November 7, 2018 Ms. Kavita Kale Michigan Public Service ...

November 7, 2018 Ms. Kavita Kale Michigan Public Service Commission 7109 W. Saginaw Hwy. P. O. Box 30221 Lansing, MI 48909 RE: MPSC Case No. U-20162 Dear Ms. Kale: The following is attached for paperless electronic filing:

Direct Testimony of William Kenworthy and Kevin Lucas on behalf of the Environmental Law & Policy Center, the Ecology Center, the Solar Industries Association, and Vote Solar Exhibits ELP-1 – ELP-51

Proof of Service Sincerely, _____________________________ Margrethe Kearney Environmental Law & Policy Center [email protected]

cc: Service List, Case No. U-20162

mailto:[email protected]

STATE OF MICHIGAN MICHIGAN PUBLIC SERVICE COMMISSION

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 other relief

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Case No. U-20162

DIRECT TESTIMONY OF WILL KENWORTHY

ON BEHALF OF

THE ENVIRONMENTAL LAW AND POLICY CENTER,

THE ECOLOGY CENTER,

THE SOLAR INDUSTRIES ASSOCIATION,

AND VOTE SOLAR

November 7, 2018

Will Kenworthy · Direct Testimony · Page 1 of 57 · Case No .U-20162

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Introduction 1

Q. WHAT IS YOUR NAME AND ADDRESS? 2

A. My name is William Kenworthy. I am Regulatory Director, Midwest for Vote Solar. My 3

business address is 18 South Michigan Avenue, Suite 1200, Chicago, IL. 60603. 4

Q. PLEASE DESCRIBE VOTE SOLAR? 5

A. Vote Solar is a non-profit grassroots organization working to foster economic 6

opportunity, promote energy independence, and fight climate change by making solar a 7

mainstream energy resource across the United States. Since 2002, Vote Solar has 8

engaged in state, local, and federal advocacy campaigns to remove regulatory barriers 9

and implement key policies needed to bring solar to scale. Vote Solar is not a trade group 10

and does not have corporate members. Vote Solar has more than 70,000 members 11

nationally, including over 2,700 members in Michigan. 12

Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY? 13

A. I serve as Regulatory Director, Midwest for Vote Solar. I oversee policy development 14

and implementation related to large scale and distributed solar generation in the region. I 15

also review regulatory filings, perform technical analyses, and testify in commission 16

proceedings relating to solar generation. 17

Q. WHAT ARE YOUR QUALIFICATIONS? 18

A. I have nearly 30 years of experience in the energy industry in both the public and private 19

sector working in the renewable energy business and in energy policy. Of that 20

experience, I spent 8 years in solar energy project development working primarily on 21

commercial and industrial distributed solar projects in the Midwest. 22


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Prior to Vote Solar, I was Managing Director – Midwest for Microgrid Energy, where I 1

was responsible for leading the Company’s expansion of their solar project development 2

capabilities into markets in the Midwest. As a solar project developer, I analyzed 3

financial and economic aspects of projects. This involved understanding all aspects of 4

project finance and economics for our customers, partners and financiers. My project 5

development experience includes project finance, rate analysis, economic modelling, risk 6

assessment, regulatory compliance, sales and customer relations. 7

During my tenure at Microgrid Energy, we completed the Solar Chicago program, a 8

residential bulk purchase program, as well as a number of commercial projects ranging in 9

size from 25 kW to 2 MW. Prior to that, I was a partner with Tipping Point Renewable 10

Energy based in Dublin, Ohio, where we developed what was at the time the largest 11

rooftop solar project in Ohio for the City of Columbus. 12

In addition, my tenure at Microgrid Energy was punctuated with a one-year hiatus during 13

which time I served as President of Infer Energy, currently Root3 Technologies. Infer 14

Energy provided energy optimization services to large commercial and industrial energy 15

users. We used advanced data analytics and machine learning algorithms to optimize 16

complex energy systems. 17

Prior to joining the solar energy industry, I have over 20 years of experience in energy 18

policy at the federal and state level. As a consultant, I represented electric utilities and 19

other industry participants before Congress, the Department of Energy, the Nuclear 20

Regulatory Commission, the Environmental Protection Agency and the Office of 21

Management and Budget. I began my career as a Professional Staff Member to the House 22

Energy & Commerce Committee, where I represented Chairman Dingell and other 23


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majority members of the Committee in negotiations and legislative drafting on nuclear 1

regulatory matters, the Clean Air Act Amendments of 1990 and electric industry structure 2

issues, among others. 3

I received a Master of Public & Private Management from the Yale University School of 4

Management with a concentration in Regulation and Competitive Strategy. My research 5

in graduate school focused on regulatory theory and practice. I also have a Bachelor of 6

Science in Foreign Service from Georgetown University. 7

Q. HAVE YOU TESTIFIED BEFORE THE COMMISSION PREVIOUSLY? 8

A. No. 9

Purpose and Summary 10

Q. HAVE YOU REVIEWED AND ANALYZED THE PROPOSED DISTRIBUTED GENERATION 11

(“DG”) TARIFF RIDER 18 SUBMITTED BY DTE ELECTRIC (“COMPANY”) IN THIS CASE? 12

A. Yes. 13

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 14

A. The purpose of my testimony is to describe certain problems with the Company proposed 15

Rider 18 and the arguments made in Company sponsored exhibits and testimony. I also 16

describe a counterproposal based on the Inflow/Outflow billing method described by the 17

Commission in U-18383 that is just and reasonable for the Company, DG customers and 18

non-DG customers. 19


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Q. PLEASE DESCRIBE HOW YOUR TESTIMONY IS ORGANIZED. 1

A. First, I describe the background and impetus for the new Distributed Generation Tariff 2

filed by the Company. Second, I describe the general proposal that the Company made 3

for its new DG Tariff in its proposed Rider 18 and the rationale expressed by the 4

Company for its proposal. Third, I examine the specific proposals made by the Company 5

to implement the DG Tariffs, specifically examining the System Access Contribution 6

(“SAC”) and the Inflow/Outflow billing method proposed by the Company. Third, I 7

analyze the impact that the proposed Rider 18 would have on prospective solar customers 8

in the Company service territory. Finally, I propose an alternative Inflow/Outflow 9

mechanism consistent with the Commission’s Order in U-18383. 10

Q. PLEASE SUMMARIZE YOUR FINDINGS WITH RESPECT TO THE SYSTEM ACCESS 11

CONTRIBUTION IN PROPOSED RIDER 18? 12

A. The proposed System Access Contribution does not reflect an “equitable cost of service” 13

for prospective owners of distributed generation, is not cost-based as required by statute 14

and rule and is not justified by evidence in the record. I recommend that the Commission 15

not approve the System Access Contribution. 16

Q. PLEASE SUMMARIZE YOUR FINDINGS ON THE COMPANY PROPOSED INFLOW/OUTFLOW 17

MECHANISM IN RIDER 18? 18

A. The Company is required by Order of the Commission to propose a DG tariff to replace 19

net metering. However, the Inflow/Outflow mechanism proposed by the Company is not 20

cost-based, is not “equitable and just” for prospective owners of distributed generation 21

and is not supported by evidence. Therefore, the Company’s DG Tariff proposal should 22


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be rejected by the Commission and the Commission should instead order the Company to 1

implement an equitable cost-based Inflow/Outflow mechanism. 2

Q. PLEASE SUMMARIZE YOUR RECOMMENDATIONS FOR A REVISED DG TARIFF 3

CONSISTENT WITH THE COMMISSION’S PRIOR ACTIONS IN THIS MATTER AND 4

EQUITABLE COST OF SERVICE PRINCIPLES. 5

A. I recommend that in establishing a replacement DG Tariff, the Commission focus on (1) 6

the cost to serve customer-generators for the services that are provided to them by the 7

utility; and (2) the appropriate compensation for services that are provided to the grid by 8

the customer-generator. 9

Consistent with these principles, I recommend replacing the Company’s proposed Rider 10

18 with a new Rider 18 based on Exhibit A of the April 18, 2018 Order in U-18383 that: 11

1.) does not include a System Access Contribution; 12

2.) bills Inflow at the customer’s underlying rate schedule; 13

3.) includes a credit for generation during inflow to reflect cost-based benefits 14

delivered by DG customers even when they are not exporting; and 15

4.) bills Outflow credit based on the “fair valuation” recommendation of the Staff 16

Report. 17

Commission Guidance 18

Q. WHAT IS THE STATUTORY BACKGROUND FOR THIS PROCEEDING? 19

A. On December 21, 2016, Governor Rick Snyder signed 2016 PA 341 (Act 341) into law. 20

Section 6a(14) of Act 341 directs the Commission to “conduct a study on an appropriate 21


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tariff reflecting equitable cost of service for utility revenue requirements” and to 1

“approve such a tariff” in a rate case filed after June 1, 2018. 2

Q. HAS THE COMMISSION TAKEN ACTION TO IMPLEMENT THE REQUIREMENTS OF SECTION 3

6A(14) OF ACT 341? 4

A. In response to that Act, the Commission initiated a proceeding to study “an appropriate 5

tariff reflecting equitable cost of service for utility revenue requirements.” The 6

Commission opened Case No. U-18383 In the matter, on the Commission's own motion, 7

to implement the provisions of sections 173 and 183(1) of 2016 PA 342, and Section 8

6a(14) of 2016 PA 341. 9

At the direction of the Commission, the Commission Staff (Staff) convened a Distributed 10

Generation Workgroup (DG Workgroup) that held a number of meetings between March 11

and December 2017. 12

The Staff issued a report entitled Report on the MPSC Staff Study to Develop a Cost of 13

Service-Based Distributed Generation Program Tariff, (the Staff Report) on February 21, 14

2018.1 In that report the Staff recommended a new approach to billing DG customers 15

called the Inflow/Outflow billing method. The Inflow/Outflow method bills inflows and 16

outflows of power separately. The Staff also provided a framework tariff. 17

The Commission issued an order in Case No. 18-18383 on April 18, 2018. The 18

Commission ordered “that, in any rate case filed after June 1, 2018, the rate-regulated 19

1 Report on the MPSC Staff Study to Develop a Cost of Service-Based Distributed Generation Program Tariff, Michigan Public Service Commission Staff, February 21, 2018.


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utility must file the Inflow/Outflow tariff, attached to this order as Exhibit A. The rate-1

regulated utility may also file its own distributed generation tariff, if desired.”2 2

Summary of Company Proposal 3

Q. PLEASE OUTLINE THE OVERALL STRUCTURE OF THE COMPANY’S PROPOSED RIDER 18. 4

A. The Company has proposed a new Rider 18 that would be applicable to new distributed 5

generation customers beginning in May 2019. There are two significant structural 6

components of the proposed Rider 18. First, the Company proposes to adopt a modified 7

version of the Commission-recommended method for billing inflows and outflows as a 8

replacement for net metering. Second, the Company proposes a System Access 9

Contribution, which is a monthly charge imposed only on distributed generation 10

customers and is based on the installed capacity of their distributed generation system. 11

The Company proposes an inflow/outflow model whereby inflows are defined as the total 12

number of metered kilowatt hours delivered by the Company to the customer during the 13

billing period or time-based pricing period.3 The Company defines outflows as the 14

metered quantity of the customer’s generation not used on site and exported to the utility 15

during the billing month or time-based pricing period. 16

Under the Company’s proposed Rider 18, and indeed as proposed by the Commission, 17

the inflows and outflows are billed differently. Inflows for full service customers will be 18

2 Commission Order of April 18, 2018, Exhibit A “Distributed Generation Tariff,” p. 4. 3 The Company proposal specifically refers to the “billing period or time-based pricing period.” In response to discovery, the Company described this as: “Billing period refers to the time-period covered in the bill; typically, customers have 12 monthly billing periods annually. Time-based pricing period refers to the fact that some of the rates offered by the Company vary by time of consumption – see the Company’s tariff book for specific time of use periods attributable to specific rate schedules.” (ELPCDE-1.7) Attached as Exhibit ELP-1 (WK-1)


8

billed according to the customer’s retail rate schedule (i.e. D1 customers would be billed 1

for their inflows at the D1 rate schedule). Retail Open Access Customers would be billed 2

as stated on the customer’s Retail Open Access Rate Schedule. 3

In contrast, outflows from the customer’s system will be credited for the billing period or 4

time-based rate period. For full service customers, the Company proposes to credit each 5

kilowatt-hour (kWh) of outflow at the monthly average real-time locational marginal 6

price (LMP), irrespective of the time the outflow is generated. Customers on time-based 7

rate schedules will be credited for each kWh of outflow at the monthly average real-time 8

LMP during the relevant time of use pricing period. 9

In addition to the Company’s proposed modified inflow/outflow billing method, the 10

Company’s proposed Rider 18 includes a completely new charge that will be levied only 11

on distributed generation customers called a System Access Contribution. Under the 12

proposed new charge, customers attaching to the proposed Rider 18 that are on residential 13

secondary or commercial secondary rate schedules that do not have a delivery demand 14

charge, will be subject to a charge based on the installed capacity (size) of the customer’s 15

distributed generation facility. The proposed charges would be $2.31/kW of installed 16

capacity per month for residential customers and $2.28/kW of installed capacity per 17

month for commercial customers. For a customer with an average sized solar array (6.7 18

kW according the Company), this would amount to a new, additional fixed monthly 19

charge of $15.48 above and beyond their normal usage charges. 20


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Q. IS THE INFLOW/OUTFLOW MECHANISM PROPOSED BY THE COMPANY THE SAME AS THE 1

DG TARIFF APPROVED IN ATTACHMENT A OF THE COMMISSION’S ORDER IN U-18383? 2

A. No. The Company’s proposal differs from the DG Tariff framework proposed by the 3

Staff and adopted by the Commission in its Order on U-18383 in several important 4

respects. In general, the Company has submitted a complete replacement for the 5

Commission proposed tariff that, while structurally similar, includes significant 6

modifications to most sections. Without detailing every change, there are some important 7

differences summarized in Table 1 below: 8

Commission proposed Tariff Company proposed Tariff Eligibility of existing net metering Customers increasing load.

Not addressed If an existing customer who participates on Rider 16 (the Net Metering program) increases their aggregate generation following the effective date, then all generation on site will be subject to the terms and conditions of the tariff.

Inflow Credit The customer will be billed according to their retail rate schedule, plus surcharges, and Power Supply Cost Recovery (PSCR) Factor on metered Inflow for the billing period or time-based pricing period.

Same

Outflow Credit Methodology for Full Service Customers

Not addressed Customers on non-time-based rate schedules will be credited for each kWh of Outflow at the monthly average real-time locational marginal price for energy at the DTE Electric-appropriate load node. Customers on time-based rate schedules will be credited for each kWh of Outflow at the monthly average real-time locational marginal price for energy at the DTE Electric-appropriate load node during the time of use pricing period.

Unused outflow credit

Unused outflow credit from previous months will be applied to the current billing month, if applicable.

Unused Outflow Credit from previous months will be applied to the current billing month, if applicable, to offset the power supply component and PSCR components of the customer’s bill.

System Access Contribution

No fee similar to the System Access Contribution is contemplated by the Staff Report or the Commission’s Order.

Customers on residential secondary or commercial secondary rate schedules will be subject to a charge based on the installed capacity (size) of the customer’s distributed generation facility $2.31/kw of installed capacity per month for residential customers $2.28/kW of installed capacity per month for


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commercial customers.

Customer Termination

Upon termination from the Distributed Generation Program, any existing credit on the customer’s account will either be applied to the customers final bill or refunded to the customer. The Company will refund to the customer any remaining credit in excess of the final bill amount.

Upon customer termination from the Distributed Generation Program, any existing credit on the customer's account will be forfeited. Distributed Generation Program credit is non-transferrable.

Company Termination

Upon Company termination of the Distributed Generation Program, any existing credit on the customer’s account will either be applied to the customers final bill or refunded to the customer. The Company will refund to the customer any remaining credit in excess of the final bill amount.

Upon Company termination of the Distributed Generation Program, any existing credit on the customer's account will be forfeited. Distributed Generation Program credit is non-transferrable.

Discussion of the Company’s Proposal 1

Cost shifting and the DG Customers’ “relationship to the grid” 2

Q. IN GENERAL, HOW DOES THE COMPANY PRESENT ITS CASE FOR THE PROPOSED DG 3

TARIFF? 4

A. In general, the Company argues that there is a cost shift from net metering customers to 5

non-net metering customers because “When kWh consumed from the distribution system 6

declines without a concurrent and equivalent decline in cost, this continuing unrecovered 7

cost shifts to all other customers.”4 8

Q. WHAT EVIDENCE DOES COMPANY WITNESS CAMILO SERNA (“WITNESS SERNA”) 9

PROVIDE TO DEMONSTRATE THIS COST-SHIFTING? 10

A. Witness Serna provides no calculations, citation or documentation to support this 11

assertion. It appears that Witness Serna relies on a comparison of the average summer 12

load curves of DG and non-DG customers to underlie this argument. While this 13 4 See Qualifications and Direct Testimony of Camilo Serna Direct, Michigan Public Service Commission. Case No. U-20162, July 6, 2018. p. CS -54. (“Serna Direct”)


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comparison is addressed in more detail below it is important to note that cost shifting is a 1

much more complex issue than simple load shape comparison can address. In order to 2

determine whether or not a cost shift exists, the analyst must compare the cost to serve a 3

subset of customers based on the cost-causing (and benefit causing) attributes of their 4

load and compare those costs to the revenues received under current rates. Loads are an 5

input to this analysis but cannot substitute for a full examination. 6

Q. HAS WITNESS SERNA CONDUCTED THE REQUIRED ANALYSES TO BE ABLE TO 7

DETERMINE WHETHER OR NOT A COST SHIFT EXISTS? 8

A. No. It appears that Witness Serna bases his assertion on circumstantial evidence 9

regarding load shapes and an alleged adverse relationship between DG customers and the 10

grid. Absent from any of the Company’s proposal is an examination of the relationship of 11

the cost to serve DG customers and the revenues received from those customers under 12

current rates. In addition, the Company’s cost shift argument is specious because it 13

focuses only on one side of the equation. In fact, it ignores the many benefits that 14

distributed solar contributes to reducing system load, thus reducing overall costs at the 15

distribution, transmission and generation level. 16

Q. WHAT DOES WITNESS SERNA ASSERT ABOUT THE RELATIONSHIP BETWEEN DG 17

CUSTOMERS AND THE GRID? 18

A. The Company argues that solar customers receive services from the grid for which they 19

fail to compensate the Company. 20

However, distributed generation customers receive a range of additional grid services 21

from the electric system that are unique to their choice to utilize distributed generation. 22


12

They leverage the electric system above and beyond traditional customers, make more 1

intensive demands of the infrastructure, and generally use the electric system itself as a 2

transactional service provider and balancing resource to meet their energy needs when 3

their generation (primarily solar panels) is not operating at full output or when there are 4

additional electrical demands that solar can’t meet (eg., start-up of large appliances). 5

(Serna Direct, p. CS – 51) 6

In this short passage, Witness Serna makes several claims regarding DG customers. He 7

claims that DG customers: 8

1.) receive “additional grid services;” 9

2.) leverage the electric system above and beyond traditional customers; 10

3.) make more intensive demands on the infrastructure; and 11

4.) generally, use the system as a transactional service provider and balancing resource 12

to meet their energy needs when their generation is not operating at full output or 13

when there are additional demand that solar cannot meet like appliance start-up 14

loads. 15

Q. DO YOU AGREE WITH WITNESS SERNA’S ASSERTIONS WITH RESPECT TO THE 16

RELATIONSHIP BETWEEN DG CUSTOMER AND THE GRID? 17

A. No, and I would like to address each assertion independently. 18

Q. DO DG CUSTOMERS RECEIVE “ADDITIONAL GRID SERVICES” FROM THE GRID? 19

A. No, the primary difference between DG and non-DG customers is that the former exports 20

energy to the grid. But that is a service – generation – which the DG customer provides to 21

the utility, not the other way around. Moreover, the generation service that DG 22


13

customers provide to the utility ends at the DG customer’s meter, where the utility 1

accepts and takes title to the exported power. It is the utility that delivers the exported DG 2

power to the DG customer’s neighbors. It is the utility that is compensated by the 3

neighbors for the service that the utility provides in delivering the DG exports to them. 4

The DG customer is in no way responsible for the delivery of their exported power, has 5

no control over who receives their exports, and receives no compensation for the delivery 6

of the exports. There is no difference in the generation service that any other third-party 7

generator, of any size, provides to the utility at the generator’s busbar where the utility 8

accepts the generated power into its transmission and distribution system. Beyond 9

exported generation, a DG customer receives all of the same services from the grid as a 10

traditional customer. 11

Q. DO DG CUSTOMERS “LEVERAGE THE ELECTRIC SYSTEM ABOVE AND BEYOND 12

TRADITIONAL CUSTOMERS?” 13

A. No. In fact, DG customers use most of their production on-site to serve their own loads, 14

and thus reduce their impacts on the grid. By doing so, the DG customer becomes a 15

smaller customer of the utility, with reduced inflows of power, than before the customer 16

installed DG. As will be discussed below, there is considerable variation of load shape 17

and usage within the customer class, and DG customers as a group fall within that range 18

of variation. As a result, DG customers should not be treated differently than other types 19

of customers in terms of how they are charged for the inflows of power that they take 20

from the grid. 21


14

Q. DO DG CUSTOMERS “MAKE MORE INTENSIVE DEMANDS OF THE INFRASTRUCTURE?” 1

A. No, in fact the opposite is true. Solar operates during times of high load on the system 2

and relieves congestion, actually decreasing demands on infrastructure. In fact, when the 3

utility delivers exported power from a DG customer to the DG customer’s neighbors, the 4

utility needs to use only a small portion of its distribution system to make this delivery. 5

This unloads and makes available upstream transmission and distribution capacity that 6

the utility can use to serve other customers and satisfy growing loads elsewhere without 7

upgrades. The utility’s use of DG exports thus allows it to avoid both generation and 8

delivery costs. 9

Q. DO DG CUSTOMERS “GENERALLY USE THE ELECTRIC SYSTEM ITSELF AS A 10

TRANSACTIONAL SERVICE PROVIDER AND BALANCING RESOURCE TO MEET THEIR 11

ENERGY NEEDS WHEN THEIR GENERATION (PRIMARILY SOLAR PANELS) IS NOT 12

OPERATING AT FULL OUTPUT OR WHEN THERE ARE ADDITIONAL ELECTRICAL DEMANDS 13

THAT SOLAR CAN’T MEET?” 14

A. No. Of course DG customers utilize the grid when their demand exceeds the output of 15

their on-site generation, but this use of the grid is no different than other customers. All 16

customers expect that the lights will go on when a switch is flipped, and they rely on the 17

grid to provide inflow service in exchange for the rates that they pay. All customers also 18

have appliances that start up, and DG customers are no different. All customers, 19

including DG customers, pay more to the utility when the inflow of power from the grid 20

is higher and the meters run forward more quickly, as when an appliance starts up. As has 21

already been observed and will be discussed in greater detail below, there is considerable 22


15

variation of load shape and usage within the customer class, but DG customers as a group 1

do not vary that much compared to other types of customers. 2

Q. WHAT DOES WITNESS SERNA ASSERT ABOUT THE OPERATIONAL AND TECHNICAL 3

IMPACTS OF DG ON ELECTRIC SYSTEM FUNCTIONS? 4

A. Witness Serna argues that DG creates two unique electric system dynamics that are 5

different from traditional customer impacts: 6

1. “The nearly instantaneous change in inverter-based generation output, either because 7

the generator trips offline or cloud cover rapidly changes, introduces potential for 8

impacts to system protective equipment”; and 9

2. “Distributed generation may introduce reverse power flows into equipment not 10

originally designed to accommodate them.”5 11

Q. DO YOU AGREE WITH WITNESS SERNA’S ASSERTION ABOUT THE OPERATIONAL AND 12

TECHNICAL IMPACTS OF DG ON ELECTRIC SYSTEM FUNCTIONS? 13

A. No. The Company provides no data or examples of either of these phenomena to support 14

this assertion that they create issues on DTE’s system. Furthermore, to the extent there 15

are any safety/reliability issues related to DG, they are covered by Michigan’s 16

interconnection standards. These are not DG tariff issues – they are interconnection 17

issues. 18

Additionally, while the Company does not possess the ability to monitor all DG systems 19

in real time, they similarly lack the ability to monitor all individual customer load 20

fluctuations in real time. Fluctuations in residential demand due to HVAC systems or 21

5 Serna Direct, p. 53.


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electric vehicle cycling can exceed PV system output. The Company has managed 1

customer load fluctuations for decades. This is a nominal condition for the grid, and it is 2

equipped to manage it. It is not credible that an inability to monitor and control DG 3

systems in particular presents any exceptional challenges for the utility. 4

If the Company suspected that reverse power flows were adversely impacting its system, 5

I would expect that the Company would investigate and quantify this issue. However, the 6

Company was asked in discovery to provide all analyses produced by (or for) the 7

Company that demonstrate that outflow energy from current net metering customers is 8

ever exported beyond the distribution substation level of the distribution system. The 9

Company responded simply that: “The Company has not performed such analyses.”6 10

Likewise, when asked to provide all documentation and analyses produced by the 11

Company related to the “operation and technical impacts of distributed generation on 12

electric system functions,” the Company replied: “The Company has not performed an 13

analysis specific to the operational and technical impacts of distributed generation on the 14

Company’s electric system functions.”7 15

Finally, I would note that the MIT Energy Initiative published an extensive study of DG 16

in 2016 that evaluates potential system cost increases resulting from higher levels of DG 17

penetration.8 However, as shown in Figure 1 below (reproduced from the MIT study), 18

system cost increases are negligible with DG penetration levels below 5%, as in 19

6 ELPCDE-1.24f, Attached as Exhibit ELP-2 (WK-2). 7 ELPCDE-1.26, Attached as Exhibit ELP-3 (WK-3). 8 MIT Energy Initiative, “Utility of the Future,” December 2016, p. 48. available at: http://energy.mit.edu/wp-content/uploads/2016/12/Utility-of-the-Future-Full-Report.pdf .

http://energy.mit.edu/wp-content/uploads/2016/12/Utility-of-the-Future-Full-Report.pdf


17

Michigan which has a current penetration of only 0.1%.9 Moreover, as DG penetration 1

levels increase there will likely be opportunities to use DG and smart inverters to help the 2

Company regulate voltage and maintain overall system reliability. 3

4 Penetration in Michigan is expected to remain significantly below 5% even decades into 5

the future.10 It is therefore highly unlikely that DG will cause the Company to incur any 6

significant incremental system costs in the next several years. In the interim, as 7

residential DG continues to grow, improved technological options and increased data 8

from net metering experiences across the country will provide the Commission with 9

better and more reliable information with which to assess whether any costs that are 10

9 Michigan Public Service Commission, Net Metering & Solar Program Report for Calendar Year 2016, December 2017, pg. 4. 10 See discussion below.


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incurred at higher penetration levels would justify a change in the rate design when those 1

higher levels are reached. 2

The Company’s Comparisons between DG Customers and Non-DG Customers ignore 3

important characteristics of distributed generation and contributions to load diversity. 4

Q. WHAT DOES THE COMPANY ASSERT ABOUT HOW DG CUSTOMERS’ “INTERACTION WITH 5

THE ELECTRIC SYSTEM COMPARE[S] TO OTHER CUSTOMERS?” 6

A. Witness Serna asserts that “distributed generation customers have a significantly different 7

load shape and relationship with the electric system than traditional customers.”11 He 8

then provides Figure 1 of his testimony which shows comparative summer loads for DG 9

net metering Customers and Customers without net metering. 10

11 11 Serna Direct, CS – 52.


19

Witness Serna argues that the bidirectional relationship between the distribution system 1

and distributed generation customers is a key and fundamental distinction of these 2

customers from traditional customers. 3

Q. DO YOU AGREE WITH WITNESS SERNA’S ASSERTION THAT THERE IS A FUNDAMENTAL 4

DISTINCTION BETWEEN DG CUSTOMERS AND NON-DG CUSTOMERS? 5

A. The nature of the bi-directional relationship does represent a difference between DG 6

customers and non-DG customers. Clearly, the underlying tariffs do not account for 7

exported power and thus require a supplemental rider to provide for such accounting and 8

to compensate the DG customer for the generation service that it supplies to the utility at 9

its meter. This difference is properly addressed by developing appropriate compensation 10

for the energy service provided by the DG customer to the utility under Rider 18 but 11

should not be conflated with differences in the costs and revenues associated with service 12

the utility provides to the customer. 13

Q. DOES THE COMPANY’S PROPOSED SAC CONSTITUTE DOUBLE-RECOVERY OF THE 14

DELIVERY CHARGE? 15

A. Yes. When a DG customer exports energy to the grid, it is consumed by neighboring 16

customers who compensate the utility for that service at the full retail rate, inclusive of 17

fully-loaded delivery charges. Therefore, to the extent that DTE’s proposed SAC charge 18

is meant to compensate the utility for delivering the DG customer’s exported power, it 19

represents a double-recovery of the utility’s costs to deliver the DG exports. The utility 20

already recovers those delivery costs once from the neighboring customers to whom the 21

utility actually delivers the exports. Thus, also seeking to recover such costs though the 22

SAC charge imposed on the DG customer would amount to double recovery. 23


20

Q. DO YOU SUPPORT WITNESS SERNA’S ASSERTION THAT THE DIFFERENCE BETWEEN DG 1

CUSTOMERS’ AVERAGE SUMMER LOAD PROFILE AND NON-DG CUSTOMERS AVERAGE 2

SUMMER LOAD PROFILE CONSTITUTE A COST-BASED REASON TO SUPPORT DIFFERENT 3

TREATMENT IN THE PROPOSED RIDER 18? 4

A. No. When Witness Serna raises the “significantly different load shape and relationship 5

with the electric system”, the implication is that the Company incurs different and higher 6

costs to serve the different load shape of DG customers. However, as discussed below, 7

DTE has not conducted a cost-of-service study to measure whether DG customers as a 8

class are more costly to serve than other residential customers. 9

Moreover, allocating costs to DG customers based on their total site load shape does not 10

correspond with the services those customers provided to the utility. The principles of 11

rate regulation allocate costs based on class characteristics, not the characteristics of 12

subgroups within a class. 13

DG customers have chosen one way to manage their own load, but they remain 14

fundamentally residential customers. (As will be demonstrated below, even though the 15

DG customer’s load differs from other loads within the Residential Class, that variation is 16

well within the range of variation of other existing archetypes of customers in the class). 17

It is inappropriate to allocate utility costs to solar customers based on services the utility 18

did not provide. The only appropriate basis for allocating costs is on the services 19

provided by the utility, which for all residential customers, with and without onsite DG, 20

is delivered load (i.e. inflows). 21


21

Q. HOW DO YOU RECOMMEND THE COMMISSION TREATS CUSTOMERS WHO ENGAGE IN 1

ACTIVITIES THAT REDUCE THE AMOUNT OF ENERGY THEY PURCHASE FROM THE 2

COMPANY? 3

A. I recommend that the Commission ensure that all customers who use some type of 4

distributed energy resource (DER) – that is, all customers who choose to install DG, 5

adopt energy efficiency measures, charge an electric vehicle, or utilize any other 6

technologies that modify their consumption of utility-delivered energy – should be 7

treated the same regarding cost of service allocation as their next-door neighbors who 8

have not installed such technologies. Rates that solar and other DER customers pay for 9

energy deliveries from the utility should be based on standard cost-of-service principles 10

applied in an equivalent manner to all other utility ratepayers. 11

Q. WHAT EVIDENCE DOES WITNESS SERNA ASSERT SHOWS HOW A DISTRIBUTED 12

GENERATION CUSTOMER’S INTERACTION WITH THE ELECTRIC SYSTEM COMPARES TO 13

THE AVERAGE CUSTOMER? 14

A. Figure 1 in Witness Serna’s testimony (discussed above) shows the comparative summer 15

loads between DG customers and non-DG customers. 16

This accurately shows the average daily load profile for DG and non-DG customers 17

during the summer months. However, there are several important points about this 18

Figure and this argument in general: 19

1.) The Figure selectively shows the average load profiles during summer months 20

when the differences would be the most pronounced. However, Figure 2 below 21


22

shows the comparative winter (December, January and February) and summer 1

loads from the same data set.12 2

3 Figure 2 4

2.) I would point out that the average profile of one sub-group of customers is not a 5

part of the cost of service study and such an analysis should not serve as the basis 6

for an equitable cost of service rate. 7

3.) As will be shown below, there is considerable variation between different customer 8

archetypes and the variation between different archetypes and the “average 9

12 ELPC Discovery Request 1 Attachment “U-20162 ELPCDE-1.3ab Comparative Summer Loads.xlsx”


23

customer profile” are as large, or larger, than the variations between DG customers 1

and the “average customer.” 2

Q. GIVEN THE DIFFERENCES BETWEEN SUMMER LOAD PROFILES OF DG AND NON-DG 3

CUSTOMERS, IS DIFFERENTIAL TREATMENT OF SOLAR CUSTOMERS FOR RATE DESIGN 4

PURPOSES NECESSARY OR DESIRABLE? 5

A. No. Load profile information is an input to cost of service analysis that forms the basis 6

for rate design. While the load profiles shown in the figures are indeed different, such a 7

difference in and of itself cannot justify separate rate treatment. Additionally, it is 8

important to consider the variation within the customer class before one can determine 9

whether separate rate treatment is warranted. Indeed, the differences between summer 10

load profiles of DG and non-DG customers turns out to be irrelevant to cost to serve these 11

customers, as I will discuss further below. The Company has not made a case that their 12

observation about this difference makes any impact on the cost of serving the rate class. 13

Q. HAS THE COMMISSION PREVIOUSLY ACKNOWLEDGED THAT THERE IS DIVERSITY OF 14

CUSTOMER LOAD IN THE RESIDENTIAL CLASS? 15

A. In its report issued in U-18383, the Staff found that: 16

For example, it is generally agreed that residential customers with air-17 conditioning have a distinctly different load (inflow) profile than non-air 18 conditioning customers. The same with customers that work during the day vs. 19 those that are at home all day, such as the elderly. In Staff’s opinion, the 20 differences between load profiles of other full requirement customer “subgroups” 21 are just as significant as the difference between the DG subgroup and average full 22 requirement customers.13 23

13 Staff Report, pg. 24.


24

Q. HAS VOTE SOLAR PREVIOUSLY EXAMINED THE ISSUE OF LOAD DIVERSITY WITHIN THE 1

RESIDENTIAL CUSTOMER CLASS? 2

A. Yes. Research clearly shows that there is significant diversity within the residential 3

customer classes. Figure 3 shows the results from a study of customers conducted by 4

Arizona Public Service Company.14 This study concluded that considerable diversity 5

exists within the residential class by identifying five archetypes of customers with highly 6

variable load patterns. For context Vote Solar extended APS’s study to compare the five 7

APS-defined customer types to the group of rooftop solar customers within that 8

residential class. 9

In that case, we found that while there was a difference between the rooftop solar 10

customers and other customers, there was also a significant variety of archetypes within 11

the residential rate class. In this context it is easy to see that while the subset of 12

residential customers with rooftop solar have a distinctive load shape, there are many 13

other subsets of residential customers that have just as distinct of a load shape. Indeed, as 14

shown in Table 2 many of these other subsets of customers are much larger in customer 15

number than the group of rooftop solar customers. 16

14 Direct Testimony of Briana Kobor on Behalf of Vote Solar. Arizona Corporation Commission Docket Nos. E-01345A-16-0036 and E-01345A-16-0123. P 69 (Feb 3, 2017). http://docket.images.azcc.gov/0000177081.pdf


25

1 APS’s residential class breaks down into the various customer types as shown in Table 2 2

below. 3

Table 2: APS Residential Customer Class by Customer Type 4 Customer Type Percentage of Customers


26

Weekday Evening Peakers 42% Weekday Steady Eddies 19% Weekday Daytimers 16% Weekday Twin Peaks 10% Weekday Night Owls 10% Rooftop Solar Customers 3%

1

The results from the APS study show that there can be distinct groups of customers at 2

least as numerous as the group of rooftop solar customers who also have highly varying 3

load shapes that have potential implications for cost recovery. As explained above, DTE 4

has made no effort to evaluate and understand this potential variability within the 5

residential customer class and the impact it may have on cost of service. Yet despite the 6

variability identified by Staff in its report and demonstrated through analysis of other 7

utility data, it is only solar customers who DTE has singled out for discriminatory rate 8

treatment. 9


27

Q. WITNESS SERNA POINTS OUT THAT DG CUSTOMERS HAVE SUMMER NET PEAK DEMAND 1

NEARLY HALF A KILOWATT (“KW”) GREATER THAN TRADITIONAL RESIDENTIAL RATE 2

SCHEDULE D-1 CUSTOMERS. (SERNA DIRECT, CS-51) IS THIS RELEVANT TO A COST OF 3

SERVICE DETERMINATION ABOUT DG CUSTOMERS? 4

A. Witness Serna does not conduct sufficient analysis to determine whether or not it is 5

relevant. What really matters is not just how big a DG customer’s peak is, but the 6

complex relationship between the various usage attributes of the customer that cause 7

costs (energy, coincident peak [CP] demand, non-coincident peak [NCP] demand, etc.) 8

and the revenue received from the customer under current rates. It is this quantitative 9

analysis of “cost causation” compared to revenues collected that determines whether 10

customers are covering their fair share of costs. 11

Q. WAS A COST OF SERVICE STUDY CONDUCTED ON THE DG CUSTOMERS? 12

A. No. DTE did not conduct a cost of service study on DG customers. 13

Q. WHAT DID THE STAFF REPORT FIND ABOUT THE COSTS IMPOSED BY DG CUSTOMERS ON 14

THEIR CLASS RELATIVE TO NON-DG CUSTOMERS? 15

A. The Staff found that DG customers actually lower the costs allocated to their class 16

because their use during Monthly System Peak Hours reduce demand during those 17

periods. 18

The results of Staff’s COSS (based on DTEs 2014 inflow NEM data) indicate that on 19

both the production and distribution side, a DG customer would be responsible for a 20

lower total revenue requirement than a similarly-sized non-DG customer. This is intuitive 21


28

as a DG customer would be using its own generation on some of the peak hours (CP and 1

NCP) and would lower the peak measurement for the DG class.15 2

Q. DO SOLAR CUSTOMERS COST LESS TO SERVE THAN NON-NET METERING CUSTOMERS? 3

A. Yes, a number of studies have found that solar customers actually cost less to serve than 4

non-net metering customers.16 The most relevant finding for this case comes from the 5

Staff Report. In an effort to establish a cost-based mechanism, the staff conducted a cost-6

of-service analysis to compare the residential customer class as a whole to residential 7

NEM customers as a distinct customer class, using 2014 data provided by DTE. 8

The Staff Report found that “on both the production and distribution side, a DG customer 9

would be responsible for a lower total revenue requirement than similarly sized non-DG 10

customer.”17 The Staff Report concluded that the Residential Inflow COSS Revenue 11

Requirement per Customer for similarly sized customers showed that DG Customers 12

have a lower total revenue requirement than non-DG customers. 13

Figure 418 14

Production Distribution Total

DG $545.40 $574.14 $1,119.54

Non-DG $648.88 $515.71 $1,162.59

15 Staff Report, pg. 21. 16 See Rebuttal Testimony of Briana Kobor on Behalf of Vote Solar, In the Matter of the Application of Idaho Power Company for Authority to Establish New Schedules for Residential and Small General Service Customers with On-site Generation. Idaho Public Utilities Commission Case No IPC-E-17-13, January 26, 2018. Also, see Crossborder Energy, Response to Net Metering Working Group Sub-group 2, filed October 25, 2017 as Attachment A to the Sub-Group 1 Reply Comments in Arkansas PSC Docket No. 16-027-R. 17 Staff Report, pg. 21. 18 Staff Report, pg. 23.


29

It should be noted, that the Staff also observed that “the average 2014 DG customer is 1

much larger (from an electricity standpoint) than the rest of the residential class.” Thus, 2

there is some apples-to-oranges comparison when comparing DG to non-DG customers. 3

Q. WHAT DO YOU CONCLUDE ABOUT THE COMPANY’S COMPARISON OF DG CUSTOMERS 4

AND NON-DG CUSTOMERS? 5

A. The Company makes a number of assertions about the differences between DG and non-6

DG customers that are either not supported in the record and/or not relevant to 7

establishing an equitable cost of service based rate consistent with Act 341 and the 8

Commission’s Order in 18-18383. 9

System Access Contribution is Not Justified, Not Supported by Evidence, Not Cost 10

Based and Not Just and Reasonable 11

Q. WHAT HAS THE COMPANY PROPOSED FOR THE SYSTEM ACCESS CONTRIBUTION? 12

A. The Company proposed that customers attaching the proposed DG Tariff rider to 13

residential secondary rate schedules, or to commercial secondary rate schedules that do 14

not have delivery demand charges, shall be subject to the SAC charge. The proposed 15

SAC charge would be: 16

1. Residential Customers: $2.31 per kW of installed AC capacity, per month 17

2. Secondary Commercial Customers with no delivery demand charge: $2.28 per kW of 18

installed AC capacity, per month 19

Q. ON WHAT BASIS DOES THE COMPANY PROPOSE THE SAC? 20

A. The Company' justifies the SAC based on the “distribution impacts” of DG. Specifically, 21

Witness Serna indicates, “To complement the inflow/outflow model filed here pursuant 22


30

to Commission Orders in Case No. U-18383, DTE is proposing a System Access 1

Contribution (SAC) to account for the 24/7 optionality all distributed generation 2

customers maintain to use the full capability of the electric system.”19 Further, Witness 3

Serna explains, “DTE is proposing a SAC that assigns a cost per kW AC of nameplate 4

system capacity based on the system-cost responsibility of distributed generation 5

customers.” 6

Q. DO YOU BELIEVE THESE ARE VALID BASES FOR ESTABLISHING THE PROPOSED SAC? 7

A. No. As discussed elsewhere in this testimony, the optionality that all customers have 8

about how and when to use the system is a fundamental characteristic of the utility’s grid 9

management paradigm. Customers have the ability to use their HVAC and other 10

appliances, charge electric vehicles, take energy efficiency measures and make other 11

decisions about their energy use. And for residential and small commercial users, the 12

Commission and the utilities have adopted volumetric rates to send transparent, 13

predictable and actionable price signals about energy usage. The Company even avers to 14

this when Witness Serna says, “The volumetric basis is an insufficient but serviceable 15

approach to recovering fixed utility system costs when loads are stable and predictable on 16

a time horizon consistent with demand related distribution investments.”20 17

However, the SAC violates that principle by removing a significant incentive to reduce 18

energy usage for DG customers. 19

19 Serna Direct, CS – 57. 20 Serna Direct, CS – 60.


31

Q. WHAT DOES THE COMPANY ARGUE ABOUT “OPTIONALITY”? 1

A. Witness Serna also argues that “While distributed generation customers maintain their 2

full electric system use optionality at every point in time, they are not supporting the 3

costs of the infrastructure required for their service.”21 4

As discussed above, the argument for cost-shift is not supported by data or COS based 5

analysis. Witness Serna provides no evidence that DG customers create additional costs 6

to the system, or that the revenue collected from DG customers does not compensate for 7

those costs. 8

Q. WHAT DOES THE COMPANY ARGUE ABOUT INRUSH CURRENT AS AN UNCOMPENSATED 9

COST INTENDED TO BE RECOVERED BY THE SYSTEM ACCESS CONTRIBUTION? 10

A. Witness Serna also asserts that the need for inrush current is an uncompensated cost that 11

is recovered through the SAC.22 This service for supporting motor startup surge current is 12

supplied to customers with and without DG. While solar customer inrush current 13

requirements are not reduced in proportion to their reduction in energy requirements, the 14

Cost of Service Study allocating costs for the residential class already captures this issue 15

through its widely accepted allocation factors. While inrush current is a service, in the 16

most literal sense, it is provided by the whole of the grid system that is already allocated 17

to customers. 18

21 Serna Direct, CS – 60. 22 Serna Direct, CS – 61.


32

Q. IS THE COMPANY’S PROPOSAL COST-BASED? 1

A. No. The Company’s proposal is based on a calculation of replacing the lost revenue that 2

they estimate customers would have contributed to the utility without solar. The 3

Company should base its cost analysis on delivered load, not imputed load. 4

The Cost of Service Study is designed to align the rates customers pay for the services 5

received. However, allocating costs to DG customers based on their total site load in the 6

absence of solar does not align with the services received from the utility. DG customers’ 7

site loads are served only partially by their utility, with their DG systems serving some 8

portion of their loads as well. It is inappropriate to allocate utility costs to solar customers 9

based on services the utility did not provide. The only appropriate basis for allocating 10

costs in the COSS is an allocation based on the services provided by the utility, which for 11

all customers, with and without onsite DG, is delivered load, i.e. inflows. 12

There is no principle of utility regulation that gives utilities a “right” to a certain level of 13

revenue from any given customer. It’s fundamental that if a customer chooses to reduce 14

their consumption (through efficiency, conservation, or DG) they should have the right to 15

do so without the utility penalizing them to make up for “lost revenue.” Penalizing DG 16

customers for lost revenue (as opposed to charging a rate that is based on COS principles) 17

is simply discriminatory 18

Q. WHY IS TOTAL SITE LOAD, RATHER THAN DELIVERED LOAD, AN INAPPROPRIATE 19

MECHANISM? 20

A. Reaching behind the meter and allocating DG customer costs based on total site load 21

(regardless of whether a portion of the load is met by self-generation) is equivalent to 22


33

allocating costs to a customer for the energy they would have consumed from the utility 1

had they not installed energy-efficient windows; or the energy they would have consumed 2

had their kids not gone off to college; or the energy they would have consumed if they 3

were year-round, rather than seasonal, residents. When a customer chooses to install new 4

technology or undergoes a lifestyle change that affects their energy consumption, the 5

services they require of their utility change. As a result, that customer’s cost-causing 6

usage patterns change. However, it would be inappropriate to continue to charge them 7

based on their past usage patterns, or upon their potential future usage patterns. Rather, 8

customers should be charged based on their actual usage, which is measured by their 9

delivered load. 10

Q. WHAT IS THE COMPANY’S RATIONALE FOR THE CALCULATION OF THE SAC? 11

A. The SAC charge is predicated on an under collection from solar customers in terms of the 12

impact on the grid. This is refuted by analysis, described above, which shows that the 13

cost of serving the loads of solar customers is probably less than the cost to serve the 14

average retail customer. Further, solar customers do not impose costs on the grid when 15

they export power; if anything, their exports can contribute meaningfully to deferral of 16

distribution system upgrades by unloading the grid upstream from their location. This 17

“locational value of solar” is a potentially significant benefit of DG and is being actively 18

examined in a number of states. 19

Q. IS THE COMPANY’S PROPOSAL BASED ON INCREMENTAL, MARGINAL OR AVOIDED 20

COSTS? 21

A. The Company does not track incremental cost, so can make no assertion that DG 22

customers impose any incremental costs. In ELPCDE-1.4a, Witness Serna states, “The 23


34

Company as standard practice, does not track incremental costs specific to any given 1

customer (either with distributed generation or without).” Nor does the Company track 2

utility-owned infrastructure for DG customers.23 3

Q. DOES THE COMPANY TREAT DISTRIBUTED GENERATION DIFFERENTLY THAN OTHER 4

FORMS OF LOAD REDUCTION MEASURES THAT CAN BE TAKEN BY CUSTOMERS? 5

A. Yes, the Company appropriately encourages and incentivizes load reduction and load 6

management measures taken by customers through its Energy Waste Reduction 7

programs. These measures encourage customers to take steps to reduce energy load and 8

thus reduce overall system requirements. Similarly, the decision by a customer to install a 9

solar system should be viewed by the Company and the Commission as a decision to 10

reduce their burden on the system. 11

With the System Access Contribution, the Company makes a calculation to estimate the 12

amount of distribution revenue that the customer would have provided to the utility had 13

they not reduced their load through installing a solar system. The Company’s proposal to 14

reward load reduction in one context (energy waste reduction) and punish it in another 15

(solar energy) is inconsistent and discriminatory. 16

Q. IS THE COMPANY’S SAC PROPOSAL CONSISTENT WITH REGULATORY PRINCIPLES OF 17

SENDING ACTIONABLE PRICE SIGNALS TO RATEPAYERS? 18

A. No. The Company’s approach to imposing a fixed fee on customers for the privilege of 19

connecting to their system (contrary to the most basic principles of requiring access to all 20

customers) is not consistent with sound regulatory principles. 21

23 ELPCDE-1.4b, Attached as Exhibit ELP-4 (WK-4).


35

Just as customers have the right to grow and harvest timber on their own land to use for 1

heating their homes, customers have the right to install distributed generation to serve 2

their on-site energy needs. In this respect, the Commission should recognize customers’ 3

rights to choose the amount of energy to purchase from the grid, the amount to self-4

produce and consume on the customer’s side of the meter, and the amount to save 5

through efficiency measures that reduce consumption. This freedom includes the right to 6

install solar generation equipment at the customer’s site and to safely interconnect to the 7

utility grid without discrimination. While any electrical devices connected to the grid 8

must not compromise safety, reliability, or power quality, utilities do not have the right to 9

restrict the decisions of customers regarding how to manage energy use on their own 10

property. 11

Solar penetration levels in the Company’s service territory do not justify 12

extraordinarily punitive DG Tariff policies. 13

Q. ARE THERE REASONS RELATED TO GRID IMPACTS THAT DEMONSTRATE THAT THE 14

COMPANY’S COST SHIFTING ARGUMENT IS SPECIOUS? 15

A. Yes. The penetration of solar in the DTE service territory is de minimus. Even if the 16

Company’s arguments about a cost shift were valid (when I have shown that they are 17

not), it would not impact the rates for DTE’s other customers in a material way. 18

According to the most recent Net Metering & Solar Program Report for Calendar Year 19

2016,24 the penetration of solar DG in the Company service territory is .09% for Category 20

1 DG (20 kW installed capacity and under) and .01% for Category 2 DG (>20 kW – 150 21

24 Michigan Public Service Commission, Net Metering & Solar Program Report for Calendar Year 2016, December 2017.


36

kW installed capacity). As of the end of 2016, there were 1,418 Category 1 customers 1

representing 10.165 MW of installed capacity and 27 Category 2 customers with an 2

installed capacity of 1.561 MW of installed capacity. 3

These penetration levels are significantly lower than the national average penetration rate 4

of 0.4% customer adoption and far lower than customer adoption levels for utilities in 5

Hawaii (8-12%), California (5%), and Arizona (4%).25 6

Q. ARE CURRENT LEVELS OF CUSTOMER-OWNED DG HAVING A SIGNIFICANT IMPACT ON 7

THE OPERATION OF THE COMPANY’S SYSTEM AT THIS TIME? 8

A. No. While Witness Serna points to some instances of theoretical operational issues 9

associated with distributed generation, the Company has acknowledged in discovery in 10

this case that none of these theoretical issues have been observed by DTE. 11

When asked to “describe any and all adverse impacts on its distribution system that the 12

Company has experienced to date as a result of interconnecting DG systems,” the 13

Company replied simply: 14

To date, the Company is not specifically aware of any adverse impacts related to 15 Rider 16 customers.26 16

Q. IS ADOPTION OF DG IN MICHIGAN EXPECTED TO INCREASE OVER TIME? 17

A. Maybe. Current levels of distributed generation adoption were encouraged, in part, by the 18

policies adopted by the Commission that provided fair compensation for the value of DG 19

systems. Likewise, future adoption of distributed generation will depend in large part on 20

25 Galen Barbose, Putting the Potential Rate Impacts of Distributed Solar into Context, Energy Analysis and Environmental Impacts Division Lawrence Berkeley National Laboratory, LBNL-1007060, p. 10 (Jan. 2017), https://emp.lbl.gov/sites/all/files/lbnl-1007060.pdf (“Rate Impacts of Distributed Solar”). 26 ELPCDE-1.12, Attached as Exhibit ELP-5 (WK-5).

https://emp.lbl.gov/sites/all/files/lbnl-1007060.pdf


37

the policies adopted by this Commission. Under a just and equitable DG tariff, it is 1

reasonable to expect that adoption of distributed generation will continue to grow, but 2

even then, it will likely remain at a relatively low level compared to other states. A recent 3

study from Lawrence Berkeley National Lab found that rooftop solar adoption in 4

Michigan would remain the 13th lowest of the lower 48 states in the country as far out as 5

2030,27 accounting for a negligible percentage of retail sales, as shown in Figure 5 below. 6

If the Commission adopts an adverse DG tariff that significantly reduced the value to 7

customers, it is expected that adoption would be even lower.8

9

The National context for developing successors to net metering 10

Q. DID THE COMPANY REVIEW THE NATIONAL CONTEXT AND EXPERIENCES IN OTHER 11

STATES IN PROPOSING A SUCCESSOR TO NET METERING? 12

A. Yes. Witness Serna provides information on a number of states where net metering is 13

being reconsidered. In fact, this is true, and in some cases this reconsideration is 14

27 Including the District of Columbia.


38

resulting in outcomes that are fair and equitable. Among the states where net metering 1

successors are being considered or have been implemented are California, Hawaii and 2

other states that have significantly higher penetrations of distributed generation on the 3

grid. 4

Michigan has not yet begun to approach the level at which distributed generation 5

adversely impacts either the smooth operation of the grid or the economic interests of 6

other customers. In fact, as discussed below, at penetration levels experienced in 7

Michigan generally, and DTE Electric’s service territory specifically, DG is likely to 8

have a positive net impact on the grid and other customers. 9

The Outflow credit proposed is not cost based, is not just and reasonable, and ignores 10

the Commission’s previous Order in U-18383 and staff recommendations. 11

Q. WHAT HAS THE COMPANY PROPOSED AS AN OUTFLOW CREDIT? 12

A. Customers on non-time-based rate schedules will be credited for each kWh of Outflow at 13

the monthly average real-time locational marginal price for energy at the DTE Electric-14

appropriate load node. Customers on time-based rate schedules will be credited for each 15

kWh of Outflow at the monthly average real-time locational marginal price for energy at 16

the DTE Electric-appropriate load node during the relevant time of use pricing period. 17

For the outflow credit, the Company proposed the “DTE Electric-appropriate load node 18

during the time of use period.” 19


39

Q. IS MONTHLY AVERAGE LMP AN ACCURATE MEASURE OF THE ENERGY VALUE OF 1

SOLAR? 2

A. No, the energy value of the exported solar is almost certainly higher than the LMP, if 3

only because of short term market price effects. The exported solar is sold to nearby 4

customers at full retail and displaces the need for the utility to purchase power on the day 5

ahead or hourly market. Less purchases means lower prices, so the exported solar is 6

actually saving money for ratepayers across all energy procurement, not just for the 7

power that solar exports displace. Add to that all the avoided generation, distribution and 8

transmission capacity costs, environmental and social benefits, the possibility of avoided 9

ancillary service costs, and general resiliency benefits, and it is reasonable to conclude 10

that the LMP is not an adequate measure of the value of exported solar. 11

Q. WHAT WOULD BE THE VALUE OF THE OUTFLOW CREDIT PROPOSED BY THE COMPANY? 12

A. In response to discovery, the Company indicated that DECO.NEC is the DTE Electric-13

appropriate load node. The Company also indicated that this is the only Company load 14

node and would be the load node of record for its proposed outflow pricing.28 15

Using data provided by MISO, I calculated the average real-time locational marginal 16

price for energy at DECO.NEC load node and found that in 2017, the average real-time 17

LMP was $0.031.29 18

28 ELPCDE-1.10a, Attached as Exhibit ELP-6 (WK-6). 29 Cite calculation to be provided with workpapers.


40

Q. IS LMP A TRANSPARENT AND PREDICTABLE PRICE SIGNAL TO SEND TO PROSPECTIVE 1

SOLAR CUSTOMERS? 2

A. No, monthly average LMP is an unpredictable and difficult to access measure for most 3

consumers. Company response in ELPCDE-1.10d shows how opaque LMP is and how 4

little they have thought about how they will communicate such prices to their customers. 5

The Company’s response to the request to provide all information that DTE plans to 6

make available to prospective or actual DG customers that will allow such customers to 7

understand the credit that they will receive for each kWh of outflow was this: 8

The Company plans to provide an explanation of outflow credits and how they are 9 calculated for Rider 18 DG customers on its website, once Rider 18 DG is 10 approved. The Company will also be prepared to explain outflow credits to 11 customers who call and inquire about the DG Program. The Company may also 12 leverage the Insight app or other similar communication approaches as 13 appropriate. Additional communication could include making available historical 14 LMP information on the Company website.30 15

In addition, the average monthly LMP for the DECO.NEC load node varies considerably 16

on a monthly basis and is impossible to predict for consumers. As such, it would lack the 17

transparency that is the hallmark of best practices in ratemaking. Figure 6 shows the 18

average monthly real-time LMP for DECO.NEC load node from July 2014 to July 2018. 19

30 ELPCDE-1.10d, Attached as Exhibit ELP-7 (WK-7).


41

1

Q. DOES THE COMPANY PROPOSE TO CREDIT CAPACITY FOR THE OUTFLOW? 2

A. No, the Company argues that there is no capacity value for distributed generation 3

customers. Witness Serna asserts: 4

“Given the unpredictability of distributed generation customer outflow, either due to 5

higher load on-site or lower than expected production, no capacity requirement is offset 6

by the distributed generation and net metering customer.” (Serna Direct, CS – 63) 7

Further, Witness Serna asserts: 8

The proposed avoided cost method assigns significant capacity value to purchased 9 energy. These generators have no temporal production contract with DTE, they 10 have no total production contract with DTE, and their primary purpose is not to 11 provide DTE with energy or capacity but to offset on-site consumption. Simply 12 stated, distributed generation customers cannot be counted on to generate when 13 needed by the DTE system and have no obligation to do so. Therefore, there is no 14 tangible capacity value or capacity offset provided by the distributed generation. 15 (Serna Direct, CS – 64) 16


42

Q. DOES THE MIDWEST INDEPENDENT SYSTEM OPERATOR (“MISO”) PROVIDE CAPACITY 1

CREDIT TO UTILITY SCALE SOLAR? 2

A. Yes, according to the MISO’s Business Practices Manual, MISO credits solar capacity at 3

50% of nameplate capacity for new resources.31 Once a solar resource is in service, the 4

MISO calculation uses the past consecutive three years of hourly net output (in MW) for 5

hours ending 15, 16, and 17 EST from June, July and August. This shows that for 6

purposes of system wide reliability planning, MISO expects that solar is reliability 7

enough to credit, at least partially, for meeting system-wide capacity needs. 8

Q. DOES THE COMPANY BENEFIT FROM A REDUCTION IN ITS CAPACITY REQUIREMENTS 9

DUE TO SOLAR? 10

A. Yes, although MISO does not credit the capacity of behind the meter solar systems, to the 11

extent that DG systems are reducing system load during peak hours during which peak 12

capacity loads are being measured, then the Company’s capacity requirements are lower. 13

Thus, the Company is required to provide less capacity and all customers benefit from 14

this reduced capacity requirement. All production from solar DG, including exports, 15

contributes to providing these reductions in capacity-related costs. 16

Q. ARE THERE OTHER VALUES OF SOLAR THAT ARE NOT RECOGNIZED IN THE COMPANY 17

PROPOSAL? 18

A. Yes, the Company proposal fails to compensate for other values of solar and potential 19

benefits that have been broadly recognized in other states, as discussed further below. 20

With the advent of advanced metering technology, we have an increasingly sophisticated 21

31 BPM-110r19 Appendix V.


43

view of the benefits provided by DG, including the positive dollar impacts on grid 1

operations. The picture that emerges is one of significant value that equals or exceeds 2

average generation market prices. 3

Outflow credits should be cost based and should reflect all avoided costs to the utility. 4

Q. WHAT DID THE COMMISSION STAFF PROPOSE AS AN OUTFLOW CREDIT? 5

A. In the Commission’s Order in U-18383, the Commission said simply that “The Outflow 6

compensation methodology will be established by the Commission in a contested case 7

proceeding.”32 8

The staff observed that: 9

A fair valuation method for DG resources injected into the grid by DG customers consists 10 of two parts: (1) an avoided capital and energy cost; and (2) all other avoided cost or 11 benefit elements such as avoided distribution line losses, transmission and distribution 12 costs, avoided air emission and environmental costs, the solar-fuel price hedge, and 13 reactive supply and voltage control. Many DG workgroup stakeholders were also of the 14 view that all avoided costs and other benefits must be included to set a fair compensatory 15 rate. (Staff Report, page 15) 16

The staff noted that neither they nor DG workgroup stakeholders had had the opportunity 17

to “rigorously quantify a total valuation.” 18

In its conclusion the staff recommended that the Commission adopt the PURPA avoided 19

cost methodology for crediting outflows. Specifically, the Staff Report found: 20

What is available at this time is a proxy generation plant calculation of energy and 21 capacity, grossed up for avoided distribution line losses, and that value is approximately 22 10 cents per kWh (See Appendix E). 23

In addition, the staff indicated that they believe using PURPA avoided cost methodology 24

for crediting outflow had other important benefits. 25

32 Commission Order of April 18, 2018, Exhibit A “Distributed Generation Tariff,” p. 4.


44

Staff believes that the recognition of approved PURPA rates as a proxy for establishing 1

DG program credits is administratively efficient, provides an equitable valuation of 2

energy/capacity resources provided to the grid, and is fair to the balance of full 3

requirements customers who pay for such resources as part of the utility’s resource 4

portfolio.33 5

While the Commission declined to conduct a proceeding to establish a uniform outflow 6

compensation method and instead chose to leave the establishment of the outflow 7

compensation method to be determined in individual proceedings, the Staff did 8

recommend setting an interim compensation price at the DG customer’s power supply 9

component of the retail rate.34 10

Q. DO YOU AGREE THAT THE PURPA AVOIDED COST IS AN APPROPRIATE BASIS FOR THE 11

OUTFLOW CREDIT? 12

A. While there are arguments in favor of using the PURPA avoided cost set for each utility 13

as the basis for the outflow credit, it is problematic as a long run solution for a several 14

reasons. First, there is considerable uncertainty around the methodology for setting 15

PURPA avoided costs. Specifically, Consumers Energy has proposed changing the 16

methodology for their PURPA avoided cost calculation from the proxy plant 17

methodology to one based on competitive bidding. Without taking a position one way or 18

another on that matter, this uncertainty would be a hindrance to setting predictable and 19

transparent rates for outflow crediting going forward. 20

33 Staff Report, p. 16 34 Staff Report, p 17.


45

Q. DOES THE PURPA AVOIDED COST METHOD COMPENSATE ALL VALUES OF DG? 1

A. No. As observed in the Staff Report, the “fair valuation” of DG includes avoided capital 2

and energy costs, but also includes “all other avoided cost or benefit elements.” The Staff 3

Report enumerates the following: 4

1.) avoided distribution line losses; 5

2.) transmission and distribution costs; 6

3.) avoided air emission and environmental costs; 7

4.) the solar-fuel price hedge; and 8

5.) reactive supply and voltage control. 9

There are other values and benefits that were discussed during the DG workgroup process 10

that should be considered in the context of a fair valuation calculation as well. 11

Q. IS THE COMPANY REQUIRED TO PROVIDE A COST-BASED MECHANISM? 12

A. Yes. Act 341 envisions that the process of establishing a cost-of-service based DG tariff 13

begins with the Commission undertaking a formal study. The Commission directed the 14

Staff to lead this study, and the Staff convened a collaborative workgroup process to 15

facilitate its analysis. The Staff has created a sample Inflow/Outflow “tariff” and attached 16

it to the Staff Report as Appendix A. The Inflow/Outflow billing mechanism is 17

recommended as the conceptual framework for establishing a DG program that equitably 18

recovers the cost-of-service. 19


46

The Staff interpreted the word “tariff” in Sec. 6a (14) of Act 341 as providing the 1

Commission broad discretion in the type of billing mechanism, subject only to the 2

requirement that such tariff be “equitable” in the recovery of the “cost of service.”35 3

Q. DOES THE LANGUAGE IN SECTION 177(4) AND (5) OF ACT 295, MCL 460.1177(4) AND 4

(5) LIMIT THE AMOUNT OF THE OUTFLOW CREDIT? 5

A. The Company argued that the use of avoided cost to credit a DG customer’s outflow does 6

not comply with the two compensation methods, locational marginal pricing (LMP) or 7

the power supply component, dictated by Section 177(4). 8

Without giving a legal opinion, I do observe that the Commission has already found that 9

Section 177 “does not apply to any DG billing method, such as the Inflow/Outflow 10

billing mechanism, that implements a COS based tariff under Act 341. Instead, under 11

Inflow/Outflow, a rate (full retail_ is assigned to the energy supplied to the grid by the 12

customer (the outflow).”36 My evaluation of the Company’s proposal is based on the 13

clear direction from the Commission in its Order. 14

Q. IS THE COMPANY’S I/O CREDITING MECHANISM COST-BASED? 15

A. No. 16

Q. IS THERE AN ALTERNATIVE, EXISTING COST-BASED MEASURE OF VALUATION THAT 17

COULD FAIRLY REFLECT THE VALUE OF OUTFLOWS? 18

A. As an alternative approach, I would observe that the outflow credit could be based on the 19

full Power Supply Charge in the Residential Time-of-Day Service Rate (D1.2). This has 20

35 Staff Report, p. 5. 36 Commission Order, p. 15.


47

several advantages to crediting at the rate applicable to the particular customer. Most 1

importantly, this is a cost-based power supply charge that the Commission has already 2

found to be justified under a cost-of-service regime. The time of day crediting also 3

provides a more accurate measure of the energy, capacity and other cost-based values that 4

solar DG provides to the system since the peaks periods in the Time-of-Day Service Rate 5

align well with the production profiles of solar DG. 6

If adopted the following rates would be credited to DG customer outflows (based on the 7

currently approved D1.2 rate): 8

June – October November - May On Peak Hour Capacity + Non-Capacity Energy Outflow Credit

17.48¢ 14.767¢

Off Peak Capacity + Non-Capacity Energy Outflow Credit

5.885 ¢ 5.655 ¢

9

The Residential Time-of Day rate is cost-based and provides accurate and predictable 10

values for DG during the times when DG customers would be exporting to the grid. 11

Q. IS THE TIME-OF-DAY BASED ALTERNATIVE FOR THE OUTFLOW CREDIT COST BASED? 12

A. Yes. The rates in Residential Time-of-Day Service Rate (D1.2) are approved by the 13

Commission as cost based and thus accurately represent the value of the power supply 14

delivered to the utility. 15


48

The Inflow billing rate ignores key cost-based benefits of solar energy that should be 1

credited to customers. 2

Q. HAVE OTHER STATES ALSO PURSUED MORE COMPREHENSIVE VALUATIONS OF THE 3

POWER SUPPLIED BY DG CUSTOMERS IN THEIR EVALUATIONS OF NET METERING 4

POLICIES? 5

A. Yes. Many states have sought to evaluate the benefits of the power produced by solar 6

DG using comprehensive valuations that include, at a minimum, the elements listed by 7

the Staff.37 These states include: 8

• Arizona. The Arizona Corporation Commission issued Decision 75859 in 9

January 2017 in its “Value of Solar” Docket No. E-00000J-14-0023. This 10

decision adopted new methodologies to calculate export rates from solar DG 11

based on either (1) a five-year projection of avoided costs including avoided 12

T&D or (2) recent costs for utility-scale solar PPAs plus an adder for avoided 13

T&D costs.38 14

• The California PUC included these avoided cost elements, and more, in the 15

Public Tool model that it developed as the analytic framework for its evaluation 16

of NEM in Rulemaking 14-07-002, which resulted in Decision 16-01-0144 17

adopted the state’s “NEM 2.0” program. 18

• Georgia has used a detailed Framework for Determining the Costs and Benefits 19

of Solar Generation in Georgia proposed by Georgia Power in its 2016 20

Integrated Resource Plan (Georgia PSC Docket No. 40161). 21

37 Staff Report, p. 15. 38 See ACC Decision 75859, at pp. 106-109 and 147-152.


49

• Minnesota’s Value of Solar process examined and evaluated a comprehensive list 1

of solar benefits that can be used to create a Value of Solar tariff in lieu of net 2

metering.39 3

• Nevada’s PUC in 2015 ended net metering and cut the DG export rate to 2.6 4

cents per kWh, even though it admitted that this was based on quantifying 5

valuing just two of the 11 components to the value of DG.40 After major layoffs 6

in the solar industry, a public outcry, lawsuits, a ballot initiative, and the 7

governor’s replacement of several PUCN commissioners, Nevada re-instated net 8

metering in 2017 using an export rate close to the full retail rate.41 9

• Oregon is evaluating a comprehensive list of solar benefits to determine the 10

Resource Value of Solar in Dockets UM 1710, 1711, and 1712.42 11

The Company’s proposal for the non-refundability of Outflow credits upon program 12

termination are not supported by the record and are unfair. 13

Q. HOW DOES THE COMPANY PROPOSED RIDER 18 DEAL WITH TERMINATION OF THE 14

RIDER EITHER BY THE COMPANY OR BY THE CUSTOMER? 15

A. The Company proposes to make any credit accumulated by the customer non-refundable 16

in both the case in which the customer terminates participation in the Rider or the 17

Company terminates the program. 18

39 Legislation enacted in 2013 (H.F. 729) required the Minnesota Department of Commerce (DOC) to develop a distributed solar valuation methodology. Minnesota investor-owned utilities are permitted to use the approved methodology to create a Value of Solar Tariff (VOST) that would be used in lieu of a net metering. The Minnesota Public Utilities Commission approved the Value of Solar Method in an order dated April 1, 2014 in Docket No. E-999/M-14-65. 40 See PUCN December 23, 2015 Order in Dockets Nos. 15-07-041 and 15-07-042, at pp. 66-67 and 95-96. 41 See PUCN Order in Dockets Nos. 16-06006 et al. issued December 20, 2016. 42 The list of the 11 value elements adopted for inclusion in Oregon’s RVOS is listed in Oregon PUC Order 17-357.


50

Q. IS THIS DIFFERENT FROM THE PROPOSED COMMISSION DG TARIFF IN U-18383? 1

A. Yes. The Commission proposed that upon Company termination of the Distributed 2

Generation Program, any existing credit on the customer’s account will either be applied 3

to the customers final bill or refunded to the customer. The same principle applied to 4

customer-initiated termination. 5

Q. WHAT DO YOU RECOMMEND WITH RESPECT TO BOTH CUSTOMER-INITIATED AND 6

COMPANY-INITIATED TERMINATION OF PARTICIPATION IN RIDER 18? 7

A. The Company’s proposal to change the Commission proposed DG Rider tariff to require 8

forfeiture of DG outflow credits upon termination of participation in the program is not 9

addressed at all in the Company’s testimony. In the absence of any justification for the 10

change in practice related to terminations, the Commission’s original DG Rider with 11

respect to refund of outflow credits is a fair and reasonable and should be adopted. 12

The requirement that existing Rider 16 customers that increase their aggregate 13

capacity move the entire system to Company proposed Rider 18 is unsupported and 14

unreasonable. 15

Q. WHAT DOES THE COMPANY PROPOSE WITH RESPECT TO EXISTING CUSTOMERS 16

PARTICIPATING IN RIDER 16 THAT INCREASE THEIR DG CAPACITY? 17

A. The Company proposed that if existing customer who participates on Rider 16 (the Net 18

Metering program) increases their aggregate generation following the effective date, then 19

all generation on site will be subject to the terms and conditions of the new Rider 18. 20


51

Q. WHAT DO YOU RECOMMEND? 1

A. This proposal is not supported in the record. Existing customers participating in Rider 16 2

should be allowed to have their existing systems continue to participate in Rider 16 under 3

the terms of their existing agreements. 4

The Company’s proposed Rider 18 would have a significant adverse impact on 5

future solar development in Michigan. 6

Q. WHAT IMPACT WOULD THE PROPOSED RIDER 18 HAVE ON EXISTING OR NEW DG 7

CUSTOMERS IF ADOPTED AS PROPOSED? 8

A. I conducted a rate impact analysis on the Company’s proposed Rider 18 in two ways to 9

demonstrate the significant adverse economic impact on solar customers both as a group 10

and using several sample customer configurations. The first analysis was a Hypothetical 11

Customer analysis using data from DOE datasets. The second analysis used existing net 12

metering customer data provided in discovery to examine the impacts that the proposed 13

Rider 18 could have across a large sample of actual systems. 14

Q. PLEASE DESCRIBE THE RESULTS OF THE HYPOTHETICAL CUSTOMER RATE IMPACT 15

ANALYSIS. 16

A. The Hypothetical Customer Rate Impact Analysis selected a typical customer load profile 17

using a data set available from the Department of Energy. The DOE dataset Commercial 18

and Residential Hourly Load Profiles for all TMY3 Locations in the United States 19

includes representative energy use profiles for residential customers throughout the 20


52

United States.43 I selected a load profile for a residential customer in Mt. Clemens, 1

Michigan. For the solar production data, I modeled a 5 kW system located in Detroit, 2

Michigan using default settings on NREL’s PV Watts solar production calculator.44 3

Table 3 summarizes the difference in the savings that an average customer could realize 4

under full net metering compared to the proposed Rider 18. 5

Customer 8,971 kWh/year

Consumption 5 kW Array

Customer Annual Bill with Net Metering

Customer Annual Bill under Company Proposed

Rider 18 Percent Increase in

Customer Bill Total Bill $576 $1,062 84% Thus, my analysis showed that the hypothetical customer would see their annual bill 6

increase by 84% under the Company proposed Rider 18. 7

Q. PLEASE DESCRIBE THE METHODOLOGY OF VOTE SOLAR’S EXISTING CUSTOMER RATE 8

IMPACT ANALYSIS? 9

A. At my direction and under my direct supervision, I worked with Vote Solar’s Regulatory 10

Research Manager Tyler Fitch45 to conduct an analysis of the actual impact that the 11

proposed Rider 18 would have had on all of DTE’s net metering customers using 2017 12

meter data. We used data provided by DTE in 20162-ELPC-DTE-15 to calculate the 13

differences in the savings that actual solar customers on the D1 tariff would have realized 14

compared to full service from DTE without solar, under both traditional net metering and 15

under the new proposed Rider 18. 16

43 Commercial and Residential Hourly Load Profiles for all TMY3 Locations in the United States, available here: https://openei.org/doe-opendata/dataset/commercial-and-residential-hourly-load-profiles-for-all-tmy3-locations-in-the-united-states

44 PVWatts Calculator, National Renewable Energy Laboratory, https://pvwatts.nrel.gov. Detroit Metropolitan Airport was selected as the nearest site with the highest quality weather modelling data. 45 Mr. Fitch’s qualifications and CV, Attached as Exhibit ELP-8(WK-8).

https://pvwatts.nrel.gov/


53

In conducting this analysis, we understand that existing Net Metering customers taking 1

service under Rider 16 will continue to receive service under that Rider for ten years 2

from the original date of enrollment in a net metering program. This analysis simply 3

seeks to show the distribution of impacts across the service territory using actual systems 4

installed by DTE customers. 5

Q. PLEASE DESCRIBE THE FINDINGS OF VOTE SOLAR’S EXISTING CUSTOMER RATE 6

IMPACT ANALYSIS. 7

A. We find that current DTE customers who have elected to generate their own power 8

through rooftop solar stand would suffer tremendously from the Company’s proposed 9

Rider 18. This analysis shows that, on average, more than half of customers’ savings 10

compared to the previous net metering regime would be wiped out by DTE’s proposal. 11

The analysis shows that DG customers would save 58% less under the Company’s 12

proposed Rider 18 than under traditional net metering. Under full net metering, the 13

hypothetical customer would have a simple payback of 24.0 years, which is essentially 14

equal to the expected life of the system (and thus at best a marginal long-term 15

investment). However, under the Company’s proposed Rider 18, that simple payback 16

would extend to 55.7 years which far exceeds the expected life of the system. Even 17

taking into consideration the federal Investment Tax Credit, median solar payback would 18

go from an estimated 16.8 years to 38.9 years. 19

The graph in Figure 7 shows the distribution of lost savings that would result for DTE’s 20

current NEM customers (data sourced from DTE discovery response 20162-ELPC-DTE-21

115 (j)) moving from Rider 16 (net metering) to the proposed Rider 18: 22


54

1

2

Q. DID THE COMPANY’S FILING ANALYZE THE IMPACT THAT ITS PROPOSED RIDER 18 3

WOULD HAVE ON PROSPECTIVE SOLAR CUSTOMERS? 4

A. No. The Company conducted no analysis of the impact that its proposed Rider 18 would 5

have on prospective customers in its direct testimony. 6

Q. DID THE COMPANY ANALYZE THE IMPACT THAT ITS PROPOSED RIDER 18 WOULD HAVE 7

ON PROSPECTIVE SOLAR CUSTOMERS IN RESPONSE TO DISCOVERY REQUESTS? 8

A. No. While they analyzed a previous iteration, there was no analysis conducted of the 9

impact of the final proposal. 10

Q. FINALLY, WHAT IMPACT WOULD THE ADOPTION OF THE COMPANY’S PROPOSED RIDER 11

18 HAVE ON FUTURE ROOFTOP SOLAR DEPLOYMENT IN MICHIGAN? 12

A. Rider 18 as proposed by the Company would have a significant adverse impact on the 13

economic viability of rooftop solar deployment in the DTE Electric service territory. The 14

potential market impacts are significant. Given the significant impact on payback periods 15


55

it is safe to say that the fledgling rooftop solar market in Michigan would fail to take off 1

and may indeed expire completely. 2

An “equitable and just” replacement for the DG Tariff. 3

The Inflow/Outflow billing mechanism can be used to establish a “fair and equitable” 4

use of the grid for DG customers 5

Q. IS THE COMPANY’S PROPOSED RIDER 18 CONSISTENT WITH COMMISSION'S ORDER IN 6

U-18383? 7

A. The Company's filing differs from the proposed DG tariff in the Staff Report, the 8

recommendations of the staff in the Staff Report and from the intentions of the 9

Commission in adopting the Inflow/Outflow mechanism. 10

1.) The Staff Report recommended that there be a capacity credit for outflows. 11

2.) The Staff Report recommended that (DG customers not be subject to any other 12

charges not applied to full requirements customers of the underlying COS rate 13

schedule, such as fixed charges, or standby charges. 14

The Commission should Order the Company to Replace Rider 18 with a DG Tariff 15

consistent with the Commission’s Order in U-18383 which recognizes the full value of 16

energy in the Outflow credit and deletes the System Access Contribution. 17

Q. DO YOU PROPOSE A REPLACEMENT FOR RIDER 18 AND IF SO, PLEASE SUMMARIZE IT? 18

A. Yes, I propose that the Commission order the Company to replace its proposed Rider 18 19

with one that is cost-based and consistent with the Commission’s final order in U-18383. 20

Specifically, I recommend replacing the Company’s proposed Rider 18 with a new Rider 21

18 that does not include a System Access Contribution, bills Inflow at the customer’s 22


56

underlying rate schedule with a credit for generation during inflow to reflect cost-based 1

benefits delivered by DG customers even when they are not exporting, and an Outflow 2

credit that reflects the “fair valuation” referenced in the Staff Report.46 3

Q. WHAT DO YOU PROPOSE FOR INFLOW BILLING? 4

A. As recommended in the Commission Staff Report, the billing rate for all inflows to the 5

customer should be at their applicable rate schedule (i.e. a Full-Service Residential 6

Service Rate Customer on Rate Schedule No. D1 would continue to pay all applicable 7

charges on that rate). In addition, I recommend that a credit be applied to the customer’s 8

inflow rate based on the benefit provided to the lower cost to serve the DG customer. 9

Q. WHAT DO YOU PROPOSE AS A CREDIT FOR OUTFLOW? 10

A. I recommend development of a “fair valuation” as described in the Staff Report based on: 11

1.) An avoided capital and energy cost; and 12

2.) All other avoided cost or benefit elements such as avoided distribution line losses, 13

transmission and distribution costs, avoided air emission and environmental costs, the 14

solar-fuel price hedge, and reactive supply and voltage control. 15

Further, I recommend that the proxy generation plant calculation of energy and capacity, 16

grossed up for avoided distribution line losses is an appropriate starting point for this 17

valuation, but it should include all the values listed above. 18

The most simple and straightforward approach in this case would be to use the proxy 19

generation plant as a basis and include a Market Transformation adder to compensate for 20

46 Staff Report, p. 15.


57

other avoided costs while the Commission continues to refine the calculation of those 1

values. 2

Conclusion 3

The Commission should order the Company to replace the proposed Rider 18 with one 4

that is consistent with sound regulatory principles and the Commission’s Order in U-5

18383. 6

I recommend replacing the Company’s proposed Rider 18 with a new Rider 18 that does 7

not include a System Access Contribution, bills Inflow at the customers underlying rate 8

schedule with a credit for generation during inflow to reflect cost-based benefits 9

delivered by DG customers even when they are not exporting. I recommend the outflow 10

credit be based on a cost-based “fair valuation” as described in the Staff Report. 11



) ) ) ) )

Case No. U-20162

EXHIBITS OF WILL KENWORTHY

ON BEHALF OF


THE ECOLOGY CENTER,


AND VOTE SOLAR

November 7, 2018

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.7 Respondent: P. W. Dennis Page: 1 of 1 Question: Please refer to proposed Sheet No D-112.00, which states that the Inflow

for Full Service Customers “will be billed according to their retail rate schedule, plus surcharges, and Power Supply Cost Recovery (PSCR) Factor on metered Inflow for the billing period or time-based pricing period.”

Please define the “billing period” or “time-based pricing period” for each

customer class. Answer: The proper reference is proposed Sheet No. D-113.00 as reflected on

Exhibit A-16, F10. Billing period refers to the time-period covered in the bill; typically, customers have 12 monthly billing periods annually. Time-based pricing period refers to the fact that some of the rates offered by the Company vary by time of consumption – see the Company’s tariff book for specific time of use periods attributable to specific rate schedules.

Case No. U-20162 Exhibit ELP-1 (WK-1)

Witness: Kenworthy Date: November 7, 2018

Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.24f Respondent: C. Serna / R. Mueller Page: 1 of 1 Question: Please refer to Testimony of Witness C. Serna at 51, Lines 5-13, where

witness Serna states: “[D]istributed generation customers receive a range of additional grid

services from the electric system that are unique to their choice to utility distributed generation. They leverage the electric system above and beyond traditional customers, make more intensive demands of the infrastructure, and generally use the electric system itself as a transactional service provider and balancing resource to meet their energy needs when their generation (primarily solar panels) is not operating at full output or when there are additional electrical demands that solar can’t meet (eg., start-up of large appliances).”

f. Please provide all analyses produced by (or for) the Company that

demonstrates that outflow energy from current net metering customers is ever exported beyond the distribution substation level of the distribution system.

Answer: The Company has not performed such analyses.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.26 Respondent: C. Serna / R. Mueller Page: 1 of 1 Question: Please refer to Testimony of Witness C. Serna at 53. Provide all documentation and analyses produced by the Company related

to the “operation and technical impacts of distributed generation on electric system functions.”

Answer: The Company has not performed an analysis specific to the operational and

technical impacts of distributed generation on the Company’s electric system functions. Attachment “ELPCDE-1.24a The Integrated Grid” discusses perspectives on the operational and technical impacts of distributed generation on electric system functions, generally.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.4b Respondent: C. Serna / R. Mueller Page: 1 of 1 Question: For each interconnected customer with distributed generation, please

provide:

b. A list of the utility-owned equipment for distributed generation customers that is incremental to non-distributed generation customers; and

Answer: The Company does not specifically track utility-owned infrastructure for

distributed generation customers.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.12 Respondent: C. Serna / R. Mueller Page: 1 of 1 Question: Please describe any and all adverse impacts on its distribution system that

the Company has experienced to date as a result of interconnecting DG systems.

Answer: To date, the Company is not specifically aware of any adverse impacts

related to Rider 16 customers.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.10a Respondent: P. W. Dennis/D. M. Arnold Page: 1 of 1 Question: Please refer to proposed Sheet No D-112.00, which states: “Customers on non-time based rate schedules will be credited for each kWh

of Outflow at the monthly average real-time locational marginal price for energy at the DTE Electric-appropriate load node. Customers on time based rate schedules will be credited for each kWh of Outflow at the monthly average real-time locational marginal price for energy at the DTE Electric- appropriate load node during the time of use pricing period.”

a. Define “the DTE Electric-appropriate load node,” and explain how this

node will be determined for each distributed generation (DG) customer on the DTE system.

Answer: The proper reference is proposed Sheet No. D-113.00 as reflected on

Exhibit A-16, F10. DECO.NEC is “the DTE Electric-appropriate load node” at this time. This is the only Company load node and it would be the load node of record for outflow pricing.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.10d Respondent: P. W. Dennis Page: 1 of 1 Question: Please refer to proposed Sheet No D-112.00, which states: “Customers on non-time based rate schedules will be credited for each kWh

of Outflow at the monthly average real-time locational marginal price for energy at the DTE Electric-appropriate load node. Customers on time based rate schedules will be credited for each kWh of Outflow at the monthly average real-time locational marginal price for energy at the DTE Electric- appropriate load node during the time of use pricing period.”

d. Provide all information that DTE plans to make available to prospective

or actual DG program customers that will allow such customers to understand the credit that they will receive for each kWh of outflow. If no information is currently available, explain what information DTE plans to make available to customers.

Answer: The Company plans to provide an explanation of outflow credits and how

they are calculated for Rider 18 DG customers on its website, once Rider 18 DG is approved. The Company will also be prepared to explain outflow credits to customers who call and inquire about the DG Program. The Company may also leverage the Insight app or other similar communication approaches as appropriate. Additional communication could include making available historical LMP information on the Company website.



Page 1 of 1



) ) ) ) )

Case No. U-20162

DIRECT TESTIMONY OF KEVIN LUCAS

ON BEHALF OF


THE ECOLOGY CENTER,


AND VOTE SOLAR

November 7, 2018

Kevin Lucas · Direct Testimony · Page i of 43 · Case No. U-20162

TABLE OF CONTENTS

I. Introduction and Qualifications ............................................................................................................. 1

II. DTE’s Inflow/Outflow Methodology Inappropriatly and Substantially Undervalues Solar PV’s

Contribution ........................................................................................................................................... 5

DTE’s Inflow/Outflow Methodology Undervalues Solar’s Contribution ....................................................... 5

DTE Incorrectly Excludes Line Losses and Capacity Credits from its Outflow Credit ................................. 8

DTE Claims that the Intermittent Nature of DG PV is Disqualifying Despite Supporting a DR Program

That Produces Substantially the Same Outcomes ............................................................................ 13

DTE Conflates the Characteristics of an Individual DG Customer with How the Power System is Designed

and How Costs are Allocated .......................................................................................................... 17

DTE’s Export Valuation is Based on a Misinterpretation of the Underlying Statute .................................. 27

III. The System Access Contribution is Unjustified .................................................................................. 30

IV. DTE’s Proposal to Eliminate Excess Credits is Unjust and Should be Rejected ................................. 35

V. DTE’s DG Tariff Proposal is unnecessary given the low level of penetration of DG PV in its

Territory ............................................................................................................................................... 37

VI. Conclusions .......................................................................................................................................... 41

Kevin Lucas · Direct Testimony · Page 1 of 43 · Case No. U-20162

I. INTRODUCTION AND QUALIFICATIONS 1

Q. PLEASE STATE FOR THE RECORD YOUR NAME, POSITION, AND BUSINESS ADDRESS. 2

A. My name is Kevin Lucas. I am the Director of Rate Design at the Solar Energy 3

Industries Association (SEIA). My business address is 1425 K St NW, Suite 1000, 4

Washington, DC 20005. 5

Q. PLEASE SUMMARIZE YOUR BUSINESS AND EDUCATIONAL BACKGROUND. 6

A. I began my employment at SEIA in April 2017 as the Director of Rate Design. SEIA is 7

the national trade association for the U.S. solar industry. SEIA works with its 1,000 8

member organizations to advance solar power through education and advocacy. It seeks 9

to champion the use of clean, affordable solar in America by expanding markets, 10

removing market barriers, strengthening the industry, and educating the public on the 11

benefits of solar energy. 12

As Director of Rate Design, I work with other members of SEIA’s State Affairs 13

team to engage in various regulatory dockets. I have developed testimony in rate cases 14

on rate design and cost allocation, worked on the New York Reforming the Energy 15

Vision (NY-REV) proceeding on rate design and distributed generation compensation 16

mechanisms, and performed a variety of analyses for internal and external stakeholders. 17

Before I joined SEIA, I was Vice President of Research for the Alliance to Save 18

Energy (Alliance) from 2016 to 2017, a DC-based nonprofit focused on promoting 19

technology-neutral, bipartisan policy solutions for energy efficiency in the built 20

environment. In my role at the Alliance, I co-led the Alliance’s Rate Design Initiative, a 21

working group that consisted of a broad array of utility companies and energy efficiency 22

products and service providers that was seeking mutually beneficial rate design solutions. 23

Additionally, I performed general analysis and research related to state and federal 24

policies that impacted energy efficiency (such as building codes and appliance standards) 25

and domestic and international forecasts of energy productivity. 26


2

Prior to my work with the Alliance, I was Division Director of Policy, Planning, 1

and Analysis at the Maryland Energy Administration, the state energy office of 2

Maryland, where I worked between 2010 and 2015. In that role, I oversaw policy 3

development and implementation in areas such as renewable energy, energy efficiency, 4

and greenhouse gas reductions. I developed and presented before the Maryland General 5

Assembly bill analyses and testimony on energy and environmental matters, and 6

developed and presented testimony before the Maryland Public Service Commission on 7

numerous regulatory matters. 8

I received a Master’s degree in Business Administration from the Kenan-Flagler 9

Business School at the University Of North Carolina, Chapel Hill, with a concentration in 10

Sustainable Enterprise and Entrepreneurship in 2009. I also received a Bachelor of 11

Science in Mechanical Engineering, cum laude, from Princeton University in 1998. 12

Q. HAVE YOU TESTIFIED PREVIOUSLY BEFORE THE MICHIGAN PUBLIC SERVICE 13

COMMISSION? 14

A. Yes, I have. I previously submitted testimony in Case No. U-18149, In the matter of the 15

application of DTE Electric Company for approval of Certificates of Necessity pursuant 16

to MCL 460.6s, as amended, in connection with the addition of a natural gas combined 17

cycle generating facility to its generation fleet and for related accounting and ratemaking 18

authorizations. 19

I also submitted direct and rebuttal testimony in Case No. U-20165, In the matter 20

of the application of Consumers Energy Company for approval of its integrated resource 21

plan pursuant to MCL 460.6t and for other relief. 22

Q. HAVE YOU TESTIFIED PREVIOUSLY BEFORE OTHER STATE UTILITY COMMISSIONS? 23

A. Yes. I have testified before the Maryland Public Service Commission in several rate 24

cases and merger proceedings. Additionally, I have testified before the Maryland Public 25

Service Commission in several rulemaking proceedings, technical conferences, and 26

legislative-style panels, covering topics such as net metering, EmPOWER Maryland 27


3

(Maryland’s energy efficiency resource standard), and offshore wind regulation 1

development. 2

I have also submitted testimony before the Public Utility Commission of Texas, 3

before the Public Utilities Commission of the State of Colorado, and before the Public 4

Utility Commission of Nevada. My complete CV is attached to my testimony as 5

Appendix A. 6

Q. ON WHOSE BEHALF ARE YOU SUBMITTING TESTIMONY? 7

A. I am testifying on behalf of the Environmental Law & Policy Center, the Solar Energy 8

Industries Association, Vote Solar and the Ecology Center. 9

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 10

A. I discuss several aspects of DTE Electric Company’s (DTE or the Company) rate case, 11

with a particular focus on the issues affecting distributed generation (DG) PV. I analyze 12

DTE’s technical and policy approach to DG PV and contrast it with the Company’s 13

approach to other similar non-DG PV policy and programs. I also critique the 14

Company’s Rider 18 proposal showing that it is attempting to relitigate issues that have 15

already been closed by the Commission. Notwithstanding this, I demonstrate that DTE’s 16

proposal is systematically biased against DG PV and is fundamentally unsupported by 17

DTE’s filings. 18

Q. CAN YOU PLEASE DESCRIBE DTE’S PROPOSED DISTRIBUTED GENERATION TARIFF? 19

A. DTE proposes to implement a modified version of the “inflow/outflow” tariff 20

recommended by Staff in its February 21, 2018 report in Case. No. U-18383 (DG 21

Report).1 In DTE’s proposal, instantaneous inflows (i.e. when consumption from the grid 22

exceeds DG generation) would be accumulated separately from instantaneous outflows 23

(i.e. when DG generation exceeds consumption from the grid). Total inflows would be 24

1 Report on the MPSC Staff Study to Develop a Cost of Service-Based Distributed Generation Program Tariff, February 21, 2018, Case No. U-18383.


4

charged at the retail rate, while total outflows would be credited at the Locational 1

Marginal Price (LMP) of MISO Zone 7, DTE’s pricing node. In addition to these 2

charges, DTE proposes a System Access Contribution (SAC) that would be based on the 3

size of a customer’s PV system. As with all residential customers, the Company 4

proposes to increase the monthly customer charge on DG PV customers to $9.00 from 5

$7.50. 6

Q. CAN YOU SUMMARIZE THE CONCLUSIONS THAT YOU REACHED ABOUT DTE’S 7

PROPOSAL? 8

A. There are multiple instances in DTE’s filing when it supports outcomes from non-PV 9

programs and policies but does not support similar outcomes when they come from PV 10

programs and policies. This pervades the Company’s testimony and responses to data 11

requests, and results in a biased proposal that, if enacted, will almost certainly end the 12

nascent DG PV industry in DTE’s territory. 13

The Company’s Rider 18 proposal attempts to relitigate issues that have 14

previously been addressed by the Commission. In doing so, DTE puts forth a proposal 15

that is not cost-based, is systematically biased against DG PV, and is fundamentally 16

unsupported by DTE’s filings. I show that the System Access Contribution concept is 17

fatally flawed and should be rejected. DTE has performed no analysis on the impact that 18

its proposal would have on prospective DG solar customers or on the DG solar industry. 19

What limited support is offered for its proposal is based on hypothetical arguments on 20

what “could” or “might” happen, but when pressed, DTE was unable to demonstrate that 21

it would actually incur any costs as a result of DG PV. 22

At the same time that DTE is advancing a flawed proposal, it attempts to make 23

other modifications to the tariff proposed by Staff that further exacerbate the flaws in 24

DTE’s proposal. 25


5

II. DTE’S INFLOW/OUTFLOW METHODOLOGY INAPPROPRIATLY AND 1

SUBSTANTIALLY UNDERVALUES SOLAR PV’S CONTRIBUTION 2

Q. PLEASE SUMMARIZE YOUR TESTIMONY IN THIS SECTION. 3

A. DTE’s aggressive proposal is out of step with the very small amount of DG PV 4

penetration in its territory. As of the end of 2017, only 1 in 1,342 residential customers 5

had a DG PV system. Despite this, the Company postulates all sorts of major impacts 6

that these systems have on its grid, and uses these arguments to justify an inappropriately 7

low export credit and SAC charge. DTE’s proposal ignores the capacity benefits that DG 8

PV provides and neglects to include line losses. 9

DTE’s Inflow/Outflow Methodology Undervalues Solar’s Contribution 10

Q. PLEASE DESCRIBE DTE’S PROPOSED INFLOW/OUTFLOW METHODOLOGY. 11

A. DTE proposes in this case to implement an Inflow/Outflow (IO) methodology to replace 12

traditional net metering. In this structure, two separate meter registers are used to track 13

and integrate the instantaneous power flows from the grid to the residence (inflow) and 14

from residence to the grid (outflows). The customer is billed the full retail rate for the 15

inflow, and compensated for outflow an “outflow rate” equal to the locational marginal 16

price (LMP).2 Note the IO methodology is separate and distinct from the SAC discussed 17

below. 18

Q. WHAT WAS THE ORIGIN FOR THIS PROPOSAL? 19

A. The Michigan Public Service Commission Staff (Staff) issued a report in February 2018 20

that summarized its efforts to develop a cost of service-based DG program tariff (DG 21

Report).3 In this report, Staff recommended an IO tariff as its solution to the statutory 22

2 Serna Direct at 57-66. 3 Report on the MPSC Staff Study to Develop a Cost of Service-Based Distributed Generation Program Tariff, February 21, 2018, Case No. U-18383.


6

requirement of Act 341 to develop a cost-based DG tariff. While the DG Report contains 1

a similar structure to DTE’s proposal, it differs in critical ways. 2

Q. WHAT ARE SOME OF THESE DIFFERENCES? 3

A. One relates to the value of the outflow credit, and a second (discussed below) relates to 4

the imposition of grid or standby charges. As discussed earlier, DTE erroneously 5

stipulates that Act 341 requires the outflow credit to be equal to either the full retail 6

power supply rate or to LMP, and subsequently recommends LMP. This is the most 7

limited option available. It does not include any credit for avoided capacity, line losses, 8

or deferral of transmission, distribution, or generation assets. 9

By contrast, the DG Report properly recognizes that more than just wholesale 10

energy is avoided by DG resources: 11

A fair valuation method for DG resources injected into the grid by DG customers 12 consists of two parts: (1) an avoided capital and energy cost; and (2) all other 13 avoided cost or benefit elements such as avoided distribution line losses, 14 transmission and distribution costs, avoided air emission and environmental costs, 15 the solar-fuel price hedge, and reactive supply and voltage control. Many DG 16 workgroup stakeholders were also of the view that all avoided costs and other 17 benefits must be included to set a fair compensatory rate.4 18

Staff’s recommendation must be a starting point for the outflow credit, but should 19

not be the end point. While the report also noted that “neither Staff nor stakeholders had 20

an opportunity to rigorously quantify a total valuation,” this does not change what should 21

go into the final valuation.5 In the absence of a more rigorously quantified value, the DG 22

Report did note that the PURPA rate based on the proxy generation plant for avoided 23

energy and capacity, grossed up for avoided distribution line losses, is available and is 24

equal to approximately 10 cents per kWh.6 25

4 DG Report at 15. 5 DG Report at 15. 6 DG Report at 15.


7

Q. DO YOU RECOMMEND THIS VALUE AS THE FINAL OUTFLOW VALUE? 1

A1. No, although it might serve as a reasonable starting point for near-term implementation. 2

As stakeholders gain access to more data and perform more comprehensive analyses of 3

avoided costs, it may be possible to shift to something akin to a “value stack” approach 4

that separately values the many avoided costs and benefits that DG PV provides. In the 5

meantime, the Commission should consider the DG Report’s recommendation on how to 6

best bridge between the current structure and the IO methodology. 7

In addition, Staff notes that a material departure from the full retail rate that is 8 implicit in the current true NEM program could have adverse impacts to the 9 Michigan solar industry, DG market players and utility customers contemplating 10 installation of solar PV systems. In this matter, the Commission could add an 11 interim market transformation adder to the base avoided cost used to compensate 12 DG customer outflow.7 13

Q1. HOW DOES THE DG REPORT’S VALUE COMPARE TO THE ONE THAT DTE PROPOSES? 14

A. DTE’s proposal for outflow credit is LMP at DTE’s MISO node. This is equivalent to 15

the energy-only portion of wholesale power. It does not include any capacity component, 16

does not include line losses, does not include avoided or deferred transmission and 17

distribution cost, does not include hedge value, and does not include reactive support and 18

voltage control. It also does not include any other environmental or non-energy benefits. 19

Under DTE’s proposal, the outflow credit would be equal to “the monthly average 20

real-time locational marginal price for the given month based on the local resource zone 21

of [MISO].”8 This value is unknown in advance and varies from month-to-month. The 22

latest data from MISO indicates that this will be worth between 3 and 3.5 cents per kWh, 23

roughly one-third of the DG Report’s recommendation, which does not include a market 24

transformation adder.9 25

7 DG Report at 17 (emphasis in original) 8 Serna Direct at 62. 9 https://www.misoenergy.org/markets-and-operations/market-reports/#nt=%2FMarketReportType%3AHistorical%20LMP%2FMarketReportName%3AHistorical%20Annual%20Real-Time%20LMPs%20(zip)&t=10&p=0&s=MarketReportPublished&sd=desc

https://www.misoenergy.org/markets-and-operations/market-reports/#nt=%2FMarketReportType%3AHistorical%20LMP%2FMarketReportName%3AHistorical%20Annual%20Real-Time%20LMPs%20(zip)&t=10&p=0&s=MarketReportPublished&sd=desc




8

Q. WHAT IS DTE’S JUSTIFICATION FOR ONLY INCLUDING THE WHOLESALE FUEL AND 1

PURCHASED POWER COMPONENT OF DELIVERED ENERGY AS ITS OUTFLOW RATE? 2

A. DTE makes the blanket claim that energy exported to its system “does not reduce the cost 3

of the Company’s distribution infrastructure nor to the Company’s generation capacity 4

required to serve customer load when their generator is not producing.”10 It continues: 5

Given the unpredictability of distributed generation customer outflow, either due 6 to higher load on-site or lower than expected production, no capacity requirement 7 is offset by the distributed generation and net metering customer...11 8

These generators have no temporal production contract with DTE, they have no 9 total production contract with DTE, and their primary purpose is not to provide 10 DTE with energy or capacity but to offset on-site consumption. Simply stated, 11 distributed generation customers cannot be counted on to generate when needed 12 by the DTE system and have no obligation to do so. Therefore, there is no 13 tangible capacity value or capacity offset provided by the distributed generation.12 14

Q. WHAT IS YOUR RESPONSE TO THIS ARGUMENT? 15

A. It is flawed on multiple fronts. DTE fails to credit exported energy for line losses. It fails 16

to recognize that solar generation at times of high load reduce the Company’s peak 17

demand, which in turn avoids capacity costs from MISO. It conflates the operation of a 18

single customer with how the power system and DTE’s cost accounting actually work. 19

Finally, it disproves its own arguments by recommending compensation in other 20

programs that have the same characteristics it refuses to recognize for DG PV. 21

DTE Incorrectly Excludes Line Losses and Capacity Credits from its Outflow Credit 22

Q. WHY IS THE EXCLUSION OF LINE LOSSES INCORRECT? 23

A. It is indisputable that energy exported onto the distribution grid flows immediately to the 24

nearest load. This is almost certainly the DG customer’s neighbor. Even if the energy 25

10 Serna Direct at 62. 11 Serna Direct at 63. 12 Serna Direct at 64.


9

flowed through the closest transformer, there is almost zero chance that it would flow 1

beyond the local substation given the miniscule fraction of customers that have DG PV. 2

Since this exported energy is being used to meet local loads, it avoids the entire 3

transmission system and almost all of the distribution system. 4

Energy that travels from a centralized power plant through the transmission 5

system, transmission substations, the distribution system, distribution substations, 6

feeders, and step-down transformers experience losses due to electrical resistance. In its 7

most recent line loss study, DTE shows that its system losses were 9.9% and 9.7% of 8

energy from source to sink in July and August, respectively.13 Given these months are 9

the most likely to contain the system peak, they are the most relevant measure of line 10

losses. By using wholesale LMP, DTE improperly assumes that local produces energy 11

offsets no line losses, contrary to its own study. 12

Q. WHY IS IT INCORRECT TO EXCLUDE COMPENSATION FOR AVOIDED GENERATION 13

CAPACITY FOR DG PV CUSTOMERS? 14

A. Generation from DG PV – whether consumed onsite or exported – helps avoid capacity 15

costs by reducing the need to procure capacity from other sources. While the Company 16

supplies much of its capacity through its own generating units, it still purchases capacity 17

from the market. In the current test year, DTE states that it spent about $4.9 million on 18

capacity purchases that were not PA295 or PURPA related.14 To the extent that energy 19

generated from DG PV is able to reduce these purchases, it should be credited for doing 20

so. 21

DG PV also reduces the capacity obligation of DTE in the MISO wholesale 22

market. When MISO calculates a load serving entity’s (LSE) capacity obligations, it 23

does so on the basis of their coincident peak demand. When DG PV produces energy 24

13 ELPCDE-1.28, attached as Exhibit ELP-10 (KL-1). 14 Exhibit A-13 Schedule C4.


10

during peak hours, it reduces the peak demand of DTE as some of the load that would 1

have otherwise been served by central generators is instead served by local generation. 2

This in turn reduces the Planning Reserve Margin Requirement (PRMR) that DTE must 3

meet to demonstrate resource adequacy. DTE acknowledges that it does not adjust its 4

peak demand forecast upward to eliminate the potential reduction of peak demand from 5

DG systems, so the reduction is appropriately incorporated into MISO calculations 6

through a reduction in peak demand.15 7

DG PV can also reduce the need for future capacity. DG PV production is well 8

aligned with system peaks, which tend to be summer weekday mid-afternoons. As more 9

DG PV is added to the system, the total power drawn from the grid during peak hours 10

will be reduced. Rather than building or purchasing incremental capacity, DTE can 11

utilize the DG PV’s generation to meet some of its future load needs. 12

Q. WHAT DATA DO YOU HAVE THAT SHOWS THAT DG PV SYSTEMS PRODUCE ENERGY AT 13

TIMES THAT CAN REDUCE OR OFFSET GENERATION CAPACITY? 14

A. There are multiple sources of data to support this. First, MISO recognizes the capacity 15

contribution that solar makes in its LOLE Study. Utility-scale projects are provided an 16

initial capacity credit of 50% of nameplate capacity based on the technology’s expected 17

performance during high-load hours.16 If actual performance during these hours is 18

higher, the solar resource will get a higher capacity credit. Residential DG systems may 19

not be as optimized as utility-scale systems, and thus may not qualify for the initial 50% 20

value, but this does not mean that their capacity contribution value is zero. 21

The DG Report also recognizes the ability of DG to avoid capacity needs. In 22

Appendix D, Staff presents a calculation for the avoided capacity benefit of outflows. 23

Using a capacity credit of 44% (slightly lower than the 50% for utility-scale projects), 24

15 ELPCDE-5.102d, attached as Exhibit ELP-11 (KL-2) 16 MISO LOLE Study at 22.


11

Staff calculates a capacity credit value of $0.036/kWh.17 This alone is roughly 1

equivalent to the LMP value. 2

Turning to DTE’s own data, the Company acknowledges that PV systems produce 3

power during summer afternoons. In a chart comparing customers with DG to those 4

without DG, the Company shows that DG customers’ net usage is lower than non-DG 5

customers between 9 AM and 7 PM during the summer.18 Summer afternoons is also 6

when the system peaks, making this generation particularly valuable. While it is true that 7

solar does not put out 100% of its nameplate capacity during all hours of the afternoon, 8

this is irrelevant. Many of MISO’s calculations for PRMR are probabilistic; discounting 9

solar to 44% of its nameplate capacity is an appropriate adjustment and accurately 10

captures the likelihood that DG PV will be contributing power during hours of high 11

system load. 12

Q. IF MISO PROCEDURES, STAFF’S REPORT, AND DTE’S OWN DATA SHOW THAT PV 13

SYSTEMS CAN REDUCE CAPACITY NEEDS, WHY DOES DTE REFUSE TO PROVIDE DG PV 14

WITH A CAPACITY CREDIT? 15

A. It is difficult to say. DTE is clearly aware of MISO procedures. It has access to data 16

showing that PV systems produce energy during hours of peak demand. It knows that 17

customers with DG use less energy than customers without DG during summer 18

afternoons. Given this, one can reasonably conclude that the Company is simply biased 19

against DG PV compared to other programs that have similar characteristics. 20

Q. IS DTE OUT OF STEP WITH THE WAY THAT OTHER JURISDICTIONS VALUE DG PV? 21

A. Yes. While utilities often disagree with advocates on exactly what benefits should be 22

included in the avoided cost bucket, DTE’s proposal to offer only LMP is an outlier. 23

Data from a recent report surveyed eleven different value of solar studies performed 24

17 DG Study, Appendix D 18 Serna Direct at 52.


12

across the country that were commissioned by utilities, PUCs, and non-utility 1

organizations.19 While the results were unsurprising, with the utility-drafted studies 2

resulting in the lowest valuations and the non-utility-drafted studies resulting in the 3

highest valuations, every single one of the studies included avoided capacity costs as part 4

of the value. Figure 1 below is taken from that report showing the relative scale of the 5

studies as well as the typical types of avoided costs and benefits that are included. 6

7

Figure 1 - Value of Solar Studies Summary 8

19 Shining Rewards, The Frontier Group. Available at https://environmentamerica.org/sites/environment/files/reports/EA_shiningrewards_print.pdf


13

DTE Claims that the Intermittent Nature of DG PV is Disqualifying Despite Supporting a DR 1

Program That Produces Substantially the Same Outcomes 2

Q. WHAT IS THE NEXT ISSUE YOU SEE WITH DTE’S APPROACH TO DG PV? 3

A2. DTE repeatedly overstates the impact that a single DG customer has on the power grid, 4

attempting to hide behind technical answers that obfuscate and exaggerate how DG 5

systems interact with the power grid. If one were to believe DTE’s position, a single DG 6

system would put such massive burdens on the distribution grid that it is a miracle that 7

the entire system hasn’t come crashing down. 8

Two examples in DTE’s testimony and responses are instructive. The first relates 9

to the Company’s position that the intermittent nature of PV requires that it be discounted 10

entirely as a capacity asset. The second relates to the position that fluctuations in PV 11

generation cause major and immitigable impacts on the distribution system. 12

Q. HOW DOES THE COMPANY DISCUSS THE INTERMITTENT NATURE OF DG PV? 13

A. An example of DTE’s approach is found below: 14

These generators have no temporal production contract with DTE, they have no 15 total production contract with DTE, and their primary purpose is not to provide 16 DTE with energy or capacity but to offset on-site consumption. Simply stated, 17 distributed generation customers cannot be counted on to generate when needed 18 by the DTE system and have no obligation to do so. Therefore, there is no 19 tangible capacity value or capacity offset provided by the distributed generation.20 20 21 The lack of contract requirements for temporal output, total output, or otherwise 22 means that the Company cannot depend on distributed solar generation capacity 23 to meet its system planning requirements. There is no expectation of production, 24 and there is no penalty for non-production. See ELPCDE-2.80a. The physical 25 reality of distributed solar production is that it may produce “at times of system 26 and class peaks”, but on any given day or hour the output is subject to variation.21 27

20 Serna Direct at 64. 21 ELPCDE-5.110a, attached as Exhibit ELP-12 (KL-3).


14

Q. WHAT IS WRONG WITH THIS POSITION? 1

A. DTE’s position that because DG PV generators are not firm, callable resources that they 2

produce no capacity benefits is readily countered by looking at other non-firm, non-3

callable resources that do produce and receive capacity benefits. 4

As discussed earlier, MISO has a methodology to account for the intermittent 5

generation of PV when determining how much credit it gets to meet the Company’s 6

PRMR. PV does not get a 1 to 1 ZRC to MW credit, but rather something lower to 7

reflect the probabilistic nature. But given that the PRMR itself is based on a probabilistic 8

approach to when peak hours will be, there is nothing inconsistent with this methodology. 9

Further, no conventional generator operates with 100% guaranteed output. 10

Conventional generators can trip offline at any time, removing not kWs but potentially 11

GWs of generation immediately. MISO accounts for this risk through its planning 12

reserve margin, which accounts for the probabilistic nature of unplanned generator 13

outages. If MISO can manage outages of multi-GW generators through its standard 14

practices, then surely DTE can manage the occasional multi-kW outage of a DG PV 15

system. 16

Q2. ARE THERE OTHER RESOURCES THAT SHARE THESE CHARACTERISTICS WITH DG PV 17

THAT ALSO OFFSET CAPACITY NEEDS? 18

A. Yes. Demand response (DR) programs operate in a similar manner. DTE offers many 19

voluntary DR programs that compensate customers for reducing their demand during 20

peak times. MISO allows DR resources to help meet a utility’s PRMR in much the same 21

way as a conventional generator, even though – much like DG PV – some of these 22

programs do not require temporal contracts and their primary purpose is to reduce on-site 23

consumption. 24


15

One such program, the Programmable Controllable Thermostat (PCT) is 1

discussed in detail by DTE.22 In this program, residential customers are provided a free 2

thermostat by the Company and required to enroll in the Dynamic Peak Pricing (DPP) 3

tariff. During DPP events, the Company sends a signal to the customer that raises the 4

thermostat by 4 degrees. This signal can be sent between 3 and 7 PM weekdays, up to 20 5

times per year.23 6

Q. DO CUSTOMERS ENROLLED IN THE PCT PROGRAM HAVE A TEMPORAL PRODUCTION 7

CONTRACT OR A TOTAL PRODUCTION CONTRACT WITH THE COMPANY? 8

A. No, they do not.24 9

Q. CAN THE CUSTOMER OVERRIDE THE CONTROL SIGNAL AND RETURN THEIR 10

THERMOSTAT TO THE ORIGINAL TEMPERATURE DURING A DPP EVENT? 11

A. Yes, they can.25 12

Q. IF A CUSTOMER IN THE PCT PROGRAM RETURNS THEIR THERMOSTAT CLOSER TO ITS 13

ORIGINAL TEMPERATURE, DOES DTE CONCEDE THAT THE DEMAND REDUCTIONS 14

GAINED BY THE CONTROL SIGNAL MAY BE REDUCED? 15

A. Yes, it does.26 16

Q3. DOES THE COMPANY AGREE THAT IF CUSTOMERS REDUCE THEIR USAGE DURING PEAK 17

HOURS THAT THIS COULD RESULT IN A REDUCTION OF FUTURE DISTRIBUTION, 18

GENERATION, AND TRANSMISSION COSTS? 19

A. Yes. When asked this question, the Company replied: 20

Lowering peak usage through demand response programs between the hours of 3 21 to 7 pm during high loads could translate into the reduction of future costs for 22 customers. It could reduce the need to acquire additional generation capacity in 23 MISO or alternatively build new capacity to satisfy future demand needs. To the 24

22 Dimitry Direct at 10-16. 23 Dimitry Direct at 10. 24 ELPCDE-2.81c, attached as Exhibit ELP-13 (KL-4). 25 ELPCDE-2.52b, attached as Exhibit ELP-14 (KL-5). 26 ELPCDE-5.104, attached as ExhibitELP-15 (KL-6).


16

extent that demand response programs reduce peak usage on overloaded circuits, 1 then it may also be possible to delay or avoid some distribution or transmission 2 investments in specific areas. 3

Q. DOES THE COMPANY CURRENTLY COMPENSATE CUSTOMERS IN THE PTC PROGRAM OR 4

THOSE WHO PURCHASE SIMILAR THERMOSTATS THAT ALLOW THE CUSTOMER TO 5

REMOTELY CONTROL THEIR HVAC SETTINGS? 6

A. Yes. DTE provides free thermostats to customers in the PCT program. All reduction in 7

usage is credited at the retail rate, which during DPP events is a massive $1.01/kWh, 8

more than five times the normal retail rate, and nearly 30 times as high as DTE’s 9

proposed outflow credit. Additionally, DTE provides a $75 rebate on Wi-Fi-enabled 10

thermostats.27 11

Q. WHAT DO YOU CONCLUDE FROM THE DISPARATE TREATMENT OF CUSTOMER WITH DG 12

PV AND CUSTOMERS IN THE PCT PROGRAM? 13

A. There is no justifiable basis for the Company’s incongruent approach to these two 14

resources. Demand reductions from the PCT program are accepted by MISO as a 15

capacity resource, do not require contracts with DTE, allow the customer to override and 16

potentially eliminate peak demand reductions, and are acknowledged by the Company to 17

have the ability to reduce the need for additional generation, transmission, and 18

distribution assets. 19

DG PV reductions also are accounted for by MISO to reduce the PRMR, also do 20

not require contracts with DTE, also sometimes provide and sometimes do not provide 21

demand reductions, but DTE steadfastly refuses to give any credit to DG PV for its 22

ability to reduce the need for additional generation, transmission, and distribution assets. 23

The Company tries to parse these differences by claiming that DG is primarily 24

designed to offset on-site usage28 and that PTC participants are provided an incentive to 25

27 ELPCDE-2.81e, attached as Exhibit ELP-16 (KL-7). 28 Serna Direct at 64.


17

reduce their usage,29 but these claims simply do not change the undeniable fact that DG 1

PV can and does provide capacity and can be used to meet DTE’s needs. DTE’s proposal 2

to exclude capacity credit from its outflow credit should be rejected. 3

DTE Conflates the Characteristics of an Individual DG Customer with How the Power System is 4

Designed and How Costs are Allocated 5

Q. HOW DOES DTE GENERALLY SPEAK OF DG PV SYSTEMS AND DG CUSTOMERS? 6

A. The Company frequently discusses the “unique” characteristics of customers with DG 7

systems, attempting to delineate the way in which these customers interact with the 8

power grid from non-DG customers. DTE attempts to cast DG PV customers as so 9

fundamentally different in their use of the grid that they threaten the reliability of the 10

distribution grid and burden other customers with additional costs. In doing so, however, 11

DTE mistakenly ignores how the actual power grid operates and how costs are allocated 12

amongst classes and customers. 13

Q. DO YOU HAVE AN EXAMPLE OF HOW DTE DISCUSSES DG CUSTOMERS? 14

A. Yes. There are many examples interspersed in DTE’s testimony and responses to data 15

requests. A typical example follows: 16

[D]istributed generation customers receive a range of additional grid services 17 from the electric system that are unique to their choice to utility distributed 18 generation. They leverage the electric system above and beyond traditional 19 customers, make more intensive demands of the infrastructure, and generally use 20 the electric system itself as a transactional service provider and balancing 21 resource to meet their energy needs when their generation (primarily solar panels) 22 is not operating at full output or when there are additional electrical demands that 23 solar can’t meet (e.g, start-up of large appliances).30 24

29 ELPCDE-2.81c, attached as Exhibit ELP-13 (KL-4). 30 Serna Direct at 51.


18

Q. IS THE COMPANY ABLE TO SUPPORT THIS STATEMENT? 1

A. No. Provided the opportunity to support its statements, the Company was unable to do 2

so: 3

• When asked to provide documentation to support the assertion that DG customers 4 “make more intensive demands of the infrastructure”, DTE replied “The 5 Company has not developed or reviewed documentation of the impacts of 6 distributed generation customers on the Company’s system.”31 7

• When asked to provide all analyses that demonstrates that outflow energy from 8 net metering customers is ever exported beyond the distribution substation level 9 of the distribution system, the Company confirmed it “had not performed such 10 analyses.”32 11

• When asked to explain if the Company had studied or calculated the benefits 12 provided by DG customers to the distribution grid (to see if there were benefits 13 that offset the supposed “intensive demands”), the Company confirmed it “has not 14 performed such study or calculation”33 15

• When asked to provide all documentation and analysis produced by the Company 16 related to the “operation and technical impacts of distributed generation on 17 electric system functions”, the Company replied that it “has not performed an 18 analysis specific to the operational and technical impacts of distributed generation 19 on the Company’s electric system functions.”34 20

• When asked to provide the most recent marginal cost study, including any 21 calculation that the Company has conducted of its marginal costs for distribution 22 capacity (to quantify the supposed impact that the “intensive demands” incur), 23 DTE replied that it “has not performed such a study or analyses.”35 24

Q. WHAT IS THE RHETORICAL DEVICE THAT DTE USES WHEN DISCUSSING DG IN THIS 25

MANNER? 26

A. Implicit in descriptions such as those above is that DG customers assume they are 27

disconnected from the distribution grid and meet all of their electrical power and energy 28

needs from their systems. DTE then points out that this is not the case, and tries to show 29

that they not only are reliant on the distribution system, but they place extraordinary 30 31 ELPCDE-1.24a Revised, attached as Exhibit ELP-17 (KL-8). 32 ELPCDE-1.24f, attached as Exhibit ELP-18 (KL-9). 33 ELPCDE-1.24g, attached as Exhibit ELP-19 (KL-10). 34 ELPCDE-1.26 Revised (quoting Serna Direct at 53), attached as Exhibit ELP-20 (KL-11). 35 ELPCDE-1.27, attached as Exhibit ELP-21 (KL-12).


19

burdens on the system. This framing is then used to justify unrealistically low 1

compensation for DG PV systems. 2

Q. ARE DG PV CUSTOMERS GENERALLY DISCONNECTED FROM THE GRID? 3

A. No. DG customers are generally connected to the grid, and SEIA supports charging DG 4

customers for their fair use of the grid and compensating for the fair value of their 5

generation. But as discussed throughout this testimony, DTE’s proposal does not charge 6

DG customers for their fair use of the grid and does not compensate them for the fair 7

value of their generation. 8

Q. ARE DG PV CUSTOMERS SUFFICIENTLY DIFFERENT FROM OTHER CUSTOMERS IN THE 9

WAYS THAT AFFECT THE DESIGN AND OPERATION OF THE POWER GRID? 10

A. No. DTE tries to obfuscate this point repeatedly. It talks about all of the unique 11

characteristics of DG PV customers, how they burden the grid, and how they are more 12

expensive to serve. While DG PV customers do have different usage characteristics from 13

other residential customers, so too do customers with air conditioners, or customers in 14

apartments, or customers in rural locations. The DG Report summarizes this point well, 15

and is worth quoting at length: 16

However, despite the fact that a reasonable analytical approach is available to 17 create separate COS rate classes for DG customers, methods for setting DG rates 18 that require withdrawing DG customers from the greater class-COS allocations in 19 a COSS create a significant regulatory-policy inconsistency. Similarly, significant 20 diversity between other full requirement customer subgroups has not been 21 considered by the Commission as rising to a level that would justify the parceling 22 out of the overall (e.g. residential class) into various subclasses. 23

For example, it is generally agreed that residential customers with air-24 conditioning have a distinctly different load (inflow) profile than non-air 25 conditioning customers. The same with customers that work during the day vs. 26 those that are at home all day, such as the elderly. In Staff’s opinion, the 27 differences between load profiles of other full requirement customer ‘subgroups’ 28 are just as significant as the difference between the DG subgroup and average full 29 requirement customers. 30


20

Staff strongly believes that separating existing COS rate classes into customer 1 sub-groups is a slippery slope that should be carefully considered so as not to 2 harm the greater public interest. Separating customers having significant 3 commonality into unique COS subclasses begs the question of when to stop the 4 subdivision process. For example, even within the DG subgroup, there can be 5 large differences in load profiles that are a function of the level of generation 6 capacity vis-à-vis total annual load. Further increasing the complexity of a 7 potential class subdivision process is the expectation that DG customers may 8 install energy storage systems that modify their load profile. The issue of when to 9 stop the division process could become intractable once regulators move down 10 that path. 11

As noted earlier, DG is only one of many items that cause diversity within a class. 12 Currently in a COSS study, there are no separate classes for DG customers. Given 13 that there are relatively few DG customers, COSS theory would not support 14 splitting those customers into a separate class. DTE has just under 2 million 15 residential customers of which DG customers number about 1,500. With a class 16 composed of 2 million customers, the differences between individual customers 17 are smoothed out and reasonable rates can be designed. There is a legitimate 18 concern that if a COSS class is created for a relatively small group of customers 19 because they have the DG characteristic in common, other non-DG characteristics 20 that they do not have in common could result in rate design that adversely affects 21 some of the customers within the class.36 22

Q. IN WHAT WAYS DOES THE TESTIMONY OF DTE RUN COUNTER TO THIS CONCLUSION? 23

A. While the Company does not propose to separate DG customer into their own class, it 24

repeatedly tries to draw a distinction between DG and non-DG customers through 25

technical and engineering examples, discussing “inrush current”, “waveform harmonics”, 26

and “electromagnetic inertia”. Despite its effort, the Company is consistently unable to 27

demonstrate that any of these hypothetical issues are actually occurring or increasing 28

costs. 29

This approach is evident in the following response to the straight-forward 30

question “Please provide all analyses that the Company performed that demonstrate a 31

36 DG Report at 24-25.


21

relationship between the size of a DG system and the cost of serving a customer with that 1

DG system.” The Company’s response in part was: 2

In general, a customer with a larger DG system needs a larger transformer and 3 larger conductors just as a customer with a larger load needs a larger service. 4 There may be required changes to relays, fuses and other protective devices – as 5 size goes up or there is increased penetration of generation in a local area this 6 becomes more common. They may require capacitor banks and statcoms, again as 7 the size (or number in close proximity) the likelihood increase. Similar 8 comparisons can be drawn for a dozen more classes of equipment and cost 9 categories.37 10

Buried in this answer are two important facts – (1) the Company does not have 11

any analysis to support its position that customers with larger DG systems incur more 12

costs, and (2) the Company is speculating when it claims that customers with larger DG 13

may require larger transformers and conductors, changes to relays, fuses, and other 14

protective devices, and may require capacitor banks and statcoms. 15

Q. IS THE COMPANY ABLE TO PROVIDE EXAMPLES OF GRID UPGRADES THAT WERE 16

SPECIFICALLY NEEDED DUE TO DG SYSTEMS? 17

A. Generally, no. DTE could not identify any specific instance of DGs triggering upgrades 18

of feeders,38 changes of fuses,39 or installation of other protective devices,40 new 19

capacitor banks,41 or new statcoms.42 DTE claims that some small transformers had to be 20

replaced, but it does not track these upgrades.43 It also states that it has had to change 21

relay settings and timings that were incompatible with larger concentrations of DG, but 22

does not clarify whether this is standard procedure as loads on a feeder change for other 23

reasons.44 24

37 ELPCDE-2.50h, attached as Exhibit ELP-22 (KL-13). 38 ELPCDE-5.99b, attached as Exhibit ELP-23 (KL-14). 39 ELPCDE-5.99d, attached as Exhibit ELP-24 (KL-15). 40 ELPCDE-5.99e, attached as Exhibit ELP-25 (KL-16). 41 ELPCDE-5.99g, attached as Exhibit ELP-26 (KL-17). 42 ELPCDE-5.99h, attached as Exhibit ELP-27 (KL-18). 43 ELPCDE-5.99a, attached as Exhibit ELP-28 (KL-19). 44 ELPCDE-5.99c, attached as Exhibit ELP-29 (KL-20).


22

The initial response and subsequent follow up illustrate DTE’s repeated approach 1

in this case. The Company lays out hypothetical problems that DG PV could cause, 2

using this to justify its policy positions. But when pushed, is unable to support its 3

original position. 4

Q. ARE THE TECHNICAL AND ENGINEERING FACTORS IMPORTANT TO CONSIDER IN 5

DISTRIBUTION SYSTEM DESIGN AND OPERATION? 6

A. Yes, but DTE’s positioning of the issue skews how the power grid is designed and the 7

degree of resilience that is built into the system. Further, some of the engineering issues 8

it claims are related to DG PV would more likely be associated with large industrial 9

customers rather than with small residential customers. For instance, DTE posits that: 10

Utility best practice is that the distribution system is always sized so that if local 11 generation is lost or local load is lost that the system can handle that load or 12 supply from that system. This prevents the customer who accidently loses their 13 generation from potentially burning out the distribution system from inrush 14 current and also protects the system from potential back feed that is more than the 15 system was designed for.45 16

The notion that a residential customer could “burn out the distribution system” if 17

its DG system tripped offline is absurd on its face. The loss of a 5 kW system on a feeder 18

that serves multiple MW of load is simply a non-issue. While this is something to be 19

considered for large industrial customers with their own on-site generation, those 20

customers are often served with their own dedicated equipment, whereas residential 21

customers share most distribution equipment with scores or hundreds of other customers. 22

Similarly, the chance that a typical residential customer would cause reverse 23

power flows sufficient to damage any piece of equipment that serves the customer is also 24

exceedingly unlikely. The worst-case scenario, such as a large, isolated, rural customer 25

at the end of a long feeder with a dedicated transformer, would be flagged during the 26

45 ELPCDE-2.50i, attached as Exhibit ELP-30 (KL-21).


23

interconnection process to prevent such damage. But this customer would be the 1

exception, not the norm. 2

Q. DOES MICHIGAN HAVE INTERCONNECTION STANDARDS THAT GOVERN THIS PROCESS? 3

A. Yes. Michigan’s interconnection standards incorporate national standards such as IEEE 4

1547 and require that DG interconnection is done safely and maintains the reliability of 5

the grid. If a system wishes to interconnect to DTE’s system, the Company will perform 6

an analysis to determine whether it can safely and reliably connect to the system, or 7

whether the connection would cause voltage or other issues that may require grid 8

upgrades. This process is required for every DG PV system that interconnects, meaning 9

that every system that is approved by DTE to connect to the grid has passed this 10

screening. 11

Q4. HOW DOES DTE ATTEMPT TO DISTINGUISH THE LOAD CHARACTERISTICS OF DG PV 12

CUSTOMERS FROM OTHER CUSTOMERS? 13

A. DTE speaks multiple times about the risk that rapid changes in DG PV generation causes 14

to the distribution grid. It talks about DG’s inability to provide sufficient “inrush 15

current” and complains about the effect of minute-to-minute variability of DG generation 16

on the grid. It tries to distinguish the impact on the grid of reductions in load from DG 17

and reductions in load from energy efficiency or demand response.46 18

Q5. DO YOU FIND THESE ARGUMENTS CONVINCING WHEN CONSIDERING HOW THE 19

DISTRIBUTION GRID IS DESIGNED AND OPERATED? 20

A. No. With the exception of the meter and service drop, and with the occasional rural 21

customer with a dedicated transformer, the distribution grid serving residential customers 22

is not designed to serve the load of an individual customer, but rather the diversified load 23

of all customers connected to the equipment. There is inherent benefit from this load 24

diversity; peaks and valley are smoothed out, rapid fluctuations are tempered, and 25

46 ELPCDE-2.51a, attached as Exhibit ELP-31 (KL-22).


24

individual usage is blended with scores or hundreds of other customers. Distribution 1

systems take advantage of this fact to extract efficiencies in scale; serving 10 customers 2

does not require 10 times the capacity of serving 1 customer, and serving 1,000 3

customers does not take 100 times the capacity of serving 10 customers. 4

Suggesting that DTE’s distribution system is being threatened by its residential 5

DG PV customers is farcical. Currently, there is one residential DG PV customer per 6

1,342 non-DG customers. The number of DG customers could increase 1,000%, and 7

non-DG customers would still outnumber DG customers by 134 to 1. The cycling of air 8

conditioning, refrigeration, ventilation, heating, cooking, and lighting needs of the 1,342 9

non-DG customers far exceeds any impact that a single DG PV customer could have on 10

the grid. 11

DTE admits that the distribution system is designed for the diversified load of its 12

customers, not the individual load of single customer.47 It acknowledges that feeders and 13

substations serve dozens or hundreds of customers with intra-minute variations in load 14

due to variations in usage of individual customers.48 And yet the Company continues to 15

insist that DG PV customers “make more intensive demands of the infrastructure” while 16

simultaneously offering no proof. Even if this were true in the instance of a single DG 17

customer (which the Company’s own data contradicts), it is clearly not true when the DG 18

customer is aggregated with other customers. 19

Q. IS THE RATE THAT RESIDENTIAL CUSTOMERS ARE CHARGED BASED ON THE LOADS OF 20

INDIVIDUAL CUSTOMERS OR BASED ON THE AGGREGATE USAGE OF THE CLASS? 21

A. They are based on the aggregate usage of the class. DTE allocates different costs in 22

different ways. Some costs are allocated based on the total residential class load during 23

the system peak, some based on the relative size of class peaks, some based on the total 24

47 ELPCDE-5.107a, attached as Exhibit ELP-32 (KL-23). 48 ELPCDE-5.103a, attached as Exhibit ELP-33 (KL-24), ELPCDE-5.103b, attached as Exhibit ELP-34 (KL-25).


25

non-coincident peak of classes, and some based on the total sales of the class. However, 1

no costs are allocated based on the energy usage or demand of an individual customer. 2

For all the reasons discussed in the DG report quoted above, there is no basis for 3

separating DG customers into their own class for cost allocation purposes. 4

DTE is not proposing in this proceeding to separate DG customer into their own 5

class for cost allocation purposes (although other utilities have advanced this proposal). 6

Yet DTE repeatedly attempts to highlight costs and burdens that individual DG customers 7

might incur through their usage of the system. Even though the majority of these claims 8

turned out to be unsupported, the Company continues to advance this narrative. 9

Q. DO YOU HAVE OTHER EXAMPLES OF HOW DTE’S TESTIMONY REGARDING DG PV IS 10

UNSUPPORTED? 11

A. Yes. On multiple occasions, DTE made strong claims in its testimony about the negative 12

impact of DG PV on the system and the lack of reliability to justify its positions. But 13

upon further questioning, DTE could provide no proof of these erroneous claims. Time 14

and time again, what was asserted strongly in testimony proved to be unsupported. 15

Below are a sample of the ways in which DTE characterized DG PV in its testimony, 16

followed by responses to data requests that directly contradict its testimony. 17

• “DG customers, as described in the example provided, put more stress and thus 18 drive more costs than customers who reduce usage through energy efficiency. The 19 DG customer is still using the same amount of energy (from two sources) so his 20 or her inrush current requirements are the same as before installing DG. 21 Furthermore, the DG customer drives additional costs due to the ramping nature 22 of their generation which changes from minute to minute due to cloud cover 23 passing through. In addition, the Company also needs to maintain backup 24 capacity to serve the DG customer’s entire load, which has not changed simply 25 due to the installation of DG and DTE might need to serve the entire load with 26 little notice if the distributed generation equipment might be offline for any 27 reason.”49 28

49 ELPCDE-2.51a, attached as Exhibit ELP-31 (KL-22).


26

o Upon further questioning, DTE was not able to identify any additional 1 costs due to the ramping nature of DG PV generation,50 does not adjust its 2 forecast upward to account for DG PV, 51 could not identify any backup 3 capacity that is maintained to serve DG PV customers’ load,52 and could 4 not put a price on the value of providing “inrush current”.53 5

• “Unlike a customer with a small DG system, the customer who is trying to 6 become more “energy efficient” does not rely on the grid to export power, their 7 load reduction is more consistent over the day (less variability), and even though 8 DG systems are producing, DG customers continue to rely on the grid for intra-9 minute increments when appliances turn on and require more voltage than can be 10 supported by their DG systems.”54 11

o Upon further questioning, DTE was not able to show that any equipment 12 was affected by load variability,55 confirmed that non-DG customers also 13 have intra-minute load variations that can be handled by the distribution 14 grid. 56,57 15

• “Inverter based PV has a tendency to change output by 40% or more in less than 16 1/60th of second. This rapid change of output can impact the life of distribution 17 equipment.”58 18

o Upon further questioning, DTE could not point to any circumstances 19 which would cause an inverter-based PV system to change output by 40% 20 or more in less than 1/60th of a second,59 could not identify how often this 21 occurred,60 and deflected a question on how fast clouds would have to be 22 moving to cause this type of a drop,61 which hides the absurd answer that 23 clouds would have to be travelling at hundreds of miles per hour to 24 traverse a typical residential system in order to cause this drop in 1/60th of 25 a second. 26

• “In discussing two reports that analyzed the financial impacts of net metering and 27 purported to show a cost shift to non-DG customers, the Company stated: “The 28 sum of these cost shifts is borne by the rest of the rate class, a group which has 29

50 ELPCDE-5.101, attached as Exhibit ELP-35 (KL-26). 51 ELPCDE-5.102d, attached as Exhibit ELP-11 (KL-2). 52 ELPCDE-5.102e, attached as Exhibit ELP-36 (KL-27). 53 MECNRDCSCDE-1.11, attached as Exhibit ELP-37 (KL-28). 54 ELPCDE-2.51b, attached as Exhibit ELP-38 (KL-29). 55 ELPCDE-5.103a, attached as Exhibit ELP-33 (KL-24), ELPCDE-5.98a, attached as Exhibit ELP-39 (KL-30). 56 ELPCDE-5.103b, attached as Exhibit ELP-34 (KL-25). 57 ELPCDE-5.103c (referring to ELPCDE-5.103b), attached as Exhibit ELP-40 (KL-31). 58 ELPCDE-2.72a, attached as Exhibit ELP-41 (KL-32). 59 ELPCDE-5.106b, attached as Exhibit ELP-42 (KL-33). 60 ELPCDE-5.106c, attached as Exhibit ELP-43 (KL-34). 61 ELPCDE-5.106d, attached as Exhibit ELP-44 (KL-35).


27

made no affirmative choice to provide such support and has no opportunity to 1 opt-out. This violates cost of service principles.”62 2

o Despite citing these studies as support for the purported cost-shift, the 3 Company would not adopt in full all methodologies, analyses, and 4 conclusions reached by the studies63, confirmed that other intra-class cost 5 shifts exist between different types of customers (such as between rural 6 and urban customers, between single-family residents and apartment 7 customers, and between customers with air conditioning or customers 8 without air conditioning),64 and confirmed that those customers also have 9 made no affirmative choice to provide such support and have no 10 opportunity to opt out.65 Finally, the Company has not even quantified the 11 types of intra-class cost shifts that is already caused by the natural 12 variation in residential customer usage.66 13

Time and time again, the Company made claims that were ultimately 14

unsupported. This was not an isolated incident, as seen by the examples above. Rather, 15

this bias against DG PV permeated DTE’s testimony. 16

DTE’s Export Valuation is Based on a Misinterpretation of the Underlying Statute 17

Q. WHAT IS DTE’S PRIMARY JUSTIFICATION FOR ITS EXPORT CREDIT VALUATION? 18

A. Company Witness Serna points to PA 341, Section 177(4) and (5)67 as being “highly 19

relevant and applicable to this proceeding and clearly define certain implementation 20

boundaries and requirements of a new tariff.”68 He continues: 21

Although I am not an attorney and don’t proposes to offer a legal opinion, it 22 seems clear to me that the plain language of these statutory provisions precludes 23 compensating distributed generation customers for anything other than the 24 statutorily predetermined value of their generation.69 25

62 Serna Direct at 56. 63 ELPCDE-2.74, attached as Exhibit ELP-45 (KL-36). 64 ELPCDE-5.108b, attached as Exhibit ELP-46 (KL-37). 65 ELPCDE-5.108c, attached as Exhibit ELP-47 (KL-38). 66 ELPCDE-5.108d, attached as Exhibit ELP-48 (KL-39). 67 MCL 460.1177(4) and (5) 68 Serna Direct at 48. 69 Serna Direct at 49.


28

Mr. Serna reiterates this view later, stating “I don’t see how this language in Michigan 1

law would permit implementation of an avoided cost or other construct that deviates from 2

Section 177(4)(a) or (b).”70 3

Q. HAS DTE MADE THIS ARGUMENT PREVIOUSLY? 4

A. Yes. In its comments in Case. No. U-18383, it makes the same argument when 5

addressing Staff’s proposal in the Staff DG Report: 6

The Company believes that Staff’s proposed DG Tariff as contained in its DG 7 Report, conflicts with Section 177(4) with respect to the credits applied to DG 8 excess generation… Therefore, DTE Electric, consistent with MCL 460.1177(4), 9 would choose one of the two methods listed in the statute to credit DG customers 10 in the Company’s next rate case filed after June 1, 2018.71 11

Q. WHAT WAS THE COMMISSION’S RESPONSE TO THIS ARGUMENT? 12

A. In its order in Case No. U-18383, the Commission unambiguously ruled that this 13

argument was flawed: 14

In their comments, DTE Electric and Consumers averred that the Staff’s 15 Inflow/Outflow billing mechanism conflicts with Section 177(4) and (5). The 16 utilities argue that subsection (4) prescribes the compensation for all excess 17 generation, whether defined on a total outflow basis or on a net excess basis 18 (outflow minus inflow), and that such compensation is limited to one of two 19 options, LMP or the power supply component of the full retail rate. The 20 Commission disagrees with this interpretation.72 21

Q. GIVEN THE COMMISSION’S ORDER ON THIS ISSUE, WHAT DO YOU RECOMMEND? 22

A. The Commission reached a decision regarding the relevance of the legislative 23

justification that DTE used in its comments in Case No. U-18383. There have been no 24

factual changes between then and now to justify reversing course. Notwithstanding this, 25

DTE advanced this same argument in the current proceeding as the key basis for its 26

proposal. 27

70 Serna Direct at 65. 71 DTE Comments dated March 12, 2018, Case No. U-18383 at 9-10 (emphasis in original). 72 Order dated April 18, 2018, Case No. U-18383 at 13.


29

DTE was granted permission by the Commission to advance an alternative DG 1

tariff in addition to filing the standard Inflow/Outflow tariff. I recommend that DTE’s 2

alternative be judged on its own merits based on principles of sound regulatory design, 3

not as the only required by the underlying statute. 4


30

III. THE SYSTEM ACCESS CONTRIBUTION IS UNJUSTIFIED 1

Q. WHAT IS THE PROPOSED SYSTEM ACCESS CONTRIBUTION CHARGE? 2

A. The SAC is a charge based on the size of a PV system that DTE proposes to apply to all 3

DG PV customers not on a demand-based tariff. The SAC would be equal to $2.31/kW 4

and $2.28/kW per month for residential and small commercial customers, respectively.73 5

Q. WHY DOES DTE CLAIM THAT IT NEEDS A SAC? 6

A. DTE claims that all distribution costs are fixed, and that the reduction of inflow kWh due 7

to DG PV meeting some of the customers’ needs causes the DG PV customer to 8

underpay for their usage of the grid. As the Company puts it, “[w]hile distributed 9

generation customers maintain their full electric system use optionality at every point in 10

time, they are not supporting the costs of the infrastructure required for their service.”74 11

Q. DOES DTE ACTUALLY KNOW WHAT THE MARGINAL COST OF ITS DISTRIBUTION 12

SERVICE IS? 13

A. No. When asked to provide its most recent marginal cost study, DTE replied that it “has 14

not performed such a study or analyses.”75 15

Q. HAS DTE EVER STUDIED WHAT BENEFITS DG PV CAN PROVIDE TO THE DISTRIBUTION 16

GRID? 17

A. No. When asked if the Company has studies or has calculated the benefits provided by 18

distributed generation customers to the distribution system, DTE replied that it “has not 19

performed such study or calculation.”76 20

73 Exhibit A-16 Schedule F9. 74 Serna Direct at 60. 75 ELPCDE-1.27, attached as Exhibit ELP-21 (KL-12). 76 ELPCDE-1.24g, attached as Exhibit ELP-10 (KL-19).


31

Q. DOES DTE KNOW HOW ITS PROPOSAL WILL AFFECT PROSPECTIVE DG PV 1

CUSTOMERS? 2

A. No. When asked to provide all bill impact analyses that have been conducted on the 3

effect of the proposed DG tariff changes (including the SAC) compared to customers 4

without DG and customers currently taking service under Rider 16, DTE replied it “has 5

not completed a bill impact analyses comparing the effect”.77 6

Q. WHAT DO YOU TAKE FROM THIS STATE OF AFFAIRS? 7

A. DTE’s lack of consideration of these important issues is stunning. The Company claims 8

that DG PV customers are not paying their fair share of distribution costs, but it has never 9

quantified the marginal cost of new distribution infrastructure. It has also never studied 10

the benefit that DG PV can provide to the system to defer or delay these infrastructure 11

investments. It has not even considered how its proposal will impact prospective DG PV 12

customers. By advancing its proposal with so little insight on these critical questions, 13

DTE is demonstrating that it simply does not care about the DG PV industry or whether 14

customer have access to DG PV in the future. 15

Q. HOW WAS THE LEVEL OF THE SAC DETERMINED? 16

A. The Company calculated the SAC to recover revenue equivalent to the distribution 17

charge multiplied by the amount of generation that is self-consumed. In other words, the 18

Company intends to charge DG PV customers for their full imputed load rather than their 19

actual inflow from the grid. This means that an average DG customer would be charged 20

the same distribution costs whether they had a PV system or not. 21

77 ELPCDE-2.84, attached as Exhibit ELP-49 (KL-40).


32

Q. DOES THE COMPANY PROVIDE ENERGY TO THE DG PV CUSTOMER EQUAL TO THE FULL 1

IMPUTED LOAD OR EQUAL TO ITS ACTUAL REQUIREMENTS? 2

A. DTE only supplies energy for the DG PV customer’s actual need. Energy that is 3

generated by the DG PV system and consumed onsite is not supplied by DTE. And yet 4

DTE proposes to charge DG PV customers for this unused energy. 5

Q. DOES DTE CHARGE CUSTOMERS WHO REDUCE THEIR USAGE THROUGH ENERGY 6

EFFICIENCY OR DEMAND RESPONSE BASED ON THEIR IMPUTED TOTAL LOAD? 7

A. No. Customers who reduce their usage through energy efficiency or demand response 8

are able to reduce their bill based on the full retail rate (including the full distribution 9

rate) and are not charged an additional fee based on imputed usage. For customers on 10

certain tariffs, such as the DPP tariff discussed earlier, these load reductions can be 11

especially valuable. By singling out DG PV customers and subjecting them to a charge 12

based on imputed load rather than actual load, the SAC is clearly discriminatory. 13

Q. DOES THE DG STUDY DISCUSS WHETHER BILLS SHOULD BE BASED ON ACTUAL OR 14

IMPUTED LOAD? 15

A. Yes, and it concludes that DG PV customers should be billed based on their actual usage 16

and not their imputed load. Further, it found that additional costs such as fixed “grid” 17

charges or standby charges should not be levied. 18

The Inflow/Outflow billing method is sufficiently flexible to accommodate 19 alternate rate designs such as time-based pricing, or multi-part rates such as those 20 including demand charges. It should be noted that if the underlying rate schedule 21 includes demand charges, a DG customer’s billing demand would be based on the 22 customer’s metered power inflows, not imputed total site usage. 23

It was further found that equity between full requirements customers and DG 24 customers requires that DG customers not be subject to any other charges not 25 applied to full requirements customers of the underlying COS rate schedule, such 26 as fixed “grid” charges, or standby charges. Equivalent and non-discriminatory 27 treatment for retail purchases by both full-service customers and DG customers 28


33

ensures that DG customers are assessed no more and no less than their fair use of 1 the grid.78 2

Q. GRANTING THAT THE SAC CHARGE IS NOT JUSTIFIABLE, IS DETERMINING IT THROUGH 3

THE SIZE OF THE PV SYSTEM A COST-BASED APPROACH? 4

A. No. DTE admits that the decision to base the SAC on the size of the DG PV system was 5

not cost-based. 6

Given the calculation was based on customers’ average inflow, outflow, and 7 generation, it is reasonable to base the collection on the average installed 8 nameplate capacity. The Company also wanted to develop a charge for customers 9 who are used to paying fixed charges that was easy to understand.79 10

Using the system size in this way does not result in a cost-based charge. If a 4 11

kW system were installed on a large customer’s house and on a small customer’s house, 12

they would both be charged the same amount through the SAC charge. However, the 13

large customer almost certainly imposes higher costs on the system than does the smaller 14

customer. 15

Q. WHAT HAPPENS TO THE ENERGY THAT IS EXPORTED FROM A DG PV SYSTEM? 16

A. It flows to the nearest load, which will almost certainly be one of the DG PV system 17

owner’s neighbors. 18

Q. DOES DTE CHARGE THE NEIGHBOR FOR THIS DELIVERED ENERGY? 19

A. Yes. Even though the energy only traversed a small fraction of the distribution system, 20

none of the transmission system, and did not lose roughly 10% of its energy through line 21

losses, DTE charges the neighbor the full retail rate for delivering this power. 22

78 DG Report at 3. While the quote discusses rate schedules with demand charges, the concept applies equally to volumetric tariffs as well. 79 ELPCDE-2.50g, attached as Exhibit ELP-50 (KL-41).


34

Q. IF DTE ALREADY CHARGES THE OTHER CUSTOMER FOR THE DELIVERY, WOULD IT BE 1

DOUBLE-CHARGING FOR DISTRIBUTION SERVICES IF IT ALSO CHARGED A SAC TO THE 2

DG PV CUSTOMER? 3

A. Yes. By failing to credit the DG PV customer for distribution costs on exported energy, 4

and by charging the neighbor its full distribution rate to deliver the energy, DTE is over-5

collecting revenue. 6

Q. WHAT DO YOU RECOMMEND WITH REGARD TO THE SAC CHARGE? 7

A. It should be rejected entirely. DTE justifies the SAC through assumptions about the cost 8

and benefits of installing DG PV systems on the distribution grid, but it has not done the 9

basic studies to determine what these costs and benefits are. It has not determined how 10

its proposal will impact potential DG PV customers. It proposes to charge a DG PV 11

customer for something that it did procure from the Company (i.e. its self-consumed 12

generation). Finally, its proposal is not cost-based and would lead to a double-recovery 13

of distribution costs. The SAC is a poorly conceived charge and DG PV customers 14

should not have to be subject to it. 15


35

IV. DTE’S PROPOSAL TO ELIMINATE EXCESS CREDITS IS UNJUST AND SHOULD 1

BE REJECTED 2

Q. IN ITS OWN DG TARIFF PROPOSAL, HOW DOES DTE PROPOSE TO HANDLE EXISTING DG 3

CREDITS IF A CUSTOMER LEAVES THE DG PROGRAM OR IF THE DG PROGRAM IS 4

TERMINATED? 5

A. DTE would require the DG PV customer to forfeit their excess credits. 6

Upon customer termination from the Distributed Generation Program, any 7 existing credit on the customer's account will be forfeited. Upon Company 8 termination of the Distributed Generation Program, any existing credit on the 9 customer's account will be forfeited.80 10

Q. DOES THE STAFF REPORT CONTAIN THIS LANGUAGE? 11

A. No. The DG Tariff proposed by staff states that “any existing credit on the customer's 12

account will either be applied to the customer's final bill or refunded to the customer. The 13

Company will refund to the customer any remaining credit in excess of the final bill 14

amount.”81 15

Q. WHAT IS DTE’S JUSTIFICATION FOR THIS EXTREME MEASURE? 16

A. The Company claims that Act 342, Section 177(4) prevents customers from “cashing 17

out” any excess credits: “If customers who terminate from the program could ‘cash out’ 18

any remaining outflow balance when service was terminated, the limitation on using the 19

credits to only offset power supply charges would essentially be null.”82 20

Q. HAS DTE MADE THIS CLAIM BEFORE? 21

A. Yes. In Case No. U-18383, DTE made the same argument that Section 177(4) prohibits 22

DG credits from reducing distribution or transmission charges. However, the 23

Commission disagreed: 24

80 Standard Contract Rider No. 18 proposed tariff language. 81 Exhibit A-16 Schedule F10.1 82 ELPCDE-2.37, attached as Exhibit ELP-51 (KL-42).


36

In comments, DTE Electric and Consumers made the argument that any DG 1 credit cannot be used to reduce distribution or transmission charges. This is an 2 incorrect interpretation of Section 177(4). The relevant subsection (4) provision 3 states, “[n]otwithstanding any law or regulation, distributed generation customers 4 shall not receive credits for electric utility transmission or distribution charges.” 5 This exclusion refers to the formula for calculating compensation, which is 6 expressed in the dual credit pricing options (LMP or power supply component 7 excluding transmission charges), that immediately follows the prohibition. Under 8 any reasonable interpretation, the transmission and distribution exclusion cannot 9 refer to the level of accrued credits that can be applied to the customer bill for the 10 following billing period since subsection (4) expressly allows the offset of the 11 total power supply charges (which include transmission charges). Clearly, the 12 transmission and distribution exclusion only applies to the modified net metering 13 formula for calculating credits for the portion of outflow that exceeds inflow. 14

Further, if the credit limitation applied across the board, i.e., to total outflow, then 15 both true net metering and modified net metering would be prohibited by 16 subsection (4) since both billing methods credit power inflows at the full retail 17 rate (which includes transmission and distribution charges). The utilities’ 18 interpretation of Section 177(4) sets the statute in conflict with itself and is thus 19 erroneous.83 20

Q6. GIVEN THIS, WHAT DO YOU RECOMMEND? 21

A. I recommend that adopt the language proposed by staff if a customer leaves the DG 22

Program or if the DG Program is cancelled. DTE’s proposal is not only contrary to the 23

underlying statute, it is needlessly harmful to DG PV customers. 24

83 Order dated April 18, 2018, Case No. U-18383 at 14.


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V. DTE’S DG TARIFF PROPOSAL IS UNNECESSARY GIVEN THE LOW LEVEL OF 1

PENETRATION OF DG PV IN ITS TERRITORY 2

Q. DOES SEIA HAVE A POSITION ON WHEN THE POLICY OF NET METERING SHOULD BE 3

REVISITED? 4

A. Yes. As discussed in SEIA’s Principles for the Evolution of Net Energy Metering and 5

Rate Design,84 the penetration of DG PV should be “the leading threshold criteria” when 6

evaluating a successor to net energy metering (NEM). While the specific level depends 7

on the specifics of a given state, a materiality threshold of 5% penetration is reasonable. 8

Even though Michigan has enacted legislation that had advanced the NEM-successor 9

discussion, the degree of DG PV penetration in DTE’s territory still remains important 10

context. Contrary to DTE’s interpretation, the statute provides flexibility on how to 11

implement successor DG tariffs, and the magnitude of the impact of these successor 12

tariffs is important to consider in setting equitable policy. 13

Q. HOW MANY DG PV CUSTOMERS DOES DTE CURRENTLY HAVE? 14

A. DTE reports that 1,520 residential customers and 310 commercial and industrial (C&I) 15

customers have active DG systems. Of these, 1,488 residential and 282 C&I customers 16

have DG PV systems. 17

Q. HOW MANY CUSTOMERS DOES DTE CURRENTLY HAVE? 18

A. DTE reports that it has 1,997,994 residential and 217,054 C&I customers “excluding 19

duplicates”.85 This implies that DG PV customers make up 0.074% of residential 20

customers and 0.13% of C&I customers. There is one DG PV system for every 1,342 21

residential customers on DTE’s system. 22

84 Available at https://www.seia.org/sites/default/files/NEM%20Future%20Principles_Final_6-7-17.pdf 85 U-20162 Rate Design Model.xlsx

https://www.seia.org/sites/default/files/NEM%20Future%20Principles_Final_6-7-17.pdf


38

Q7. HOW MUCH DG PV IS INSTALLED ON DTE’S SYSTEM? 1

A. DTE reports that there are 9,521 kW and 4,525 kW of DG PV installed by residential and 2

C&I customers, respectively.86 3

Q. WHAT IS THE PEAK DEMAND OF DTE’S SYSTEM? 4

A. The five-year average peak of DTE’s full-service load is 10,869 MW. This means that 5

DG PV represents just 0.13% of the system’s peak load. 6

Q. HOW MUCH ENERGY DO THE RESIDENTIAL DG PV SYSTEMS GENERATE AND EXPORT IN 7

A YEAR? 8

A3. The exact amount is not reported, but DTE does indicate that the average residential DG 9

customer produces 7,432 kWh from a 6.7 kW system.87 Using the specific production of 10

1,109 kWh/kW, the entire class of residential DG PV customers produce about 10,560 11

MWh per year. DTE also reports that the average customer exports 4,374 kWh, 12

producing a specific export rate of 653 kWh/kW.88 Applying to the total residential DG 13

population, this means that roughly 6,200 MWh are exported per year. The remainder of 14

the PV production is consumed onsite by the customers. 15

Q. HOW MUCH ENERGY DOES THE ENTIRE RESIDENTIAL CLASS PURCHASE FROM DTE? 16

A. DTE reports residential class sales of 14,901,667 MWh.89 DG PV generation represents 17

just 0.07% of total sales, while DG exports represent just 0.04% of total sales. 18

Q. WHAT AMOUNT OF REVENUE DOES DTE PROPOSE TO COLLECT THROUGH ITS SAC? 19

A. DTE proposes a residential SAC of $2.31 per installed kW per month.90 While the 20

charge will only apply to new DG customers, a useful benchmark is to calculate how 21

much it would collected based on the currently-installed quantity of PV. If every 22

86 ELPCDE-1.15. 87 Exhibit A-16 Schedule F9. 88 Exhibit A-16 Schedule F9. 89 U-20162 Rate Design Model.xlsx 90 Exhibit A-16 Schedule F9.


39

residential customer who had a DG PV system were charged the SAC, DTE would 1

collect roughly $264,000 per year. 2

Q. HOW DO THESE LEVELS COMPARE TO THE TOTAL REVENUE THAT DTE PROPOSES TO 3

COLLECT FROM RESIDENTIAL CUSTOMERS? 4

A. DTE is requesting to earn $2,571,253,000 per year from the residential class.91 Of this, 5

$1,186,594,000 is classified as distribution revenue.92 6

Q8. WHAT DOES THE MASSIVE DISPARITY IN THE LEVELS OF THESE FIGURES REPRESENT? 7

A. Even under DTE’s flawed logic behind the SAC, the total amount of the distribution 8

“cross subsidy” from all existing DG customers would amount to just 0.022% of 9

distribution revenue and 0.01% of overall revenue. If the $264,000 were collected from 10

all residential customers, it would cost each just over one penny per month. It would take 11

non-DG customers seven-and-a-half years to pay even $1.00 at this rate. And even as 12

negligible as this amount is, it is still conservative as it does not include any benefits that 13

DG PV can provide, such as delaying or deferring distribution upgrades. The amount of 14

hand-wringing in DTE’s testimony and data responses over an issue that is so far 15

removed from material levels suggests that its posturing is not borne out of actual 16

concerns of cross-subsidization. 17

Q. DO THESE LEVELS OF PENETRATION AND REVENUE MEET ANY REASONABLE DEFINITION 18

OF “MATERIAL”? 19

A. No. 0.07% of customers and sales is nowhere close to material. 0.13% of peak demand 20

is negligible. A penny per month is de minimus under any reasonable definition. Absent 21

the specific statutory direction to evaluate NEM, there would be no reason to have these 22

discussions given the level of DG penetration in DTE’s territory. 23

91 DTE Application, Attachment 2. 92 U-20162 Rate Design Model.xlsx


40

Q. CAN YOU PUT THE HYPOTHETICAL “COST SHIFT” TO NON-DG CUSTOMERS FROM DG 1

SYSTEMS IN CONTEXT? 2

A. DTE proposes to spend $2.42 million on “general advertising expenses” in the projected 3

test period.93 Residential customers are responsible for contributing about half of the 4

proposed revenue requirement, meaning that DTE is asking residential customers to pay 5

roughly $1.2 million per year for the Company to advertise. . 6

DTE also proposes to spend roughly $1.6 million on “Skype Video Audio 7

Collaboration”94 and $3.0 million on “2018 Emergent” innovation, described by the 8

nonsensical consulting jargon of “capital investment in innovation and emergent needs 9

focused on delivering value faster by reducing cycle times.”95 I highlight these expenses 10

not to suggest that DTE’s employees will fail to benefit from these programs but rather to 11

contrast the magnitude of costs that DTE expects its residential customers to pay for its 12

own projects with the supposed subsidy they are supplying to DG customers. 13

93 Exhibit A-13 Schedule C9. 94 Exhibit A-12 Schedule B5.7.1 95 Exhibit A-12 Schedule B5.7.5


41

VI. CONCLUSIONS 1

Q. WHAT IS YOUR OVERALL CONCLUSION OF DTE’S DG PROGRAM PROPOSAL? 2

A. DTE’s program would make DG PV uneconomic at today’s prices. By dropping the 3

outflow credit to LMP, and by adding in an SAC charge based on undelivered energy, 4

DTE will extend the payback period of DG PV beyond the useful life of the system. 5

The DG Report did a high-level analysis of the economics of different DG 6

programs (NEM, modified NEM, IO, and Buy-All Sell-All) and found that – even 7

without the SAC charge – lowering the export credit to LMP would push the payback 8

period to roughly 35 years.96 Adding the SAC charge on top of this would push this 9

payback even further out. Even if costs fell 26% from today’s level to $2.50/watt 10

installed, the DG Report shows that the LMP outflow credit would still have a payback 11

period that exceeds the life of the system, again before the SAC charge is applied.97 12

Q. WHAT DO YOU RECOMMEND THE COMMISSION DO IN THIS CASE? 13

A. I recommend that the Commission reject DTE’s proposed SAC charge and outflow 14

credit. The Commission should temporarily set the outflow credit at the value calculated 15

by Staff in Appendix E of the DG Study report (roughly $0.104/kWh) and strongly 16

consider implementing a market transition adder to help the DG PV market adjust to the 17

new paradigm. I recommend the Commission reject DTE’s language related to the 18

forfeiture of excess generation credits and instead use the language in the Commission-19

approved DG Tariff. I also recommend the Commission direct Staff to continue to 20

advance the quantitative analyses on avoided costs and other benefits, with a longer-term 21

goal to replace the market transition adder with a fuller spectrum of avoided costs and 22

benefits that were discussed by advocates in the stakeholder meetings. 23

96 DG Report at 30. 97 DG Report at 32.


42

Q. DOES THIS CONCLUDE YOUR TESTIMONY? 1

A. Yes. 2



) ) ) ) )

Case No. U-20162

EXHIBITS OF KEVIN LUCAS

ON BEHALF OF


THE ECOLOGY CENTER,


AND VOTE SOLAR

November 7, 2018

Case No. U-21062 Exhibit ELP-10 (KL-1)

Witness: Lucas Date: November 7, 2018

Page 1 of 13

DTE Electric Company MPSC Case No. U-18091

Requestor: ELPC-1 Request No. ELPCDE-1.5

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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.102d Respondent: M. B. Leuker Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.51a. The reply states: “In addition, the Company also needs to maintain backup

capacity to serve the DG customer’s entire load, which has not changed simply due to the installation of DG and DTE might need to serve the entire load with little notice if the distributed generation equipment might be offline for any reason.”

d) Does the Company adjust its peak demand forecast upward to eliminate

the potential reduction of peak demand caused from DG systems? Answer: No, not at this time. As the amount of installed DG systems are very small.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.110a Respondent: C. Serna Page: 1 of 1 Question: Refer to Company’s response to ELPCDE – 2.80b.

a) Does the lack of a temporal production contract, a lack of a total production contract, or that the primary purpose of distributed solar generators is not to provide the Company with energy or capacity but to offset on-site consumption change the physical reality that distributed solar generation can and does produce energy at times of system and class peaks? If the answer is anything other than an unqualified no, please explain in detail.

Answer: The lack of contract requirements for temporal output, total output, or

otherwise means that the Company cannot depend on distributed solar generation capacity to meet its system planning requirements. There is no expectation of production, and there is no penalty for non-production. See ELPCDE-2.80a. The physical reality of distributed solar production is that it may produce “at times of system and class peaks”, but on any given day or hour the output is subject to variation.

Attachments: n/a



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.81c Respondent: I. Dimitry Page: 1 of 1 Question: Refer to Serna Direct at 64, which states: “These generators have no

temporal production contract with DTE, they have no total production contract with DTE, and their primary purpose is not to provide DTE with energy or capacity but to offset on-site consumption. Simply stated, distributed generation customers cannot be counted on to generate when needed by the DTE system and have no obligation to do so. Therefore, there is no tangible capacity value or capacity offset provided by the distributed generation.”

c) Confirm that participants in the Programmable Controllable Thermostat

program have no temporal production contract with the Company and have no total production contract with the Company. If deny, please explain.

Answer: Confirmed. However, unlike DG, the primary purpose of demand response

programs is to provide DTE with capacity and the customers have agreed to terms and conditions under the program to serve this purpose. Further, the programs are designed with incentives to encourage participants to provide that capacity when called upon to do so by DTE.

Attachments: n/a



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.52b Respondent: I. M. Dimitry Page: 1 of 1 Question: Refer to Dimitry Direct at 10.

b) Confirm that customers can override the temperature setting between 3 to 7 PM during DPP events. If deny, please explain.

Answer: Confirmed.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.104 Respondent: I. M. Dimitry Page: 1 of 1 Question: Refer to Dimitry Direct at 10. Confirm that customers who do override the temperature setting between 3

and 7 PM during DPP events and return it closer to what it was before the DPP event would likely realize less load reduction during the peak period of 3 to 7 PM than customers who do not override the temperature setting between 3 and 7 PM during DPP events and return it closer to what it was before the DPP event. If deny, please explain in detail.

Answer: Confirmed. The Company interprets that the peak period of 3 to 7 PM when

customers would likely realize less load reduction refers to the 3 to 7 PM period of the DPP event.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.81e Respondent: I. Dimitry Page: 1 of 1 Question: Refer to Serna Direct at 64, which states: “These generators have no

temporal production contract with DTE, they have no total production contract with DTE, and their primary purpose is not to provide DTE with energy or capacity but to offset on-site consumption. Simply stated, distributed generation customers cannot be counted on to generate when needed by the DTE system and have no obligation to do so. Therefore, there is no tangible capacity value or capacity offset provided by the distributed generation.”

e) Confirm that the Company currently offers a $75 rebate on wifi-enabled

thermostats, as shown on https://www.newlook.dteenergy.com/wps/wcm/connect/dte-web/home/save- energy/residential/rebates/energy+star+appliances If deny, please explain in detail.

Answer: Confirmed. At the time of submitting this answer, the Company’s Energy

Waste Reduction program offers a rebate on wifi-enabled thermostats. Attachments: n/a



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.24g Respondent: C. Serna / R. Mueller Page: 1 of 1 Question: Please refer to Testimony of Witness C. Serna at 51, Lines 5-13, where



g. Please explain if the Company has studies or calculated the benefits

provided by distributed generation customers to the distribution system. If it has, please provide that study or calculations.

Answer: The Company has not performed such study or calculation.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.24a Respondent: C. Serna / R. Mueller Page: 1 of 1 Question: Please refer to Testimony of Witness C. Serna at 51, Lines 5-13, where



a. Provide all documentation produced or reviewed by the Company which

supports the assertion that DG customers “make more intensive demands of the infrastructure.”

Answer: The Company has not developed or reviewed documentation of the impacts

of distributed generation customers on the Company’s system. However, the topic of how distributed generation customers leverage the electric system is an important topic of research by the Electric Power Research Institute (EPRI) – an independent, non-profit research organization. The report titled “The Integrated Grid” provides information on the way distributed generation customers interact with the grid and the type of services provided by the grid to support these customers. Please see attachment “ELPCDE-1.24a The Integrated Grid.”



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.24f Respondent: C. Serna / R. Mueller Page: 1 of 1 Question: Please refer to Testimony of Witness C. Serna at 51, Lines 5-13, where



f. Please provide all analyses produced by (or for) the Company that

demonstrates that outflow energy from current net metering customers is ever exported beyond the distribution substation level of the distribution system.

Answer: The Company has not performed such analyses.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.26 Respondent: C. Serna / R. Mueller Page: 1 of 1 Question: Please refer to Testimony of Witness C. Serna at 53. Provide all documentation and analyses produced by the Company related

to the “operation and technical impacts of distributed generation on electric system functions.”

Answer: The Company has not performed an analysis specific to the operational and

technical impacts of distributed generation on the Company’s electric system functions. Attachment “ELPCDE-1.24a The Integrated Grid” discusses perspectives on the operational and technical impacts of distributed generation on electric system functions, generally.



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-1.27 Respondent: C. Serna Page: 1 of 1 Question: Please provide DTE’s most recent marginal cost study, including any

calculation that the Company has conducted of its marginal costs for distribution capacity.

Answer: The Company has not performed such a study or analyses.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.50h Respondent: R. Mueller Page: 1 of 1 Question: Refer to Exhibit A-16 Schedule F9, representing the SAC calculation for an

average residential customer for 2017.

h) Please provide all analyses that the Company performed that demonstrate a relationship between the size of a DG system and the cost of serving a customer with that DG system.

Answer: The question assumes a straight-line relationship between PV output and

cost, which is not appropriate. While there is a relationship, there are many factors that play into the cost. In a similar fashion, as costs to serve are averaged over a class of customers with similar demand, establishing two-way demand costs for distributed generation customers makes sense. Utility best practice is that the load without the generation is planned for and then the generation without the load is planned for. This mitigates any issues with sudden load tripping and the full generation hitting the grid that is inadequate or the generation tripping and the load demanding full support from the grid. In general, a customer with a larger DG system needs a larger transformer and larger conductors just as a customer with a larger load needs a larger service. There may be required changes to relays, fuses and other protective devices – as size goes up or there is increased penetration of generation in a local area this becomes more common. They may require capacitor banks and statcoms, again as the size (or number in close proximity) the likelihood increase. Similar comparisons can be drawn for a dozen more classes of equipment and cost categories.

Attachments: n/a



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.99b Respondent: R. J. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.50h.

b) Provide all instances where a residential customer with a DG system has required larger conductors as a result of installing the DG system. If none, please confirm.

Answer: DTE does not independently track these upgrades as per response to

ELPCDE-1.4a. In many areas of DTE’s territory that were developed prior to the 1970’s older and smaller services with 60 amp services were common, and upgrades to services and secondary have been needed to provide safe and effective service when any large electrical devices, such as DG, are connected. Also, see response to ELPCDE-5.99a.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.99d Respondent: R. J. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.50h.

d) Provide all instances where a residential customer with a DG system has required a change to fuses as a result of installing the DG system. If none, please confirm.


ELPCDE-1.4a. DTE must ensure that protection is properly coordinated to prevent safety hazards and to appropriately limit the size of any outage. Since Distributed Energy Resources can change the characteristics of a fault, appropriate protection changes are made as needed.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.99e Respondent: R. J. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.50h.

e) Provide all instances where a residential customer with a DG system has required a change to other protective devices as a result of installing the DG system. If none, please confirm.

Answer: DTE does not independently track these upgrades as per ELPCDE-1.4a.

DTE must ensure that protection is properly coordinated to prevent safety hazards and to appropriately limit the size of any outage. Since Distributed Energy Resources can change the characteristics of a fault appropriate protection changes are made as needed.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.99g Respondent: R. J. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.50h.

g) Provide all instances where a residential customer with a DG system has required capacity banks a result of installing the DG system. If none, please confirm.


Capacitor bank timing, and locations have been adjusted to compensate for the aggregate voltage effects of DER.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.99h Respondent: R. J. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.50h.

h) Provide all instances where a residential customer with a DG system has required statcoms as result of installing the DG system. If none, please confirm.


DTE has not had to incorporate this technology to date, however compensation for swings in KiloVar flow would require devices such as statcoms with this flexibility.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.99a Respondent: R. J. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.50h.

a) Provide all instances where a residential customer with a DG system has required a larger transformer as a result of installing the DG system. If none, please confirm.


ELPCDE-1.4a. However, since net metering qualification allows KWH to be generated up to the customer’s total KWH usage for a year, solar systems that are sized between six to eight times the normal average load in KW can be installed, some smaller transformers had to be replaced to not be overloaded or overheated.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.99c Respondent: R. J. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.50h.

c) Provide all instances where a residential customer with a DG system has required a change to relays as a result of installing the DG system. If none, please confirm.


Historically, DTE, in an effort to facilitate a safe and reliable electrical system, had some relay settings and timings that were incompatible with larger concentrations of Distributed Energy Resources. DTE has had to replace or change settings on some of these relays and continues to do so as issues are identified.



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.50i Respondent: R. Mueller Page: 1 of 1 Question: Refer to Exhibit A-16 Schedule F9, representing the SAC calculation for an


i) Please provide all analyses that the Company performed on how the relationship described in h) may change based on the underlying usage of the customer, both in terms of energy and demand.

Answer: Unless the customer’s minimum load always (even in vacation mode or shut

down mode) exceeds the capacity of the DG system then the customer is probably backfeeding onto the system. Unless the customer has a breaker to prevent backfeed, the system is always at risk of the full capacity of the local generation feeding into the distribution system. Utility best practice is that the distribution system is always sized so that if local generation is lost or local load is lost that the system can handle that load or supply from that system. This prevents the customer who accidently loses their generation from potentially burning out the distribution system from inrush current and also protects the system from potential back feed that is more than the system was designed for. Best practice for the safety and stability of the system is to plan for both the load being absent with full generation and for the generation being absent with full load. This protects everyone. If best practice is not followed, then protective equipment is required at the site including relays and breakers to trip the site anytime there is an issue with either the generation or the load disappearing.

Attachments: n/a



Page 1 of 1

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.51a Respondent: T. W. Lacey/

K. O. Farrell / C. Serna Page: 1 of 2 Question: Suppose there are two customers who have identical usage, peak demand

at the time of class and system peaks used in the cost allocation process, and non-coincident peak demand used in the cost allocation process. Suppose the first customer installs a small DG system that reduces their total annual kWh usage by 10% and never exports any energy to the Company’s distribution grid. Suppose the second customer installs a more efficient air conditioner and LED lights, and reduces their annual kWh usage by 10%. Further, suppose that the usage, the peak demand of the two customers at the time of class and system peaks used in the cost allocation process, and the non-coincident peak demand of the customers remains identical to each other after these actions.

a) In this example, confirm that according to the Company’s cost allocation

methodology that both customers incur the same cost to serve on the system before and after their actions. If deny, please explain in detail.

Answer: Not necessarily on a cost allocation basis. Schedule 300 uses the sum of

the individual customer max demands. There is a possibility that the customer who installed a small DG system sets their max demand when they are not generating, while the customer who has installed an efficient air conditioner and LED lights is reducing their demand consistently by 10%. In this scenario, the two customers’ contribution to Allocation Schedule 300 would not be equal. Assuming the only changes to allocation schedules are schedule 100 - Power Plant Energy Production (and assuming Schedule 300 as explained above, did not change) then confirmed for cost of service. However, the Company’s cost allocation methodology – like all cost of service allocation methodologies – does not perfectly reflect the true costs driven by each individual customer. DG customers, as described in the example provided, put more stress and thus drive more costs than customers who reduce usage through energy efficiency. The DG customer is still using the same amount of energy (from two sources) so his or her inrush current requirements are the same as before installing DG. Furthermore, the DG customer drives additional costs due to the ramping nature of their generation which changes from minute to minute due to cloud cover passing through. In addition, the Company also needs to maintain backup capacity to serve the DG customer’s entire load, which has not changed simply due to the installation of DG and DTE might need



Page 1 of 2

MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.51a Respondent: T. W. Lacey/

K. O. Farrell / C. Serna Page: 2 of 2 to serve the entire load with little notice if the distributed generation

equipment might be offline for any reason. The customer implementing energy waste reduction tools is actually using less total energy (from one source) than before taking action, so I would expect his or her system requirements to be less, and thus may result in lower system costs than a DG customer.

Attachments: n/a



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.107a Respondent: R. J. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.73c.

a) Are transformers and secondary lines designed to handle the sum of the absolute peaks of each individual customer served by that equipment, regardless of when those peaks occurred, or are they designed to handle the diversified demand of the aggregated load of the customers served by that equipment?

Answer: The electrical system has been designed for diversified aggregated load.

Solar PV DG systems do not produce energy that matches the profile of diversified load. Solar PV production magnitude is directly tied to availability of sunlight. As per response to ELPCDE-5.99a, DG systems will produce significantly more energy than diversified loads would be expected to be produce over certain hours. As penetration of Solar PV increases, the net powerflow during certain hours becomes less diverse as it is dominated by reverse powerflow following the solar production curve.



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.103b Respondent: C. Serna/

R. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.51b.

b) Confirm that feeders that may serve dozens or hundreds of customers experience intra- minute variations in load due to the variation in usage of individual customers, even if none of these customers have DG systems. If deny, please explain.

Answer: Feeders typically serve many customers each with inter-minute variations

in load. Distributed generation customers are the only customers who, in addition to exhibiting variations in consumptive load, outflow energy into the distribution system. This electrical outflow is a fundamentally distinct variation in load from the load characteristics of a non-DG customer. In general, see Serna Direct at 52.



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.101 Respondent: T. W. Lacey/

C. Serna Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.51a. Please identify with specificity what additional costs have been caused by

DG customers and have been included in this rate case “due to the ramping nature of their generation.” If none, please confirm.

Answer: The referenced response at ELPCDE-2.51a distinguishes between the

behavior and effect of the behavior of energy efficiency investments and distributed generation investments. It further notes that “the Company’s cost allocation methodology – like all cost allocation methodologies – does not perfectly reflect the true costs driven by each individual customer.” There are no specific additional costs “due to the ramping nature of [DG customers’] generation” included in this rate case. However, rapid changes in output may negatively impact the lifespan of distribution equipment, as described in ELPCDE-2.72a, and while not specifically included in this rate case, shortened equipment lifespans represent real cost.



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.102e Respondent: M. T. Paul / P. W. Dennis Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.51a. The reply states: “In addition, the Company also needs to maintain backup

capacity to serve the DG customer’s entire load, which has not changed simply due to the installation of DG and DTE might need to serve the entire load with little notice if the distributed generation equipment might be offline for any reason.”

e) Please list which Company assets are currently being maintained solely

as backup capacity to serve the DG customer’s entire load. Answer: DTE does not own Company assets that are currently being maintained

solely as backup capacity to serve DG customer’s entire load. Company generation assets are not assigned for any one specific purpose, and thus can be used to serve all its customers current load or for standby.



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MPSC Case No.: U-20162 Requestor: MECNRDCSCDE Question No.: MECNRDCSCDE-1.11 Respondent: T. W. Lacey Page: 1 of 1 Question: Please reference Serna Direct at 61:19-62:2. Have you quantified the cost

of providing inrush current as an unbundled service? If so, please provide the cost and produce all data, calculations, and workpapers used to quantify the cost.

Answer: I have not been asked to perform, nor am I aware of any studies quantifying

the cost of providing inrush current as an unbundled service.



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.51b Respondent: C. Serna Page: 1 of 1 Question: Suppose there are two customers who have identical usage, peak demand

at the time of class and system peaks used in the cost allocation process, and non-coincident peak demand used in the cost allocation process. Suppose the first customer installs a small DG system that reduces their total annual kWh usage by 10% and never exports any energy to the Company’s distribution grid. Suppose the second customer installs a more efficient air conditioner and LED lights, and reduces their annual kWh usage by 10%. Further, suppose that the usage, the peak demand of the two customers at the time of class and system peaks used in the cost allocation process, and the non-coincident peak demand of the customers remains identical to each other after these actions.

b) Please explain why is it appropriate to charge the first customer a SAC

to replace lost distribution revenue but it is not appropriate to charge the second customer a SAC to replace the same lost distribution revenue.

Answer: In general DG customers “reduction” in energy provided by the utility is

greater than a customer installing energy efficient lights and appliances. There are differences between the two customers in the example provided above. Unlike a customer with a small DG system, the customer who is trying to become more “energy efficient” does not rely on the grid to export power, their load reduction is more consistent over the day (less variability), and even though DG systems are producing, DG customers continue to rely on the grid for intra-minute increments when appliances turn on and require more voltage than can be supported by their DG systems. See also, direct testimony of C. Serna, page 61, line 3, through page 62, line 2.

Attachments: n/a



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.98a Respondent: R. J. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.50c.

a) Suppose a house with a DG system is simultaneously producing 3 kW of power and simultaneously consuming 3.5 kW of power, so that its instantaneous net draw on the Company’s system is 0.5 kW. Suppose another house without a DG system has an instantaneous net usage of 0.5 kW. Would the instantaneous impact on voltage, current, and resistance to energy on customers who share the secondary with these customers be the same or different? Please explain in detail.

Answer: The net draw would be similar, but the inverters have proven to have

harmonics issues, that outweigh the harmonics issues of similar sized residential UL approved equipment. The second item is based on studies by Sandia, there is a high probability that in Michigan on partly cloudy to cloudy days (roughly 300 of 365 according to NOAA) variations in the production on a 30 second or shorter basis would be frequent, something that similar sized residential appliances don’t typically do. The issue is not power flow on average, but instantaneous power flow changes and the frequency there of, and the contribution of harmonics to the system. Longitudinal studies are underway in California to quantify the loss of life to residential appliances that meet UL standards based on these kinds of issues. While DTE is not part of these studies, they are expected to report out in 2022.



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.103c Respondent: C. Serna/


c) Confirm that substations that may serve hundreds or thousands of customers experience intra-minute variations in load due to the variation in usage of individual customers, even if none of these customers have DG systems. If deny, please explain.

Answer: See response to ELPCDE-5.103b.



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.103a Respondent: C. Serna/


a) Please indicate what equipment is affected by load variability, and how the load variability impacts the performance and lifespan of the equipment.

Answer: See response to ELPCDE-5.98a.



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.106c Respondent: R. J. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.72a.

c) How often does an event occur that causes an inverter-based PV system to change output by 40% or more in less than 1/60th of a second? Please provide any data or analyses the Company has performed on this issue.

Answer: Refer to ELPCDE-5.106b



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.106d Respondent: R. J. Mueller Page: 1 of 1 Question: Refer to the Company’s response to ELPCDE – 2.72a.

d) Suppose that a passing cloud caused the system output of a system to drop by 40% when completely covered. For a PV system that is 20 feet wide (a typical width for a residential system), how fast, in miles per hour, would the cloud have to be travelling to completely cover the array in 1/60th of a second?

Answer: See ELPCDE-5.106a. Unknown. The answer would be affected by, types

of clouds, multiple cloud heights, cloud layer directions, cloud densities and the angle of the sun in calculating the speed of a shadow.



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.74 Respondent: C. Serna Page: 1 of 1 Question: Refer to Serna Direct at 55. Is the Company adopting in full all

methodologies, analyses, and conclusions reached by the studies that purport to show a cost shift from net metering customers that are listed in footnotes 56 and 57?

Answer: No. The Company provided the references to highlight the existence of

several studies that provide an assessment of the cost shift from net metering customers. The Company did not review the methodologies of both studies in detail, thus the Company does not adopt their methodologies or specific analytical approaches as part of the written testimony.

The Company adopts the conclusions to the extent those are reflected in

the Company’s written testimony. Attachments: N/A



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.108b Respondent: P. W. Dennis/

C. Serna Page: 1 of 1 Question: Refer to Serna Direct.

b) Confirm that there exist other intra-class cost shifts due to the relative usage of different customers in the same customer class and the rate design used to collect revenues. For instance, between rural and urban customers, between single-family residents and apartment customers, and between customers with air conditioning or customers without air conditioning. If deny, please explain.

Answer: Please refer to Serna Direct Testimony at pages 52 (1-11) and 54 (17-22)

for further discussion on the distinctions between distributed generation customers and those customers described in the question. All rate classes are developed on averages and have some level of intra-class cost shift.



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.108c Respondent: T. W. Lacey/


c) Confirm that customers who incur additional costs as a result of the intra-class cost shifts described in b) have made no affirmative choice to provide such support and have no opportunity to opt out.

Answer: Individual customers within a rate class are not allowed to pick and choose

which parts of the system they will pay for, or which costs are allocated to them, once they have decided to take service from DTE Electric under a particular rate schedule. As described in ELPCDE-5.108b and Serna Direct Testimony at pages 52 (1-11) and 53, distributed generation customer load profiles and the resulting system impacts are not analogous to those described in b). However, cost of service studies and rate design inherently lump customers together who generally share characteristics. That is the nature of tariff regulation and the benefits of this approach are generally viewed to outweigh the costs.

The cost shifts under current net metering tariffs are different in that a policy was established to explicitly create a new tariff to encourage DG. An explicitly designed tariff to incent DG customers at the expense of non-DG customers will not balance out on average and over time. See Serna Direct Testimony at pages 54-57 for further discussion on this point.



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-5.108d Respondent: T. W. Lacey/


d) Please provide all analyses that has quantified the impact of intra-class cost shifts such as those included in b).

Answer: The Company does not conduct analyses on intra-class cost shifts such as

those included in b).



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.84 Respondent: P. W. Dennis Page: 1 of 1 Question: Provide all bill impact analyses that have been conducted on the effect of

the proposed DG tariff changes (including the SAC) compared to customers without DG and customers currently taking service under Rider 16. Data should be provided in its native format with formulas intact. If any workpaper has an external link to another workpaper, provide the supplemental workpaper. If any workpaper has hardcoded figures derived from another workpaper, provide the supplemental workpapers.

Answer: The Company has not completed a bill impact analyses comparing the

effect of the proposed rates and DG tariff changes (including the SAC) compared to customers without DG, and customers currently taking service under Rider 16. However, the Company did complete a bill impact analysis on earlier iterations of a similar concept. Note, this bill impact analysis does not reflect the rates proposed in this case. See also the response to ELPCDE-2.61.

Attachments: U-20162 ELPCDE-2.84 analysis.xls



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.50g Respondent: P. W. Dennis Page: 1 of 1 Question: Refer to Exhibit A-16 Schedule F9, representing the SAC calculation for an


g) Please explain in detail why the Company believes that the nameplate capacity of a DG system is the proper metric to use when calculating the SAC rate.

Answer: Given the calculation was based on customers’ average inflow, outflow, and

generation, it is reasonable to base the collection on the average installed nameplate capacity. The Company also wanted to develop a charge for customers who are used to paying fixed charges that was easy to understand.

Attachments: n/a



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MPSC Case No.: U-20162 Requestor: ELPC Question No.: ELPCDE-2.37 Respondent: P. W. Dennis / C. Serna Page: 1 of 1 Question: Refer to Rider 18. In the case that the Distributed Generation Program is

terminated by the Company, please provide a narrative justification why any existing credits on the customer’s account should be forfeited. Please include an explanation why the Standard Contract Rider No 18 Section M that provides for the existing credits either be applied to the customer’s final bill or refunded to the customer is inappropriate.

Answer: The Company’s Rider 18 proposal states outflow credits can offset the

power supply portion of a customer’s bill (Exhibit A-16, Schedule F-10, Original Sheet No. D-113). If customers who terminate from the program could “cash out” any remaining outflow balance when service was terminated, the limitation on using the credits to only offset power supply charges would essentially be null. See also, testimony of C. Serna, page 62, lines 12 through 18.

In addition, Act 342, Section 177(4) states, “Notwithstanding any law or regulation, distributed generation customers shall not receive credits for electric utility transmission or distribution charges”. Finally, assuming the Commission approves the Company’s proposed Rider 18 rate structure, the Company does not anticipate customers to have much value in their banks, if at all, at time of termination.

In general, if outflow credits are determined to not be allowed to offset certain charges on a customer’s bill, but customers are then allowed to eventually “cash out” their remaining balance, the limitation of what can be offset is essentially meaningless; the timing of the customer receiving the compensation would be affected, but the compensation would essentially not be limited to offsetting only certain charges at all.

Section M of Standard Contract Rider No. 18 as referenced above is not the

Company’s proposal. As stated in the direct testimony of P. W. Dennis, page 21, line 22 through page 23, line 15, it was included as an exhibit in compliance with the Commission’s April 18, 2018 Order in Case No. U-18383.



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) ) ) ) )

Case No. U-20162

PROOF OF SERVICE

I hereby certify that a true copy of the foregoing Direct Testimony of Will Kenworthy and Kevin Lucas on behalf of the Environmental Law & Policy Center, the Ecology Center, the Solar Energy Industries Association, and Vote Solar was served by electronic mail upon the following Parties of Record, this 7th of November, 2018.

Administrative Law Judge Hon. Sally Wallace

[email protected]

MPSC Staff Amit T. Singh Daniel E. Sonneveldt Spencer A. Sattler

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

Attorney General Joel King Sebastian Coppola

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

DTE Electric Company Andrea Hayden

[email protected] [email protected]

ABATE Robert A. W. Strong Bryan A. Brandenburg James Dauphinais


Michigan Cable Telecommunications Association Michael S. Ashton

[email protected]














Michigan Environmental Council, Natural Resources Defense Council & Sierra Club Christopher M. Bzdok

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

Energy Michigan Tim Lundgren Laura Chappelle Toni Newell


Great Lakes Renewable Energy Association Don L. Keskey Brian W. Coyer


Kroger Company Kurt J. Boehm Jody Kyler Cohn Kevin Higgins


Utility Workers Union of American Local 223 John R. Canzano Benjamin L. King


ChargePoint, Inc. Timothy J. Lundgren Justin K. Ooms


Michigan Energy Innovation Business Council, Institute for Energy Innovation Laura Chappelle Toni L. Newell


Walmart Melissa M. Horne

[email protected]

Sierra Club Lydia Barbash-Riley Chinyere A. Osuala Shannon Fisk David Bender Robert M. Fagan Douglas B. Jester Avi Allison

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
























Soulardarity Lydia Barbash-Riley Mark Templeton Robert Weinstock Rebecca Boyd

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

Margrethe Kearney Environmental Law & Policy Center [email protected]






November 7, 2018 Ms. Kavita Kale Michigan Public Service ...

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