before the council for the city of new orleans application of entergy new … · council for the...

BEFORE THE

COUNCIL FOR THE CITY OF NEW ORLEANS APPLICATION OF ENTERGY NEW ORLEANS, LLC FOR A CHANGE IN ELECTRIC AND GAS RATES PURSUANT TO COUNCIL RESOLUTIONS R-15-194 AND R-17-504 AND FOR RELATED RELIEF

) ) ) ) ) )

DOCKET NO. UD-18-__

DIRECT TESTIMONY

OF

DR. AHMAD FARUQUI

ON BEHALF OF

ENTERGY NEW ORLEANS, LLC

JULY 2018

Entergy New Orleans, LLC Direct Testimony of Dr. Ahmad Faruqui CNO Docket No. UD-18-__ July 2018

i

TABLE OF CONTENTS

I. INTRODUCTION AND PURPOSE .................................................................................. 1

Name and Qualifications......................................................................................... 1 A.

Purpose of Testimony ............................................................................................. 3 B.

II. DEMAND-SIDE MANAGEMENT COST RECOVERY ................................................. 7

DSM and Utility Incentives in the U.S. .................................................................. 7 A.

ENO’s Proposed Rider DSMCR ........................................................................... 22 B.

Comparison of ENO’s Proposal with Other U.S. Utilities’ Cost Recovery C.Mechanisms .......................................................................................................... 29

III. DISTRIBUTION GRID MODERNIZATION RIDER .................................................... 36

Grid Modernization Initiative in the U.S. ............................................................. 36 A.

ENO’s Proposed Distribution Grid Modernization Rider .................................... 43 B.

Comparison with Similar Infrastructure Improvement and Modernization C.Recovery Riders in the U.S. .................................................................................. 49

IV. CONCLUSION ................................................................................................................. 56

EXHIBIT

Exhibit AF-1 Dr. Ahmad Faruqui Resume


1

I. INTRODUCTION AND PURPOSE 1

Name and Qualifications A.2

Q1. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 3

A. My name is Ahmad Faruqui. My business address is 201 Mission Street, Suite 2800, San 4

Francisco, California 94105. 5

6

Q2. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY? 7

A. I am a Principal with the Brattle Group, an economics consulting firm. 8

9

Q3. ON WHOSE BEHALF ARE YOU TESTIFYING? 10

A. I am filing this Direct Testimony on behalf of Entergy New Orleans, LLC (“ENO” or the 11

“Company”) before the Council of the City of New Orleans (the “Council”). 12

13

Q4. PLEASE DESCRIBE YOUR EDUCATION AND PROFESSIONAL EXPERIENCE. 14

A. I hold B.A. and M.A. degrees from the University of Karachi, Pakistan, an M.A. in 15

agricultural economics and a Ph.D. in economics from the University of California at 16

Davis. I have 40 years of academic, consulting and research experience as an energy 17

economist. During my career, I have advised more than 150 clients in the energy 18

industry, including utilities, regulatory commissions, government agencies, transmission 19

system operators, private energy companies, equipment manufacturers, and information 20

technology companies. Besides the U.S., my clients have been located in Australia, 21

Canada, Chile, Egypt, Hong Kong, Jamaica, Philippines, Saudi Arabia, South Africa, and 22

Vietnam. I have advised them on a wide range of issues including energy efficiency, 23


2

demand response, advanced metering technologies, rate design, load forecasting, 1

distributed energy resources (“DERs”), integration of retail and wholesale markets, and 2

integrated resource planning. I have testified or appeared before several state, provincial 3

and federal regulatory commissions, and legislative bodies. I have been an invited 4

speaker at major energy conferences in Africa, Asia, Australia, Europe, North America, 5

and South America. Finally, I have authored, co-authored, or co-edited more than 150 6

articles, books, editorials, papers, and reports on various facets of energy economics. 7

More details regarding my professional background and experience are set forth in my 8

Statement of Qualifications, included as Exhibit AF-1. 9

10

Q5. DO YOU HAVE EXPERIENCE SPECIFICALLY IN MATTERS RELATED TO COST 11

RECOVERY ASSOCIATED WITH UTILITY-SPONSORED DEMAND-SIDE 12

MANAGEMENT (“DSM”)? 13

A. I do. I have testified before the Corporation Commission of Oklahoma on behalf of 14

Oklahoma Gas and Electric Company in support of its application for cost recovery and 15

performance incentive mechanisms associated with DSM.1 I have also reviewed best 16

practices for designing cost recovery and performance incentive regulatory mechanisms 17

(in relation to declining electric sales due to DSM as well as other risk factors) and 18

provided recommendations to several utilities and stakeholders, including California’s 19

investor-owned utilities, Florida Power & Light, DTE Energy, Puget Sound Energy, a 20

large Canadian utility, and a Chilean utilities trade association. I have also addressed the 21

1 DSM includes a variety of utility energy solutions designed to actively manage the load shape of the customer, including energy efficiency (“EE”) and demand response (“DR”).


3

topic in DSM guidebooks written for the Electric Power Research Institute. Lastly, I 1

presented on the topic at a conference organized by the International Energy Agency in 2

Australia. 3

4

Q6. HAVE YOU PREVIOUSLY PROVIDED TESTIMONY IN ANY REGULATORY 5

PROCEEDINGS? 6

A. Yes. In Exhibit AF-1, I list my prior testimonies. 7

8

Purpose of Testimony B.9

Q7. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 10

A. The purpose of the first part of my testimony is to comment on the reasonableness of 11

ENO’s proposed Demand-Side Management Cost Recovery (“DSMCR”) rider (“Rider 12

DSMCR”). Recognizing the significant shift in how customers are interacting with the 13

electric grid and how they are using electricity in their homes and businesses, Company 14

witness D. Andrew Owens explains that the Company’s goal is to increase its DSM 15

offerings and to incorporate DSM as a core component of its business. He also addresses 16

how the Company views DSM as an increasingly viable option for addressing its 17

customers’ energy needs, particularly given customer interest in expanded DSM 18

offerings. It is my understanding that Rider DSMCR is designed to facilitate this 19

transition. 20

I also understand that ENO is proposing Rider DSMCR as a means of putting DSM 21

and traditional supply-side resources on a more equal financial footing, which encourages 22

future investment in DSM and can help to facilitate the Council’s goal of seeing 23


4

significant increases in DSM savings. I explain how ENO’s proposed Rider DSMCR is 1

in line with current industry best practices for implementing fair and supportive 2

ratemaking structures that have proven records of accomplishing those goals. 3

The purpose of the second part of my testimony is to comment on the 4

reasonableness of ENO’s proposed Distribution Grid Modernization (“DGM”) rider 5

(“Rider DGM”), which is designed to support the Company’s efforts to improve and 6

modernize the electric distribution grid. ENO witness Erica H. Zimmerer describes how 7

changing technology and customer expectations, along with the Council’s policy 8

directives, as stated in R-18-36, have resulted in ENO pursuing a comprehensive grid 9

modernization initiative. As a result, the Company has proposed Rider DGM to facilitate 10

the Company and Council’s shared goals in this regard. I explain how ENO’s proposed 11

Rider DGM is in line with current industry best practices for implementing similar 12

comprehensive grid modernization strategies. 13

14

Q8. PLEASE SUMMARIZE YOUR TESTIMONY. 15

A. DSM is a clean and cost-effective resource that has been deemed a priority by the 16

Company and the Council. I explain how supportive and fair ratemaking structures can 17

fully align the interests of ENO and its customers in order to maximize the savings 18

produced from ENO’s DSM offerings. ENO’s proposed ratemaking structure (Rider 19

DSMCR) accomplishes that goal by incorporating three important components of modern 20

and fair DSM cost recovery that are listed below: 21

• First, ENO’s proposal recognizes that utilities historically have not earned 22

a return on money spent on DSM as they have on investments in supply-23


5

side and other traditional infrastructure. At the outset of the creation of 1

ENO’s Energy Smart DSM portfolio, the Council recognized the 2

importance of addressing this issue through ratemaking in order to 3

encourage investment in DSM.2 ENO’s proposed Rider DSMCR includes 4

a methodology that provides an earnings incentive to pursue DSM, which 5

puts DSM on a more level financial playing field with supply-side 6

resources. 7

• Second, ENO’s proposal recognizes that, by continuously reducing energy 8

sales, DSM results in lost contribution to fixed costs (“LCFC”). ENO’s 9

proposed Rider DSMCR includes a methodology for recovering LCFC 10

until base rates are adjusted under a separately proposed formula rate plan 11

(“FRP”) based on historic sales. 12

• Third, ENO’s proposal recognizes that utilities need to recover DSM 13

costs,3 and ENO’s proposed Rider DSMCR includes a methodology for 14

recovering DSM costs. 15

I note that the Council has previously acknowledged in its Resolution R-07-600 the 16

importance of these cost recovery components in encouraging robust DSM. 17

I have reviewed the elements of ENO’s proposal and have found that it is well-18

aligned with current industry practices. Specifically, ENO is proposing to (a) recover 19

each year’s DSM investments over a 3-year time horizon while earning a return on those 20 2 See Resolution No. R-07-600. 3 DSM costs include design costs and implementation costs (e.g., direct and indirect administrative costs, customer education, marketing, rebates, and evaluation, measurement, and verification (“EM&V”)). Throughout my testimony I will often refer to these DSM costs as ENO’s investment in DSM, or “DSM investment.”


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investments and (b) to also recover the LCFC that is attributable to lost sales from DSM. 1

The proposal would allow ENO to earn a return on DSM investments and would put 2

DSM on a more level playing field with supply-side opportunities. ENO has proposed a 3

structure that not only provides additional incentives if ENO exceeds the Council’s 4

energy savings targets, but also calls for penalties if ENO falls short of those targets. 5

Cost recovery that includes earning a return on DSM investments, as proposed by ENO, 6

has recently re-emerged as a preferred tool for utilities and regulators that wish to 7

facilitate robust DSM portfolios. As I discuss in more detail later, the regulatory asset-8

based model that allows this to take place has been endorsed by both the utility and 9

environmental advocacy communities through a joint statement recently issued by the 10

Edison Electric Institute (“EEI”) and the Natural Resources Defense Council (“NRDC”).4 11

I also explain that there is a correlation between DSM energy savings and the 12

presence of the supportive ratemaking mechanisms proposed by ENO. In fact, the 13

components of the ratemaking structure proposed by ENO for supporting DSM 14

investment are commonly implemented throughout the U.S. For example, at least 27 15

states authorize the recovery of DSM costs and LCFC and allow utilities to earn an 16

incentive that encourages investment in DSM. 17

I have also reviewed ENO’s proposal for a rider to recover grid modernization 18

investments. Grid modernization is an increasingly important element of utility activity 19

around the U.S. I conclude that ENO’s proposal to recover those costs through a separate 20

4 Edison Electric Institute and Natural Resources Defense Council, “Joint EEI/NRDC Statement to NARUC,” February 14, 2018, accessed May 28, 2018, https://www.nrdc.org/resources/nrdceei-joint-statement-state-utility-regulators.

https://www.nrdc.org/resources/nrdceei-joint-statement-state-utility-regulatorshttps://www.nrdc.org/resources/nrdceei-joint-statement-state-utility-regulators


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rider will streamline the project approval process and ensure that ENO is able to prioritize 1

those investments in its capital allocation decisions. 2

3

Q9. HOW IS YOUR TESTIMONY ORGANIZED? 4

A. Section II of my testimony addresses issues related to DSM cost recovery. I provide an 5

overview of utility DSM offerings and performance incentives across the U.S. I also 6

describe ENO’s proposed Rider DSMCR and benchmark it against other utility cost 7

recovery approaches. Section III of my testimony discusses grid modernization cost 8

recovery. I briefly summarize grid modernization initiatives across the U.S., describe 9

ENO’s proposed Rider DGM, and compare that proposal to grid modernization cost 10

recovery mechanisms in other jurisdictions. Section IV presents the conclusions of my 11

testimony. 12

13

II. DEMAND-SIDE MANAGEMENT COST RECOVERY 14

DSM and Utility Incentives in the U.S. A.15

Q10. WHAT IS DEMAND-SIDE MANAGEMENT? 16

A. DSM broadly encompasses efforts by electric utilities to induce changes in energy 17

consumption in order to produce economic and environmental benefits for customers, 18

utilities and the public as a whole. DSM can be divided into two main categories: energy 19

efficiency (or conservation) and demand response. Energy efficiency measures target a 20


8

reduction of overall energy consumption, which can also help to reduce peak demand.5 1

Demand response measures aim at reducing customer demand during specific times – 2

typically system peak hours – and to shift load during peak periods to off-peak periods, 3

thereby reducing system costs and/or helping mitigate reliability issues. DSM is carried 4

out through a broad array of financial incentives, technology offerings, and/or 5

educational offerings to induce changes in customer behavior and/or to upgrade the 6

efficiency of customer equipment and facilities. In aggregate, these functions of DSM 7

make it an effective resource for helping utilities meet their customers’ needs, including 8

their desire to consume as little electricity as possible. 9

10

Q11. PLEASE PROVIDE A BRIEF OVERVIEW OF TRENDS IN UTILITY DSM 11

INITIATIVES ACROSS THE UNITED STATES. 12

A. Utilities have offered DSM programs in the U.S. for decades. A recent report by the 13

Institute for Electric Innovation estimated that utilities spent $7.5 billion on their DSM 14

offerings in 2016, and these efforts produced 183,000 GWh of energy savings.6 This 15

study also estimates that both EE investments and resulting energy savings have grown 16

by a factor of two between 2008 and 2016. 17

5 For further discussion of the peak impacts of energy conservation programs, see Annika Todd et al, “Insights from Smart Meters: The Potential for Peak-Hour Savings from Behavior-Based Programs,” Lawrence Berkeley National Laboratory Paper LBNL-6598E, March 2014, available at http://escholarship.org/uc/item/2nv5q42n#page-1. 6 Institute for Electric Innovation, “Energy Efficiency Trends in the Electric Power Industry,” December 2017, p. 1, accessed March 8, 2018, http://www.edisonfoundation.net/iei/publications/Documents/IEI_Energy%20Efficiency%20Report_Dec2017.pdf.

.

http://escholarship.org/uc/item/2nv5q42n#page-1http://escholarship.org/uc/item/2nv5q42n#page-1http://www.edisonfoundation.net/iei/publications/Documents/IEI_Energy%20Efficiency%20Report_Dec2017.pdf


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DSM initiatives vary from one state to another both in nature (e.g., types of 1

measures offered, customers targeted) and in scale (i.e., budget and savings goals are 2

larger in some states than in others). Each utility’s DSM plan is designed to align with 3

the market characteristics and customer requirements of its service territory and also with 4

state policy objectives. For instance, to address issues specific to low-income customers, 5

some utilities’ DSM efforts specifically provide home insulation measures for low 6

income customers. Other utilities, particularly in warmer climates, may introduce EE 7

measures that target efficiency improvements for customer segments with old, inefficient 8

air-conditioning units. Summer DR offerings for residential customers could also address 9

issues related to constrained grid infrastructure on the highest peak days in regions with a 10

hot summer climate where the use of residential air conditioning units is growing, similar 11

to ENO’s pilot direct load control program. 12

13

Q12. HOW IS DSM TYPICALLY FUNDED? 14

A. Regulated, investor-owned utilities such as ENO typically apply to their regulatory body 15

for approval to recover the costs of investing in DSM through customer rates, which is 16

most often accomplished through a dedicated rider. Conditions of approval typically 17

require analysis showing that the DSM portfolio will be cost-effective according to one 18

or more cost-effectiveness screens that take into account the perspective of customers and 19

the utility system. The utility’s application to the regulator also typically demonstrates 20

that the proposed measure is likely to produce energy and/or demand savings that are 21

consistent with applicable regulatory and policy objectives. 22


10

Participants also benefit through a bill reduction due to energy and/or demand 1

savings.7 Non-participants should benefit as well if the DSM portfolio is cost-effective in 2

that the utility will experience a long-run reduction in system costs and, thus, ultimately 3

lower retail electricity rates. 4

5

Q13. HOW HAVE REGULATORS THAT DESIRE ROBUST DSM ENCOURAGED ITS 6

ADOPTION? 7

A. Regulators and policymakers have increasingly recognized DSM as an important tool for 8

mitigating rising power costs by deferring or in some instances avoiding supply-side 9

solutions, leveraging emerging energy management technologies, providing customers 10

with new services and opportunities to integrate DERs, and decarbonizing the 11

environment. Fair and supportive policy and ratemaking mechanisms have been viewed 12

as the key to promoting DSM that is beneficial for utility customers. Accordingly, 13

regulators have implemented a variety of measures that enhance DSM’s benefits to the 14

utility’s customers and support the utility’s goal of incorporating DSM into its core 15

business. These ratemaking measures have centered on addressing the challenges that are 16

inherent in implementing DSM. 17

7 The bill savings involve both a short-run and a long-run component. In the short run, the reduction in electricity consumption will reduce the variable portion of the customer’s bill. In the long run, reduced energy sales and capacity needs will defer and lessen overall the need for more traditional supply-side and other infrastructure investments.


11

Q14. PLEASE EXPLAIN THE CHALLENGES YOU REFERENCE. 1

A. Under cost-of-service (“COS”) regulation,8 regulators offer a utility recovery of its 2

various operating and other costs plus an allowed rate of return on prudent capital 3

investments, such as generation, transmission, and distribution facilities. The rate of 4

return is made up of a return on debt (bonds sold by the utility) and a return on equity 5

(capital put into the utility by shareholders), weighted to reflect the proportional shares of 6

total capital each type provides. The intended result is to provide the utility sufficient 7

capital, at an optimal and tax-efficient cost, to build and maintain an electric grid offering 8

universal safe, reliable, affordable, and increasingly clean electric service. Under this 9

type of regulation, the returns provided to utility owners (shareholders) compensate the 10

owners for making capital available to provide a valued service to the public. 11

Because DSM measures are often expensive to implement and, absent supportive 12

ratemaking mechanisms, provide little to no value to a utility’s shareholders and lenders 13

in terms of having an opportunity to earn a return on DSM investments funded by these 14

same shareholders and lenders, investor-owned utilities can face challenges in 15

implementing DSM. This occurs for at least two reasons. 16

First, if utilities are not able to recover the costs of DSM offerings, the result is a 17

direct loss to the utility. It is akin to asking a utility to generate electricity from a power 18

plant but not allowing the utility to recover the fuel costs the utility incurs from its 19

customers. 20

8 Since ENO operates under a cost-of-service regulatory paradigm, it should be assumed that my testimony refers to COS regulatory paradigms unless otherwise noted.


12

Second, retail electric rates are typically set based on a level of energy sales that 1

does not take into account the impact of forecasted DSM efforts. The rate design for 2

residential and smaller commercial customers is mostly volumetric in nature, meaning 3

that both fixed and variable costs are recovered through the sale of energy (kWhs). An 4

effective utility DSM portfolio will reduce future energy sales below that forecasted 5

amount. When that happens, the collected revenue will be insufficient to cover both 6

fixed costs and the associated allowed return on investment. This is called Lost 7

Contribution to Fixed Cost (LCFC). 8

9

Q15. PLEASE DESCRIBE THE DIFFERENT TYPES OF COST RECOVERY 10

MECHANISMS PUT IN PLACE BY REGULATORS TO OVERCOME THOSE 11

CHALLENGES AND ENCOURAGE ROBUST DSM INVESTMENT. 12

A. To address the issue of cost recovery, regulators in many states allow utilities to recover 13

DSM investments that are deemed to be prudent expenditures. As described previously, 14

such cost recovery commonly requires that the DSM expenditures pass one or more cost-15

effectiveness screens.9 16

To address the issue of LCFC, regulators in many states allow utilities to recover 17

the LCFC that is specifically associated with reduced energy sales due to the utility’s 18

DSM investments. Recovery of DSM-specific LCFC is most commonly achieved 19

concurrently through a dedicated DSM rider based on a forward-looking period. In some 20

9 There are exceptions for DSM that promotes certain policy goals, but may not otherwise be considered cost-effective using standard screening tools.


13

states, regulators have instead chosen to fully decouple the utility’s revenues from its 1

energy sales (known as “full revenue decoupling”). 2

To make DSM an attractive opportunity for shareholder investment, regulators have 3

approved a variety of methods to incentivize the utility and its shareholders, with most 4

mechanisms allowing the utility to share with customers the net benefits that result from 5

implementation of the DSM. These are generally known as “performance incentives.” 6

One method of effectively combining cost recovery of DSM offerings and a performance 7

incentive is a “rate-basing” mechanism linked to a performance requirement, which 8

allows utilities to capitalize and amortize DSM investments and earn a return on the 9

unamortized balance during the period over which the investments are being amortized 10

and recovered from customers. This mechanism is analogous to the return utilities earn 11

on supply-side and other infrastructure investments, such as building new power plants, 12

transmission lines, distribution substations, circuits, feeders, transformers and meters. As 13

such, this kind of mechanism can be an effective way of overcoming the challenges I 14

discuss above and to put investment in demand-side and supply-side resources on a more 15

equal footing while ensuring DSM measures are performing. 16


14

Q16. ARE SUCH POLICIES COMMON IN THE U.S.? 1

A. Yes. First, it would be very unusual for a utility to be denied the recovery of its prudent 2

DSM expenditures. Regulatory approval for DSM cost recovery is now considered 3

almost guaranteed, assuming the DSM measures themselves have been approved.10 4

LCFC recovery is also common in the United States. Figure 1 below illustrates 5

each of the 32 states11 where utilities have been allowed LCFC recovery. 6

Figure 1 States with Lost Revenue Recovery Provisions

Source: The Brattle Group analysis using data from Institute for Electric Innovation, “Energy Efficiency Trends in the Electric Power Industry,” December 2017 and regulatory commission dockets.

10 For instance, the American Council for an Energy-Efficient Economy (“ACEEE”) asserts that “[the recovery of] the direct costs associated with implementing energy efficiency programs […] is a minimum threshold requirement for utilities and related organizations to fund and offer efficiency programs; every state meets it in some form.” See ACEEE, “The 2017 State Energy Efficiency Scorecard,” September 2017, p. 46, accessed March 20, 2018, https://aceee.org/research-report/u1710. 11 For the purpose of this survey, I include the District of Columbia as a state.

https://aceee.org/research-report/u1710


15

Performance incentives are also very common as regulators have come to 1

understand that they are the best mechanism to achieve robust DSM offerings. Incentives 2

are often provided along with LCFC recovery but in some cases they are provided 3

without any LCFC recovery mechanism as shown in Figure 2. 4

Figure 2 States with Lost Revenue Recovery and Incentive Provisions

Source: The Brattle Group analysis using data from Institute for Electric Innovation, “Energy Efficiency Trends in the Electric Power Industry,” December 2017 and regulatory commission dockets.

Q17. WHAT SPECIFIC TYPES OF PERFORMANCE INCENTIVES ARE IN PLACE IN 5

OTHER U.S. JURISDICTIONS? 6

A. A “shared savings” mechanism is currently a very common type of performance 7

incentive. This mechanism compares the cost of the DSM portfolio to its benefits (i.e., 8


16

avoided resource costs, such as reduced fuel and purchased power costs and the need for 1

generation and transmission capacity). If the benefits outweigh the costs – as they should 2

in a cost-effective DSM portfolio – the utility keeps a share of the net benefits as a form 3

of “return” on its “investments” in DSM. The rest is passed on as long-term savings to 4

customers. 5

Another common type of performance incentive allows utilities to earn a percentage 6

of their DSM investment according to achievement of savings targets. These 7

performance incentives typically include a minimum target achievement threshold in 8

order to be eligible for the incentive. The incentive is often capped at an established level 9

based on the savings goals. 10

A third type of incentive allows utilities to earn a return on DSM investments by 11

including them in a regulatory asset-based mechanism. Unlike the “shared-savings” and 12

energy savings-based incentives, the regulatory asset-based incentive is built into the 13

recovery of DSM investment and presents a more direct incentive to the utility akin to the 14

incentive that it has for making supply-side investments. The rate of return-based 15

incentive was first implemented in the 1980s.12 This mechanism is seeing renewed 16

interest from utilities, regulators, and environmental groups, in part because it enables 17

utilities to earn a financial return on their DSM investments similar to what is involved 18

with recovering traditional supply-side and other infrastructure investments.13 19

20 12 National Action Plan for Energy Efficiency, “Aligning Utility Incentives with Investment in Energy Efficiency,” November 2007, accessed June 2, 2018, https://www.epa.gov/sites/production/files/2015-08/documents/incentives.pdf. 13 Brian Hedman and Jill Steiner, “DSM in the Rate Case,” Public Utilities Fortnightly, January 2013, p. 36, accessed May 30, 2018, https://www.cadmusgroup.com/wp-content/uploads/2013/01/1301-DSMRateCase-hires.pdf.

https://www.epa.gov/sites/production/files/2015-08/documents/incentives.pdfhttps://www.epa.gov/sites/production/files/2015-08/documents/incentives.pdfhttps://www.cadmusgroup.com/wp-content/uploads/2013/01/1301-DSMRateCase-hires.pdf


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Q18. HAVE THESE POLICY MECHANISMS FOR PROMOTING UTILITY DSM 1

INITIATIVES BEEN SUCCESSFUL IN FACILITATING INCREASED SAVINGS? 2

A. The data on state energy savings indicates a correlation between those states with 3

supportive DSM policy mechanisms and those with significant DSM energy savings. 4

Figure 3 shows that average incremental savings are higher in states with LCFC recovery 5

and performance incentive mechanisms in place. 6

Figure 3 7 Average EE Incremental Savings as a % of Retail Sales (2016)

Source and Notes: The Brattle Group analysis using data from ACEEE’s 2017 State Scorecard. Values are calculated by taking a simple average of relevant states’ 2016 net incremental energy savings as a percentage of total 2016 retail sales in the state. See Figure 2 for more information on which states are included in each bar.


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Q19. WOULD AUTHORIZATION FOR RECOVERY OF DSM COSTS AND LCFC 1

ALONE INDICATE FAIR AND SUPPORTIVE RATEMAKING AND ENCOURAGE 2

ROBUST DSM INVESTMENT? 3

A. No. While comprehensively addressing those two issues would largely mitigate the 4

potential losses that utilities face for pursuing DSM, they would not encourage robust 5

investment in DSM. In other words, the utility would be made whole, or “get back to 6

zero,” on its DSM expenditures and resulting lost energy sales, but such a policy regime 7

would not convey the same level of regulatory support to the utility to pursue new DSM 8

investments relative to the alternative option of investing in supply-side resources and 9

other infrastructure (e.g., new power plants and transmission and distribution lines). 10

In other words, since utilities are allowed to have a reasonable opportunity to earn a 11

return on capital expenditures (and must do so to attract capital for new investments), 12

developing supply-side resources and other traditional infrastructure investments to meet 13

load growth remains the financially rational approach in the context of traditional COS 14

regulation. In order to make utilities, and the shareholders who supply them with capital, 15

indifferent between investing in supply-side resources and DSM, supportive ratemaking 16

would include mechanisms that create the opportunity for the utility to earn a return on 17

investment in DSM in order to encourage robust investments in DSM. Such an incentive 18

would require the opportunity to recover more than just direct costs of DSM offerings 19

and LCFC. 20

Ultimately, putting demand-side investments on a more level playing field with 21

supply-side resources and other traditional infrastructure investments should change the 22

way the utility contemplates increased investment in DSM. That is, with a supportive 23


19

and stable regulatory model in place, utilities can treat DSM as a meaningful component 1

of their core business and make the necessary plans for long-term sustainable investment. 2

3

Q20. DO NATIONAL DSM AND ENVIRONMENTAL POLICY GROUPS SUPPORT 4

LCFC RECOVERY AND PERFORMANCE INCENTIVES AS IMPORTANT 5

ASPECTS OF A ROBUST DSM INITIATIVE? 6

A. Yes. For instance, the ACEEE maintains that the traditional utility COS model 7

discourages investment in energy efficiency, recognizes the need to incorporate an 8

appropriate mechanism for recovery of lost revenues, and recognizes the need for 9

creating meaningful performance incentives.14 The NRDC, a national environmental 10

group, likewise asserts that current policies can position energy efficiency investments 11

against utilities’ financial obligations, and that “regulator and governing boards should 12

update these policies to ensure utilities' incentives are fully aligned with those of their 13

customers in receiving reliable and affordable energy services.”15 To do so, the NRDC 14

recommends allowing utilities to recover revenues that were reduced as a result of 15

efficiency efforts. 16

14 Dan York and Martin Kushler, “The Old Model Isn’t Working: Creating the Energy Utility for the 21st Century,” September 2011, p. 4, accessed May 5, 2018, http://aceee.org/files/pdf/white-paper/The_Old_Model_Isnt_Working.pdf. 15 National Resources Defense Council, “Doing More and Using Less: Regulatory Reforms for Electricity and Natural Gas Utilities Can Spur Energy Efficiency,” January 2011, p. 6, accessed May 7, 2018, https://www.nrdc.org/sites/default/files/doingmoreusingless.pdf.

http://aceee.org/files/pdf/white-paper/The_Old_Model_Isnt_Working.pdfhttp://aceee.org/files/pdf/white-paper/The_Old_Model_Isnt_Working.pdfhttps://www.nrdc.org/sites/default/files/doingmoreusingless.pdf


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Q21. IS DSM A PRIORITY FOR THE COUNCIL? 1

A. Yes. The Council and the Council’s Advisors have defined incremental energy savings 2

targets for Energy Smart for the next several years, and have expressed that they 3

“strongly support the Energy Smart program and its continued success.”16 The Council 4

has also encouraged ENO to request additional Energy Smart funding and propose 5

“specific funding mechanisms” as part of this rate case.17 Further, as Mr. Owens 6

discusses, other stakeholders in New Orleans have been very supportive of increased 7

funding for Energy Smart as well as expanded DSM offerings. Mr. Owens also discusses 8

the history of and the Council’s support for DSM in more detail in his direct testimony, 9

including how the Council has historically allowed recovery of the three core components 10

that I discuss above. 11

12

Q22. HAS THE COUNCIL ENCOURAGED THE ADOPTION OF DSM? 13

A. Yes. ENO introduced Energy Smart in 2009 in fulfillment of a directive from the 14

Council. Initially consisting entirely of EE measures, the scope of Energy Smart has 15

since expanded to also include DR. In its first seven years, the program produced 16

approximately 135 GWh of cumulative energy savings.18 17

16 Council Resolution R-15-599, December 10, 2015, pp. 3, 17. 17 Council Resolution R-17-504, September 27, 2018, p. 6. 18 ENO achieved total energy savings of 116 GWh in Program Years (“PY”) 1 through 6, and 19 GWh in PY 7 (a 9-month PY). See 2017-2019 Energy Smart Supplemental & Amended Plan Report, CNO Docket No. UD-08-02, September 29, 2017, Exhibit 1, p. 4 and Entergy New Orleans, Energy Smart Program Year 7 Annual Report, Dockets UD-08-02 and UD-17-03, May 30, 2018.


21

Q23. PLEASE DESCRIBE WHAT IS OFFERED THROUGH ENERGY SMART. 1

A. Currently, Energy Smart offers customers financial incentives for a range of energy 2

saving measures. These include customer incentives for efficient appliances such as air-3

conditioning and lighting, customer incentives for efficient new construction, a variety of 4

measures for commercial and industrial customers, direct control of air-conditioning load 5

for DR benefits, and various pilot programs, among others. 6

7

Q24. HAS THE COUNCIL RECENTLY URGED INCREASED IMPLEMENTATION OF 8

DSM? 9

A. Yes. My understanding is that the Council recently implemented savings goals for 10

Energy Smart.19 Under those goals, annual energy savings increase at a rate of 0.2% per 11

year for roughly the next nine years. The annual savings achievement was 0.34% in 2016 12

(PY 6), resulting in a savings goal of 0.54% in 2017. This goal equates to roughly 12% 13

cumulative energy savings by 2025, relative to 2016 levels. Figure 4 summarizes the 14

program goals, as defined by the Council and beginning in PY 7.20 In addition to those 15

savings goals, Mr. Owens describes other instances where the Council has expressed an 16

interest in increasing DSM in New Orleans. 17

19 Council Resolutions R-17-100 and R-17-176. 20 Neither I, nor the Brattle Group, have performed or purported to perform any analysis to determine whether the goals described are achievable.


22

Figure 4 Energy Smart Forecasted Energy Savings Goals

Sources and Notes: The Brattle Group. Savings goals for PYs 7-9 are reported in Filing to demonstrate the reallocation of kWh savings forecasted for Program Year 7 to Program Year 8, CNO Docket No. UD-08-02, January 22, 2018. The Council approved ENO’s plan for incremental 0.2% savings targets in Resolution R-17-176, April 6, 2017. Cumulative savings do not include savings for Program Years 1-6.

1

ENO’s Proposed Rider DSMCR B.2

Q25. HAS ENO PROPOSED A NEW RIDER MECHANISM TO ADDRESS ISSUES OF 3

COST RECOVERY ASSOCIATED WITH ENERGY SMART? 4

A. Yes. In this filing, ENO is proposing to address cost recovery associated with Energy 5

Smart. This proposal is in furtherance of the Council’s goal to establish permanent and 6


23

stable funding source for its DSM initiatives,21 as well as in fulfillment of additional 1

requirements that ENO address Energy Smart funding in this proceeding, which Mr. 2

Owens describes in more detail. 3

ENO’s proposal is designed to address the issues I have described previously in my 4

testimony. Namely, ENO’s proposal would address the challenges inherent in 5

implementing DSM and, further, would provide a performance incentive that helps 6

position DSM investment on a more level playing field with supply-side alternatives from 7

a financial standpoint. The proposal is a customer-centric solution that would facilitate 8

new and expanded demand-side options for ENO’s customers and better allow ENO to 9

fully incorporate DSM into its core business. In other words, adoption of the Company’s 10

proposal and Rider DSMCR would support ENO’s goal of increasing DSM offerings and 11

facilitate the Council’s goal of increasing DSM savings. 12

Accordingly, ENO’s proposal in this rate case is comprised of the three previously-13

described elements: (1) full recovery of prudent DSM investments, (2) mitigation of 14

under-recovered fixed costs due to reduced energy (kWh) sales, and (3) performance 15

incentives for achievement of DSM goals. When combined, these features have a proven 16

track record of success in other jurisdictions. 17

21 Council Resolution R-07-600, December 6, 2007.


24

Q26. PLEASE START WITH RECOVERY OF DSM INVESTMENTS. WHAT 1

SPECIFICALLY HAS ENO PROPOSED IN THIS REGARD? 2

A. ENO has proposed to recover DSM investments through Rider DSMCR. The proposal is 3

to effectively “rate-base” DSM investments through the creation of a new regulatory 4

asset-based balance each year, and then to amortize that balance over three years. This 5

means that Rider DSMCR will be updated on an annual basis to recover during the 6

following year a portion of the balance until the amount is fully recovered subject to 7

necessary true-ups. It is my understanding that ENO has always been allowed to recover 8

the costs of its DSM efforts. ENO is proposing to continue this long-standing Council-9

approved policy except that recovery will be spread over a 3-year period and ENO would 10

be permitted to earn a return on its DSM investments in lieu of the existing performance 11

incentive mechanism, although the amount of that return would be tied to the savings 12

ENO’s DSM investments achieve. 13

14

Q27. WHAT ARE THE BENEFITS OF RATE-BASING RATHER THAN EXPENSING 15

DSM INVESTMENTS IN TERMS OF COST RECOVERY? 16

A. Placing DSM investments in rate base effectively puts those investments on a more level 17

playing field with supply-side resources and other traditional infrastructure investments 18

and ensures that DSM will be treated in a similar fashion. As discussed in Section II.A, 19

utilities typically earn a return on their capital expenditures, but do not earn a return on 20

DSM expenditures if they are simply treated as operating expenses. Treating DSM in a 21

manner similar to a supply-side investment facilitates ENO’s goal of incorporating DSM 22

offerings into ENO’s core business and the Council’s goal of increasing energy savings. 23


25

Another benefit of using a regulatory asset-based approach is that it spreads and 1

smooths out fluctuations in cost recovery from customers. By amortizing costs over 2

time, ENO’s proposed Rider DSMCR avoids the significant short-term rate impacts that 3

can occur with a lump sum recovery of large DSM expenditures. 4

5

Q28. HAS ENO PROPOSED TO RECOVER LOST CONTRIBUTIONS TO FIXED COSTS 6

IN RIDER DSMCR? 7

A. Yes. ENO is proposing a LCFC recovery mechanism for years beyond year nine of 8

Energy Smart, which I understand would be 2020 and beyond. The LCFC recovery 9

mechanism would apply specifically to lost energy sales due to DSM efforts, defined as 10

kWh savings times applicable adjusted gross margin (“AGM”).22 As described in Mr. 11

Owens’ Direct Testimony, the proposed mechanism calculates a projected LCFC amount 12

for the upcoming year, to be recovered contemporaneously through Rider DSMCR. 13

There is then an annual true-up mechanism in the following year to reconcile the 14

difference between LCFC associated with projected energy savings and LCFC resulting 15

from the savings that actually occurred as well as to address timing differences between 16

rates being set under Rider DSMCR effective each year in January and base rates being 17

adjusted each year under a separate FRP. 18

22 I understand that AGM is a term ENO uses to describe the volumetric (cents per kWh) portion of ENO’s base rates excluding fuel and other riders.


26

Q29. LASTLY, PLEASE DISCUSS UTILITY PERFORMANCE INCENTIVES. IS THERE 1

CURRENTLY A UTILITY PERFORMANCE INCENTIVE MECHANISM IN PLACE? 2

A. Yes, ENO is currently allowed a performance incentive based on relative achievement of 3

its energy savings goals. However, funding for the incentive will extend only through the 4

current program period (years 7 through 9, or 2017 through 2019). Beyond 2019, no 5

determinations have been made regarding the design of a performance incentive. 6

7

Q30. PLEASE DESCRIBE ENO’S PERFORMANCE INCENTIVE PROPOSAL. 8

A. ENO is proposing to implement a new performance incentive for the years beyond PY 9 9

(i.e., starting in 2020). As described in greater detail by Mr. Owens, the proposed 10

performance incentive consists of a return on the unamortized balance related to DSM 11

investments made for that PY. The return is calculated as ENO’s pre-tax weighted 12

average cost of capital based on its allowed return on equity (“ROE”), subject to a 13

performance adjustment tied to ENO’s achievement of the Council’s savings goal. On a 14

sliding-scale basis, the proposed performance adjustment can decrease the allowed rate of 15

return by up to 100 basis points for underachievement of the savings goal, or increase it 16

by up to 200 basis points for overachievement. The performance incentive is also subject 17

to an annual true-up mechanism that reconciles calculation of the performance 18

adjustment in the prior year with verified savings. 19


27

Q31. DOES THE PROPOSED PERFORMANCE INCENTIVE CREATE A RISK OF 1

PRIORITIZING SPENDING OVER SAVINGS? 2

A. No. First, ENO’s Energy Smart portfolio for each PY must be approved by the Council 3

to be eligible for the performance incentive. This approval typically follows completion 4

of the separate Integrated Resource Plan proceedings, which includes a DSM Potential 5

Study that identifies cost-effective DSM measures and informs the design of each PY’s 6

portfolio of offerings. ENO will also have to demonstrate that the costs incurred would 7

be reasonable and prudent. Following implementation for a given PY, ENO will employ 8

a third-party to carry out EM&V procedures. These procedures will determine if the 9

DSM measures were cost-effective using standard screening tests. If the measures do not 10

pass these screening tests, the measures will be modified to ensure their cost-11

effectiveness or eliminated altogether, depending on the Council’s directives. Annual 12

EM&V reviews will ensure that ENO’s DSM spending is yielding the projected savings 13

and will be a key aspect of the proposed annual true-up process. 14

In addition, the performance adjustment on the rate of return provides performance 15

targets that reward energy savings and cost-effective spending. ENO is rewarded for 16

exceeding its energy savings goals, and penalized for falling short of them, similar to the 17

savings-based performance incentive currently in place. 18

19

Q32. DOES THE PERFORMANCE INCENTIVE REPLACE THE NEED FOR LOST FIXED 20

COST RECOVERY, OR VICE VERSA? 21

A. No. ENO’s proposed performance incentive and its proposed LCFC recovery mechanism 22

are unrelated and designed to accomplish different objectives. The LCFC recovery 23


28

mechanism mitigates what would otherwise be reduced earnings to the utility due to the 1

establishment of rates that do not account for the impacts of DSM on energy sales. 2

Therefore, while the LCFC recovery mechanism makes ENO, and its owners, whole with 3

respect to return of (and on) its other capital investments, it does not provide a return on 4

DSM investments nor does it provide any incentive to invest in DSM. The purpose of the 5

separate performance incentive is to provide an adequate incentive for pursuing future 6

DSM initiatives, both to ENO and the owners who provide the capital that funds DSM 7

investments, and to put DSM on an equal financial footing with supply-side resources 8

and infrastructure. 9

10

Q33. IS THERE A RISK THAT ENO COULD BE COMPENSATED TWICE FOR A 11

POTENTIAL UNDER-RECOVERY OF FIXED COSTS IF BOTH THE 12

PERFORMANCE INCENTIVE AND THE LOST FIXED COST RECOVERY 13

MECHANISM ARE ACCEPTED BY THE COUNCIL? 14

A. No, there is no double-counting. The performance incentive is entirely incremental to the 15

LCFC recovery mechanism. Appropriate treatment of LCFC ensures that ENO and its 16

owners are recovering fixed costs while investing in DSM. A separate performance 17

incentive places DSM investment on equal financial footing with more traditional utility 18

investments. 19


29

Comparison of ENO’s Proposal with Other U.S. Utilities’ Cost C.1 Recovery Mechanisms 2

Q34. HOW DOES ENO’S RIDER DSMCR PROPOSAL COMPARE WITH THE 3

REGULATORY CONSTRUCT IN PLACE FOR DSM PROGRAMS IN OTHER U.S. 4

JURISDICTIONS? 5

A. As described in section II.A, recovery of DSM investments, recovery of potential lost 6

contributions to fixed cost, and incentives related to the performance of DSM initiatives 7

are widespread in the U.S. At least 27 states already allow utilities to recover DSM 8

investments, to recover their lost contribution to fixed costs, and to earn a performance 9

incentive related to their DSM investments. In this context, ENO’s proposal to include 10

all three of these incentive elements is in line with common practices in the U.S. and is 11

also consistent with prior Council decision-making on Energy Smart as I understand. 12

13

Q35. DO OTHER JURISDICTIONS ALLOW UTILITIES TO RECOVER DSM COSTS 14

THROUGH A REGULATORY ASSET-BASED COST RECOVERY MODEL LIKE 15

ENO IS PROPOSING? 16

A. Yes. Cost recovery through rate-basing has been in place in Maryland since 2008, and 17

was implemented in Illinois and Utah in 2016 and in New York in 2017. As I discuss 18

further below, this is the beginning of a new trend. 19


30

Q36. HOW DOES ENO’S PROPOSED RATE-BASING COST RECOVERY MECHANISM 1

COMPARE WITH THOSE IN OTHER JURISDICTIONS? 2

A. Although utilities in each of these jurisdictions have adapted their DSM rate-basing cost 3

recovery mechanism to state-specific situations and legislation, the structure of their cost 4

recovery mechanism is similar to the one ENO is proposing. 5

Maryland has had a rate-basing cost recovery mechanism in place for DSM since 6

2008, following the passage of the EmPOWER Maryland Energy Efficiency Act.23 In 7

Maryland, Baltimore Gas & Electric (“BGE”) has implemented an Electric Efficiency 8

Charge to recover DSM investments. DSM investments include design and 9

implementation costs for approved DSM measures, and are amortized over five years at 10

BGE’s full authorized rate of return. Maryland’s mechanism is considered “one of the 11

most successful cost-recovery mechanisms for EE in the country.”24 12

Illinois began allowing electric utilities to earn a ROE for DSM spending in 2017. 13

This was authorized by the Future Energy Jobs Act (“FEJA”). Commonwealth Edison 14

Company (“ComEd”) received approval for its Energy Efficiency Formula Rate rider in 15

compliance with FEJA.25 The rider is calculated following the traditional revenue 16

requirement formula, but using a rate base specific to ComEd’s DSM offerings. It 17

collects the annual amortization of DSM costs over the weighted average measure life of 18

the measures deployed each year, which is more complicated to implement than ENO’s 19

23 EmPOWER Maryland Energy Efficiency Act of 2008, House Bill 374, accessed May 21, 2018, http://mlis.state.md.us/2008rs/chapters_noln/Ch_131_hb0374E.pdf. 24 CLEAResult, “Creating Customer and Investor Value through Energy Efficiency,” July 11, 2017, accessed May 21, 2018, https://www.clearesult.com/insights/whitepapers/creating-customer-and-investor-value-through-energy-efficiency/. 25 Order 451965, Petition for approval of energy efficiency formula rate tariff and charges authorized by Section 8-103B of the Public Utilities Act, Docket 17-0287, August 15, 2017.

http://mlis.state.md.us/2008rs/chapters_noln/Ch_131_hb0374E.pdfhttps://www.clearesult.com/insights/whitepapers/creating-customer-and-investor-value-through-energy-efficiency/https://www.clearesult.com/insights/whitepapers/creating-customer-and-investor-value-through-energy-efficiency/


31

proposed three-year amortization period. Similar to ENO’s proposed DSM Rider 1

DSMCR, ComEd’s formula rate includes a performance adjustment, which can either 2

increase or decrease the ROE by up to 200 basis points. Both riders are also calculated 3

first on the basis of projected data for the following calendar year, and then trued-up 4

annually for under- or over- collection using verified costs and savings. 5

Utah passed Senate Bill 115 in 2016 establishing the Sustainable Transportation 6

and Energy Plan Act (“STEP”).26 STEP allows Utah’s largest electric utility, Rocky 7

Mountain Power (“RMP”), to capitalize and amortize its DSM costs over a period of 10 8

years.27 As with ENO’s proposed Rider DSMCR, costs are recovered through an 9

Efficiency & STEP Programs rider. However, RMP’s mechanism is somewhat different 10

in that part of the amount collected through the rider feeds into a separate fund to 11

accelerate depreciation of old coal plants being retired.28 12

Finally, the New York Public Service Commission approved rate-basing for 13

Consolidated Edison (“ConEd”) in 2017 as part of its most recent rate case. ConEd’s 14

new base rates are designed to recover the costs of its Energy Efficiency Program over 15

ten years, “including the overall pre-tax rate of return on such costs.”29 16

26 Utah State Legislature, “S.B. 115 Sustainable Transportation and Energy Plan Act,” accessed May 30, 2018, https://le.utah.gov/~2016/bills/static/SB0115.html. 27 Rocky Mountain Power serves 80% of Utah’s population. See American Council for an Energy-Efficient Economy, “State and Local Policy Database: Utah,” accessed May 30, 2018, https://database.aceee.org/state/utah. 28 Supplemental Testimony of Steven R. McDougal, Docket No. 16-035-36, October 2016. 29 Joint Proposal, Case 16-E-0060, September 19, 2016, p. 81. The joint proposal was approved in an order issued January 25, 2017.

https://le.utah.gov/~2016/bills/static/SB0115.htmlhttps://database.aceee.org/state/utah


32

Q37. YOU MENTIONED EARLIER THAT RATE-BASING WAS ONCE PREVALENT IN 1

OTHER JURISDICTIONS. PLEASE PROVIDE HISTORICAL CONTEXT FOR THE 2

RATE-BASING MODEL. 3

A. Rate-basing was especially popular in the late 1980s and early 1990s, when utility energy 4

efficiency investment at the time was at its peak and performance incentives to encourage 5

DSM efforts were still relatively new.30 Use of the rate-basing model declined in the 6

mid-1990s for several reasons. First, restructuring of the electric utility industry at the 7

time caused overall DSM investments to decline, as restructuring proponents advocated 8

for cuts to utility-sponsored DSM arguing that the competitive market would likely 9

provide such services. That has not proven to be the case.31 10

In addition, many states moved away from rate-basing due to costs associated with 11

lengthy amortization periods. A utility incurs carrying charges from holding an 12

unrecovered balance on its books. The longer the amortization period, the greater the 13

total carrying charges the utility must recover through the return on its unamortized 14

balance. 32 15

A third problematic issue for the rate-basing model of the 1980s and 1990s was 16

that, for many utilities, the return earned was not associated with the DSM performance 17

30 National Action Plan for Energy Efficiency, “Aligning Utility Incentives with Investment in Energy Efficiency,” November 2007, p. 4-5; Nadel and Jordan, “Does the Rat Smell the Cheese? A Preliminary Evaluation of Financial Incentives Provided to Utilities,” in Regulatory Incentives for DSM (1992), p. 229, accessed June 12, 2018, http://aceee.org/ebook/regulatory-incentives-for-demand-side-management. 31 Nadel, Steve, “Utility Energy Efficiency Programs: Lessons from the Past, Opportunities for the Future,” in Energy Efficiency: Towards the End of Demand Growth (2013), p. 54. 32 National Action Plan for Energy Efficiency, “Aligning Utility Incentives with Investment in Energy Efficiency,” November 2007, pp. 4-5, 4-6.

http://aceee.org/ebook/regulatory-incentives-for-demand-side-management


33

achieved.33 This was even the case in several states that implemented “rate base 1

premiums,” which allowed utilities to earn a higher rate of return for rate-based DSM 2

expenditures than for supply-side investments. The absence of relationship between 3

utilities DSM plans’ performance and the level of earned return created concerns that 4

utilities were being rewarded purely to invest, and may be incentivized to increase 5

investments in poorly performing DSM plans.34 6

7

Q38. ARE THESE CONCERNS ADDRESSED IN ENO’S PROPOSED COST RECOVERY 8

MECHANISM? 9

A. Yes. Specifically, ENO’s proposed cost recovery mechanism addresses the relevant 10

concerns, and the other concerns do not apply to the current DSM landscape. As far as 11

concerns that the cost recovery mechanism encourages spending with no consideration 12

for outcome, this is addressed through ENO’s proposed performance adjustment. The 13

performance adjustment would tie the allowed rate of return to outcome, adjusting it 14

downwards or upwards based on ENO’s achievement of the Council’s approved savings 15

goals. Moreover, as I discussed earlier, Energy Smart measures will still be subject to 16

EM&V tests, which will ensure that spending is yielding the projected savings, with 17

benefits that outweigh the costs of the measures. EM&V procedures are much more 18

33 National Action Plan for Energy Efficiency, “Aligning Utility Incentives with Investment in Energy Efficiency,” November 2007, p. 4–8. 34 U.S. Congress, Office of Technology Assessment, “State Energy Efficiency Initiatives,” in Energy Efficiency: Challenges and Opportunities for Electric Utilities (Washington, DC: U.S. Government Printing Office, September 1993), pp. 132, 137, accessed June 4, 2018, http://ota.fas.org/reports/9323.pdf; Nadel, Reid, and Wolcott, “Ratebasing of DSM Expenditures,” in Regulatory Incentives for DSM (1992), p. 95.

http://ota.fas.org/reports/9323.pdf


34

rigorous and developed now than they were in the 1980s; hence, utilities are held to 1

higher cost-effectiveness standards and kept accountable for their spending. 2

To limit carrying costs that increase regulatory asset balances, ENO has also 3

proposed an amortization period of three years, which is relatively short compared to 4

those of other utilities that either have or had rate-basing of DSM costs.35 This avoids 5

large cumulative rate impacts from carrying charges and reduces long-term risk to 6

customers. 7

More broadly speaking, performance incentives for DSM spending as a whole have 8

become more established since the implementation of rate-basing in the 1980s.36 9

Although rate-basing is currently less common than other forms of utility incentives like 10

“shared savings,” it addresses the same present-day challenges to maximizing DSM 11

investment in a way that is more transparent and requires less regulatory supervision. 12

Furthermore, as DSM becomes an increasingly core component of a utility’s business, it 13

is seeing renewed interest from regulators and legislative bodies as a preferred cost 14

recovery mechanism. 15

16

Q39. WHY IS THERE RENEWED INTEREST IN THE U.S. UTILITY INDUSTRY IN 17

RATE-BASING OF DSM INVESTMENTS? 18

A. As utilities are striving to meet their customers’ and their regulators’ expectations to offer 19

increasingly more DSM, they have to make greater investments in DSM. Accordingly, 20

35 National Action Plan for Energy Efficiency, “Aligning Utility Incentives with Investment in Energy Efficiency,” November 2007, p. 4-6. 36 Nadel and Jordan, “Does the Rat Smell the Cheese? A Preliminary Evaluation of Financial Incentives Provided to Utilities,” in Regulatory Incentives for DSM (1992), p. 229.


35

there has been growing support for placing demand-side and traditional supply-side and 1

other infrastructure investments on more equal footing, which is achieved through rate-2

basing of demand-side costs.37 For example, a recent joint statement from the EEI and 3

the NRDC supports further success in utilities’ energy efficiency investments, and 4

specifically recommends “earnings opportunities for such investments, like more 5

traditional regulatory assets.”38 6

7

Q40. DO YOU BELIEVE THAT ENO’S PROPOSAL WILL FACILITATE ENO’S GOAL 8

OF INCORPORATING DSM AS A CORE COMPONENT OF ITS BUSINESS AND 9

THE COUNCIL’S GOAL OF INCREASING SAVINGS? 10

A. Yes. DSM is a customer-centric resource that provides multiple benefits, including 11

improving the environment and helping reduce customer bills. By placing DSM 12

investment on a more equal playing field with supply-side resources, rate-basing will 13

enable ENO to make DSM a core feature of its business. Given the increase in 14

investment needed to keep up with the escalating goals for Energy Smart, it is important 15

that the Council provide the necessary support by approving ENO’s fair and appropriate 16

ratemaking proposal. 17

37 Brian Hedman and Jill Steiner, “DSM in the Rate Case,” Public Utilities Fortnightly, January 2013. 38 Edison Electric Institute and Natural Resources Defense Council, “Joint EEI/NRDC Statement to NARUC,” February 14, 2018, p. 2.


36

III. DISTRIBUTION GRID MODERNIZATION RIDER 1

Grid Modernization Initiative in the U.S. A.2

Q41. WHAT IS GRID MODERNIZATION? 3

A. Grid modernization can encompass many different kinds of upgrades to the power grid 4

that make it more reliable, resilient, and responsive. Utilities and regulators have 5

recognized that infrastructure investments are needed for these upgrades so that utilities 6

can keep up with advancements in energy technologies, customer engagement, and the 7

integration of DERs on both the supply- and demand-side. An enhanced and more 8

flexible grid can unlock many benefits, both operational and customer-facing, which can 9

help reduce costs and improve reliability, resiliency, sustainability, security, and quality 10

of service for all customers. 11

The U.S. Department of Energy (“DOE”) Grid Modernization Initiative39 (“GMI”) 12

defines three main areas in which “key developments” are needed to advance the nation 13

to a modernized grid:40 14

• Technology (i.e., hardware): Develop and demonstrate technologies for 15

better measurement (e.g., sensors), integration (e.g., inverters), 16

management and control of grid operations (e.g., transformers) 17

• Modeling and Analysis (i.e., software): Develop and disseminate new 18

and improved models for analysis, management and optimization of grid 19

performance (e.g., solar and wind prediction) 20 39 See U.S. Department of Energy, “Grid Modernization Initiative,” accessed May 4, 2018, https://www.energy.gov/grid-modernization-initiative-0. 40 U.S. Department of Energy, “Grid Modernization Multi-Year Program Plan,” November 2015, p. xi, accessed May 4, 2018, https://www.energy.gov/downloads/grid-modernization-multi-year-program-plan-mypp.

https://www.energy.gov/grid-modernization-initiative-0https://www.energy.gov/downloads/grid-modernization-multi-year-program-plan-mypp


37

• Institutional and Business: Develop the analytical methodologies and 1

frameworks for improving business models that can deliver to consumers 2

the value and benefits of grid modernization. 3

Nationwide, environmental policy and other similar advocacy organizations are also 4

supportive of grid modernization efforts as a necessary foundation for DER integration 5

and enhanced customer information and education. For instance, the Environmental 6

Defense Fund (“EDF”) wrote a whitepaper in 2017 on grid modernization. In the paper, 7

EDF states that “[g]rid modernization is essential to ensuring the energy systems that 8

power our lives and underpin our economy are protected from future disruptive events” 9

and that it will “[create] a platform to make meaningful progress on mitigating the future 10

impacts of climate change.”41 11

12

Q42. ARE GRID MODERNIZATION INVESTMENTS CONSIDERED DIFFERENT FROM 13

ROUTINE DISTRIBUTION CAPITAL EXPENDITURES? 14

A. Yes. Distribution grid investments are incurred by the utility in the “normal course of 15

business” to replace and maintain equipment and facilities, which are a combination of 16

older infrastructure and some limited new technology (e.g., replacement of deficient 17

meters, line transformers, broken poles, or damaged circuits and feeders). Grid 18

modernization investments (e.g., distribution automation) are specifically motivated by 19

long-term objectives of improvement (e.g., enhanced grid resiliency, integration of 20

DERs, customer education) for the jurisdiction, set by the regulator and/or the utility. 21

41 Environmental Defense Fund, “Grid Modernization: The foundation for climate change progress,” December 6, 2017, p. 2, accessed May 4, 2018, https://www.edf.org/sites/default/files/GridModReport.pdf.

https://www.edf.org/sites/default/files/GridModReport.pdf


38

While the former is often considered mandatory for the utility to continue providing safe 1

and reliable service in the short term, the latter is considered critical to the health and 2

reliability of the system in the longer term. However, in bolstering the grid, proactive 3

grid modernization investments can also produce immediate reliability benefits for 4

customers. 5

6

Q43. PLEASE BRIEFLY DESCRIBE GRID MODERNIZATION EFFORTS OCCURRING 7

IN THE U.S. 8

A. Grid modernization initiatives are widespread and have especially accelerated over the 9

last few years. The North Carolina Clean Energy Technology Center catalogued in its 10

recent “50 States of Grid Modernization” report42 some 288 state actions related to grid 11

modernization in 2017, spanning 40 states (including Washington D.C.). In particular, 12

this report indicates that 12 states have active proceedings “regarding the deployment of 13

technologies aimed at modernizing the distribution system.”43 Regionally, utilities are 14

facing different immediate and longer-term challenges, and therefore are prioritizing 15

different types of investments. Some recurrent themes are advanced metering 16

infrastructure (“AMI”) deployment and other smart grid technology upgrades that enable 17

42 North Carolina Clean Energy Technology Center, “The 50 States of Grid Modernization: 2017 Review and Q4 2017 Quarterly Report,” January 2018, p.12. 43 North Carolina Clean Energy Technology Center, “The 50 States of Grid Modernization: 2017 Review and Q4 2017 Quarterly Report,” January 2018, p. 34.


39

energy storage, smart cities, enhancement of customer engagement, and transportation 1

electrification.44 2

3

Q44. WHAT IS THE MAGNITUDE OF DISTRIBUTION INFRASTRUCTURE UPGRADE 4

INVESTMENTS THROUGHOUT THE U.S.? 5

A. Electric distribution infrastructure investments in the U.S. have tripled in the last 6

20 years. Figure 5 below summarizes average utility distribution plant additions since 7

1990.45 8

44 North Carolina Clean Energy Technology Center, “The 50 States of Grid Modernization: 2017 Review and Q4 2017 Quarterly Report,” January 2018, p. 38; Environmental Defense Fund, “Grid Modernization: The foundation for climate change progress,” December 6, 2017. 45 I consider distribution plant additions to be a good indicator of how distribution infrastructure investments have grown, however I note it includes all kinds of infrastructure upgrades (e.g., extensions of the grid to areas not previously served by the utility, AMI deployment, line replacements).


40

Figure 5 Distribution Plant Additions per Utility in the United States

Sources and Notes: The Brattle Group analysis using S&P global, Federal Energy Regulatory Commission Form 1 data. The sample of utilities with available data increased during the time period analyzed.

Significant multi-year grid modernization investment plans have been proposed by 1

utilities in recent years.46 Some of these plans have already received regulatory 2

approval.47 3

4

Q45. HOW DO UTILITIES TYPICALLY RECOVER CAPITAL INVESTMENTS? 5

A. There are two common ways for utilities to recover the cost of capital investments. First, 6

capital expenditures can be included in a utility’s rate base and then recovered through 7

46 For example, see North Carolina Clean Energy Technology Center, “The 50 States of Grid Modernization: 2017 Review and Q4 2017 Quarterly Report,” January 2018, Table 3 p. 35. 47 For example, Xcel Energy Colorado was approved in 2017 a 6-year plan for a $612 million investment, with costs recovered in rate base (COPUC Proceeding 16A-0588E). Duke Energy Indiana was approved in 2016 a 7-year plan for a $1.4 billion investment, with 80% of costs recovered through a rider (IURC Cause No. 44720).


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base rates after the approval of the corresponding investments in the context of a general 1

rate case or an FRP update. Alternatively, capital expenditures can be recovered through 2

a separate rider (i.e., a surcharge) under certain circumstances. Riders can be updated on 3

a more timely basis than base rates, which require either a general rate case or an annual 4

FRP proceeding. 5

6

Q46. WHEN DOES IT MAKE SENSE TO RECOVER CAPITAL EXPENDITURES 7

THROUGH A RIDER AND NOT THROUGH BASE RATES? 8

A. Recovering capital expenditures through a rider is warranted when a regulator values grid 9

modernization and wants to create a mechanism for enabling a utility to pursue grid 10

modernization on an expedited basis while maintaining regulatory oversight. Some 11

capital expenditures are allowed to be accounted for separately to ease the process and 12

resulting timeliness of recovery and accelerate these investments. Recovering specific 13

investments through a rider reduces the regulatory burden that is often associated with 14

filing a full rate case. The regular update of the rider typically comes with a filing to 15

include recent capital investments. Furthermore, many riders, like ENO’s proposed Rider 16

DGM, do not have definitive end dates, while formula rate plans typically do (e.g., three 17

years in ENO’s case). The rider mechanism provides the utility an opportunity to invest 18

in beneficial infrastructure in a timely fashion. 19

If a jurisdiction is determined to prioritize or accelerate certain types of 20

investments, creation of a rider may ease the process for a utility, eliminate uncertainty in 21

the timing of cost recovery relative to regulatory lag, and thereby encourage the 22

investment. A well-designed rider targets specific types of investments in such a way 23


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that it is relatively easy to determine whether an investment qualifies or not. A capital 1

rider is intended to smooth out the process for approving new investments. A rider may 2

also be implemented when the types of investments targeted are well defined, but the cost 3

and timing of those investments are still uncertain. In that case, a rider will allow the 4

accounting separation of such investments and enable the regulatory body to follow 5

closely the progress of the actually-incurred costs and timing. 6

7

Q47. ARE INFRASTRUCTURE IMPROVEMENT AND MODERNIZATION RECOVERY 8

RIDERS COMMON AMONG U.S. UTILITIES? 9

A. Yes. It is common for regulators to prioritize and want to expedite some investments 10

toward infrastructure improvement or modernization. Entergy Louisiana, LLC’s (“ELL”) 11

Gas Infrastructure Investment Recovery Rider is a good example. This rider was created 12

when the Louisiana Public Service Commission (“LPSC”) was looking to improve safety 13

by incentivizing capital expenditures toward replacement of aging natural gas pipelines. 14

A recent S&P Global RRA Regulatory Focus report48 notes that “regulators in 40 of the 15

53 jurisdictions covered by RRA have implemented expedited cost recovery mechanisms 16

associated with infrastructure improvement plans for at least one company in the state.” 17

The report also notes that more than 40% of companies surveyed currently have some 18

form of infrastructure investment-related adjustment clause (or rider). 19

48 RRA Regulatory Focus, “Themes in U.S. energy utility markets and regulation,” April 30, 2018, p. 19.


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Infrastructure investment riders in the context of the modernization of the electric 1

distribution network are also relatively common among U.S. utilities. I expand upon the 2

use of such riders further in section III.C below. 3

4

ENO’s Proposed Distribution Grid Modernization Rider B.5

Q48. PLEASE DESCRIBE ENO’S DISTRIBUTION GRID MODERNIZATION PLAN. 6

A. As explained by Company witness Erica H. Zimmerer, ENO is upgrading its distribution 7

infrastructure to add new technologies and intelligent devices that facilitate safe multi-8

directional energy flows, automate operations, enable wireless control, facilitate 9

operational efficiency, improve service, increase reliability and resiliency, and expand 10

options for customers. ENO’s grid modernization plan, as described by Ms. Zimmerer, 11

fits into the broader scope of U.S. grid modernization efforts and as defined by the DOE. 12

Ms. Zimmerer describes five projects currently in development. These projects 13

involve upgrades such as: 14

• the creation of “self-healing networks” by installing automatic reclosers 15

and smart devices to increase visibility of real-time system conditions; 16

• the redesign of overhead circuit segments; 17

• the improvement of communication with the AMI network and control of 18

the grid via the Distribution Management System and Outage 19

Management System (“DMS/OMS”) interface; and 20


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• the sectionalization or reconfiguration of circuits to minimize the number 1

of customers exposed to outages.49 2

The preliminary estimate of the total investment necessary for these five projects 3

is $52.4 million over approximately five years.50 4

5

Q49. DOES ENO’S GRID MODERNIZATION PLAN INCLUDE INVESTMENTS 6

RELATED TO AMI DEPLOYMENT? 7

A. No. The deployment of AMI in ENO’s service area was approved in Council Resolution 8

R-18-37 dated February 8, 2018, and the ratemaking mechanism to recover AMI 9

deployment capital costs has been proposed by ENO in the current proceeding.51 10

However, the grid enhancements proposed by ENO as part of its grid modernization plan 11

will enable a “broader scope of applications upon completion of AMI deployment”52 and 12

serve as a foundation to the Council’s Smart Cities’ initiative. 13

14

Q50. IS GRID MODERNIZATION IMPORTANT FOR THE CITY OF NEW ORLEANS? 15

A. I understand that grid modernization is a major near-term objective for the City of New 16

Orleans. The Council also has expressed a goal of making New Orleans a “Smart City” 17

and explained that the modernization of its electric distribution grid is an important step 18

toward that goal. For instance, at a recent meeting of the Council’s Utility, Cable, 19

49 See Direct Testimony of Ms. Zimmerer. 50 As Ms. Zimmerer explains, ENO will have a much better understanding of the projected costs of the projects once it completes the first of the projects and can refine its projections and estimates based on that real-world experience. 51 See Direct Testimony of Company witness Joshua B. Thomas. 52 ENO’s Grid Modernization and Smart Cities Report, Docket No. UD-18-01, April 10, 2018, p. 9.


45

Telecommunications and Technology Committee, it was reported that “among the first 1

goals of the [Smart City] initiative is to gather detailed information on modernizing the 2

Entergy New Orleans (ENO) electric distribution system to upgrade the physical 3

structures and the functional technology.” Further, “the Committee indicated that an 4

immediate short-term goal would be to pursue a greater penetration of distributed 5

generation.”53 Following that meeting, the Council issued Resolution R-18-36, on 6

February 8, 2018, opening an inquiry “into establishing a Smart City initiative for the city 7

of New Orleans and directing [ENO] to report with respect to matters related to grid 8

modernization.” The Council has also announced its intention to create a new Committee 9

devoted to developing a master plan for the Smart Cities initiative.54 10

11

Q51. WHAT ARE THE BENEFITS ASSOCIATED WITH ENO’S GRID 12

MODERNIZATION PLAN? 13

A. ENO’s distribution grid modernization plan is expected to benefit customers most 14

immediately by increasing the reliability of the grid. It should reduce the number and 15

frequency of outages and reduce restoration times (i.e., improved System Average 16

Interruption Frequency Index (“SAIFI”) and System Average Interruption Duration Index 17

(“SAIDI”)).55 According to Ms. Zimmerer, the five proposed projects are “expected to 18

improve reliability by reducing the number of [customer interruptions] by more than 19 53 “UCTT Committee Chair Jason Williams Announces Smart Cities Initiative to Ensure New Orleans Will Be a 21-st Century City,” New Orleans City Council, January 31, 2018, accessed May 6, 2018, http://nolacitycouncil.com/content/display.asp?id=54&nid={C80A4FE4-B7A2-4AA1-AEA3-31AB7A64B69C}. 54 “New Orleans City Council's at-large members, only returning councilor will lead key committees,” The New Orleans Advocate, May 27, 2018, https://www.theadvocate.com/new_orleans/news/article_40ab2570-6232-11e8-8bec-4bf67c83c1e7.html. 55 See Direct Testimony of Ms. Zimmerer.

http://nolacitycouncil.com/content/display.asp?id=54&nid=%7bC80A4FE4-B7A2-4AA1-AEA3-31AB7A64B69C%7dhttps://www.theadvocate.com/new_orleans/news/article_40ab2570-6232-11e8-8bec-4bf67c83c1e7.htmlhttps://www.theadvocate.com/new_orleans/news/article_40ab2570-6232-11e8-8bec-4bf67c83c1e7.html


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53,000 per year and lowering the number of [customer minutes of experienced outages] 1

by