BEFORE THE

COUNCIL OF THE CITY OF NEW ORLEANS

IN RE: EXAMINATION OF OPPORTUNITIES FOR AND EFFECTS OF CONSUMER-BASED RENEWABLE TECHNOLOGIES IN THE CITY OF NEW ORLEANS

) ) ) ) )

DOCKET NO. UD-13-02

ENTERGY NEW ORLEANS, INC.’S COMMENTS

AND NET ENERGY METERING PROPOSAL Entergy New Orleans, Inc. (“ENO”)1 respectfully submits its comments and net energy

metering (“NEM”) proposal (“Proposal”) in response to step (4) of the procedural schedule of

Council Resolution R-15-438, adopted on September 3, 2015, which states in part:

On or before September 28, 2016, the Companies should submit their NEM [net energy metering] proposal, which may include a proposal to maintain the status quo NEM Rules and NEM Tariff, to the Advisors and Intervenors. Their proposal should include: (1) a capacity and energy forecast of net metering saturation through 2020, based on the same assumptions used in the sales forecast in the Companies' current business plan; (2) any Companies' proposed changes to the NEM Rules and NEM Tariffs; (3) an analysis of the costs and benefits of the existing and any proposed NEM program from the perspective of a NEM residential and commercial customer, as well as from the perspective of all ratepayers, to assist the Council in determining whether any proposed NEM program is in the public interest and not unduly discriminatory; (4) an analysis of the cost of service related to residential and commercial NEM customers under the Council's existing NEM Rules and NEM Tariffs, and any proposed changes; (5) consideration of whether other rate design mechanisms, including but not limited to, minimum bills, marginal costs and time-of-use rates, could provide an appropriate alternative to any NEM proposal; (6) any differentiation in eligibility between existing NEM customers and prospective NEM customers under the existing NEM Rules and NEM Tariff; (7) any differentiation in eligibility between existing NEM customers and prospective NEM customers under any proposed NEM Rules and NEM Tariff; and (8) proposed changes to the annual NEM reporting framework for consideration by the Council to facilitate the ongoing monitoring and regulation of its NEM policies.

1 Although the Resolutions related to this proceeding refer to “Companies,” the transfer of Algiers was approved by

the Council of the City of New Orleans (the “Council”) in Resolution R-15-194 and was completed in September 2015 where all retail electric customers in Orleans Parish are now served by ENO.

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ENO submits this preliminary Proposal in compliance with this aspect of the procedural

schedule. Following this submission, the Resolution provides the Advisors and Intervenors an

opportunity to submit written feedback to ENO on or before November 7, 2016. ENO may then

submit its final NEM Proposal to the Council on or before January 11, 2017.

ENO begins by providing an Executive Summary of its Proposal followed by a brief

summary of the filing ENO made on March 3, 2015. The remainder of the filing describes

ENO’s efforts around three technical meetings that ENO convened in the first half of 2016 (in

compliance with Resolution R-15-438) and presents various forecasts and analyses ENO

completed, as well as ENO’s general recommendations for consideration by the Council’s

Advisors, other Stakeholders, and the Council, and a request for written feedback.

1.0 Executive Summary

It bears repeating at the outset that ENO has consistently said it believes individual retail

customers should have the choice to install self-generation equipment on their property, whether

a solar photovoltaic (“PV”) system or some other technology, and such customers should be

provided non-discriminatory access to the grid for interconnection. This point is irrefutable.

And of course, long-standing federal, state, and Council policies support those rights. However,

ENO’s efforts to consistently advocate for all of its customers on issues related to NEM policy

have, at times, caused Stakeholders to criticize ENO by claiming that ENO desires to stifle this

freedom of choice through policy changes that unfairly single out solar PV or fail to account for

various benefits provided by distributed generation from such systems. Nothing could be further

from the truth. Through this proceeding, ENO seeks to revise existing policies in a way that will

help make them more equitable and, in doing so, treat all of its customers more fairly.

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In this filing, ENO summarizes indicative results from various analyses it conducted,

which do in fact illustrate a very real cost-shift to non-NEM customers. The shift results from

two major drivers: (1) long-standing rate designs that mainly utilize volumetric (cents/kWh)

charges to recover ENO’s (mostly fixed) infrastructure and operating costs (excluding fuel and

purchased power), and (2) near-term avoided energy and capacity costs in the Midcontinent

Independent System Operator, Inc. (“MISO”) market that are lower today than they are expected

to be further out in time; in addition, current avoided costs do not reflect federal policies such as

carbon regulation, which may not take effect until the early 2020s depending on on-going legal

challenges. In conjunction with conducting its analyses, ENO convened three technical meetings

during the first half of 2016 in accordance with the procedural schedule established by

Resolution R-15-438. During and following these three technical meetings, parties in this

proceeding had multiple opportunities to provide specific, credible evidence that is quantifiable,

and therefore actionable, regarding the input assumptions, data, and methodologies used in the

various analyses. To ENO’s knowledge, no party in this proceeding provided such quantifiable

evidence.2 Regardless, ENO believes that the analyses referenced herein used reasonable input

assumptions and methodologies.

ENO also performed three parallel cost-benefit analyses of an alternative NEM policy (2-

Channel Billing, which ENO discussed extensively as a concept in the March 2015 filing) 3 that

2 The Alliance for Solar Choice (“TASC”) did provide a table listing potential costs and benefits, but to ENO’s

knowledge, there was no method of quantification that accompanied any of the potential costs and benefits included in the table. PosiGen, LLC (“PosiGen”) also provided an estimate of the regulatory costs of the proceedings in this Docket to date that was unsupported by facts and not relevant to this matter. Given the importance of reliable and demonstrable facts, ENO confined its analysis to known and quantifiable inputs provided or presented during the proceedings.

3 Please see Section 7.2, “Avoided Cost on Excess Energy.” 2-Channel Billing separates the treatment of electricity consumed by a customer (as recorded on Channel 1 of the NEM customer’s bi-directional net meter) versus excess energy delivered to the grid (as recorded on Channel 2 of the NEM customer’s meter). Under 2-Channel Billing (which some refer to as “net billing”), the customer is billed at the retail rate for all energy consumed from

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could begin after January 2020. To reiterate an important point made in Section 7 of the March

2015 filing, ENO suggested that it might be appropriate for the Council to consider

“grandfathering” existing NEM customers as of either a point in time or once a pre-determined

cap is reached (in the event that the Council were to adopt some form of a cap on NEM

participation).4 As such, under the illustrative comparative analyses, ENO considered two

different scenarios beyond the analysis of the status quo NEM policy. In the first scenario,

existing NEM customers, including those completing a valid interconnection application to take

NEM service on or before December 31, 2019, would be unaffected by the shift to 2-Channel

Billing. In the second analysis, ENO modeled a hypothetical scenario in which all NEM

customers would transition effective January 2020 to 2-Channel Billing. A separate cost of

service (“COS”) analysis was completed based on using 2015 as a test year. Table 1 summarizes

the results of the various illustrative analyses completed by ENO.

Table 1: Results of Cost-Benefit and COS Analyses.

Analysis

Net Benefits (Nominal)

Net Benefits (NPV)

Current 1:1 NEM Policy (2016 – 2034) ($31,462,360) ($16,988,318) 2-Channel Billing (new systems only after Jan 2020) ($30,452,170) ($16,618,206) Change in Net Benefits $1,054,654 $561,768 2-Channel Billing (all systems after Jan 2020) ($23,716,894) ($13,905,088) Change in Net Benefits $7,745,466 $4,296,598 COS (based on 2015 Test Year only) ~($550,000) Not Applicable

Note: Negative Net Benefits implies costs-shifting is occurring

the grid net of behind the meter usage (Channel 1) and receives a bill credit for all excess energy exported to the grid (Channel 2) during a billing cycle based upon a predetermined credit rate tied to the utility’s avoided costs.

4 For purposes of the analyses, January 2020 was chosen, to illustrate comparisons between maintaining the status quo NEM policy and implementing 2-Channel Billing as of a specific date.

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These results demonstrate that other customers are, and will continue to be, negatively

affected by the current policy over the expected 20+ year life of net metered rooftop solar PV

systems installed to date (much less ones that will be installed in the future).5 The cost-benefit

analyses also show that a change in policy to 2-Channel Billing, beginning in January 2020 (and

grandfathering existing customers under current NEM rules), can help to alleviate a portion of

this negative effect. However, the benefits of such a change in policy would be mitigated if the

Council directs ENO to grandfather existing NEM customers. If the Council did not grandfather

existing NEM customers, the benefit is more pronounced, but still does not fully address the total

projected cost-shifting principally because the 2-Channel Billing methodology only involves

excess energy delivered to the grid.

Alternatives to 2-Channel Billing such as developing and implementing rate design

changes, as has been done in some jurisdictions, could produce a more measureable impact on

mitigating future cost-shifting. In ENO’s March 2015 filing, a variety of other approaches to 2-

Channel Billing were described in detail along with potential pros and cons associated with each

of those approaches. However, ENO has not at this time developed any proposal(s) that involves

altering the current residential rate design; as such proposal(s) would be more properly addressed

in the next rate case.

It is important to note that the Council is by no means alone in terms of reviewing its

current NEM policy and rules. As rooftop solar penetration has proliferated, retail regulators in a

number of jurisdictions around the U.S. have undertaken reviews of NEM policies over the past

few years. In the past 12-18 months, several states have made changes in NEM policy to address

5 On this point, the Council should note that these analyses are based on a forecasted NEM adoption rate that may or may not be accurate depending on a number of factors including future equipment and installation costs, shifts in tax policy, consumer behaviors, etc. An adoption rate greater than that assumed in ENO’s analyses would increase the detrimental effects to other customers beyond the level identified by ENO’s analyses.

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growing concerns regarding cost-shifting.6 There is also growing recognition among some solar

advocates that changes to the NEM policy are warranted. In a recent interview, Jon Wellinghoff,

Chief Policy Officer at SolarCity Corp. stated:

“I disagree with Lynn [Jurich, CEO of SunRun7]. Places like Nevada have pushed us to immediately address the problem. Net metering was just an artifice set up as a proxy that provided for some payment to people that represented what the value was that they were contributing to the system. We now need to get to a much more transactive system that does have more market-based values incorporated into it to ensure that we know completely what the costs and benefits are of all these resources and how they can play in the entire ecosystem.”

A similar sentiment was expressed by California Commissioner Michel Florio on CPUC

Decision 16-01-044:8

“Going forward, I favor a compensation structure that reflects the value of exported generation. Participating customers should be compensated at the retail rate for generation consumed on site. Exports should be compensated in a way that reflects their value, which should at minimum be differentiated by time and location. … I applaud this step forward, but ultimately believe compensation for exports should be delinked from retail rates altogether.”

ENO’s proposed 2-Channel Billing methodology is very much in line with the sentiments

expressed by Mr. Wellinghoff and Commissioner Florio.

Although many parties have appeared in this Docket to advocate on behalf of the interests

of NEM customers, and the businesses that supply solar PV systems, only ENO has advocated

for the interests of non-NEM customers, whose interests are also the responsibility of the

Council and its Advisors. Through this filing, ENO seeks clear direction from the Council on

6 Three examples include Hawaii (PUC Docket No. 2014-0192, Decision and Order No. 33258, issued 10/12/2015),

California (CPUC, Rulemaking 14-07-002 in conjunction with AB 327), and Nevada (PUC Order in Docket Nos. 15-07041 & 15-07042, issued 12/23/2015.

7 In a debate over net metering, Jon Wellinghoff was responding to Lynn Jurich, who had just said “Our penetration level is 1% of U.S. households. Let's keep it simple for a while and let's see what innovation comes in … and then we'll work it out over time and we'll learn and we'll figure out what [distributed energy resources] can do for the grid.” Source: SNL story on Solar Power International, Las Vegas, NV, September 13, 2016.

8 Dissent of Commissioner Michel P. Florio on Decision 16-01-044, Adopting a Net Energy Metering Successor Tariff, February 3, 2016. http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M158/K236/158236263.pdf

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how to best protect the interests of all customers. Specifically, ENO seeks input on certain key

parameters like grandfathering, and the appropriate methodology and/or rate to use for crediting

excess energy under ENO’s proposed 2-Channel Billing methodology. ENO respectfully

requests that the Council provide such direction within sufficient time for ENO to evaluate the

Council’s feedback prior to drafting ENO’s final Proposal, which Resolution R-15-438 requires

ENO to submit on or before January 11, 2017.

2.0 March 2015 Filing

In conjunction with Paragraph 4 of Council Resolution R- 14-364, adopted on September

4, 2014, the Council found that:

Issues of costs and benefits related to all other renewable technologies, including but not limited to, consumer-installed renewable distributed generation resources and associated rate impact and rate design issues such as (but not limited to) net metering and feed-in tariffs shall be considered in Council Docket UD-13-02. The Companies are directed, within 180 days from the adoption of this Resolution, to make a filing in Docket UD-13-02 with the Council explaining in detail the Companies’ current treatment of such resources, the physical and rate impacts such resources have on the Entergy System and ratepayers, and any proposed changes to the treatment of such resources, along with an analysis of the impact of such proposed changes. After such a filing has been made, the Companies, Advisors, and Intervenors will work collaboratively to develop a procedural schedule to address that filing.9

Pursuant to this directive, ENO made its filing on March 3, 2015. The filing included

background information on NEM policy and billing, data and charts regarding growth of NEM in

New Orleans, adoption drivers for solar photovoltaic PV, a description of utility rate design and

how costs can be shifted to other customers, and, finally, an extensive discussion of various

alternatives that could be employed to help mitigate concerns related to cost-shifting.

The rate of NEM adoption in New Orleans has slowed to some degree since early 2015

and is certainly lower than its peak in 2013. As of June 2016, total installed NEM capacity was

9 The byproduct of that collaborative effort was Resolution R-15-438, adopted on September 3, 2015.

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~36 MWDC. Figure 1 (below) shows cumulative net metered rooftop solar PV systems installed

through June 2016.

Figure 1: Growth of Rooftop Solar PV Systems in Orleans Parish.

3.0 Technical Meetings

Pursuant to Resolution R-15-438, ENO convened three separate technical meetings

earlier this year on March 3rd, April 19th, and June 27th. At the March 3rd meeting, the

Advisors guided the discussion concerning the following items:

• ENO made an introductory presentation based on its March 2015 filing • Existing Louisiana and Council rules and policies • Developing load shapes for various analyses

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• Cost and benefit categories and potential sources of relevant data and input assumptions including a forecast of future NEM adoption

• Cost-benefit analysis methodology and inputs • Cost of service analysis methodology and inputs

After a lengthy discussion, a number of important issues were addressed at the March 3rd

meeting regarding the analyses to be performed, as well as the numerous input assumptions and

data necessary for those analyses. Between the March 3rd and April 19th meetings, ENO

worked on several parallel efforts including developing 8,760 hour profiles for a typical NEM

customer, NEM customers in aggregate, all other customers, and the output of an average-sized

residential rooftop solar PV system. The various hourly profiles were to be used as inputs in the

separate cost-benefit and COS analyses. ENO also began to develop a forecast of future NEM

adoption using recent installation data and Stakeholder feedback. Finally, ENO reviewed the

cost and benefit categories and worked to determine which of the categories were both

appropriate to include and possible to quantify. ENO then began to collect the necessary inputs

and data (e.g., forecasts of MISO hourly energy prices and annual capacity auction results,

carbon prices, and other environmental inputs from the on-going 2015 Integrated Resource Plan).

At the April 19th meeting, there was discussion and clarification regarding the two

analyses. At the first technical meeting on March 3rd, PosiGen represented that average hourly

solar PV production data more representative of the New Orleans area was available, and could

be used as an alternative to ENO’s identified data from the National Renewable Energy

Laboratory’s PVWatts Model. Ultimately, such hourly data was not provided. Discussion

followed about the various hourly profiles that would be used in the two analyses. Several

concerns were raised about whether NEM customers, which have higher than average usage

prior to installing their rooftop solar PV systems, have different profiles than an average

customer. ENO committed to perform an analysis that would evaluate historic load research data

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in an attempt to further “stratify” residential customers. That stratification analysis was

performed and also provided to the Advisors and Stakeholders by email. Among other matters,

the analysis was described and discussed on a conference call.

Prior to the April 19th meeting, ENO circulated an Excel forecast of future NEM

installations based on “high” and “low” cases. The two cases were developed using recent

historic installation data for ENO and Algiers. Feedback from Stakeholders at the April 19th

meeting indicated that the high case was unrealistic given changes to state tax credits (enacted by

2015 legislation) and recent electrical permitting activity in Orleans Parish. The notion of using

a high case was abandoned based upon feedback provided by Parties at this meeting.

Stakeholders suggested that the low case was more reasonable and consistent with current

permitting activity, but that ENO should apply a growth factor of 5-10% for at least the next few

years to account for the extension of the federal 30% investment tax credit (“ITC”). As a result,

ENO selected a mid-point of 7.5% to develop the forecast.10 For purposes of routine

forecasting, ENO normally uses a rolling 12-month average of historic monthly data to develop

forecasts. However, for purposes of this analysis, ENO used the 2016 year-to-date (January

through August) installation figures and stakeholder input on future growth to create a forecast of

future NEM installations. The reason September through December 2015 were not considered is

because of significant changes to Louisiana’s state solar tax credit that took effect in July 2015

such that 2015 monthly installation figures are unlikely to be representative of 2016 and beyond.

Figure 2 shows a comparison of average monthly installations in Orleans Parish from 2011

projected through 2021.

10 It is important to note that the 7.5% value used in modeling was based on stakeholder input; ENO does not endorse or otherwise have a specific point of view on growth of future NEM installations.

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Figure 2: Average Total Monthly System Installs Projected to 2021.

In its various forecasts of future NEM adoption, ENO attempted to perform two

additional analyses looking at long-term economic attractiveness from the consumer’s

perspective under two different scenarios: with and without the 50% Louisiana state tax credit.

Various possible methods exist for modeling these two scenarios to capture overall economics

from the individual consumer’s perspective. However, numerous important assumptions around

each consumer’s income tax bracket, borrowing rate, etc. also make achieving representative

estimates about payback difficult. The fact that consumers continue to purchase and install

rooftop solar PV systems today absent the likelihood that they will receive the 50% state tax

credit indicates that more factors than just economics play a role in consumer adoption.

At the April 19th meeting, ENO also provided a matrix that it had developed with

descriptions of the cost and benefit categories developed by the Advisors along with potential

sources of input assumptions and data. ENO, the Advisors, and Stakeholders engaged in an

extensive discussion around the cost and benefit categories. Parties also discussed which

0

50

100

150

200

250

2011 2012 2013 2014 2015 2016 2017P 2018P 2019P 2020P 2021P

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categories might be possible to quantify in the event that input assumptions and data sources had

not already been identified (e.g., MISO ancillary services). As for the COS analysis, several

calls with the Advisors and other Stakeholders were held between the March 3rd and April 19th

meetings to discuss how the hourly profiles would be utilized, potential sources of input

assumptions and data (e.g., 2014 and 2015 FERC Form 1 filings), allocation methods and

factors, and overall methodology given that ENO’s last COS had been conducted for a 2008 rate

case.

Between the April 19th and June 27th meetings, several additional calls were held with

the Advisors and Stakeholders regarding updated input assumptions, including a final NEM

forecast for use in the cost-benefit analysis. At the final technical meeting held on June 27th, a

number of issues were discussed and debated. ENO discussed the final NEM adoption forecast,

which had been submitted in Excel format to the Advisors and Stakeholders prior to the meeting.

ENO presented preliminary results from the cost-benefit and COS analyses. ENO also briefly

described its understanding of the procedural schedule and the filing to be made by September

28, 2016. Two other issues covered at the June 27th meeting included a brief discussion on

grandfathering of existing NEM customers and a separate discussion of several ideas presented

by a Stakeholder (Building Science Innovators, LLC).

4.0 Cost-Benefit Analysis

ENO performed the initial cost-benefit analysis based on the current NEM policy (i.e.,

full 1:1 retail credit for any kWh produced by the customer’s rooftop solar PV system whether

used behind the meter or delivered to the grid as excess energy), the current and forecasted level

of NEM adoption through 2034, and the quantification of various costs and benefits. Table 2

summarizes the categories of costs and benefits that were considered as well as whether the cost

or benefit was modeled in the analysis. Throughout the multiple technical conferences and

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interim steps described, quantifiable information related to items marked “N/C” was not

provided and, thus, these items were not considered in the cost-benefit analysis.

Table 2: Cost and Benefit Categories.

Category

Cost / Benefit

Utility NEM Installation Costs Cost Utility NEM Management Costs Cost Customer Credit for Delivered Capacity/ Energy Cost Avoided Energy Benefit Avoided Capacity Benefit Avoided T&D Capacity N/C Avoided Losses Benefit Avoided Environmental Costs Benefit Reliability Costs or Benefits N/C Grid Support/ Ancillary Services Costs or Benefits Benefit Avoided Outage Costs N/C Market Price Effects N/C Non-Energy Benefits N/C Fuel Hedging Value in Managing Risk N/C Other N/C

Note: N/C = Not Considered

ENO’s analysis included: (1) the most recent forecast of NEM adoption (see explanation

above) and (2) hourly NEM customer energy profiles (accounting for consumption, excess

energy exports to the grid, and solar energy production). With respect to benefits, total hourly

solar energy production was multiplied by avoided energy costs (forecasted MISO locational

marginal prices or “LMPs”), avoided environmental costs (NOX and CO2), and avoided ancillary

services costs. A separate calculation is made for each year (2016 through 2034) of avoided

MISO capacity costs as well as line losses, which are conservatively estimated at 10% of avoided

energy costs.

With respect to costs, three different categories were modeled. The first category covers

labor and overhead costs incurred by ENO for processing NEM interconnection applications and

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agreements, the incremental cost of a bi-directional digital net meter, and labor, overheads, and

equipment costs associated with field installation of the net meter. Currently, ENO charges a

residential customer an upfront charge of $50 to cover these administrative costs, whereas the

actual costs of processing paperwork and physically replacing the existing meter are higher. The

~$68 gap between the $118 one-charge used by Entergy Mississippi, Inc. and ENO’s current $50

one-time fee is socialized to all customers.11 The second category of costs are labor and

overhead costs incurred related to customer calls, complaints, billing issue resolution, and

resources involved with routine monitoring and reporting. Currently, ENO has one dedicated

full-time equivalent employee that manages NEM customer relations. But, other ENO

employees from various functions often get involved in, for example, resolving billing questions

and customer complaints.

The third and final cost category that was modeled is by far much larger than the first two

and involves what a NEM customer offsets when their net metered rooftop solar PV system

produces energy. As described in great detail in ENO’s March 2015 filing, a customer that

produces a kWh through NEM self-generation avoids purchasing that kWh from ENO whether

they use the energy they produce behind the meter or deliver it in some hours to the grid in the

form of excess energy. Based on ENO’s current residential rate (excluding the fixed customer

charge), every kWh that a customer doesn’t purchase from ENO saves the NEM customer ~9.7

cents/kWh. To the extent that a customer producing a kWh offsets variable fuel and purchased

power costs, all customers benefit, especially if the incremental cost of purchased energy is

higher than the average cost billed to customers that month. However, as described in detail by

11 Entergy Mississippi, Inc. recently estimated these costs to be $118. EMI’s Net Energy Metering Rider Schedule

NEM-1 was approved by the Mississippi Public Service Commission in August 2016 and requires new net metering customers to pay an upfront charge of $118. For modeling purposes, it is assumed that $118 represents a reasonable proxy for the current total cost to install a bi-directional net meter.

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ENO in its March 2015 filing, much of the Energy Charge and other riders involve fixed

infrastructure and other costs that are not avoided or reduced by when a NEM customer produces

a kWh. The fixed infrastructure and other costs ultimately end up being borne by other

customers.

A fourth, and final, cost that was not quantified or modeled falls within the category

labeled “Reliability Costs or Benefits” in Table 2. As noted in the March 2015 filing, ENO has

not experienced operational issues to-date, nor has it had to knowingly make investments

specifically related to rooftop solar PV systems to maintain adequate reliability. That said,

further expansion of NEM on specific highly penetrated feeders may drive future investment in

distribution reliability projects. These additional investments will depend significantly on the

level of penetration of customer‐owned generation on a given circuit. On circuits with a high

penetration of customer‐owned generation, particularly intermittently operating rooftop solar PV

systems, ENO may have to make additional capital investments to ensure on‐going reliable

service for all customers.

ENO made several changes to the cost-benefit model as a result of feedback received

from Stakeholders and the Advisors during the June 27th technical meeting. First, using the

current volumetric retail rate of ~9.7 cents/kWh, the volumetric portion of ENO’s residential rate

is projected through 2034 using a 2.12% annual escalation factor. As noted in the final NEM

forecast Excel file, attached,12 the 2.12% escalation factor is based on the compound annual

growth rate of ENO’s average residential rate for the 20-year period between 1997 and June

2016. Another change made to the model was to incorporate an assumed 1% annual degradation

rate in solar PV capacity and energy output beginning in 2016.

12 As with previous versions, ENO will provide this final forecast to parties who have executed the Council’s non-

disclosure agreement to receive Highly Sensitive Protected Materials (“HSPM”) items.

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For each year between 2016 and 2034, the three categories of costs and five categories of

benefits are summed to provide an overall net benefits value. A negative value for net benefits

implies that projected costs exceed projected benefits and, as such, costs will ultimately be

shifted to other customers. The results of the initial cost-benefit analysis are summarized in

Table 1 above. On a nominal basis over the 19-year period modeled, total net benefits are

projected to be ($31,462,360). Figure 3 illustrates projected costs and benefits expressed on a

cents/kWh-basis with the differential between the lines representing negative net benefits.

Figure 3: Projected Nominal Costs and Benefits in Cents/kWh from 2016 – 2034.

Table 3 (below) illustrates a cost versus benefit breakdown by category on a nominal basis over

the entire 19-year period that was modeled. Figure 4 (below) illustrates the same information

graphically.

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Table 3: Projected Nominal Costs and Benefits by Category in Cents/kWh.

Total Costs

Total Benefits

Utility NEM Install Costs 0.02 Utility NEM Management Costs 0.20

Customer Credit for Avoided Charges 11.88 Avoided Energy 6.54

Avoided Capacity 1.55 Avoided Losses 0.65

Avoided Environmental Costs 0.57 Avoided Ancillary Services 0.01

Total Costs 12.11 Total Benefits 9.31

Net Benefits (2.80)

Figure 4: Projected Nominal Costs and Benefits by Category in Cents/kWh.

As discussed above, ENO performed two variations of the initial cost-benefit analysis to

estimate the impact of 2-Channel Billing starting January 2020. In the first variation, new NEM

customers would receive 2-Channel Billing instead of receiving a 1:1 full retail credit for excess

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energy delivered to the grid. Under the second variation, all NEM customers would be

transitioned to 2-Channel Billing starting January 2020. As far as what occurs under 2-Channel

Billing, only excess energy is affected. In other words, any energy produced by the solar PV

system that is used behind the customer’s meter during each measured time interval is unaffected

and will receive a full retail credit as is the case under the current NEM policy. Instead of being

netted, excess energy that is recorded on Channel 2 of the net meter in any hour is credited at the

forecasted hourly MISO LMP plus 10% for avoided line losses. Table 4 illustrates 2-Channel

Billing calculation focusing on one specific hour in September 2020 under the first variation in

which only new NEM systems are affected (i.e., with grandfathering).

Table 4: 2-Channel Billing Impact at Hour 12 on September 9, 2020.

Description Value Units Total NEM 8,884 Systems

NEM Customer Load 13,401 kWh Solar PV Output 23,834 kWh

Channel 1 (Net Usage) 0 kWh Channel 2 (Excess Energy) 10,433 kWh

2-Channel Billing Customers 512 Systems % of NEM Receiving 2-Channel Billing 5.77% 512 / 8,884

Channel 2 (Excess Energy) 602 kWh (10,433 x 5.77%) Total Volumetric Charges 10.591 Cents/kWh

Credit (MISO LMP + 10%) 5.877 Cents/kWh Delta 4.714 Cents/kWh

Cost-Shift Mitigation $28.36 (602 x 4.714)/100

Summing all hours from January 1, 2020 to December 31, 2034 provides the total

estimated impact of transitioning new NEM customers from the current NEM policy to 2-

Channel Billing beginning January 2020. As summarized in Table 1, the total impact on

projected net benefits is ~$1.05 million or, put another way, a reduction to the estimated cost-

shift of approximately 3% relative to the projected net benefits of ($31,462,360) for the current

NEM policy. Also, as noted in the Executive Summary, this modest change occurs for two

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reasons: (1) with a significant majority of NEM customers assumed to be grandfathered under

the scenario, the change in policy affects a relatively small population of customers and (2)

because 2-Channel Billing only reduces the full retail credit for excess energy delivered to the

grid, the vast majority of energy produced by a rooftop solar PV system is unaffected because it

is used behind the customer’s meter to offset utility purchases. Under the second variation that

was modeled in which NEM customers are not grandfathered and 2-Channel Billing begins

January 2020, the mitigation of cost-shifting is more pronounced.

5.0 COS Analysis

Using recent FERC Form 1 data, ENO first determined the revenue requirement by the

four main functional areas: Production, Transmission, Distribution, and Customer Service. This

step was performed directly where applicable, however, allocations were made if necessary

(commonly referred to as “Functionalization”). The revenue requirement was also segregated by

Rate Base and Expenses.

Once Functionalized, ENO determined the appropriate “Classification” to be used (i.e.,

Demand, Energy, or Customer). For example, Production and Transmission are classified as

Demand, Distribution is classified as either Demand or Customer, and Customer Service is

classified as Customer.

After the Functionalization and Classification steps were completed, costs were then

“Allocated” to the various Rate Classes (Residential, Small Electric, Large Electric, etc.). It is

important to note that Rate Classes are not the same as Revenue Classes (i.e., Residential,

Commercial, Industrial, and Governmental). In the analysis, ENO isolated the Residential Class,

and lumped all of the other classes together. Also, ENO took the Functionalized and Classified

revenue requirement for the Residential Class, and applied allocation factors based on the data

relationships between NEM and non-NEM customers using hourly load shape data developed by

20

load research efforts. Table 5 summarizes the results of the COS analysis as it relates to the

residential NEM customers contribution to their overall cost of service or revenue requirement.

Table 5: Results of COS Analysis (2015 Test Year).

Residential NEM

Estimated Revenue Requirement $5,200,000 Estimated Sales 79,500,000 kWh Estimated Rate/kWh $0.0585/kWh Estimated Revenue (Sales x Rate/kWh) $4,650,000 Revenue Shortfall (Rev. Req. - Rev.) ~$550,000

6.0 Conclusion

ENO again notes its consistent and continued support for customers’ freedom to choose

to install self-generation systems on their property while also enjoying non-discriminatory access

to interconnect with the grid. However, the analyses described above show that the current NEM

policy and associated rules unfairly shift the costs of utility infrastructure and other fixed

operating expenses to customers who have not chosen, or cannot afford to choose, to adopt self-

generation technologies. A policy that inherently benefits one class of customers at the expense

of another does not comport with the Council’s duty to equitably represent the interests of all

customers.

As such, ENO’s filing, along with its initial filing made in March 2015, presents analysis

and alternatives for the Council to consider as remedies to the presently inequitable and

unsustainable net energy metering policy that is in place today. For example, an eventual change

in policy to 2-Channel Billing can help, in part, to ameliorate the cost-shift issue and is also

consistent with moving towards a more market-based approach to valuing energy that is exported

to the grid. The various cost-benefit analyses described in this filing demonstrate as much.

While other policies such as developing and implementing rate design changes, as has been done

21

in some jurisdictions, could produce a more measureable impact on mitigating future cost-

shifting, such proposals are more appropriate to consider in the context of the next rate case.

Thus, ENO makes this filing in compliance with Resolution R-15-438 in order to present its

preliminary Proposal to transition to 2-Channel Billing and is seeking Council feedback on

important issues such as grandfathering.

Pursuant to Resolution R-14-438, ENO will consider any written input provided by the

Advisors and/or Intervenors, on or before November 7, 2016, before crafting its final Proposal to

be submitted by January 11, 2017.

Respectfully submitted:

BY: __ __________________________________ Timothy S. Cragin, Bar No. 22313 Brian L. Guillot, Bar No. 31759 Alyssa Maurice-Anderson, Bar No. 28388 Harry Barton, Bar No. 29751 639 Loyola Avenue, Mail Unit L-ENT-26 E New Orleans, Louisiana 70113 Telephone: (504) 576-2984 Facsimile: (504) 576-5579

ATTORNEYS FOR ENTERGY NEW ORLEANS, INC.

CERTIFICATE OF SERVICE CNO DOCKET NO. UD-13-02

I hereby certify that I have this 28th day of September 2016, served the required number of copies of the foregoing correspondence in accordance with the applicable provisions of the New Orleans City Code via one of the following: electronic mail, facsimile, overnight mail, hand delivery, and/or United States Postal Service, postage prepaid. Ms. Lora W. Johnson, CMC Clerk of Council Council of the City of New Orleans Room 1E09, City Hall 1300 Perdido Street New Orleans, LA 70112

Pearlina Thomas Chief of Staff W. Thomas Stratton, Jr. Director City Council Utilities Regulatory Office City Hall, Room 6E07 1300 Perdido Street New Orleans, LA 70112

Norman S. Foster Department of Finance City Hall, Room 3W06 1300 Perdido Street New Orleans, LA 70112

Jeffrey S. Gulin, Esq. Hearing Officer 3203 Bridle Ridge Lane Lutherville, MD 21093

Rebecca Dietz City Attorney Office Law Department City Hall – 5E03 New Orleans, LA 70112

Joseph A. Vumbaco, P.E. Victor M. Prep Joseph F. Rogers Legend Consulting Group Limited 8055 East Tufts Avenue, Suite 1250 Denver, CO 80237-2835

Clinton A. Vince, Esq. Presley R. Reed, Jr., Esq. Emma F. Hand, Esq Dentons US LLP 1900 K Street, NW Washington, DC 20006

Basile J. Uddo, Esq. J. A. “Jay” Beatmann, Jr. c/o Dentons US LLP 650 Poydras Street, Suite 2850 New Orleans, LA 70130

Walter J. Wilkerson, Esq. Kelley Bazile Wilkerson and Associates, PLC The Poydras Center, Suite 1913 650 Poydras Street New Orleans, LA 70130

Errol Smith, CPA Bruno and Tervalon 4298 Elysian Fields Avenue New Orleans, LA 70122

Seth Cureington Polly S. Rosemond Entergy New Orleans, Inc. 1600 Perdido Street, L-MAG-505B New Orleans, LA 70112

Gary Huntley Entergy New Orleans, Inc. 1600 Perdido Street, L-MAG-505A New Orleans, LA 70112

Joseph Romano, III Suzanne M. Fontan Danielle Burleigh Therese Perrault Entergy Services, Inc. 639 Loyola Avenue, L-ENT-4C New Orleans, LA 70113

Kathryn J. Lichtenberg, Esq. Brian L. Guillot, Esq. Timothy S. Cragin, Esq. Alyssa Maurice-Anderson, Esq. Harry M. Barton, Esq. Entergy Services, Inc. 639 Loyola Avenue, L-ENT-26E New Orleans, LA 70113

Mr. Michael L. Winberry Business Manager Jacobs Technology Inc. 13800 Old Gentilly Road, Building 320 New Orleans, LA 70129

Casey DeMoss, CEO Logan Atkinson Burke Alliance for Affordable Energy 4035 Washington Ave., New Orleans, LA 70125

Rick Boyd The Folger Coffee Company 14601 Old Gentilly Road New Orleans, La 70129

Ernest Lanier Edwards, Jr. The Law Office of Ernest L. Edwards, Jr. APLC 300 Lake Marina Ave., Unit 5BE New Orleans, LA 70124

Mr. Fred M. Mazurski, CEM, CDSM Senior Manager, Energy USG Corporation USG Corporation 550 West Adams Street Chicago, IL 60661

Joshua Smith Staff Attorney Sierra Club Environmental Law Program 85 Second Street, 2nd Floor San Francisco, CA 94105

Jeff Cantin, President Heather Pohnan, Administrative Director GSREIA 643 Magazine St., Ste. 102 New Orleans, LA 70130

Myron Katz Building Science Innovators, LLC 302 Walnut Street New Orleans, LA 70118

Karla Loeb Director of Business Development Margot Want Associate General Counsel 2424 Edenborn Ave., Suite 550 Metairie, LA 70001

Mark Zimmerman Air Products and Chemicals, Inc. 7201 Hamilton Blvd. Allentown, PA 18195-1501

Robert L. Suggs, Jr., CEO South Coast Solar, LLC 2605 Ridgelake Drive Metairie, LA 70002

Raoul A. Galan, Jr., Manager Tasta Energy, LLC 3320 Galan Drive Kenner, La 70065

Gracie Walovich The Alliance for Solar Choice 595 Market Street, Floor 29 San Francisco, CA 94105

Andrew Jacoby The Alliance for Solar Choice Varadi, Hair & Checki, LLC 650 Poydras St., Suite 1550 New Orleans, LA 70130

Thadeus B. Culley, Regulatory Counsel The Alliance for Solar Choice Keyes, Fox & Wiedman LLP 401 Harrison Oaks Blvd, Suite 100 Cary, NC 27513

New Orleans, Louisiana, this 28th day of September, 2016.

___________________________________ Harry M. Barton