements of the preceding sentence for waiver of insurance, then the Company will purchase insurance in the amount of $2,500,000 to protect the Company (but not the customer). The cost of such insurance will be paid by the customer. The customer’s insurance, its waiver, or insurance purchased by the Company shall not limit the Customer's indemnity obligations. Parallel operation will not be permitted (or will be terminated) if the Customer fails to provide insurance, meet the waiver requirements or pay the cost of insurance obtained by the Company.

METERING REQUIREMENTS: All customers taking service under this rider must install the necessary equipment to permit metering. The Company will supply the metering equipment. The output of customer generation or, if appropriate, the load served by another source of power or the customer's prime mover, inflow from the Company and outflow to the Company if applicable will all be metered with demand-recording equipment by the Company.

STANDBY CONTRACT CAPACITY: Standby contract capacity in kW will be established for electric capacity sufficient to meet the customer's standby load. Unit sizes, number of units, site demands, operating characteristics and other factors impact the amount of electric capacity that is sufficient to meet the customer's standby load. Standby contract capacity will be established according to one of the following methods with the intent to use the method which best determines the electric capacity sufficient to meet the customer's standby load.


Is Issued December 30, 2013 Effective for service rendered onN. A. Khouri and after January 5, 2014Vice PresidentRegulatory Affairs Issued under authority of the

Michigan Public Service CommissionDetroit, Michigan dated December 6, 2013 in Case No. U-17251


Filed _______________

January 8, 2014January 8, 2014January 8, 2014



Page 31 of 81

M.P.S.C. No. 1 - Electric First Revised Sheet No. D-69.00DTE Electric Company Cancels Original Sheet No. D-69.00(Add Station Power Standby Service Provision)

(Continue from Sheet No. D-68.00)


(a) If the customer's generating units are electrically base loaded during peak hours the standby contract capacity for billing months that include periods from calendar months June through October will be set at the 1001st highest half-hourly kW output toward internal load during billing months that include periods from calendar months June through October over the latest 12-month period. The standby contract capacity for remaining billing months will be set at the 1001st highest half-hourly kW output during those months over the latest 12-month period. The standby contract capacity will be adjusted on an ongoing basis reflecting the current month and preceding eleven months.

“output toward internal load” means the simultaneous output of all units less excess generation flowing back through the interconnection to the Company’s system.

(b) If the customer's generating units are operated with the intent to provide energy to the system and standby is only required for site load during outages the standby contract capacity will be set at the maximum half-hourly demand provided to the facility.

(c) For customers with units that do not operate in parallel with the system but have the ability to connect load normally served by unmetered on site generation to the system during generation outages, (throw over standby), the standby contract capacity will be set at the maximum metered half-hourly demand thrown over to the system and supplemental demand will the metered inflow less the metered throw over load.

(d) For customers demonstrating unusual operating conditions, including but not limited to initial unit operation, unpredictable generation from renewable resource units or generation that follows thermal load and prolonged periods with no generation, standby contract capacity may be set by mutual agreement of the Company and the customer to levels sufficient to meet the customer's standby load.

STANDBY POWER: Standby energy is electric energy provided by the Company to serve the customer's total internal load which would have been provided by the customer’s generation had it operated at its contract capacity. Standby demand is electric capacity provided by the Company to serve the customer’s total internal load which would have been provided by the customer’s generation had it operated at its contract capacity less any reduction the customer can accomplish by reducing the supplemental demand at the time of the daily on-peak standby demand below the maximum monthly on peak supplemental demand but not less than zero.

SUPPLEMENTAL POWER: Supplemental power is electric energy and capacity provided by the Company to serve the customer's total internal load which is in addition to that portion of the customer's total internal load equal to the standby contract capacity. For each point of service, total internal load equals the output toward internal load of the customer's generation plus the power supplied by the Company. Supplemental demand equals total internal load less standby contract capacity, but not less than zero. Supplemental high on-peak demand used to establish Power Supply Demand will be highest supplemental demand from the dates and times at which the daily on-peak standby demands are set. Supplemental power will be billed under the applicable rate schedule for supplemental service ("supplemental rate schedule").


Issued December 30, 2013 Effective for service rendered onN. A. Khouri and after January 5, 2014Vice PresidentRegulatory Affairs Issued under authority of the

Michigan Public Service CommissionDetroit, Michigan dated December 6, 2013 in Case No. U-17251


Filed _______________

January 8, 2014January 8, 2014January 8, 2014



Page 32 of 81

M.P.S.C. No. 1 - Electric Fifth Revised Sheet No. D-70.00 DTE Electric Company Cancels Fourth Revised Sheet No. D-70.00 (Final Order Case No. U-18014)

Issued February 23, 2017 Effective for service rendered on D. M. Stanczak and after February 7, 2017 Vice President Regulatory Affairs Issued under authority of the Michigan Public Service Commission Detroit, Michigan dated January 31, 2017 in Case No. U-18014



RATES: Power Supply Charges: Monthly Generation Reservation Fee: $1.94 times the standby contract capacity in kW, per month.

Demand Charges: A daily on-peak standby demand charge will be charged based on the determination of standby power coincident with the daily highest 30-minute integrated reading during on-peak hours of the demand meters which measure the total load served by the Company. Standby demand equals standby contract capacity minus the 30-minute output toward internal load of the customer's generator less any reduction the customer can accomplish by reducing the supplemental demand below the maximum monthly on peak supplemental demand, but not less than zero, and not greater than the total load served by the Company. The daily on-peak backup demand charge is $5.09 per kW per day during periods other than maintenance periods as defined below. The daily on-peak backup demand charge is $2.88 per kW per day during maintenance periods as defined below.

Energy Charge:

An energy charge for back-up and maintenance power will be charged based on standby contract capacity less the output toward internal load of the customer's generator, but not less than zero. For customers served on supplemental rate schedules D4, D11, D6.2 and D8, the energy charge will be the D11 on-peak power supply energy charge, 4.330¢ per kWh, plus appropriate power supply credits, including but not limited to off-peak credit, and voltage level credit. For customers served on supplemental rate schedules D3, D3.2 and D3.3, the energy charge will be the applicable power supply energy charge specified in the customer’s supplemental rate. The energy as stated herein, is also subject to provisions of the PSCR clause and other Surcharges and Credits Applicable to Power Supply as approved by the Commission. See Section C8.5.

Waivers and limits for demand/energy rates: For customers taking supplemental service at demand/energy rates schedules D4, D11, D6.2 and D8, and customers switching from energy only rates to demand/energy/rates, the following applies. If the total of daily demand charges for the month is less than the monthly generation reservation fee,

then the daily demand charges will be waived for that month. If the total of daily demand charges for the month is greater than the monthly generation reservation fee,

then the generation reservation fee will be waived for that month.



Filed _______________

February 27, 2017



Page 33 of 81

M.P.S.C. No. 1 - Electric Third Revised Sheet No. D-71.00DTE Electric Company Cancels Second Revised Sheet No. D-71.00(Final Order Case No. U-17767)



If the total of daily demand charges for the month is greater than the Rider 3 Daily Demand Cap the customer will pay the Daily Demand Cap. For customers served on supplemental rates schedule D4, The Daily Demand Cap will be determined as the D11 Power Supply Demand Charge times the maximum standby contract capacity utilized plus the Rider 3 Generation Reservation Charge times the difference between the total standby contract capacity and the maximum standby utilized. For customers served on supplemental rates schedules D6.2, D8 and D11, the Daily Demand Cap will be determined as the D11 Power Supply Demand Charge times the maximum standby contract capacity utilized plus the difference between the product of the D11 Distribution Demand Charge times the standby contract capacity utilized and the standby Distribution Charge times the standby contract capacity utilized plus the voltage specific D11 Delivery Charge energy component applied to all standby energy delivered plus the Rider 3 Generation Reservation charge times the difference between the total standby contract capacity and the maximum standby utilized.

Waivers and limits for energy-only rates:For customers taking supplemental service on energy-only rates for the entire billing cycle, schedules D3, D3.3, and E5, the following applies.

If the total of daily demand charges for the month is less than the monthly generation reservation fee, then the daily demand charges will be waived for that month.

If the total of daily demand charges for the month is greater than the monthly generation reservation fee, then the daily demand charges will be waived for that month provided that the supplemental rate continues as an energy-only rate. If not, then paragraphs (6)(b) and (6)(c) above will apply.

MAINTENANCE PERIODS: A customer may specify, subject to conditions below set by the Company, up to 20 on-peak days during a year as maintenance days. In addition standby daily demands on the day after Thanksgiving and on-peak days occurring during the period from December 24 through January 1 will be priced at the maintenance day rate specified above. A maintenance day is a calendar 24-hour day.Conditions for setting maintenance days:

(a) The customer must request maintenance days in writing.

(b) The Company must receive the request at least 45 days before the first requested maintenance day.

(c) Requests will be honored according to the date received.

(d) Requests may be refused by the Company if they conflict with the Company’s own schedule of maintenance and expected demands. The Company will permit the customer to select alternative maintenance days.

(e) If there is a substantial change in circumstances which make the agreed upon schedule impractical for either party, the other party upon request shall make reasonable efforts to adjust the schedule in a manner that is mutually agreeable.


Issued January 8, 2016 Effective for service rendered onD. M. Stanczak and after December 17, 2015Vice PresidentRegulatory Affairs Issued under authority of the

Michigan Public Service CommissionDetroit, Michigan dated December 11, 2015

in Case No. U-17767


Filed _______________

January 20, 2016



Page 34 of 81

M.P.S.C. No. 1 - Electric Sixth Revised Sheet No. D-72.00 DTE Electric Company Cancels Fifth Revised Sheet No. D-72.00 (Final Order Case No. U-18014)




Delivery Charges: Service Charge:

$275 per customer per month for customers served at primary voltage. $375 per customer per month for customers served above primary voltage. $95 per customer per month for customers served at secondary voltages. Distribution Charge:

Distribution charges will be as follows: $3.96 per kW at primary voltage applied to the standby contract capacity $1.54 per kW at subtransmission voltage applied to the standby contract capacity $0.73 per kW at transmission voltage applied to the standby contract capacity

For service provided in conjunction with a secondary voltage base rate the Delivery Charge will be the greater of $9.80 per kW applied to standby contract capacity or 3.920¢/kWh applied to all standby energy delivered.

Substation Credit: Available to customers served at subtransmission voltage level (24 to 41.6 kW) or higher who provide the on-site substation including all necessary transforming, controlling, and protective equipment. A credit of $.30 per kW shall be applied to the distribution demand charge per kW of standby capacity. An additional credit of 0.040¢ per kWh of standby delivered will be given where the service is metered on the high voltage side of the transformer.

Surcharges and Credits Applicable to Delivery Service: As approved by the Commission. See Section C9.8.

ADJUSTMENT OF PRIOR RATCHETS: When a customer takes standby service under Rider No. 3, the setting

or the increasing or decreasing of standby contract capacity will affect the existing ratchet levels on the supplemental rate as follows: (a) An amount in kW equal to the initial standby contract capacity (or to the increase or decrease) will be

subtracted from (or subtracted from or added to) the existing ratcheted maximum demand level for customers on supplemental rates D6.2 and D8 and D11.

(b) An amount in kW equal to 65% of the initial standby contract capacity (or of the increase or decrease) will

be subtracted from (or subtracted from or added to) the existing ratcheted on-peak billing demand level for customers on supplemental rates D4, D6.2 and D8 and D11.

LATE PAYMENT CHARGE: See Section C4.8.

SCHEDULE OF ON-PEAK HOURS: See Section C11.



Filed _______________

February 27, 2017



Page 35 of 81

M.P.S.C. No. 1 - Electric Third Revised Sheet No. D-73.00DTE Electric Company Cancels Second Revised Sheet No. D-73.00(Final Order Case No. U-17767)



POWER FACTOR CLAUSE: The rates and charges under this tariff are based on the customer maintaining a power factor of not less than 85% lagging. Customers are responsible for correcting power factors less than 70% at their own expense. The size, type and location of any power factor correction equipment must be approved by the Company. Such approval will not be unreasonably withheld. A penalty will be applied to the total amount of the monthly billing for supplemental and standby service for power factor below 85% lagging in accordance with the table in Power Factor Determination, Section C12. The penalty will not be applied to the on-peak billing demand ratchet nor to the minimum contract demand of the supplemental rate, but will be applied to metered quantities.

INTERRUPTIBLE STANDBY SERVICE:

(a) Interruptible standby service is supplied in conjunction with supplemental rates D8 and D3.3, provided that the customer qualifies for D8 or D3.3 under the provisions of the respective rates.

(b) For customers taking service on supplemental rate D8, the daily demand charge for back-up power and maintenance power will be waived on a day that the Company requests interruption, provided that the customer is assessed neither a non-interruption fee nor a non-interruption penalty under the terms of the D8 rates.

(c) For customers taking service on supplemental rate D3.3, the customer's generator, prime mover, or other source of energy must be connected only to the interruptible circuit. The energy charge for back-up power and maintenance power will be the same as the energy charge for the D3.3 rate. The daily demand charge will be waived on a day that the Company interrupts the circuit.

(d) Interruptible standby service will also be supplied in conjunction with any new interruptible supplemental rates approved by the Commission after January 1, 1989, under terms to be incorporated in this section.

SPECIAL TERMS AND CONDITIONS: Customer-owned equipment must be operated so that voltage fluctuations on the Company’s system shall not exceed permissible limits.

Upon the request of a customer, the Company will provide monthly reports of the data from the meters measuring the load served by the Company and the output of the customer’s generators, for a charge of $10.00 per report per month. Each report contains data from one meter.

Application of Rider No. 2 for redundant service for customers served under this rider will be the same as for customers without generating equipment.

Service under this rider will not be affected by ownership of the generation facility provided that: (1) the generation facility is located on the customer’s site, (2) the load served by the generation facility is on the same site, and (3) the total output of the generation facility is utilized by the customer or sold to the Company.




in Case No. U-17767


Filed _______________

January 20, 2016



Page 36 of 81

M.P.S.C. No. 1 - Electric First Revised Sheet No. D-73.01DTE Electric Company Cancels Original Sheet No. D-73.01(Final Order Case No. U-17767)



CONTRACT TERM: The contract term is for a five-year period unless terminated by mutual consent and extending thereafter from month to month until terminated by mutual consent or by thirty day's written notice by either party.

DISPUTE RESOLUTION PROCEDURE: Any customer who disputes a determination or interpretation made by the Company under this rider may deliver a written notice of such dispute to the customer's service representative at the Company. The Company will respond to the notice in writing within 20 working days.

Disputes between the Company and the customer may be presented to the Commission for informal resolution.

Any customer who disputes a determination made by the Company under this rider may at any time file a formal complaint with the Office of the Secretary of the Commission.




in Case No. U-17767


Filed _______________

January 20, 2016



Page 37 of 81

M.P.S.C. No. 1 - Electric Third Revised Sheet No. D-73.02 DTE Electric Company Cancels Second Revised Sheet No. D-73.02 (Final Order Case No. U-18014)


(Continued from Sheet No. D-73.01) STANDARD CONTRACT RIDER NO. 3 (Contd.).) PARALLEL OPERATION AND STANDBY SERVICE AND STATION POWER STANDBY SERVICE

STATION POWER STANDBY SERVICE

SERVICE UNDER THIS PROVISION BECOMES EFFECTIVE APRIL 1, 2014 STATION POWER STANDBY SERVICE: Available to customers with generation facilities that are located within

the Company’s retail service territory and that are interconnected to ITC Transmission. The power supply requirements necessary to maintain and operate the generating facility that are normally served by the facility’s on-site generation but which instead are provided by the facility’s taking power through its transmission interconnection must be provided under the station Power Standby Service provisions of this rider.

APPLICABLE TO: General Service Rate Schedule Designation D3

HOURS OF SERVICE: 24 hours, subject to interruption by agreement, or by advance notice.

CONTRACT CAPACITY: Customers shall initially contract for a specified capacity in kilowatts sufficient to meet expected maximum requirements. Any single reading of the demand meter or aggregation of demand meters recording inflow to the facility in any month that exceeds the contract capacity then in effect shall become the new contract capacity.

METERING REQUIREMENTS: All customers taking service under this rider must install the necessary equipment to permit metering. The Company will supply the metering equipment. Service to the customer under this Rider will be metered with demand-recording equipment. Any equipment installed by the customer necessary to accommodate the Company’s metering equipment must be approved by the Company and must be compatible with the Company’s Meter Data Acquisition System.

RATES: Power Supply:

Station Power Energy Service will be priced on the basis of the real time MISO locational hourly marginal energy price for the Company-appropriate load node. In additional to the MISO locational hourly marginal energy price the following charges will also apply: 0.733¢/kWh for MISO network transmission costs and MISO energy market costs plus, An administrative charge of 1.619¢/kWh plus, Surcharges and Credits Applicable to Power Supply, excluding PSCR, as approved by the Commission. See Section C8.5

Service Charge: Primary Service Charge: $275 per month Subtransmission and Transmission Service Charge: $375 per month

LATE PAYMENT CHARGE: See Section C4.8

CONTRACT TERM: The contract term is from month to month until terminated by mutual consent or on one month written notice by either party.


Filed _______________

February 27, 2017



Page 38 of 81

M.P.S.C. No. 1 – Electric WPSC Rate ZoneUpper Michigan Energy Resources Corporation First Revised Sheet No. D-119.00

Replaces Original Sheet No. D-119.00

D4. LARGE COMMERCIAL & INDUSTRIAL SERVICE Cp-1M

EFFECTIVE IN: All territory served.

AVAILABILITYThis schedule is applicable to customers whose monthly demand is equal to or greater than 100 kW or 25,000 kWh/month for three consecutive months and others taking standby service. This schedule is also available to small commercial and industrial customers who contract for service under the Cp-I2M Interruptible Rider. This service is not available for customers required to take service under the Power Supply Default Service. Customers taking service under the Retail Access Service Tariff (RAST) shall be responsible for the Distribution Charges but not the Power Supply Charges under this rate schedule. Customers that purchase power supply service from the Company shall be subject to both the Distribution and Power Supply charges contained in this rate schedule.

The transmission rates are available to customers that take service directly from a company-owned substation (i.e. Company owns no distribution facilities downstream of substation). For customers that meet this condition, a monthly charge of $0.49/kVA of installed substation transformer capacity as determined by the company shall apply.

MONTHLY RATEDistribution Service Secondary Primary Transmission

Fixed Charge:Monthly $142.00 $673.00 $990.00Daily $4.6685 $22.1260 $32.5479

Demand Charge1. Customer Demand:$/kW $2.95 $2.22 $0.00

Per KW of maximum demand during the current and preceding 11 months, plus,2. On-Peak Demand

a. Winter (Oct-May): $/kW $1.14 $1.14 $1.1410:00 AM to 8:00 PM; Monday through Friday (except holidays)

b. Summer (Jun-Sep): $/kW $1.14 $1.14 $1.1410:00 AM to 11:00 PM; Monday through Friday (except holidays)

Power Supply Service (Optional) Secondary Primary TransmissionOn-Peak Demand

a. Winter (Oct-May):$/kW $12.90 $12.61 $12.4410:00 AM to 8:00 PM; Monday through Friday (except holidays)

b. Summer (Jun-Sep):$/kW $12.90 $12.61 $12.4410:00 AM to 11:00 PM; Monday through Friday (except holidays)

Energy Charge Secondary Primary Transmission1. On-Peak

a. Winter (Oct-May):$/kWh $0.06197 $0.06017 $0.059426:00 AM to 10:00 PM; Monday through Friday (except holidays)

b. Summer (Jun-Sep):$/kWh $0.06197 $0.06017 $0.059427:00 AM to 11:00 PM; Monday through Friday (except holidays)

2. Off-Peaka. Winter (Oct-May):$/kWh $0.03350 $0.03253 $0.03212

10:00 PM to 6:00 AM; Monday through Friday, all day Saturday, Sunday, and holidaysb. Summer (Jun-Sep):$/kWh $0.03350 $0.03253 $0.03212

11:00 PM to 7:00 AM; Monday through Friday, all day Saturday, Sunday, and holidays

Note: For a 10:00 PM change between on peak and off peak time periods in the Winter months, on peak consumption will be recorded through 10:00 PM. Off Peak consumption will begin at 10:00:01 PM as recorded by the meter.


Issued April 11, 2017 Effective for service rendered on and T. T. Eidukas after April 24, 2017Vice-President,Milwaukee, Wisconsin Issued under authority of the

Michigan Public Service Commissiondated April 23, 2015in Case No. U-17669


Filed _______________

April 13, 2017



Page 39 of 81

M.P.S.C. No. 1 – Electric WPSC Rate Zone Upper Michigan Energy Resources Corporation Original Sheet No. D-120.00 D4. LARGE COMMERCIAL & INDUSTRIAL SERVICE Cp-1M (Continued from Sheet No. D-119.00) MINIMUM CHARGE The monthly minimum charge is the fixed charge, the demand charges, and the energy optimization charge. POWER SUPPLY COST RECOVERY CLAUSE: See Schedule PSCR.

PRIMARY & TRANSMISSION CHARGES The customer shall provide a support for the company to terminate the primary conductors and install other required

equipment. Customer owned substation equipment shall be operated and maintained by the customer. The support and substation equipment is subject to the company's inspection and approval.

ENERGY OPTIMIZATION See Schedule EO starting on Sheet D-156.00 The above listed voltages are phase-to-ground for wye-connected company systems and phase-to-phase for delta-connected

company systems. STANDBY SERVICE Where service is made available to loads which can be served by a source of power other than the company's (excluding

emergency standby maintained in the event of failure of company's supply), billing shall be at the above rate, but the monthly minimum demand charge (total of customer charge, on-peak demand charge, and substation transformer capacity charge) for standby service shall be not less than the following per kW of contracted demand: Cp Secondary: $3.50 Cp Primary: $2.75 Cp Transmission: $2.00

This standby service clause assumes that standby customers shall schedule normal maintenance of the customer-owned

source of power during periods of the year that are satisfactory to the company. Accordingly, customers shall advise the company of planned maintenance with as much advance notice as possible. These waivers are granted on a conditional basis. The company will rescind the waiver of increased demand during times of emergency interruptions. The company shall confirm in writing the maintenance schedule that is satisfactory to both parties.

The portion of the on-peak demand shall be billed on a prorated basis on a $/kW/day basis as shown below.

Pro-ration Formula - Firm Load: On-Peak Demand Charge * 12 months / No. of annual peak days * No. of waiver days Pro-ration Formula - Interruptible Load: Variable Interruptible Demand Charge * 12 months / No. of annual peak days * No. of waiver days These billing benefits shall only apply to the unusual portion of the customer’s monthly demand. All demands except

that portion of the peak load demand resulting from a company-approved maintenance schedule shall be billed as standard normal demand in accordance with all other sections of this rate schedule. The above clause shall not apply to customer-owned generation served under the Standby Service clause of this rate schedule and/or Maintenance Rate of the Pg-2 rate schedule because customers served under these clauses have similar provisions within their clauses. If the highest demand in any month exceeds the contract demand, the minimum demand charge shall thereafter be based on the highest actual demand. The company may install suitable devices to limit the actual demand to the contract demand and may limit size of standby load to be served under this rate to the available system capacity at the customer's location.

(Continued on Sheet No. D-121.00) Issued December 21, 2016 Effective for service rendered on and T. T. Eidukas after January 1, 2017 Vice-President, Milwaukee, Wisconsin Issued under authority of the Michigan Public Service Commission dated December 9, 2016 in Case No. U-18061


Filed _______________

January 3, 2017



Page 40 of 81

M.P.S.C. No. 1 – Electric WPSC Rate Zone Upper Michigan Energy Resources Corporation Original Sheet No. D-121.00 D4. LARGE COMMERCIAL & INDUSTRIAL SERVICE Cp-1M (Continued on Sheet No. D-120.00) REACTIVE LOAD The customer shall keep his lagging reactive load at a level that does not exceed his Kw demand and shall not operate with a

leading reactive load. SHORT TERM SERVICE Short term and temporary service is available to customers requiring service for less than annual periods.

1. a) For holiday/decorative lighting see Schedule Ls-1M, b) For special events see Schedule RIIIM, Temporary Service c) For construction see Schedule RIIIM, Temporary Service 2. Standard proration rules shall apply to the initial and final billing periods. 3. At the expiration of any month, the customer may cancel his contract for service under these provisions and may

contract for one year or more under the standard rate applicable to his service. VARIATION OF DEMAND Variation of customer load shall be limited to time changing demand levels which are within system standards of operation

as established by the company. Failure to take service in a manner which meets these standards may result in discontinuation of service.

TERM OF CONTRACT Minimum period of one year except that for new or additional loads of 5,000kW or more, a term of not less than five years

will be required. DETERMINATION OF DEMAND The customer demand in kilowatts shall be the highest single 15 minute integrated load observed or recorded during the

current or preceding 11 months. For new Cp-1M customers, this demand provision applies on and after the date of transfer to this rate schedule.

The on-peak billing demand in kilowatts shall be the highest single 15 minute integrated load observed or recorded during

each respective time period in the month, provided that no billing demand shall be less than 60% of the highest billing demand of the preceding 11 months.

Unusual on-peak billing demands approved by advance authority from the company shall be billed but will not be

considered in the determination of the 60% ratchet. Customer requests for unusual demands shall be made in advance with as much allowance as possible. The advance authorization from the company shall be confirmed in writing.

HOLIDAYS The days of the year which are considered holidays are: New Year's Day, Good Friday, Memorial Day, Fourth of July,

Labor Day, Thanksgiving Day, Friday After Thanksgiving, Day Before Christmas, Christmas Day, Day Before New Year's Day.

ESTIMATION PROCEDURE In the event of loss of data for calculation of one or more billing parameters, the company shall forecast on the basis of

historic billing parameters to obtain an estimate of current month's billing parameters. This estimate shall be subject to modification or replacement based on known and quantifiable operating conditions of the current month.

Issued December 21, 2016 Effective for service rendered on and T. T. Eidukas after January 1, 2017 Vice-President, Milwaukee, Wisconsin Issued under authority of the Michigan Public Service Commission dated December 9, 2016 in Case No. U-18061


Filed _______________

January 3, 2017



Page 41 of 81

UPPER PENINSULA POWER COMPANY

Issued: 9-23-16 Effective for Service By S C Devon On and After: 9-23-16 Director – Regulatory Affairs Issued Under Auth. of Marquette, Michigan Mich Public Serv Comm

Dated: 9-8-16 In Case No: U-17895

MPSC Vol No 8-ELECTRIC 5th Rev. Sheet No. D-25.10 Replaces 4th Rev. Sheet No. D-25.10

D2. Large Commercial & Industrial Service Cp-U

R R

WHO MAY TAKE SERVICE:

This schedule is applicable to customers whose monthly demand is equal to or greater than 200 kW for three consecutive months and at least once in each succeeding 12 month period and others taking standby service. This service is not available for customers required to take service under the Power Supply Default Service. Customers taking service under the Retail Access Service Tariff (RAST) shall be responsible for the Distribution Charges but not the Power Supply Charges under this rate schedule. Customers that purchase power supply service from the Company shall be subject to both the Distribution and Power Supply charges contained in this rate schedule. Customers that take service directly from the company-owned substation (i.e. Company owns no distribution facilities downstream of substation) will be classified as Transmission and receive the Substation Transformer Capacity charge.

MONTHLY RATE Secondary Primary Transmission DISTRIBUTION SERVICE

Customer Charge: Monthly $250.00 $325.00 $750.00

Daily $8.2192 $10.6849 $24.6575

Demand Charge 1. Customer Demand:$/KW $2.60 $1.95 $0.00 Per KW of maximum demand during the current and preceding 11 months, plus, 2. On-Peak Firm Demand: $/KW $2.14 $2.06 $1.99 Interruptible Demand: $/KW $2.14 $2.06 $1.99 7:00 AM to 11:00 PM; Monday through Friday (except holidays). Substation Transformer Capacity: $/kVA $0.75 Continued to Sheet No. D-25.20


Filed _______________

September 26, 2016



Page 42 of 81


MPSC Vol No 8-ELECTRIC 4th Rev. Sheet No. D-25.20 Replaces 3rd Rev. Sheet No. D-25.20

D2. Large Commercial & Industrial Service Cp-U

R R R R

Continued from Sheet No. D-25.10 Secondary Primary Transmission POWER SUPPLY SERVICE (Optional) On-Peak Firm Demand: $/kW $11.05 $10.66 $10.26 Interruptible Demand: $/kW $3.55 $3.16 $2.76 7:00 AM to 11:00 PM; Monday through Friday (except holidays). Energy Charge 1. On-Peak Energy Charge:$/kWh $0.09003 $0.08678 $0.08360 7:00 AM to 11:00 PM; Monday through Friday (except holidays). 2. Off-Peak Energy Charge:$/kWh $0.05854 $0.05642 $0.05435 11:00 PM to 7:00 AM; Monday through Friday, all day Saturday, Sunday, and

holidays. MINIMUM CHARGE The monthly minimum charge is the customer charge, demand charges, substation charges and the energy optimization charge. POWER SUPPLY COST RECOVERY CLAUSE This rate is subject to the Company’s Power Supply Cost Recovery shown on Sheet No. D-3.00. PRIMARY & TRANSMISSION CHARGES The customer shall provide a support for the company to terminate the primary conductors and install other required equipment. Customer owned substation equipment shall be operated and maintained by the customer. The support and substation equipment is subject to the company's inspection and approval. ENERGY OPTIMIZATION This rate is subject to the Energy Optimization Surcharge shown on Sheet No. D-73.00. DEFINITIONS For customers with company metering equipment installed at: Secondary Under 6,000 volts Primary 6,000 volts to 15,000 volts, inclusive Transmission Over 15,000 volts Continued to Sheet No. D-25.30

Issued: 9-23-16 Effective for Service By S C Devon On and After: 9-23-16 Director – Regulatory Affairs Issued Under Auth. of Marquette, Michigan Mich Public Serv Comm



Filed _______________

September 26, 2016



Page 43 of 81


MPSC Vol No 8-ELECTRIC 1st Rev. Sheet No. D-25.30 Replaces Original Sheet No. D-25.30

D2. Large Commercial & Industrial Service Rules Cp-U Continued from Sheet No. D-25.20

The above listed voltages are phase-to-ground for wye-connected company systems and phase-to-phase for delta-connected company systems.

STANDBY SERVICEWhere service is made available to loads which can be served by a source of power other than the company's (excluding emergency standby maintained in the event of failure of company's supply), billing shall be at the above rate, but the monthly minimum demand charge (total of customer demand charge, on-peak demand charge, and substation transformer capacity charge) for standby service shall be not less than the following per KW of contracted demand:

Cp-U Secondary: $3.50 Cp-U Primary: $2.75 Cp-U Transmission: $2.00

This standby service clause assumes that standby customers shall schedule normal maintenance of the customer-owned source of power during periods of the year that are satisfactory to the company. Accordingly, customers shall advise the company of planned maintenance with as much advance notice as possible. These waivers are granted on a conditional basis. The company will rescind the waiver of increased demand during times of emergency interruptions. The company shall confirm in writing the maintenance schedule that is satisfactory to both parties.

The portion of the on-peak demand shall be billed on a prorated basis on a $/KW/day basis as shown below.

Pro-ration Formula - Firm Load:

CycleBillinginWeekdaysNonholidayofNumber

CycleBillinginWeekdaysNonholidayApprovedofNumber*ChargeDemandPeakOn

Pro-ration Formula - Interruptible Load:

CycleBillinginWeekdaysNonholidayofNumber

CycleBillinginWeekdaysNonholidayApprovedofNumber*ChargeDemandbleInterruptiVariable

These billing benefits shall only apply to the unusual portion of the customer’s monthly demand. All demands except that portion of the peak load demand resulting from a company-approved maintenance schedule shall be billed as standard normal demand in accordance with all other sections of this rate schedule. The above clause shall not apply to customer-owned generation served under the Standby Service clause of this rate schedule and/or Maintenance Rate of any net metering or parallel generation rate schedule because customers served under these clauses have similar provisions within their clauses.

If the highest demand in any month exceeds the contract demand, the minimum demand charge shall thereafter be based on the highest actual demand. The company may install suitable devices to limit the actual demand to the contract demand and may limit size of standby load to be served under this rate to the available system capacity at the customer's location. Continued to Sheet No. D-25.40

Issued: 12-22-10 Effective for Service By J F Schott On and After: 1-1-11VP External Affairs Issued Under Auth. of Green Bay, Wisconsin Mich Public Serv Comm



Filed _______________

January 5, 2011



Page 44 of 81


MPSC Vol No 8-ELECTRIC 1st Rev. Sheet No. D-25.40 Replaces Original Sheet No. D-25.40

D4. Large Commercial & Industrial Service Rules Cp-U D

Continued from Sheet No. D-25.30 REACTIVE LOAD The customer shall keep his lagging reactive load at a level that does not exceed his Kw demand and shall not operate with a leading reactive load. SHORT TERM SERVICE Short term and temporary service is available to customers requiring service for less than annual periods. 1. a) For holiday/decorative lighting see Schedule SL-X, b) For special events or construction see Sheet No. C-19.00, Section

III – Line Extension Construction Policy Temporary Service. 2. Standard proration rules shall apply to the initial and final billing

periods. 3. At the expiration of any month, the customer may cancel his contract for

service under these provisions and may contract for one year or more under the standard rate applicable to his service.

VARIATION OF DEMAND Variation of customer load shall be limited to time changing demand levels which are within system standards of operation as established by the company. Failure to take service in a manner which meets these standards may result in discontinuation of service. Continued to Sheet No. D-25.50

Issued: 12-22-10 Effective for Service By J F Schott On and After: 1-1-11 VP External Affairs Issued Under Auth. of Green Bay, Wisconsin Mich Public Serv Comm



Filed _______________

January 5, 2011



Page 45 of 81


MPSC Vol No 8-ELECTRIC Original Sheet No. D-25.50

D4. Large Commercial & Industrial Service Rules Cp-UN N N N N N N N N N N N N N N N N N N N N N N N

Continued from Sheet No. D-25.40 DETERMINATION OF DEMAND The customer demand in kilowatts shall be the highest single 15 minute integrated load observed or recorded during the current or preceding 11 months. For new Cp-U customers, this demand provision applies on and after the date of transfer to this rate schedule. The on-peak billing demand in kilowatts shall be the highest single 15 minute integrated load observed or recorded during each respective time period in the month, provided that no billing demand shall be less than 60% of the highest billing demand of the preceding 11 months and, in no case, less than 200 Kw. Unusual on-peak billing demands approved by advance authority from the company shall be billed but will not be considered in the determination of the 60% ratchet. Customer requests for unusual demands shall be made in advance with as much allowance as possible. The advance authorization from the company shall be confirmed in writing. HOLIDAYS The days of the year which are considered holidays are: New Year's Day, Memorial Day, Fourth of July, Labor Day, Thanksgiving Day and Christmas Day. ESTIMATION PROCEDURE In the event of loss of data for calculation of one or more billing parameters, the company shall forecast on the basis of historic billing parameters to obtain an estimate of current month's billing parameters. This estimate shall be subject to modification or replacement based on known and quantifiable operating conditions of the current month.

Issued: 12-21-09 Effective for Service By J F Schott On and After: 1-1-10 VP Regulatory Affairs Issued Under Auth. of Green Bay, Wisconsin Mich Public Serv Comm



Filed _______________

December 29, 2009



Page 46 of 81

Appendix B – Conceptual Model Tariff



Page 47 of 81

Conceptual Model Standby Rate Tariff (DRAFT 10/14/16)

Monthly Customer

Charge

●Zero, assuming this is already included in the customer’s supplemental power tariff (Based on administrative costs)

AND

●Charge or Credit to reflect greater or lesser administrative costs associated with partial use customer.

Monthly Reservation

Fee

●Zero (instead recover in demand charge)

OR

●Fixed fee to recover utility’s embedded costs for generation capacity (or capacity market purchases) and transmission

based on FOR of best performing CHP systems

On-Peak Daily, Daily or Hourly Demand Charge

Scheduled

●Zero

OR

●Low variable demand charge proportionate to hours of planned usage reflecting utility’s lower costs due to planning at

times that impose zero or low cost to utility.

AND

●Reduced (or zero) variable demand charge for off-peak usage to reflect utility’s lower costs during off-peak hours.

Unscheduled

●If no Reservation Fee, variable demand charge designed to recover proportion of utility’s embedded costs for generation

capacity (or capacity market purchases) and transmission based on CHP partial-use customer’s hours of unscheduled

use.

OR

●If a fixed Reservation Fee is also charged, variable demand charge designed to recover utility’s embedded costs for



Page 48 of 81

generation capacity (or capacity market purchases) and transmission based on CHP partial use customer’s proportionate

use above FOR assumed in Reservation Fee

AND

●Reduced (or zero) variable demand charge for off-peak usage to reflect utility’s lower costs during off-peak hours.

Energy Charge

● If no Reservation Fee and Demand Charge, recover proportion of utility’s embedded costs for generation capacity (or

capacity market purchases) and transmission in energy charges based on CHP partial-use customer’s hours of use.

●Pricing should reflect utility’s lower costs for scheduled usage and off-peak usage.

OR

●If embedded generation capacity (or capacity market purchases) and transmission are recovered in Reservation Fee

and/or Demand Charge, energy pricing should reflect utility’ s average fuel and purchased energy costs (or utility’s spot

energy market purchases in the case of capacity market purchases).

AND

●Pricing should reflect peak and off-peak energy prices or real time energy prices.

Notes:

1. On-Peak Daily, Daily and Hourly demand billing units should be calculated as the customer’s demand in excess of its supplemental

service demand billing units. For example, assume a customer has a 50 MW generator and 50 MW of supplemental demand. If the

customer in a given hour has a 25 MW generation derate, but its supplemental demand is simultaneously down by 25 MW such that

the customer’s net demand is still below 50 MW, the standby demand for that customer for that hour should be zero.

2. Delivery (i.e., distribution) service charges for standby service should generally be the same for standby service as they are for

supplemental service (including any credits for a customer ownership of their own substation). However, where there are distribution

networks whose costs are driven by the peak demand on that network rather than the non-coincident peak demand of individual

customers, consideration should be given to the expected contribution of the standby service to the peak demand placed on that

distribution network.



Page 49 of 81

Appendix C: Standby Service Rate Comparison

Scenario 1: No Generator Outage Consumers DTE UMERC UPPCO

Service Charge 200 275 0 0 Delivery Capacity/Distribution

Charge 8,100 6,760 0 0

Reservation Fee 0 3,500 0 0 Demand Charges 0 0 0 0 Energy Charges 0 0 0 0

TOTAL 8,300 10,535 0 0 Scenario 2: Scheduled Generator Outage 16 hours off-peak

Consumers DTE UMERC UPPCO Service Charge 200 275 0 0

Delivery Capacity/Distribution Charge

8,100 6,760 0 0

Reservation Fee 0 3,500 0 0 Demand Charges 0 0 1,182 1,106

Energy Charges21 946 1,122 1,036 1,805 TOTAL 9,246 11,657 2,218 2,911

Scenario 3: Scheduled Generator Outage 16 hours on-peak



8,100 6,760 0 0

Reservation Fee 0 0 0 0 Demand Charges 2,232 10,400 1,182 1,106

Energy Charges 1,113 1,218 1,916 2,777 TOTAL 11,645 18,653 3,098 3,883

Scenario 4: Scheduled Generator Outage 8 hours on-peak, 8 hours off-peak



8,100 6,760 0 0

Reservation Fee 0 0 0 0 Demand Charges 1,116 5,200 1,182 1,106 Energy Charges 1,775 1,170 1,476 2,291

TOTAL 11,191 13,405 2,658 3,397

21 Energy charges calculations for Consumers provided by Consumers.



Page 50 of 81

Scenario 5: Scheduled Generator Outage 32 hours on-peak



8,100 6,760 0 0


TOTAL 14,833 30,272 6,196 7,766 Scenario 6: Unscheduled Outage 8 hours on-peak, 8 hours off-peak



8,100 6,760 0 0


TOTAL 11,191 17,545 30,536 31,631



Page 51 of 81

Appendix D-Comments



Page 52 of 81

AK Steel Corporation Chairperson: Jennifer Steiner Burner,Arconic Inc. Marathon Petroleum Corporation

CargillCorrigan Oil Co.

(419) [email protected]

The Dow Chemical CompanyEaton Corporation Executive Director: Rod WilliamsonEdw. C. Levy Co. Clark Hill PLC

Enbridge Energy Limited Partnership (910) 444-8883FCA US LLC [email protected]

General Motors LLCGerdau Macsteel

J. Rettenmaier USA LP Legal Counsel:Marathon Petroleum Corporation Michael J. Pattwell & Sean P. Gallagher

Martin Marietta Magnesia Specialties Clark Hill PLCMetal Technologies, Inc. 212 East Grand River Avenue

MPI Research Lansing, MI 48906-4328Occidental Chemical Corporation

Pfizer - Kalamazoo(517) 318-3100

[email protected], Inc.

United States [email protected]

WestRockWhite Pigeon Paper

215853014.2 07411/195499

ASSOCIATION OF BUSINESSESADVOCATING TARIFF EQUITY

June 2, 2017

Julie BaldwinManagerRenewable Energy SectionElectric Reliability DivisionMichigan Public Service Commission

Re: Michigan Public Service Commission Standby Rate Working Group

Dear Ms. Baldwin:

On behalf of the Association of Businesses Advocating Tariff Equity (“ABATE”), wewish to thank the Michigan Public Service Commission Staff (“Staff”) for providing anopportunity for stakeholders to provide comments on its May 2017 draft Standby WorkingGroup Supplemental Report (“Draft Supplemental Report”).

In general, ABATE believes the Staff has done a good job in summarizing the viewsexpressed by stakeholders during the discussions of the Standby Working Group and in thecomments submitted by stakeholders. However, ABATE believes the report would benefitfrom additional detail being provided on certain issues raised by ABATE that were captured insummary form in the Draft Supplemental Report. To this end, we have attached to thesecomments our comments from March 17, 2017, and ask that they be included in the appendixof the final version of the Staff’s Standby Rate Working Group Supplemental Report.



Page 53 of 81

Julie BaldwinJune 2, 2017Page 2

215853014.2 07411/195499

With one modification, ABATE supports the seven recommendations that the Staff hasincluded in the Draft Supplemental Report. In particular, ABATE is very pleased withRecommendation No. 3, which calls for standby capacity and delivery demand charges to bebased on net load for customers taking both supplemental and standby service. Implementingthis recommendation will help eliminate the possibility of over-recovery of capacity anddelivery service costs from these customers.

The one modification ABATE proposes to the recommendations is with respect toRecommendation No. 1. Specifically, Recommendation No.1 calls for improving standbyservice tariff transparency by having the utilities work with Staff. ABATE believes that utilitiesshould be required to work with stakeholders as well as Staff. This would ensure input is beingprovided by those who utilize, or would utilize, the standby service tariffs, in addition to Staff.To address this, ABATE proposes that Staff modify Recommendation No.1 as follows:

1. To assist with standby service tariff transparency, a clear and concise

description of the tariff structure and each term used should be

included. Utilities should work with staff and stakeholders to ensure a

good understanding of 1) the standby service tariff; 2) information

available on the company’s website; and 3) the company’s preferred

process for developers and customers to get standby service questions

answered.

As a final note, while ABATE believes the Draft Supplemental Report provides a goodreview of the standby service tariffs of Michigan’s largest utilities to ensure equitable revenueallocation and rates that are correlated to cost of service, transparent, and designed to send aclear price signal for the most efficient interface between utility and customer resources, wenote that the Draft Supplemental Report does not directly achieve these results. The DraftSupplemental Report leaves many outstanding issues for resolution in the current andforthcoming general rate proceedings of the utilities. As a result, the work will not becomplete until those issues are reasonably resolved in those proceedings. It is very importantfor that work to be completed in order to ensure customer generation is not an underutilizedresource in Michigan.

ABATE appreciates the opportunity it had to both provide these comments and toparticipate in the Standby Rate Working Group. We look forward to the opportunity toparticipate in the current and forthcoming general rate proceedings of the utilities in order toensure the standby service tariffs of Michigan’s utilities provide equitable revenue allocationand rates that are correlated to cost of service, transparent, and designed to send a clear pricesignal for the most efficient interface between utility and customer resources. If you have anyquestions regarding our comments, please do not hesitate to reach out to our consultant, JimDauphinais at either (636) 898-6725 or [email protected].



Page 54 of 81



Julie BaldwinJune 2, 2017Page 3

215853014.2 07411/195499

Thank you.

Rod WilliamsonExecutive Director of ABATE

Attachment: March 17, 2017 Comments of ABATE re: Standby Rate Working Group

cc: Jim DauphinaisSean Gallagher



Page 55 of 81

Attachment to June 2, 2017 ABATE Comments

MPSC Standby Rate Working Group:

March 17, 2017 ABATE Comments



Page 56 of 81

AK Steel Corporation Chairperson: Jennifer Steiner Burner,Arconic Inc. Marathon Petroleum Corporation

CargillCorrigan Oil Co.

(419) [email protected]

The Dow Chemical CompanyEaton Corporation Executive Director: Rod WilliamsonEdw. C. Levy Co. REW Energy Consulting

Enbridge Energy Limited Partnership (910) 444-8883FCA US LLC [email protected]

General Motors CompanyGerdau Macsteel

J. Rettenmaier USA LP Legal Counsel:Marathon Petroleum Corporation Michael J. Pattwell & Sean P. Gallagher

Martin Marietta Magnesia Specialties Clark Hill PLCMetal Technologies, Inc. 212 East Grand River Avenue

MPI Research Lansing, MI 48906-4328Occidental Chemical Corporation (517) 318-3100

Praxair, Inc. [email protected] States Gypsum [email protected]

WestRockWhite Pigeon Paper

205575818.2 07411/195499

ASSOCIATION OF BUSINESSESADVOCATING TARIFF EQUITY

March 17, 2017

Julie BaldwinManagerRenewable Energy SectionElectric Reliability DivisionMichigan Public Service Commission

Re: Michigan Public Service Commission Standby Rate Working Group

Dear Ms. Baldwin:

We wish to thank the Michigan Public Service Commission Staff (“Staff”) for providing anopportunity for stakeholders to provide comments prior to Staff drafting its Standby Rate WorkingGroup report. Today, in concert with many other global manufacturers with operations, employees andcustomers in Michigan, the Association of Businesses Advocating Tariff Equity (“ABATE”), on behalfof its members, has participated in a joint letter to Chairman Talberg emphasizing the need to ensurestandby service rates in Michigan are fair and reasonable. As stated in the letter to Chairman Talberg, itis important that the standby service tariffs of Michigan’s utilities be reviewed to ensure equitablerevenue allocation and rates that are correlated to cost of service. In addition, these rates should betransparent and designed to send a clear price signal for the most efficient interface between utility andcustomers resources.

To this end, we today offer the following additional comments with respect to accomplishingthe outcome outlined above. These comments may be publicly shared and we ask that the Staff postthem on the webpage for the Standby Rate Working Group.



Page 57 of 81

Julie BaldwinMarch 17, 2017Page 2

205575818.2 07411/195499

Separate Rate Class

Standby service customers should be placed in their own separate rate class recognizing thevery low load and coincidence factors of these customers as a whole. For example, data provided byConsumers Energy Company and DTE Electric Company indicated that, as a whole, existing standbyservice customers have load and coincidence factors in the neighborhood of 20% -- much lower than forany other group of customers.

In addition, to the extent the utility’s own generation is providing this service and there issufficient normalized data available, revenue should be allocated to this class of customers consistentwith a reasonably performed class cost of service study. If there is not sufficient normalized dataavailable, reasonable proxy data may need to be utilized for the class. This may in particular benecessary when a standby service rate is first being introduced (since there would be no existingstandby service customers) or when it is expected there will be a large expansion of the use of the rateand that expansion is expected to change the characteristics of the class as a whole. In the case where autility is providing standby service from the wholesale market, the basis of the revenue requirement forthe rate should be based on the cost of the utility to purchase capacity in the market.

Reservation Charges

Reservation charges are monthly demand charges for generation capacity and transmission(“Power Supply”) usually applied to a customer’s contracted standby service demand (“ReservationCharges”). In general, we do not support the use of Reservation Charges and instead support recoveryof the Power Supply costs through daily, or daily on-peak, demand charges applied to a customer’sactual daily, or daily on-peak, standby service demand. This sends an important price signal for thecustomer to minimize its draw of standby service demand. This said, if a Reservation Charge is used forPower Supply, it should be based on no more than the equivalent of a single day’s daily, or daily on-peak, demand charge for the rate and daily, or daily on-peak, demand charges should be waived for thefirst day of outage for a customers during a given month. Reservation Charges based on multiple daysof outages should be avoided. For example, one of the Michigan utilities currently has a ReservationCharge which collects revenues equal to that of approximately 12% of the full service monthly demandcharge of that same utility. Essentially, the utility is requiring its standby service customers to pay for aminimum of 2.4 on-peak days of standby service even if the customer does not draw any standbyservice in that month. This eliminates any price signal there might be for the customer to minimize itsuse of standby service below 2 days of on-peak standby service. It also requires members of the standbyservice class with better performance to subsidize those with poorer performance. Again, we believe itis best not to use a Reservation Charge at all, but if one is used, it should be based on no more than oneday’s, or one on-peak days, worth of daily, or on-peak daily, demand charges.

Daily, or On-Peak Daily, Standby Service Demand Charges

As we have noted, we believe Power Supply costs for the provision of standby service are bestrecovered through the use of daily, or on-peak daily, demand charges. To be consistent with theprinciples of FERC PURPA rules for standby service (18 CFR Ch. I, § 292.305 (c)) and the principlesof good rate design, these demand charges need to be designed in such a fashion as they do not assumethat forced outages or other reductions in electric output by all customer generation on an electricutility's system will occur simultaneously, or during the system peak, or both. In addition, the standby



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service demand charges should take into account the extent to which scheduled outages of customergeneration can be usefully coordinated with scheduled outages of the utility's facilities. To this end, webelieve the best practice is to use a flat prorated daily, or on-peak daily, demand charge for unscheduledoutages and a daily, or daily on-peak, demand charge of no greater than 50% of this amount forscheduled outages that have been coordinated with the customer’s utility. This rate design appliescharges to customers in proportion to their likelihood of drawing standby service for an unscheduledoutage at the time of the system peak and sends a price signal to customers to minimize their draw ofstandby service regardless of the amount of standby service they have already drawn in a given month.It also assures standby service customers with better performing generation are not subsiding standbyservice customers with poorer performing generation.

If a utility’s Power Supply revenue requirement has been reasonably allocated to the standbyservice class, the daily or on-peak daily demand charge for unscheduled outages should be very close to3.3% and 5%, respectively, of the monthly Power Supply demand charge for the full service rate thecustomers would have used if it did not have its own generation.1 In the case of a utility using thewholesale market to provide standby service, the daily or on-peak daily demand charge for unscheduledoutages should be set at 3.3% or 5%, respectively, of the utility’s market cost for capacity andtransmission. In both cases, the daily or daily on-peak demand charge for scheduled outagescoordinated with the customers’ utility should no more than 50% of the daily or daily on-peak demandcharge for unscheduled outages as the coordination of these outages with the customer’s utility shouldensure they have little to no effect on a utility’s total need for generation capacity and transmissionfacilities.

Another important consideration for standby service is the basis of daily, or on-peak daily,demand. In many cases, a customer is taking both standby service under a standby service tariff andsupplemental service under a full service tariff. In these situations, it is important that the interactionbetween the two rates not lead to the over-recovery of costs by the utility. One major way in whichover-recovery can occur is with respect to the determination of a customer’s daily, or on-peak daily,demand. Specifically, it is important that when a customer’s daily, or on-peak daily, demand isdetermined that it account for the amount of supplemental service the customer is taking at the time. Forexample, if the monthly supplemental service demand of the customer is 20,000 kW and the customer’stotal demand at the time of an outage of its 5,000 kW generator is only 20,000 kW, the customer’s

1A daily demand charge should be designed to collect revenue in proportion to the number of days of

standby service is actually taken. Thus, if standby service is taken for all the days of the month, there

should be little difference between the full service demand charge and the total demand charges

collected for standby service from that customer for that month. However, if standby service is taken by

a customer for only a single day of that month, the demand charge should be proportionally reduced to

1/30th or 3.3% of the full service monthly demand charge reflecting that there are typically 30 days in a

month. This can be accomplished by using a daily demand charge that is approximately equal to 3.3%

of the full service monthly demand charge. Such a demand charge provides a price signal to the

customer to minimize the amount of standby service taken over the course of a given month regardless

of the amount standby service the customer has already taken during that same month. When daily on-

peak demand charges are used, the same effect can be accomplished by using a daily on-peak demand

charge equal to approximately 1/20th or 5% of the full service monthly demand charge consistent with

there be typically being 20 on-peak days in a month.



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daily, or on-peak daily standby service demand, should be zero, not 5,000 kW. The reason for this isthat the customer is already paying supplemental service monthly power supply charge to the utility for20,000 kW of demand. The outage of the customer’s generation did not create any additional need forcapacity for the utility, since the customer’s supplemental demand during the time of the generationoutage was down from its monthly peak value by an amount more than sufficient to cover for theoutage of the customer’s generation. If the utility were permitted to assess a daily, or on-peak daily,standby service demand charge of 5,000 kW for this generation outage, the utility would recover thecost for that 5,000 kW of power supply twice – once through the supplemental service rate monthlydemand charges and again through the standby service rate.

Delivery Service Demand

It is also important to avoid a possibility of over-recovery of delivery service charges when acustomer is taking both standby service and supplemental service. For the supplemental service, thecustomer will be paying a delivery service demand charge for the highest supplemental service demandduring the month. To this end, delivery service demand charges should only be assessed on the basis ofthe largest net demand the customer places on the system. This can be accomplished if daily, or dailyon-peak, standby delivery service demand is determined in the manner outlined above.

Customer Charges

Another area of potential over-recovery is with respect to customer charges. A customer takingboth standby service and supplemental service should not be required to pay the same customer chargetwice. It should only pay a customer charge for supplemental service. If there is a customer charge forstandby service, it should only recover the true incremental customer-related costs that the utility toincurs provide standbys service to the customer in addition to supplemental service, to avoid over-recovery.

Existing Consumers Energy Company and DTE Electric Company Standby Service Rates

Consumers Energy Company’s (“Consumers”) current Rate GSG-2 standby service rate isgenerally consistent with many of the principles discussed above in that it does not includedReservation Charges and uses daily on-peak demand charges that are based on an on-peak day prorationof Consumers’ highest monthly market cost of capacity. However, it is still not clear at this timewhether Consumers calculates a customer’s standby service demand in consideration of the amountsupplemental service the customer is also taking. As we have discussed above, when a customer’sgeneration is having an outage or has otherwise had a reduction in output, its daily on-peak standbyservice demand should only be equal to the amount of its total demand that is in excess of its monthlysupplemental service demand. In addition, Consumers’ current standby service rate does not includeprovisions for lower daily on-peak demand charges for scheduled customer generation outages that arecoordinated with Consumers. As noted above, daily on-peak demand charges for schedules outagesshould be set at 50% or less of the daily on-peak demand charge for unscheduled outages because thecoordination of these outages with Consumers should ensure they have little to no effect on a utility’stotal need for generation capacity and transmission facilities.



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Unlike with Consumers, DTE Electric Company’s (“DTE”) current Rider 3 standbys servicerate is generally inconsistent with many of the rate design principles discussed above. It includes aReservation Charge which is currently set at approximately 12% of the full-service rate’s Power Supplymonthly demand charge. As discussed, a properly designed standby rate should not have such a chargeat all, or it should at least be limited to the equivalent of one on-peak day per month (i.e., 5% instead of12%). In light of the principles discussed above, we find it more troubling that the current daily on-peakstandby demand charge for Rider 3 is set at approximately 31.9% of the full-service rate’s PowerSupply demand charge. This is level of charge is extreme when compared with the 5% that would resultfrom an on-peak day proration of the full-service rate’s monthly demand charge. During the StandbyRate Working Group discussion, it became apparent that the underlying cause of the problems withDTE’s Rider 3 may be related to a very dated allocation of DTE’s revenue requirement to Rider 3customers. In particular, rather than treating standby service customers as a separate rate class in itsclass cost of service studies, DTE was assigning a percentage of the revenue requirement assigned toRate D11 to Rider 3 based on assumptions that are many years old. We are hopeful that modeling Rider3 customers as a separate rate class in future class cost of service studies will largely address theforgoing issues. However, other adjustments may also ultimately be needed with respect to the designof the Reservation Charge and daily on-peak demand charges for Rider 3 in order to make themreasonable.

DTE’s Rider 3 does consider monthly supplemental service demand when determining acustomer’s daily on-peak standby service demand. In addition, Rider 3 also includes lower daily on-peak demand charges for maintenance outages. However, neither of these provisions mitigates theserious problem that currently exists with the magnitude of the Rider 3 Reservation Charge and dailyon-peak demand charges.

ABATE appreciates the opportunity it had to both provide these pre-report comments and toparticipate in the Standby Rate Working Group. We look forward to the opportunity to providecomments on the Staff’s draft report upon its release. If you have any questions regarding ourcomments, please do not hesitate to reach out to our consultant, Jim Dauphinais at either (636) 898-6725 or [email protected].

Thank you.

Rod WilliamsonExecutive Director of ABATE

cc: Jim DauphinaisSean Gallagher



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Baldwin, Julie (LARA)

From: Jessica M. Woycehoski <[email protected]>Sent: Tuesday, June 06, 2017 3:49 PMTo: Baldwin, Julie (LARA)Cc: Stephen P. Stubleski; JOSNELLY C APONTESubject: Draft Standby Rate Working Group Report

Hi Julie, Sorry for the delay in getting comments to you on this report. Our comments are as follows:

The report does a good job at explaining the various components of standby rates – which they do through explanation of the DTE and Consumer’s standby tariffs. Overall the report is balanced and represents the view of the participants.

The rate comparisons to UMERC and UPPCO included emphasizes the vast difference in standby charges, but we wouldn’t want to characterize those tariffs as being more appropriate because they charge lower standby charges for minimal outages – that isn’t necessarily reflective of cost‐based service.

The Concept Model Standby Rate Tariff (draft) provided by MCA should be identified as such, so others do not view it as a consensus document nor take it as Staff’s recommendations (which it does not represent). Some of the recommendations in that concept draft are counter to cost‐based ratemaking.

The solar standby tariff (#7) recommendation was a surprise. No major disagreement with it, but more time is needed to consider this recommendation.

Please let me know if you would like to discuss further with the team or have questions or comments. Thank you. Jessica Woycehoski Energy Resources - Client Liaison Rates & Regulatory Affairs O: 517-393-2465| C: 517-315-7365 WORKING TO DELIVER THE ENERGY YOU NEED, WHENEVER YOU NEED IT. THAT’S OUR PROMISE TO MICHIGAN!



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June 6, 2017 Ms. Julie Baldwin Electric Reliability Division Michigan Public Service Commission 7109 West Saginaw Highway Lansing, MI 48917 RE: DTE Electric Company Comments on the Standby Rate Working

Group Supplemental Report The purpose of Standby Rate Work Group (SRWG) Supplemental Report is to address the additional work performed by the SRWG which was primarily focused on evaluating standby service for Combined Heat and Power (CHP) applications. The original report issued on August 19, 2016, was more focused on evaluating standby service for renewable generation applications. The Michigan Public Commission (MPSC) Staff once again did a commendable job in organizing the sessions and providing all parties opportunities to make presentations and provide comments throughout the meetings. DTE Electric Company (DTE or Company) believes the additional SRWG meetings examining the standby service requirements for CHP projects provided benefits to all members of the SRWG. DTE is supportive of economic distributed generation resources and has appreciated the opportunity to further explain its current standby tariff, as well as participate in discussions of other proposals. The Company provides the following comments (in bold) with respect to Staff’s seven recommendations provided in the SRWG Supplemental Report.

1) To assist with standby service tariff transparency, a clear and concise description of the tariff structure and each term used should be included. Utilities should work with staff to ensure a good understanding of 1) the standby service tariff; 2) information available on the company’s website; and 3) the company’s preferred process for developers and customers to get standby service questions answered.

DTE supports this recommendation. In its current general rate case filing (Case No. U-18255), DTE has proposed adding additional definitions and explanation in its Standby Service Tariff Rider No. 3. In addition, DTE will

DTE Electric Company One Energy Plaza Detroit, MI 48226-1279



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be providing a guide to understanding standby service including the process for requesting standby service on the Company’s website later in 2017.

2) Table 1 highlights the inconsistency in standby service tariffs across the state. Staff recommends that the Commission develop a standardized framework for standby service tariffs where possible. Staff recognizes there may be reason to deviate from the standard. Any differences should be justified and supported by the company.

DTE supports using a standardized framework for standby service tariffs which are consistent with the guiding principles and standby services outlined in PURPA and that follow cost of service principles.

3) For customers taking both supplemental and standby service, the standby service tariff should be structured to allow the standby capacity and delivery demand charges to be based on net load.

The Company is not clear on what is meant by “net load” in this recommendation. However, DTE does support that standby tariffs should be structured to recognize the demand interactions between supplemental and standby service.

4) Standby service tariffs, including the monthly customer charges, should be

reviewed and, if necessary, updated in each utility’s rate case to ensure they are based on the most up-to-date cost of service principles. Daily capacity demand charges and the use of generator reservation fees and how the fee relates to the daily demand charge/pro-rated daily demand charges should be considered and discussed by the parties.

The Company is not clear who this recommendation is directed to. However, the Company supports the rights of any party to recommend or challenge components of standby rates in general rate case proceedings.

5) Standby service tariffs should include a reasonable capacity price differential to encourage scheduled maintenance, which in turn may reduce unscheduled outages. Limiting options to only off-peak time periods may not result in least cost to the utility.

DTE supports capacity price differentials related to scheduled maintenance. DTE’s standby service tariff currently provides a lower price capacity rate for schedule maintenance during on-peak periods.



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6) Time of use charges for capacity and energy should be an available option for standby service customers

The Company opposes this recommendation. DTE’s standby service tariff currently provides an on-peak demand charge and separate on-peak and off-peak energy charges. The Company does not currently offer hourly capacity pricing on any of its tariff offerings and does not assign capacity costs on an hourly basis in its cost of service modeling.

7) The method for determining the solar standby tariff billing criteria should be made

clear on the tariff. Customers with solar generators should have the option to stay on their supplemental service rate schedule provided it has a demand charge for delivery services. A time of use charge for capacity and energy should be considered for these customers.

As stated in response to recommendation #6, DTE opposes using a time of use capacity charge as it is inconsistent with current cost allocation principles. Given the unique nature of solar as a distributed generation resource, the Company’s current tariff allows for standby contract capacity to be set based upon mutual agreement in order to meet the customer’s standby load.

Other Comments With respect to comments made at the SRWG regarding a separate cost of service class for standby, DTE expressed the concerns with creating a separate cost of service class for standby service to the SRWG and in its filed testimony in Case U-18255. Creating a separate cost of service class for Rider 3 presents several cost of service concerns in addition to those mentioned in the Supplement report. Fundamentally, assigning power supply costs based on 4CP to a standby cost of service (COS) class where loads can be very irregular and can vary significantly at any point in time compared to normal loads, does not follow proper cost allocation principles. This is especially true in a small class, where generation size various greatly and when one customer can influence the outcome of the entire class. In addition, the cost allocation process cannot be relied on to accurately assign costs to such a small class. Rider 3 revenues represent less than a quarter of 1 percent (0.25%) of the company’s revenues. Currently, the Company’s smallest COS class is 4 times larger than Rider 3. It is also appropriate to maintain Rider 3 in the D11 and Other COS class since the majority of standby service is provided to customers taking supplemental service on D11 and keeping the cost responsibility within the D11 and Other COS class thereby limits cross subsidies to other rate classes. Finally, there are power supply demand charge interactions between standby service and supplemental service that support keeping both Rider 3 and D11 in the same COS class In the Supplement report, a statement is made regarding cost of service for the D11 / R3 class. The report claims that 99% of the cost of service is assigned to D11 and 1% is assigned to Rider 3. Although accurate from a mathematical standpoint, this is not how DTE assigns costs to Rider 3. First, costs in the D11 and Other Class are only power supply related costs and, second, Rider 3 costs are not assigned based on 1% of the D11 and Other costs. Power supply costs are allocated to each rate in the D11 and Other cost of service



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class based on each rates present revenues. This cost allocation method is not unique to Rider 3. This is the same method used to assign costs for any cost of service class with more than one rate product, such as D1 and Other class and the D3 and Other class. Summary As a result of the SRWG, there has been an increased common understanding of Standby service concepts and Standby rate design. This would not have been accomplished but for the efforts of the SRWG. The Company also learned through these meetings that it can improve upon the language contained in its Standby tariff, and more transparency may be needed with respect to Standby rate calculations. The Company is always open to suggestions from its customers and the MPSC Staff on how to enhance communication and enable our tariffs to be better understood, and thus will initiate efforts as listed above in both its tariff and on its website. Any suggestions by parties to change DTE Electric’s Standby cost of service or rate design should be considered in the context of cost based rate making so that a specific small group of customers do not receive preferential treatment or subsidies at the expense of the larger customer base (or general population). Sincerely, Philip W. Dennis Manager, Regulatory Economics DTE Electric Company One Energy Plaza. Detroit 48226 [email protected]



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June 2, 2017 [email protected] Julie Baldwin, Manager Renewable Energy Section Electric Reliability Division Michigan Public Service Commission Re: PSC Standby Rate Working Group – Combined Heat & Power

Midwest Cogeneration Association and the Great Plains Institute Comments on May 2017 Standby Rate Working Group Supplemental Report MPSC Case No. U-17735

Dear Ms. Baldwin: The Midwest Cogeneration Association (MCA) and the Great Plains Institute (GPI) appreciate this opportunity to comment on the Michigan Public Service Commission (“Commission”) Staff’s May 2017 Standby Rate Working Group Supplemental Report (“Staff Report”) in this proceeding. As you know, MCA and its partner GPI, together with GPI’s consultant 5 Lakes Energy, were active participants in the Standby Rate Working Group (“SRWG”) in 2016 and 2017, submitting presentations, written comments and analysis on the issues discussed in the Report. We commend the Commission for providing this informal forum for an in-depth discussion of standby rate tariff structure. We appreciate the comments and information shared by the Staff, utility representatives, and other participants in the course of the SRWG’s proceedings. We believe the process resulted in an open discussion and greater appreciation of the issues faced by both standby customers and the utilities serving those customers. The Commission’s leadership in providing this forum is a model for the rest of the country. We commend the Staff Report for generally capturing very well the issues, discussion, and positions of various participants in the SRWG. We believe the Report is well-organized and articulates the major issues involved in establishing fair standby tariffs. The following are our overall comments and some further suggestions for finalizing the Staff Report to fully reflect the MCA and GPI positions.



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1. Overarching Goal We concur with the Report’s statement that the “overarching goal of the SRWG is to ensure that any resulting standby service tariffs are based on the cost to serve self-generation standby customers and to increase transparency of the tariffs.” (Report p.1) We believe there was general agreement on these goals. 2. Organization of the Report The Report properly reflects the SRWG’s identification of cost-of-service and rate design as distinct elements for review. It also properly reflects the key elements of rate design for standby tariffs that were discussed by the SRWG, and appropriately emphasizes the importance that standby charges be transparent to the customer. 3. Cost of Service A. Separate Rate Class Issue The Report reflects the SRWG discussion of whether standby customers should be placed in a separate rate class. The Report notes that the Commission’s January 31, 2017 Orders in U-18014 for DTE and in U-17990 for Consumers require the utilities to perform separate cost of service analyses for standby customers in their next rate cases. Report p. 6. The Report makes the point that the Commission’s Orders in those cases do not necessarily mean that standby customers should be in a separate rate class for rate design. The Report mentions: “Several SRWG participants commented that standby service customers should be placed in their own separate class so that the load and capacity and energy coincidence factors can be recognized and factored into the rates.” Report p. 6. Comment: MCA/GPI support the Commission’s Orders requiring separate cost of service studies for standby customers and agree with the Report’s conclusion that “Establishing that the costs allocated to standby customers are cost of service-based will build the foundation for developing an effective rate design and standby service tariff.” Report, p. 6 We believe DTE and Consumers should provide standby service cost of service studies in the new pending rate proceedings, U-18255 and U-18322. MCA/GPI believe separate cost of service studies for standby customers is critical, particularly for base-load non-intermittent standby customers such as cogeneration customers, and that the assumptions underlying that analysis must be examined and supported with utility data. B. Cost of Service Assumptions Affecting Rate Design



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Comment: The Report touches on the SRWG’s discussion of the cost-causation assumptions underlying some elements of DTE’s and Consumer’s current standby tariffs in the section titled “Standby Service Tariff Fairness,” at p. 18. We offer the paragraphs below as an addition to the Report summarizing the other SRWG participants’ different views on standby customer cost causation:

“A key cost of service issue and related rate design issue for standby tariffs is whether standby rate customers impose the same capacity and delivery costs on a utility as does a full-service customer. In the SRWG proceedings, the utilities took the position that they are required to maintain firm power and delivery capacity equivalent to a standby customer’s load at all times because a forced outage may occur at any time.

“However, PURPA provides:

“The rate for sales of back-up power or maintenance power:(1) Shall not be based upon an assumption (unless supported by factual data) that forced outages or other reductions in electric output by all qualifying facilities on an electric utility's system will occur simultaneously, or during the system peak, or both. 18 CFR § 292.305(c)(1) “MCA/GPI and ABATE took the position that the utilities’ assumption that they are required to maintain excess capacity for standby customers is unsupported, especially for non-intermittent baseload standby customers, such as cogeneration customers, because of the low rate of forced outages experienced by those customers (5%), the corresponding demand taken off the grid the remainder of the time (95%), and the diversity of cogeneration and other customer load and demand in the utilities’ customer base. MCA/GPI provided the SRWG with a 2004 study performed by Oak Ridge National Labs on the operational reliability of 125 cogeneration systems, including a variety of cogeneration technologies, which found a forced outage rate (FOR) of approximately 5%, with half of the outages (2.5%) occurring during peak periods. “To examine whether the utilities’ assumption was true, MCA/GPI and 5 Lakes Energy requested that DTE and Consumers provide customer data, without customer identification, allowing a determination of the coincidence of customer demand on the utilities’ capacity and delivery resources. The utilities declined to provide that data due to privacy concerns and the small number of customers in their territories currently utilizing their standby tariffs. To address this absence of data, MCA/ GPI asked 5 Lakes Energy to undertake an analysis of typical cogeneration customer standby service coincidence utilizing the continuous operating data collected by the New York State Energy Development Agency (NYSERDA) in its unique, long-standing cogeneration database. 5 Lakes



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https://www.law.cornell.edu/definitions/index.php?width=840&height=800&iframe=true&def_id=b91d01788d722ff730293f7963698114&term_occur=2&term_src=Title:18:Chapter:I:Subchapter:K:Part:292:Subpart:C:292.305

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Energy based its study on nineteen cogeneration facility customers in the New York ConEd territory for which the NYSERDA database had two years of continuous operating data (8760 hrs), including those customers’ usage of the ConEd standby service during that period. 5 Lakes Energy presented its study to the SRWG, including its findings on demand coincidence and recommendations for billing determinant accuracy. One of the key findings of the 5 Lakes NYSERDA analysis was that the standby users’ demand variation was inconsequential based on ConEd’s overall load diversity. 5 Lakes’ recommendation from that data was that “No distinction between standby and supplemental power appears warranted.”

“SRWG participants discussed 5 Lakes Energy’s analysis, but did not reach consensus on this issue. This is a subject which should be addressed in the new rate cases.”

4. Rate Design A. Customer Charge The Report notes that a customer’s normal rate schedule will include a monthly customer charge and also notes that Consumers’ standby tariff has an additional customer charge, while DTE’s does not. The Staff recommends that standby customer charges be reviewed by interested parties in the next rate case. Comment: MCA/GPI’s position, as indicated in our best practices “model tariff” proposal presented to the SRWG and our written comments, is that standby riders should not include customer charges which are duplicative. However, an additional standby customer charge may be justified based on any additional administrative costs incurred by a utility as a result of the customer’s standby service. We concur that this is a subject which should be addressed in the new rate cases. B. Generation Reservation Fee The Report notes the rationale for a generation reservation fee is “to compensate the utility for the capacity that the utility must have available to serve a customer during an unscheduled outage of the customer’s self-generation unit.” The report then discusses the various parties positions on reservation fees ranging from no reservation fee to a fixed fee based on nameplate capacity times 12%, and the price signals sent by each approach for efficient cogeneration system operation. Comment: MCA/GPI believe our position on this important point is not fully explained in the Staff Report. We offer the paragraphs below as an addition to the Report summarizing MCA/GPI’s position:



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“MCA and GPI take the position that reservation fees are a poor mechanism for recovering a utility’s generation capacity costs which can more accurately and transparently be recovered in a daily, ‘as used’ generation demand charge. They point out the poor relationship between reservation fees and utility costs as demonstrated by the 5 Lakes Energy statistical analysis of billing determinants presented to the SRWG. The 5 Lakes Energy NYSERDA analysis indicates no excess capacity is required to be maintained for standby customers. MCA/GPI believe a utility capacity cost for ‘standing ready’ must be cost justified by the utility in the pending rate cases. “MCA/GPI further note that DTE’s reservation fee formula results in a minimum charge to standby customers which is equivalent to a 12% outage rate, while the 2004 ORNL Report MCA provided to the SRWG found that cogeneration systems back in 2004 averaged a 5% FOR. MCA/GPI also believe cogeneration system reliability, if anything, has improved since 2004. “MCA/GPI also believe that reservation fees are a counter-productive charge in terms of incentivizing a customer’s minimum use of utility capacity. In the best case, where a customer’s forced outage rate (FOR) is the basis of the reservation fee, it is still just an estimate and fails to incentivize better self- generator performance. In the worst case, it is a fixed charge, such as DTE’s formula, with no relationship to cost causation, which actually dis-incentivizes better self-generation performance. “MCA/GPI are also concerned that generation reservation fees may duplicate generation demand charges that are also justified by utilities as necessary to recover costs for capacity which must be maintained for standby customers.”

C. Power Supply Standby Charges – Demand i. Statement of the Purpose of Demand Charges The Report states that the “purpose of [power supply standby demand] charges is to recover costs for the capacity and energy used by the customer and contribute to the utility’s cost to have generation capacity standing ready to serve the customer in the event of an outage.” Report, p.10. Comment: MCA/GPI respectfully believe this sentence misstates the rationale for power supply demand charges and could be misleading in terms of the identification of costs that should be recovered under a demand charge.



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First, it isn’t clear what “energy” costs are included in a “demand” charge. For the sake of clarity and transparency, we believe all of a utility’s “energy” costs should be recovered separately under the “energy” charge. Second, we are concerned that this sentence suggests that the demand charge serves the same function as a reservation fee – compensating the utility for “standing ready to serve the customer in the event of an outage.” As stated above on the topic of reservation fees, we believe utility costs for “standing ready” have not been demonstrated and must be cost justified by the utility in a cost of service study. Indeed, the 5 Lakes Energy NYSERDA analysis indicates no excess capacity is required to be maintained for standby customers. But, even more troubling, DTE and Consumers also charge a reservation fee based on the same rationale. Including “standing ready” as a rationale for both reservation fees and demand charges could result in confusion in the identification of costs and double recovery for the utility. MCA/GPI suggest that the rationale for standby customer demand charges should be re-stated on p. 10 simply as follows:

“The purpose of [power supply standby demand] charges is to recover the costs for the capacity used by the customer.”

ii. DTE’s Power Supply Demand Charge a. Definition of Standby Demand The Report correctly points out that DTE’s Rider 3 includes a good definition of “Standby Demand” which allows a standby customer who is able to reduce its load (or otherwise reduce use of the utility’s power) to avoid standby demand charges when the customer is operating below its contracted supplemental demand. Comment: MCA/GPI concurs that this is an appropriate definition which allows the standby customer “self-help” flexibility and avoids double charging for supplemental and standby demand. We found Consumer’s standby tariff to be unclear on this point and suggest that this same, clear definition of “Standby Demand” should be included in Consumer’s tariff. b. DTE’s Demand Charge Calculation The Report also correctly points out that DTE’s Rider 3 effectively sets standby demand charges per kW day at 32% of the cost of full-service. As a result, “After three full, on-peak outages during the month, the standby customer is paying the full service rate power supply demand charge.” Report, p. 13. Also, DTE limits standby demand charges by way of a “Daily Demand Cap.” The three calculations that a standby



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7

customer must perform to determine its power supply demand charge are shown on p. 12 of the Report. Comment: MCA/GPI believe the DTE power supply demand charge formula is both unnecessarily complicated and unfair to standby customers. With a daily charge set at 32% of the cost of a full month of service, DTE’s tariff on its face is excessive and unrelated to DTE’s actual daily capacity costs, and thus not cost justified. Further, the demand “cap” sends precisely the wrong price signal for efficient use of the utility’s generation resources. To ensure that MCA/GPI’s position on this important point is preserved in the record, MCA/GPI request that the following paragraphs be included in the final Report:

“MCA/GPI take the position that DTE appropriately charges a daily, on-peak demand charge, but that DTE’s daily charge at the rate of 32% of a full month of service is excessive, is not proportional to the costs a standby customer imposes on the utility, and discriminates against standby customers. MCA/GPI believes these charges must be cost justified by the utility in a cost of service study. “MCA/GPI also point out that the combination of DTE’s minimum reservation fee, high daily charges, and “daily demand cap” penalizes standby customers who operate with high reliability and few forced outages with higher charges, while giving a cost reduction to standby customers who operate less efficiently. This incentivizes inefficient use of the utility’s generation resources. “MCA/GPI believe DTE’s formula of high daily demand charges, a maximum daily cap, and a minimum reservation fee is also overly complicated and lacks transparency. This approach of minimum and maximum charges “hides the ball” on cost causation.”

D. Power Supply Standby Charges – Energy Comment: MCA/GPI favor simplicity, transparency, proportionality, and efficiency in standby charges. All four of these goals are achieved by “time of use” energy charges where peak vs. off-peak pricing sends a strong signal to reduce grid consumption whenever possible during the utility’s peak demand. E. Delivery Charges The Report discusses the different methodologies used by DTE and Consumers to calculate the delivery charge. Consumers uses the self-generator customer’s generation name plate capacity times a fixed rate. DTE uses the customer’s contract capacity which is calculated based on its 1001st highest ½ hour of operation during June through October.



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8

Comment: The separate high delivery charges contained in both DTE’s and Consumers’ standby tariffs were discussed in the SRWG in the course of reviewing the 5 Lakes Energy “Apples-to-Apples” comparisons and breakdown of each utility’s charges. MCA/GPI respectfully request that further discussion of this issue reflecting MCA/GPI’s position on these charges be included in the Report. We offer the following paragraphs for possible inclusion:

“MCA/GPI believe both of these methodologies suffer from the same inherent defect—i.e., they apply a fixed fee based on generation capacity (kW), effectively ratcheting this charge over a full month and not reflecting the low proportional delivery costs imposed by the self-generation customer. As can be seen in 5 Lakes Energy’s “Apples-to-Apples” comparison of charges for the scenario of a 2 MW cogeneration customer, the result of this ratchet is a high delivery charge, rendering the Michigan utilities’ standby charges substantially higher than they would be if based on the standby customer’s low proportion of use of the utility delivery resources. This can be seen in DTE’s and Consumer’s standby charges in every operating scenario examined in 5 Lakes Energy’s “Apples-to-Apples” breakdown of charges.

“As shown below, even in a “No Outage” month, DTE’s and Consumer’s standby customers who place zero demand on the utilities’ delivery resources must pay this high fixed delivery charge.

No outage Consumers DTE

Service Charge 200 275 Delivery Capacity/Distribution

Charge 8100 6760

Reservation Fee 0 3500 Demand Charges 0 0 Energy Charges 0 0

… Subtotal of Monthly Delivery and

Customer Charges 8300 7035

Subtotal of Monthly Reservation and Daily Demand

0 3500

Subtotal of Energy Charges 0 0 TOTAL 8300 10,535

“MCA/GPI question why Michigan utilities’ delivery charges should be a fixed monthly fee based on capacity rather than an “as used” daily demand charge, as both DTE and Consumers charge for power supply



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9

demand. MCA/GPI believe this fixed delivery charge fails the “best practice” design parameters as well as the Michigan Public Act 341 requirement that standby tariffs be non-discriminatory, “cost-based and just and reasonable” and the PURPA requirement for non-discriminatory standby charges. 18 C.F.R. 292.305(a)(1)(ii) (“Rates for sales …shall not discriminate against any qualifying facility in comparison to rates for sales to other customers served by the electric utility.”) As a fixed monthly fee is not proportional to a cogeneration customer’s low use of the delivery resources, MCA/GPI take the position it is discriminatory and not cost-based, just or reasonable. They also argue the fixed monthly delivery charge discourages efficient use of those resources.”

“The Staff recommend that this issue be addressed in the pending DTE and Consumers rate cases.”

F. Standby Service Tariff Complexity The Report makes the statement that “Standby service tariffs are very complex, and staff realized early in the SRWG process that a cost of service based standby service tariff can only be simplified to a certain point.” Report, p. 16. The Report refers to standby customers’ interest in transparency and the significant technical potential for greater cogeneration deployment in Michigan and the utilities’ approach to working with customers. The Report recognizes the prospective standby customer’s “need to be able to understand the standby service tariff well enough to run some initial economic evaluations to determine whether the customer is a reasonable candidate for a project.” Comment: MCA/GPI take the position that standby tariffs need not be complex and offered in the SRWG meetings both a “Model Tariff” and a one-page “Summary of Charges” table as specific mechanisms for breaking through the complexity of standby tariffs, focusing on “best practices” in four distinct buckets of charges, and summarizing charges succinctly for customers. To ensure these recommendations are included in the Report, MCA/GPI suggest the addition of the following language in this section:

“MCA/GPI’s Proposed Model Tariff “MCA and GPI take the position that standby charges should be unbundled, but need not be overly complex. The four key elements of a standby tariff are those “buckets” of charges depicted in MCA/GPI’s “Model Tariff” -- Customer Charge, Reservation Fee, Demand Charge, and Energy Charge. In Michigan, the Demand Charge is broken into a power supply demand charge and a delivery charge.



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10

While MCA/GPI believe “standardization” of standby tariffs is not required, they argue incorporation of best practices for these four types of charges should be required and believe MCA/GPI’s “Model Tariff” presented to the SRWG provides a framework for reviewing each tariff for the elements of best practices in each category of charges. They argue that tariff provisions that incorporate these best practices should be as straightforward as possible. They believe DTE’s complicated formula for determining the power supply demand charge is an example of an overly complex approach. Unpacking this complexity, MCA/GPI argue that DTE’s approach hides high daily demand charges, a reservation fee based on unrealistic outage rates assumptions, and a misguided “demand charge cap.” They contend a better approach is a simple “as used,” non-duplicative daily demand charge. While Michigan law requires that the delivery charge be stated separately, they see no reason it should not also be based on an “as used” daily charge. “MCA/GPI’s Proposed Summary of Charges Table “MCA/GPI makes the point that the standby customer simply wants to know what his/her cost will be. While standby tariffs may differ, they recommended in the SRWG that the Commission require each utility to translate their tariff charges into a one-page “Summary of Charges” table clearly showing the tariff rates in each “bucket” of charges. In the SRWG proceedings, MCA/GPI offered two examples of such a table in Ameren Missouri’s standby rider and Otter Tail Power’s ‘standalone’ standby tariff.”

5. Standby Service Tariff Fairness See our comments in Section 3.B above. 6. Standby Service Tariff Comparisons We appreciate that the Report refers to 5 Lakes Energy’s “Apples-to-Apples” standby tariff comparisons of seven utilities provided by MCA/GPI and presented to the SRWG by 5 Lakes Energy and that the slides from that presentation are attached in the Report. The Report notes that the comparison tables highlight some dramatic differences in standby service costs across the four Michigan utilities studied. The Report also notes that both Consumers and DTE agree that “benchmarking is important, but more research is needed to determine whether the comparisons are truly on an ‘apples-to-apples’ basis” and that “some state jurisdictions may have policy goals that might impact whether the standby service tariff is structured to fully collect costs from each rate class.” Report, p. 19. Comment:



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11

We concur that the “Apples-to-Apples” comparison of the utilities’ tariffs is helpful in identifying the range of different charges the cogeneration customer faces in different utility territories. The 5 Lakes breakdown of different operating scenarios and separate “snapshots” of different “buckets” of charges also highlight how different rate designs result in different overall standby service costs and different price signals for the customer. The “snapshots” also allow us to unpack how the utility is recovering its costs and whether the charges imposed are cost justified. With regard to the issue of discerning whether other states share the same goals in standby rate design, MCA/GPI note that the primary other state used in the presented comparison – Minnesota – is similar to Michigan in a number of important ways, including in its focus on cost-justification. In Minnesota’s current standby tariff docket, in which Minnesota’s four major utilities proposed revised standby tariffs based on recommended best practices, the Minnesota Department of Commerce laid out the following key goals:

Standby rates should be transparent, flexible, and promote economically efficient consumption;

Standby rates should accurately account for all relevant value streams including both costs and benefits;

Standby rates should simplify input data sets & methodology, where possible and warranted;

Standby rates should provide neither an incentive nor a disincentive for distributed generation.1

Because Michigan and Minnesota share the same goals with regard to improving standby rates, and in light of the fact that Minnesota specifically states that it does not wish to provide an incentive or disincentive for distributed generation, we believe it is clear that the “Apples-to-Apples” comparison with Minnesota utilities is valid. It should also be noted that Minnesota utilities include unbundled generation, transmission and distribution costs in their reservation fees and demand charges2. Therefore, the suggestion made by the utilities in our SRWG discussion that Michigan utilities’ separate delivery charges may be recovered in other charges in Minnesota is incorrect. Furthermore, the wide disparity among utilities within Michigan itself should not be ignored, as these are important flags for further discussion and analysis with regard to cost justification. MCA/GPI believe that the data provided in the 5 Lakes “Apples-to-Apples” comparison is valuable not only for benchmarking, but also for facilitating a constructive conversation about the transparency of each utility’s standby tariff, and the impact that a utility’s approach to standby service has on real-world customers who may be interested in installing CHP. Wide discrepancies among utilities across state lines, or within a state, might be justified based on the actual costs incurred by the utility in serving

1 Minnesota Department of Commerce, Comments re Need and Appropriate Scope for a Generic Proceeding

on Standby Service Tariffs, Docket No. E999/CI-15-115, p. 13, filed January 30, 2015. 2 Ibid, p. 4.



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12

standby customers, but a key problem with the current approach to standby service is that the link between what standby customers pay and the costs they impose on a utility is extremely unclear. Without transparent rate structures, and without a clear understanding by utility representatives, regulators and stakeholders of how proposed tariffs are applied in a variety of outage scenarios, such discrepancies will naturally raise red flags as to fairness, and will raise important questions about whether a utility’s approach to standby service is discriminatory under PURPA. 7. Michigan Public Act 341 The Report references Michigan’s new Public Act 341 and its provisions expressly requiring Commission review to ensure that standby tariffs are non-discriminatory and are “cost-based and just and reasonable.” Comment: MCA/GPI appreciates the reference to this new law and concurs with the Staff recommendation that this review should take place in rate cases wherever possible. We note that the two new pending rate cases for DTE and Consumers are a ready vehicle for this review. 8. Staff Recommendations Comment: MCA/GPI whole-heartedly support the Staff Recommendations and appreciate the leadership of the Staff in providing a path forward following the SRWG process. With regard to recommendation No. 1, we respectfully suggest that a uniform “summary of charges” table, such as Ameren Missouri and Otter Tail Power include in their standby tariffs, would be most helpful in achieving tariff transparency and should be required by the Commission, as well as discussed with the utilities. With regard to Recommendation No. 2, we respectfully suggest that the “model tariff’ framework we presented to the SRWG may provide a starting point for the Commission’s development of a “standardized framework” for standby service tariffs in Michigan. With regard to Recommendation No. 4, we agree it is essential that Michigan utility standby tariffs be reviewed in each utility’s rate case to ensure they reflect up to date cost of service principles. We concur that there is a particular need for the Commission to review the relationship between reservation fees and power supply demand charges. We also believe the Commission should review how those charges are structured, e.g., DTE’s outage rate assumptions, high daily charges, and “demand cap,” and the cost-justification and reasonableness of DTE’s and Consumers’ fixed monthly delivery charges.



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MCA and GPI appreciate the opportunity to comment on the Staff Report and

would again like to thank the Commission and Staff for their leadership on this important issue.

Sincerely,

________________________ ________________________ Patricia F. Sharkey Anna Dirkswager Policy Director Program Manager Midwest Cogeneration Association Great Plains Institute



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June2,2017JulieBaldwin,ManagerRenewableEnergySectionElectricReliabilityDivisionMichiganPublicServiceCommissionByemail:[email protected] DearMs.Baldwin:TheMichiganEnergyInnovationBusinessCouncil(MichiganEIBC),abusinessassociationof100companiesengagedinMichigan’sadvancedenergyindustry,ispleasedtosupportmanyoftheconclusionscontainedintheMichiganPublicServiceCommissionStaffSupplementalDraftReport(DraftReport)oftheStandbyRateWorkingGrouporganizedunderU-17735.Specifically,weendorsetheCommissionStaff’sstatementthatthe“overarchinggoalofthe[StandbyRateWorkingGroup]istoensurethatanyresultingstandbyservicetariffsarebasedonthecosttoserveself-generationcustomersandtoincreasetransparencyofthetariffs,”including“clearandconcisedefinitionsofthetermsandbillingdeterminantsusedwithinthetariffandalloftherateinformationnecessarytocalculateamonthlybill.”MPSCStaffSupplementalReportoftheStandbyRateWorkingGroup,May2017,pg.1.ThisgoalisconsistentwiththecommentspreviouslyfiledbyMichiganEIBCaspartoftheWorkingGroupprocess,inwhichweurgedtheCommission“toensurethatanystandbyratesaretransparent,reflectcostofserviceprinciples,anddonotcreatearbitrarybarrierstotheinstallationofCHPsystemsinMichigan.”Beyondsimplyrequiringdefinitionsoftermsandconditions,MichiganEIBCurgestheCommissiontorequireasimple,one-pagesummarythatdetailshowthetariffactuallyworks,allowingaprospectivecustomertheabilitytofullyevaluatetheeconomicsofinstallingself-generationsystemsanddecidewhethertogoforward.AddingthisrequirementwouldbeconsistentwiththeStaff’sstatedgoal“tosimplifythestandbyservicetariffsandmakeiteasierforcurrentstandbyservicecustomerstounderstandthebillingcalculationsandhowtheirbillscouldbereduced”andforpotentialcustomers“tobeabletofullyevaluatehowtheirutilityrateswillchangeiftheyundertakeaself-servicegenerationproject.”Id.,at16.Indeed,asStaffnotedintheDraftReport,“CHPprojectdevelopersneedtobeabletounderstandthestandbyservicetariffwellenoughtorunsomeinitialeconomicevaluationstodeterminewhetherthecustomerisareasonablecandidateforaproject.Increasedtransparencyinthetariffwillbehelpfulfortheseearlyscreeninganalyses.”Id.,at17.Inadditiontotransparencyissues,MichiganEIBCapplaudstheDraftReport’sfocusondevelopingastandardizedframeworkforstandbyservicetariffswherepossible,



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requiringutilitiestojustifyandsupportdeviationsfromthestandard.AshasbeenshownincomparingthetreatmentofsimilarlysituatedstandbycustomersacrossfourMichiganutilities,widevariationsexistthatappearnottobegroundedincostofserviceprinciples,servinginsteadtocreateseriousandunjustifiedbarrierstoCHPutilizationandstymieadditionalprivateinvestmentinthesesystems.Asnotedinourinitialcomments,MichiganEIBCbelievesthatstandbyratesareappropriate“onlywhentheyarebasedonacceptedcostofserviceprinciplesandfullyreflectthecostsandbenefitsofCHPtothelargergrid–includingcapacity,diversificationandreductionofload,andreductionoflinelosses.RatesthatoverstatethelikelihoodorimpactofoutagesdistortthemarketandserveasarbitrarydisincentivestotheinstallationanduseofCHPsystems.”WiththeinclusionofCHPasasystemresourcetobeconsideredinutilityintegratedresourceplansunder2016PA341,aswellastheCommission’srecentdecisiononavoidedcostcalculationsunderthePublicUtilityRegulatoryPoliciesAct(PURPA)inU-18090,therearewell-groundedpolicyreasonstosupporteffortstoencouragedeploymentofCHPresourcesinMichigan.Inordertoensurethatratesare,indeed,basedoncost-of-serviceprinciples,MichiganEIBCfurthersupportsestablishingstandbycustomersasaseparaterateclass.WhileMichiganEIBCnotestheStaff’sargumentthat“theremaynotbeenoughstandbyservicecustomerstowarrantaseparateclass,”Id.,at5,wecautionthatthelackofnumbersmayinfactbeatleastpartiallyattributabletoarbitrarycostsandalackoftransparencythatcausesmanypotentiallyinterestedcustomersnottoinstallsystems.OnlybytreatingstandbycustomersasaseparateclassforratedesignpurposescantheCommissionfullyensurethatratesaretrulybasedoncostofservice.MichiganEIBCagainapplaudsCommissionStafffortheirworkindevelopingthisdraftSupplementalReport.WeurgetheCommissiontocontinuetomoveforwardwithrecommendationsthatincreasetransparency,ensureratesarebasedonacceptedcost-causationprinciples,andremoveremainingbarrierstodeploymentofCHPsystemsinMichigan.Sincerely,

LieslEichlerClarkPresidentMichiganEnergyInnovationBusinessCouncil



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Case No: U-18255

Exhibit AB-22



Page 1 of 3

All Rates in Effect as of February 4, 2017

Contracted Standby Service Demand 20,000 kW

Service Voltage 120 kV (or higher)

Power Factor 85% Lagging

# of Meters and Generation Installations 1

Energy Optimization Self-Directed Plan

Ameren

CECo DTE NIPSCO Missouri

GSG-2 R3 Rider 776 Rider SSR

Delivery Charges

Total Delivery Non-Energy Charges for Customer $12,501 $18,018 $0 ($2,934) per month

Total Delivery Energy Charges for Customer $0.000066 $0.004806 $0.000000 $0.000000 per kWh

Power Supply Charges

Total Power Supply Generation Reservation Fees $0 $35,000 $0 $17,400 per month

Power Supply Daily On-Peak Demand Charge (Non-Maintenance Periods) $0.63 $4.67 $0.00 $0.78 per kW per on-peak day

Power Supply Daily On-Peak Demand Charge (Maintenance Periods) $0.63 $2.60 $0.00 $0.39 per kW per on-peak day

Power Supply Daily Demand Charge (Non-Maintenance Periods) $0.00 $0.00 $0.52 $0.00 per kW per day

Power Supply Daily Demand Charge (Jan, May and Dec Maintenance Periods) $0.00 $0.00 $0.45 $0.00 per kW per day

Power Supply Daily Demand Charge (Feb-Apr and Oct-Nov Maintenance Periods) $0.00 $0.00 $0.25 $0.00 per kW per day

Total Power Supply On-Peak Energy Charge (Non-Maintenance Periods) $0.04300 $0.03817 $0.04466 $0.03870 per kWh

Total Power Supply Off-Peak Energy Charge (Non-Maintenance Periods) $0.03380 $0.03517 $0.03546 $0.03167 per kWh

Total Power Supply On-Peak Energy Charge (Maintenance Periods) $0.04300 $0.03817 $0.05169 $0.03400 per kWh

Total Power Supply Off-Peak Energy Charge (Maintenance Periods) $0.03380 $0.03517 $0.05169 $0.03400 per kWh

Notes:

For DTE only, Reservation Fees are waived if the sum of the On-Peak Daily Demand Charges for a month exceed the Reservation Fees.

For DTE only, the sum of the On-Peak Daily Demand Charges for a month are capped at the D11 full service rate monthly power supply demand charge.

As a proxy for CONS.CETR real-time LMPs, LMP averages for the DTE Load Zone from U-18014 Exhibit A-27 were used since they conform to the DTE On-Peak definition.

NIPSCO Rider 776 limits the use of non-maintenance power to 45 days per 12 rolling months.

NIPSCO Rider 776 power supply charges inherently include all applicable delivery service charges (Indiana does not have unbundled retail electric rates).

As a proxy for NIPSCO Load Zone real-time LMPs, LMP averages for the DTE Load Zone from U-18014 Exhibit A-27 were used since they conform to the DTE On-Peak definition.

Ameren Missouri Delivery Charges, Daily On-Peak Power Supply Demand Charges and Power Supply Energy Charges are a weighted average of the applicable summer and winter charges.

The higher of on-peak standby demand and 50% of off-peak standby demand is applied to Ameren Missouri's Daily On-Peak Power Supply Demand Charge.

Sources:

CECo and DTE Tariff Books as posted on MPSC Website on February 4, 2017.

CECo Response to Data Request HSC-CE-24 in U-17990.

DTE Exhibit A-27 from U-18014

NIPSCO Tariff Book as posted on NIPSCO website on February 6, 2017

Ameren Missouri Witness Davis Exhibit WRD-1 in MO PSC Case No. ER-2016-0179

Consumers Energy GSG-2 versus DTE Electric Rider 3 vs Northern Indiana Public Service Company Rider 776 vs Ameren Missouri

Rider SSR-- Standby Service

Case No: U-18255

Exhibit AB-22



Page 2 of 3


Daily On-Peak and Daily Standby Demand Charges Normalized by Monthly Full Service Demand Charge






Ameren


GPD D11 Rate 733 Rider SSR

Full Service Power Supply Demand Charge 17.05 $14.65 $15.68 $12.46 per kW per month

Ameren



Power Supply Daily On-Peak and Daily Demand Charges

Power Supply Daily On-Peak Demand Charge (Non-Maintenance Periods) 3.7% 31.9% 0.0% 6.3% per kW per on-peak day

Power Supply Daily On-Peak Demand Charge (Maintenance Periods) 3.7% 17.7% 0.0% 3.2% per kW per on-peak day

Power Supply Daily Demand Charge (Non-Maintenance Periods) 0.0% 0.0% 3.3% 0.0% per kW per day

Power Supply Daily Demand Charge (Jan, May and Dec Maintenance Periods) 0.0% 0.0% 2.9% 0.0% per kW per day

Power Supply Daily Demand Charge (Feb-Apr and Oct-Nov Maintenance Periods) 0.0% 0.0% 1.6% 0.0% per kW per day

Notes:


For DTE only, the sum of the On-Peak Daily Demand Charges for a month are capped at the D11 full service rate monthly power supply demand charge.

For CECo, a weighted average of the summer and non-summer Rate GPD Power Supply Demand Charges was used assuming flat demand across the months.



For Ameren Missouri, a weighted average of the summer and winter SC No. 11(M) Demand Charges was used assuming flat demand across the months.

Ameren Missouri Daily On-Peak Power Supply Demand Charges are a weighted average of the applicable summer and winter charges.


Sources:

CECo and DTE Tariff Books as posted on MPSC Website on February 4, 2017.




Consumers Energy GSG-2 versus DTE Electric Rider 3 vs Northern Indiana Public Service Company Rider 776 vs Ameren Missouri

Rider SSR-- Standby Service

Case No: U-18255

Exhibit AB-22



Page 3 of 3


Using 5 Lakes Outage Scenarios






Ameren


No Outage GSG-2 R3 Rider 776 Rider SSR

Customer and Delivery Charges $12,501 $18,018 $0 ($2,934)

Reservation and Daily Demand Charges $0 $35,000 $0 $17,400

Energy Charges $0 $0 $0 $0

Total $12,501 $53,018 $0 $14,466

Ameren


Schedule Outage 16 Hours Off-Peak (2 separate days) GSG-2 R3 Rider 776 Rider SSR


Reservation and Daily Demand Charges $0 $35,000 $18,000 $25,267

Energy Charges $10,816 $11,254 $16,540 $10,880

Total $23,338 $65,810 $34,540 $33,212

Ameren


Scheduled Outage 16 Hours On-Peak (2 separate days) GSG-2 R3 Rider 776 Rider SSR


Reservation and Daily Demand Charges $25,013 $104,000 $18,000 $33,133

Energy Charges $13,760 $12,214 $16,540 $10,880

Total $51,295 $135,770 $34,540 $41,079

Ameren


Scheduled Outage 8 Hours On-peak, 8 Hours Off-peak (2 separate days) GSG-2 R3 Rider 776 Rider SSR



Energy Charges $12,288 $11,734 $16,540 $10,880

Total $37,317 $83,290 $34,540 $37,146

Ameren





Energy Charges $27,520 $24,429 $33,080 $21,760

Total $90,090 $253,523 $69,080 $67,692

Ameren


Unscheduled Outage 8 Hours On-peak, 8 Hours Off-peak (2 separate days) GSG-2 R3 Rider 776 Rider SSR



Energy Charges $12,288 $11,734 $12,819 $11,259

Total $37,317 $124,690 $33,439 $49,224

Consumers Energy GSG-2 versus DTE Electric Rider 3 vs Northern Indiana Public Service Company Rider 776 vs Ameren

Missouri Rider SSR-- Standby Service

Executive Summary Report:

Distributed Generation Operational Reliability and Availability Database

ORNL Subcontract 4000021456

Submitted to: Oak Ridge National Laboratory

P.O. Box 2008 1 Bethel Valley Road

Oak Ridge, TN 37831-6065

Energy Solutions Center 400 North Capital St. NW

4th Floor Washington, DC 20001

New York State Energy Research & Development Authority

17 Columbia Circle Albany, NY 12303-6399

January 2004

Submitted By: Energy and Environmental Analysis, Inc.

1655 N. Fort Myer Drive, Suite 600 Arlington, Virginia 22209

(703) 528-1900

Case No.: U-18255

Exhibit: AB-23

Witness: J. R. Dauphinais


Page 1 of 13

Case No.: U-18255

Exhibit: AB-23



Page 2 of 13

DG/CHP Operational Reliability and Availability Energy and Environmental Analysis, Inc.

EXECUTIVE SUMMARY

This report summarizes the results of the project, “Distributed Generation Market Transformation Tools: Distributed Generation Reliability and Availability Database,” sponsored by Oak Ridge National Laboratory (ORNL), Energy Solutions Center (ESC), New York State Energy Research and Development Authority (NYSERDA), and Gas Technology Institute (GTI).

Using operations and maintenance field data provided by distributed generation (DG)/combined heat and power (CHP) project operators, owners, and developers, the project team analyzed the operational reliability (OR) performance of various onsite generation technologies. OR generally refers to the reliability, availability, and maintainability attributes of a process system and its components. Specifically, the project team analyzed event histories for 121 DG/CHP units over a two-year time period. These 121 units represented 731 MW of installed capacity and operated for 1,669,411 service hours. Data concerning 2,991 outage events were collected. A data collection and management process was developed as well as a database. Each event was described using a consistent equipment taxonomy and outage codes consistent with IEEE Standard 762. The primary sources of data included O&M log books, outage summary reports, and contractor service reports. This project represented the first attempt to establish a baseline operating and reliability database for DG/CHP systems in more than a decade.

The methodology and OR measures used in this project are consistent with established industry standards. Measures include availability factor, forced outage rate, scheduled outage factor, service factor, mean time between forced outage, and mean down time. The results of this project provide insights into the actual OR performance of onsite power generation systems. This data base provides a solid foundation upon which additional units can be added or periodic annual updating of data can be performed in the future.

Objectives

The increased deployment of Distributed Generation (DG)/Combined Heat and Power (CHP) has been identified as a means to enhance both individual customer reliability and electric transmission and distribution system reliability. DG/CHP reliability and availability performance relates to several significant issues affecting market development. The reliability/availability profiles for DG/CHP systems can affect electric standby charges and back-up rates, the value of ancillary services offered to Independent Transmission System Operators (ISO), local grid stability and reliability, customer power delivery system reliability, and customer economics. Interest in power reliability has heightened in recent years in light of high-profile system.

Specific objectives of this project were to:

1

Case No.: U-18255

Exhibit: AB-23



Page 3 of 13

• Establish baseline operating and reliability data for distributed generation systems • Identify and classify DG/CHP system failures and outages • Determine failure modes and causes of outages • Quantify system downtime for planned and unplanned maintenance • Identify follow-on research and/or activities that can improve the understanding

of reliability of DG/CHP technologies.

The primary deliverables of the project is a database framework populated with 121 DG/CHP units which is used to estimate the operational reliability (OR) of various DG/CHP technologies. From the data, key operational reliability (OR) measures were calculated. These objectives were accomplished with the valued participation of actual DG/CHP users and access to their operations and maintenance data.

Technical Approach

The methodology for assessing the operational reliability of DG systems was to establish baseline operating and reliability data for DG/CHP systems through an exhaustive collection of data from a sample of operating facilities. Data was collected from user maintenance logs, operation records, manufacturers’ data, and other available sources. The project team calculated key operational reliability indices. We then identified and classified DG system failures and outages for various types of technologies and applications. Finally, the project team assessed forced outage causes and quantified system downtimes for planned and unplanned maintenance. The final work product was a database framework of operational reliability data for DG/CHP systems that characterizes unit reliability over a two year period. This database can be augmented with additional sites in the future or be improved to allow for additional operating data to be added on a regular basis, e.g., monthly.

The technical approach used was based on the following guidelines:

• Operational reliability data should address a diverse set of prime mover technologies and applications

• Data collection process will have to rely heavily on user participation and their records

• Procedures for collecting, processing, and analyzing data must be tightly controlled.

The scope of work consited of the following tasks:

• Review of Prior Work • Identify and Select Candidate Sites • Collect Operating Data • Reduce and Analyze Data • Assess Reliability • Perform Forced Outage Cause Assessment

2

Case No.: U-18255

Exhibit: AB-23



Page 4 of 13


The project team conducted an exhaustive review of public and private databases to screen potential sites to populate the database. Two databases in particular that were used extensively are the PA Consulting/Hagler-Bailly and Energy Information Administration databases of non-utility power plants. In a parallel effort to screen sites, the project team utilized its network of contacts at manufacturers, developers, gas utilities, associations, and packaged cogeneration players. As the databases of existing facilities become less accurate for sites less than 1 MW in size, these personal contacts were important in identifying the smaller sized sites. In addition, we mailed letters to various stakeholders.

The project team collected raw data for 121 DG/CHP units. The breakdown of the 121 units is shown Figures 1 and 2.

Figure.1 - Distribution of Sample by Technology by Units (n=121)

# Units by Technology (N=121)

Gas Turbines 34%

Steam Turbines 21%

Reciprocating Engines

33%

Fuel Cells 12%


Gas Turbines

Steam Turbines

Fuel Cells

3

Case No.: U-18255

Exhibit: AB-23



Page 5 of 13

Figure 2 - Distribution of Sample by Technology by Capacity

Total Capacity by Technology (Total = 731.1 MW)

Gas Turbines 61%

Steam Turbines 34%

Fuel Cells 1%


4%


Gas Turbines

Steam Turbines

Fuel Cells

These 121 units represented 731.MW of installed capacity and operated for 1,669,411 service hours. Data concerning 2,991 outage events were collected. Each event was described using a consistent equipment taxonomy and outage codes consistent with ANSI/IEEE Standard 762 Standard Definitions for Use in Reporting Electrical Generating Unit Reliability, Availability, and Productivity. IEEE Standard 762 contains 66 reliability related terms and 25 OR performance indices (none of which is explicitly named “reliability”). The primary sources of data included O&M log books, outage summary reports, and contractor service reports.

The project team developed a data collection plan that addressed the framework and procedures used to screen potential participants, enter data and analyze OR performance. The project team calculated OR measures consistent with industry practices. Measures include availability factor, forced outage rate, scheduled outage factor, service factor, mean time between forced outage, and mean down time. The OR measures calculated are shown in Figure 3 and are consistent with ANSI/IEEE 762.

4

Case No.: U-18255

Exhibit: AB-23



Page 6 of 13

Period Hours (PH)

System Available Hours (AH) System Down for Maintenance

System OperatingService Hours (SH)

Reserve StandbyHours (RSH)

ScheduledOutage

Hours (SOH)

ForcedOutageHours(FOH)


Figure 3 – Operational Reliability Measures and Definitions

Period Hours (PH)

System Operating Reserve Standby Scheduled Forced Service Hours (SH) Hours (RSH) Outage Outage

Hours (SOH) Hours (FOH)

System Available Hours (AH) System Down for Maintenance

RReelialiabbiilitlityy PPeerrffoorrmmaannccee IInnddiicceess FFoormrmuullaa PPeerriiodod ofof DDeemmaand (nd (PPOODD)):: MMeeaassuurreses tthhe te tiimmee tthhe ue unniitt wwaass ppllannanneedd ttoo ooppereratate.e.

PPOODD == PHPH -- RRSSHH-- SOSOHH

AAvvaailailabbiliilittyy FFaaccttoorr ((AAFF,, %%)):: MMeeaassuurreses,, oonn aa ppeerrcentcent babassiiss,, tthhe une uniitt’’ss ““ccoouulldd rruun”n” ccaappaabibilliittyy.. IImmppaacctteedd byby ppllannanneedd anandd uunnplplannanneedd mmaaiinntteenannanccee..

AAFF == ((PPHH - S- SOOHH - F- FOOHH)) ** 110000 PHPH

FFoorcedrced OOuutataggee RRaattee ((FFOORR,, %%)):: MeMeaassuurreess ppoorrttiioonn ooff dodowwnnttiimmee duduee ttoo uunnplplanannneedd ffaaccttoorrss..

FFOORR == FFOOHH * 10* 1000 (S(SHH ++ FFOOHH))

ScSchehedduulleedd OOuuttaaggee FFaaccttoror ((SSOOFF,, %%)):: MMeeaassuurreess peperrcentcent ooff ttiimmee setset aassiidde foe forr plplanannneedd mmaaiinntteenannanccee..

SSOOFF == SOSOHH ** 110000 PHPH

SServerviiccee FFaactoctorr (S(SFF,, %%)):: PePerrcceenntt ofof ttoottaall ppeerriiodod hhourourss tthhee uunniitt iiss oonn--lliinne –e – vvaarriieses duedue ttoo sisittee--rreellatateded oorr ecoeconnoommiicc fafactctoorrss..

SSFF == SSHH ** 100100 PHPH

MMeeaann TTiimmee BBeetwtweeeenn FFoorrcedced OOuutataggeess (M(MTTBBFFOO):): MMeeaassurureses tthhee nnoommiinanall ttiimmee bbeettwweeeenn uunnsscchheedduulleedd foforrcedced ououttaaggeess..

MMTTBBFFOO == SSHH .. # F# Foorrcedced OOuuttaagegess

MMeeaann DoDownwn TTiimmee ((MMDDTT)):: MMeeaassuurreses tthhee nnoommiinnaall dduurraattiioonn tthhe ue unniitt iiss ddoowwnn dduurriinngg mmaaiinntteennaannce evce evenenttss..

MMDDTT == SSOOHH ++ FFOOHH .. ## FoForrced Oced Ouuttaaggeess ++ ## PlPlanantt OOuuttaagesges

5

Case No.: U-18255

Exhibit: AB-23



Page 7 of 13

Results

The entire project methodology was based heavily on the involvement of DG/CHP users. Data (maintenance logs, operation records, and other available sources) and results came directly from actual customer operating data and experience. This required an extremely labor-intensive effort on the part of both project participants and the project team. The voluntary cooperation of participating facilities and time assembling data and being interviewed was greatly appreciated. While time-intensive, the involvement of users created better understanding of actual operations.

The OR performance of a unit is affected by many factors including technology and operations and maintenance practices. When compared to electric utility units reported by the North American Electric Reliability Council Generating Availability Data System (NERC GADS), most DG/CHP units reviewed in this project demonstrated comparable to superior OR performance. OR statistics for units are shown tables 1 through 4.

Table 1 – Summary Statistics for Reciprocating Engine Systems

Rec ip roc a ting Eng ines <100kW 100-800 kW 800-3000 kW

Numb er Samp led

Min.

14

Avg. Ma x. Min.

8

Avg. Ma x. Min.

18

Avg. Ma x.

Ava ilab ility (%) 96.27 97.93 99.00 84.55 95.99 99.93 91.14 98.22 100.00

Forc ed Outa ge Rate (%) 0.86 1.76 3.07 0.00 1.98 5.05 0.00 0.85 6.63

Sc heduled Outage Fa c tor (%) 0.26 0.73 1.33 0.07 2.47 14.22 0.00 1.12 3.42

Servic e Fa c tor (%) 68.20 75.11 79.60 2.06 51.76 95.43 1.50 40.59 91.39

Mean Time Between Forc ed Outa g es (hrs) 505.96 784.75 1376.60 361.18 1352.26 4058.71 263.00 3582.77 14755.30

Mean Down Time (hrs) 7.29 13.71 24.21 12.50 50.66 173.05 0.00 27.06 91.91

6

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Exhibit: AB-23



Page 8 of 13


Table 2 – Summary Statistics for Gas Turbine Systems

Gas Turbines 0.5-3 MW 3-20 MW 20-100 MW

Number Sampled Min.

11 Avg. Max. Min.

21 Avg. Max. Min.

9 Avg. Max.

Availability (%) 88.88 97.13 100.00 88.56 94.97 99.60 86.33 93.53 99.45

Forced Outage Rate (%) 0.00 2.89 18.84 0.00 2.88 9.07 0.00 1.37 6.63

Scheduled Outage Factor (%) 0.00 0.99 4.57 0.00 2.39 11.44 0.00 5.14 13.50

Service Factor (%) 5.33 57.93 97.27 6.26 82.24 99.01 70.27 88.74 99.45

Mean Time Between Forced Outages (hrs) 765.62 2219.72 4318.00 216.77 1956.46 15298.00 536.00 3604.62 17424.00

Mean Down Time (hrs) 0.17 65.38 325.09 2.77 68.63 501.75 21.29 75.30 288.50

Table 3 – Summary Statistics: Fuel Cells and Steam Turbines

Other Tec hnolog ies Fuel Cells <200kW Stea m Turb ines <25MW

Numb er Sa mp led 15 Min. Avg . Ma x.

25 Min. Avg . Ma x.

Ava ila b ility (%) 42.31 76.84 95.04 72.37 92.02 99.82

Forc ed Outa ge Ra te (%) 4.31 22.94 57.51 0.00 2.34 16.41 Sc heduled Outa ge Fa c tor (%) 0.48 0.92 1.23 0.00 6.01 27.63

Servic e Fa c tor (%) 42.27 74.01 92.21 3.37 81.12 99.65 Mea n Time Between Forc ed Outa g es (hrs) 1416.71 2004.47 2696.33 120.18 5317.73 29585.00

Mea n Down Time (hrs) 66.92 369.24 1686.83 5.51 292.06 4848.00

7

Case No.: U-18255

Exhibit: AB-23



Page 9 of 13

The North American Reliability Council Generating Availability Data Service (NERC GADS) was created to provide utilities with information on OR perfomance of electric generating units and their related equipment. One of the primary reports that NERC GADS produces is the Generating Availability Report (GAR). The GAR reports OR data over a cumulative five years, annually. The statistics in the GAR are calculated from data that electric utilities report voluntarily to (NERC GADS). Operating histories for more than 4,400 electric generating units reside in GADS. Data are reported by 178 utilities in the United States and Canada, representing investor-owned, municipal, state, cooperative, provincial, and federal segments of the industry. NERC aggregates these data and presents the results annually in its GAR. Table 4 shows 1997-2001 OR performance data for five central station technologies. Data on onsite generation technologies assessed for this project are comparable or better than the most recent NERC GAR OR data on central station technologies.

Table 4 - NERC GAR 1997-2001 Summary OR Statistics

OR Measure Fossil (Boiler)

Nuclear Gas Turbine

Combined Cycle

Hydro

# of Units 1524 128 887 80 823 Availability Factor (%) 86.66 82.87 90.31 85.85 90.62 Forced Outage Rate (%) 5.16 7.83 41.40 3.24 4.68 Scheduled Outage Factor (%)

9.59 10.09 6.36 7.64 6.53

Service Factor (%) 68.98 82.85 4.72 61.36 57.95

Table 5 summarizes the OR statistics calculated from the database by technology group. The technology groups were defined as:

Reciprocating Engines Group 1: <100 kW Group 2: 100 - 800 kW Group 3: 800 kW – 3 MW Fuel Cells Group 4: <200 kW Gas Turbines Group 5: 500 kW – 3 MW Group 6: 3 MW – 20 MW Group 7: 20 – 100 MW Microturbines Group 8: <100 kW Steam Turbines Group 9: <25 MW

8

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Exhibit: AB-23



Page 10 of 13


With the exception of Technology Group 4 (fuel cells), all technology groups demonstrated acceptable to very good OR performance. Good performance is generally considered to be 90% availability factor or higher. Fuel cell OR performance was greatly affected by downtime associated with unusually long delays and not related to typical operation. Waiting time for service or replacement parts can have a serious effect. For example, several multi-month outages due to delays in service created an inaccurate representation of fuel cell OR performance. In those specific cases the availability calculated can become more a measure of the service system than the inherent disposition of the equipment to perform. It should also be noted that single units in both the 0.5-3000 MW and 3-20 MW gas turbine groups (groups 5 and 6) accounted for a disproportionate amount of forced outage time.

The project team included units in all technology groups with the exception of Group 8, microturbines. This is due to the fact that units installed and operating by January 2000, the cut-off date for the required two years of operation to be included in this project were either pre-commercial or first generation microturbines. Developers and users would have had to provide data and characterize operational reliability of this class of technology based on units that would not be representative of the products that would ultimately be used in the market. They were justifiably reluctant to participate on this basis. In fact, this effect was seen in the fuel cell data collected and analyzed for this project. The decision was made not to include microturbine data at this time but to structure the database to accommodate the addition of microturbine data at a later date if so desired.

Table 5 - Summary Operational Reliability Statistics by Technology Group

Tec hnology Group n

Ava ila b ility (%) Avg.

Outa ge Ra te (%)

Outage Fac tor (%)

Fa c tor (%) Avg.

Between Forc ed

Mea n Down Time (hrs)

1 14 97.93 1.76 0.73 75.11 784.75 13.71

2 8 95.99 1.98 2.47 51.76 1,352.26 50.66

3 18 98.22 0.85 1.12 40.59 3,582.77 27.06

4 15 76.84 22.94 0.92 74.01 2,004.47 369.24

5 11 97.13 2.89 0.99 57.93 2,219.72 65.38

6 21 94.97 2.88 2.39 82.24 1,956.46 68.63

7 9 93.53 1.37 5.14 88.74 3,604.62 75.30

9 25 92.02 2.34 6.01 81.12 5,317.73 292.06 Entire Samp le 121 93.09 4.65 2.66 70.23 2,869.83 138.53

Table 6 summarizes the OR statistics calculated from the database by duty cycle. Cycling average data is less impressive than the other duty cycles. This is primarily due to the fact that a number of fuel cell systems fall into this category. With regard to very low service factor units (e.g., standby units with service factor 3 %), an additional future analysis based on starting

9

Case No.: U-18255

Exhibit: AB-23



Page 11 of 13

reliability may provide improved insights. These units are characterized by approximately 100-300 hours of annual operation and service hours that range from 100 to 200 hours of maintenance and service. They have a very large percentage of their time in the state of reserve standby during which the unit is fully available but not operating. Using the same OR measures as higher service factor may not represent their reliability accurately.

Table 6 – Summary Operational Reliability Statistics by Duty Cycle

Duty Cycle

Service Factor Range N

Availability (%) Avg.

Forced Outage Rate (%)

Avg.

Scheduled Outage

Factor (%) Avg.

Service Factor (%)

Avg.

Mean Time Between Forced

Outages (hrs)

Mean Down

Time (hrs)

Peak 1-10% 14 99.42 0.02 0.58 2.60 456.80 22.21 Cycling 10-70% 26 88.76 10.15 2.16 54.03 2,339.48 383.19 Baseload >70% 81 93.39 3.69 3.18 87.11 3,457.13 80.10

Entire Sample 0-100% 121 92.62 6.48 1.59 36.86 1,659.54 250.93

During the time period unit operations were assessed, specific units were observed to exhibit both very good to poor OR performance. In almost all technology groups, subsystems other than the prime movers themselves contributed more significantly to the occurrence of forced outage events. Many events that occur are the result of random equipment failures expected of any complex power system. Other events may be nonrandom in nature, indicating problems that may relate to issues pertaining to the unit design or installation. This project did not result in the identification of any such systemic problems. Most failures within technology groups appear to be random occurrences of short duration.

It is noteworthy that OR performance of established commercial technologies (i.e., reciprocating engines and gas turbines) was significantly better than the sample of emerging technologies (fuel cells) included in the project. The OR performance of emerging technologies and early commercial products need to be compared separately. Established products have the benefit of millions of hours of operation from which to develop operations and maintenance best practices. Their observed performance in this project and prior work bears this out. As time passes and more experience is gained from the operation of emerging technologies, it is likely their demonstrated OR performance will improve to the level of the other technologies. Fuel cell operational reliability indices calculated were significantly lower than all other technology groups and what fuel cell manufacturers typically quote. Availability, forced outage rate and mean down time was greatly affected by downtime associated with unusually long delays (e.g., maintenance personnel response, availability of replacement parts, site operations) and not related to typical operation. Waiting time for service or replacement parts can have a serious effect. For example, several multi-month outages due to delays in service created an inaccurate representation of fuel cell OR performance. In those specific cases the availability calculated can become more a measure of the service system than the inherent disposition of the equipment to perform.

10

Case No.: U-18255

Exhibit: AB-23



Page 12 of 13


Conclusions and Recommendations

The database is intended to establish a baseline of OR data on DG/CHP and allow current and potential users to benchmark reliability. The methodology and framework for recording and analyzing data is straight forward, repeatable and consistent with industry standards. It should be noted that the data reviewed for this project is only for 2000-2002 time period. The database does not include very large samples in all technology groups. It is structured to accommodate more units and technology groups in a follow-on effort. Future periodic updating and maintenance on a regular basis will ensure continued usefulness and increase the confidence in the measures calculated.

The first version of the DG/CHP Reliability and Availability Database provides a general framework for recording operating data and analyzing OR performance. It provides a solid foundation for future improvements and enhancements. Recommended improvements to the database framework include:

• Add additional units in under-represented technology groups to improve the robustness of the data

• Update data on an annual basis to include years of operation beyond the original time period

• Include microturbines with at least two years of operations (not including R&D demonstration) along with fuel cells with similar operating history in a separate database pertaining to emerging DG/CHP technologies

Any follow-up effort needs an efficient site identification and data collection process. For example, monthly data submission by site operators with secure web-based data entry system would reduce the labor costs associated with data collection substantially.

11

Case No.: U-18255

Exhibit: AB-23



Page 13 of 13

Michigan Public Service Commission Case No.: U-18255

DTE Electric Company Exhibit: AB-24

Present and Proposed Revenue Witness: J. R. Dauphinais


Parallel Operation And Standby Service Rider - R3 Page: 1 of 1

All Voltages

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

Line

No. Description

Full Service Power Supply Quantity Units Rate Revenue Rate Revenue Rate Revenue

1 Station Power ($000) ($000) ($000)

2 Capacity

3 Administrative Charge 6,007 MWh 0.01619 97 0.01660 100 0.01660 100

4 Station Power Capacity 6,007 MWh 97 100 100

5

6 Non-Capacity

7 MISO Energy Charge 6,007 MWh 0.02644 159 0.02644 159 0.02644 159

8 Net Trans MISO MKT 6,007 MWh 0.00733 44 0.00736 44 0.00736 44

9 Administrative Charge 6,007 MWh 0.00070 4 0.00070 4

10 Station Power PS Subtotal 6,007 MWh 300 307 307

11

12 Standard R3 Scale Factor 0.2883

13 Capacity

14 Power Supply Demand

15 Generation Reservation Fee 394,471 kW 1.94 765 2.74 1,080 0.79 311

16 Daily Demand 127,412 kW 5.09 649 7.18 915 2.07 264

17 Maintenance Demand 24,623 kW 2.88 71 4.08 100 1.18 29

18 Maximum Billing Demand 193,335 kW 15.79 3,053 17.01 3,288 4.90 948

19 Voltage Level Discount

20 Subtransmission 447,816 kW (1.13) (505) (0.33) (146)

21 Transmission 251,886 kW (0.50) (125) (0.14) (36)

22

23

24 Energy

25 Secondary 3,228 MWh 0.07743 250 0.05496 177 0.05496 177

26 Primary Total 128,866 MWh 0.04330 5,580 0.01724 2,222 0.01724 2,222

27 132,093 MWh

28

29 Primary Off-Peak Discount 107,224 MWh (0.010000) (1,072) (0.010000) (1,072) (0.010000) (1,072)

30


32 Subtransmission 83,486 MWh (0.00141) (118) (0.00033) (27) (0.00033) (27)

33 Transmission 30,850 MWh (0.00214) (66) (0.00055) (17) (0.00055) (17)

34 Standard R3 Capacity 132,093 MWh 9,111 6,036 2,653

35

36 Non-Capacity

37 Energy

38 Secondary 3,228 MWh 0.02804 91 0.02804 91

39 Primary Total 128,866 MWh 0.02606 3,358 0.02606 3,358

40


42 Subtransmission 83,486 MWh (0.00071) (60) (0.00071) (60)

43 Transmission 30,850 MWh (0.00122) (37) (0.00122) (37)

44 Standard R3 PS Subtotal 132,093

45

46 PSCR 132,093 MWh 0.00000 0 0.00000 0 0.00000 0

47 REPS 47 Cust. 0.00 0 0.00 0 0.00 0

48 Total Full Service Power Supply 138,101 MWh 6.81¢ 9,411 7.02¢ 9,694 4.57¢ 6,311

ABATE Alternate Proposal1

(b)

Billing Determinants Present DTE Proposed

1. This is not ABATE's primary proposal, but an illustration of a methodology to reduce the revenue collected from the R3 class. ABATE's primary rate design proposal for R3 is discussed in the direct testimony of Mr. Dauphinais at pages 31-32.

Case No.: U-18255

Exhibit: AB-25



Page 1 of 3

Consumers, NIPSCO and Ameren Missouri Rates in Effect as of February 4, 2017






ABATE Ameren



Delivery Charges

Total Delivery Non-Energy Charges for Customer $12,501 $15,618 $0 ($2,934) per month

Total Delivery Energy Charges for Customer $0.000066 $0.004806 $0.000000 $0.000000 per kWh

Power Supply Charges

Total Power Supply Generation Reservation Fees $0 $19,450 $0 $17,400 per month

Power Supply Daily On-Peak Demand Charge (Non-Maintenance Periods) $0.63 $0.97 $0.00 $0.78 per kW per on-peak day

Power Supply Daily On-Peak Demand Charge (Maintenance Periods) $0.63 $0.49 $0.00 $0.39 per kW per on-peak day

Power Supply Daily Demand Charge (Non-Maintenance Periods) $0.00 $0.00 $0.52 $0.00 per kW per day

Power Supply Daily Demand Charge (Jan, May and Dec Maintenance Periods) $0.00 $0.00 $0.45 $0.00 per kW per day

Power Supply Daily Demand Charge (Feb-Apr and Oct-Nov Maintenance Periods) $0.00 $0.00 $0.25 $0.00 per kW per day

Total Power Supply On-Peak Energy Charge (Non-Maintenance Periods) $0.04300 $0.03539 $0.04466 $0.03870 per kWh

Total Power Supply Off-Peak Energy Charge (Non-Maintenance Periods) $0.03380 $0.02539 $0.03546 $0.03167 per kWh

Total Power Supply On-Peak Energy Charge (Maintenance Periods) $0.04300 $0.03539 $0.05169 $0.03400 per kWh

Total Power Supply Off-Peak Energy Charge (Maintenance Periods) $0.03380 $0.02539 $0.05169 $0.03400 per kWh

Notes:


As a proxy for CONS.CETR real-time LMPs, LMP averages for the DTE Load Zone from U-18014 Exhibit A-27 were used since they conform to the DTE On-Peak definition.



As a proxy for NIPSCO Load Zone real-time LMPs, LMP averages for the DTE Load Zone from U-18014 Exhibit A-27 were used since they conform to the DTE On-Peak definition.

Ameren Missouri Delivery Charges, Daily On-Peak Power Supply Demand Charges and Power Supply Energy Charges are a weighted average of the applicable summer and winter charges.


Sources:

Exhibit AB-26

CECo Tariff Book as posted on MPSC Website on February 4, 2017.




Ameren Missouri Witness Davis Exhibit WRD-1 in MO PSC Case No. ER-2016-0179

Consumers Energy GSG-2 versus ABATE Proposed DTE Electric Rider 3 vs Northern Indiana Public Service Company Rider 776 vs

Ameren Missouri Rider SSR-- Standby Service

Case No.: U-18255

Exhibit: AB-25



Page 2 of 3

Consumers, NIPSCO and Ameren Missouri are Rates in Effect as of February 4, 2017

Daily On-Peak and Daily Standby Demand Charges Normalized by Monthly Full Service Demand Charge






ABATE Ameren


GPD D11 Rate 733 Rider SSR

Full Service Power Supply Demand Charge 17.05 $19.45 $15.68 $12.46 per kW per month

ABATE Ameren



Power Supply Daily On-Peak and Daily Demand Charges

Power Supply Daily On-Peak Demand Charge (Non-Maintenance Periods) 3.7% 5.0% 0.0% 6.3%

Power Supply Daily On-Peak Demand Charge (Maintenance Periods) 3.7% 2.5% 0.0% 3.2%

Power Supply Daily Demand Charge (Non-Maintenance Periods) 0.0% 0.0% 3.3% 0.0%

Power Supply Daily Demand Charge (Jan, May and Dec Maintenance Periods) 0.0% 0.0% 2.9% 0.0%

Power Supply Daily Demand Charge (Feb-Apr and Oct-Nov Maintenance Periods) 0.0% 0.0% 1.6% 0.0%

Notes:


For CECo, a weighted average of the summer and non-summer Rate GPD Power Supply Demand Charges was used assuming flat demand across the months.



For Ameren Missouri, a weighted average of the summer and winter SC No. 11(M) Demand Charges was used assuming flat demand across the months.

Ameren Missouri Daily On-Peak Power Supply Demand Charges are a weighted average of the applicable summer and winter charges.


Sources:

Exhibit AB-26

CECo Tariff Book as posted on MPSC Website on February 4, 2017.




Consumers Energy GSG-2 versus ABATE Proposed DTE Electric Rider 3 vs Northern Indiana Public Service Company Rider 776 vs

Ameren Missouri Rider SSR-- Standby Service

Case No.: U-18255

Exhibit: AB-25


Date: Agust 29, 2017

Page 3 of 3

Consumers, NIPSCO and Ameren Missouri Rates in Effect as of February 4, 2017

Using 5 Lakes Outage Scenarios






ABATE Ameren


No Outage GSG-2 R3 Rider 776 Rider SSR


Reservation and Daily Demand Charges $0 $19,450 $0 $17,400

Energy Charges $0 $0 $0 $0

Total $12,501 $35,068 $0 $14,466

ABATE Ameren


Schedule Outage 16 Hours Off-Peak (2 separate days) GSG-2 R3 Rider 776 Rider SSR


Reservation and Daily Demand Charges $0 $19,450 $18,000 $25,267

Energy Charges $10,816 $8,125 $16,540 $10,880

Total $23,338 $44,731 $34,540 $33,212

ABATE Ameren





Energy Charges $13,760 $11,325 $16,540 $10,880

Total $51,295 $47,931 $34,540 $41,079

ABATE Ameren


Scheduled Outage 8 Hours On-peak, 8 Hours Off-peak (2 separate days) GSG-2 R3 Rider 776 Rider SSR



Energy Charges $12,288 $9,725 $16,540 $10,880

Total $37,317 $46,331 $34,540 $37,146

ABATE Ameren





Energy Charges $27,520 $22,650 $33,080 $21,760

Total $90,090 $80,243 $69,080 $67,692

ABATE Ameren


Unscheduled Outage 8 Hours On-peak, 8 Hours Off-peak (2 separate days) GSG-2 R3 Rider 776 Rider SSR



Energy Charges $12,288 $9,725 $12,819 $11,259

Total $37,317 $46,331 $33,439 $49,224

Consumers Energy GSG-2 versus ABATE Proposed DTE Electric Rider 3 vs Northern Indiana Public Service Company Rider

776 vs Ameren Missouri Rider SSR-- Standby Service

Michigan Public Service Commission Case No.: U-18255

DTE Electric Company Exhibit: AB-26

Present and Proposed Revenue Witness: J. R. Dauphinais


Primary Supply Rate - D11 Page: 1 of 1

All Voltages

(a) (c) (d) (e) (f) (h) (i)

Line

No. Description

Full Service Power Supply Quantity Units Rate Revenue Rate Revenue Rate Revenue

Capacity ($000) ($000) ($000)

1 Power Supply Demand 23,352,708 kW 15.79 368,739 17.01 397,122 17.21 401,948


3 Subtransmission 2,840,248 kW (1.13) (3,203) (0.64) (1,811)

4 Transmission 6,144,666 kW (0.50) (3,058) (0.96) (5,905)

5

6 Energy

7 On-Peak 3,242,961 MWh 0.04330 140,420 0.01853 60,087 0.01853 60,087

8 Off-Peak 9,375,159 MWh 0.03330 312,193 0.00853 79,956 0.00853 79,956

9 Total Energy 12,618,120 MWh

10


12 Subtransmission 1,748,562 MWh (0.00141) (2,465) (0.00033) (569) (0.00033) (569)

13 Transmission 4,082,133 MWh (0.00214) (8,736) (0.00055) (2,259) (0.00055) (2,259)

14 Total Capacity 12,618,120 810,151 528,076 531,448

15

16 Non-Capacity

17 Demand Charge 23,352,708 kW 3.39 79,074


19 Subtransmission 2,840,248 kW (0.13) (356)

20 Transmission 6,144,666 kW (0.19) (1,162)

21

22 Energy 12,618,120 MWh 0.02477 312,570 0.01863 235,015

23 Voltage Level Discount 0

24 Subtransmission 1,748,562 MWh (0.00071) (1,250) (0.00071) (1,250)

25 Transmission 4,082,133 MWh (0.00122) (4,962) (0.00122) (4,962)

26 Power Supply Subtotal 12,618,120 834,434 837,806

27

28 PSCR 12,618,120 MWh 0.00000 0 0.00000 0 0.00000 0

29 REPS 2,183 Cust. 0.0 0 0.0 0 0.0 0

30 Total Full Service Power Supply 12,618,120 MWh 6.42¢ 810,151 6.61¢ 834,434 6.64¢ 837,806

(b)

DTE ProposedPresent ABATE ProposedBilling Determinants

Documents

Clark Hill PLC 151 S. Old Woodward Suite 200 Birmingham