Entergy New Orleans 2012 IRP 2013 Public Q&A

Transcription

1 Procedural Questions 1) Are comments as well as questions accepted online? a. Yes. As stated at the February technical conference, ENO has accepted both questions and comments specifically related to the 2012 IRP during the 15-day window following the conference, as prescribed by the City Council in Resolution R ) Has Entergy New Orleans responded to any and all questions submitted? a. The Company has responded to questions that are related to the 2012 IRP. Please also see the response to question 3 immediately below. 3) How will public questions/comments/themes thereof be officially taken into account, and what is the process by which public input can have a tangible impact on the decisions taken by the Council regarding the adoption and amendment of the current proposed version of the IRP? a. As part of the ongoing rulemaking related to integrated resource planning (docket UD ), the Council recently passed Resolution R which outlines the process by which all parties involved can participate in the review of and comment on ENO s 2012 IRP and upcoming Implementation and Cost Recovery filing (to be made April 1 st ). As part of the Council s process, it established a procedural schedule that called for ENO to host a public technical conference and corresponding 15-day question and answer period related to the 2012 IRP. The conference was held on February 20 th and the corresponding deadline for submission of questions was therefore set on March 6 th as required by the Council. On April 1 st, ENO is required to make an Implementation Plan and Cost Recovery filing regarding future DSM programs beyond the current Energy Smart programs set to expire in March Within 20 days of the April 1 st filing, the Council s procedural schedule requires that the Advisors host a Community Hearing at City Hall whereby the public can provide their input on BOTH the 2012 IRP and April 1 st filing. 4) How can the public get a computer editable copy of ENO's submissions? a. Filings are made by the company in pdf format. 5) How can the participants get an electronic copy of the sign-in sheet and presenters for the meeting on 2/20/13 with addresses? a. The Company s policies regarding protection of non-public information gathered as part of its ongoing business precludes providing the sign-in sheet. The presenters names and affiliation were listed on the agenda included in the conference packet handed out to participants at the meeting on February 20 th and subsequently posted to the ENO website at 1

2 6) How can I get a copy of the presentations made at the 2/20/13 meeting? a. All of the information presented at the February 20 th Public Technical Conference is publicly available on ENO s IRP website located at Renewables/Supply-Side Alternatives 7) Why should the city of New Orleans want a power grid instead of an energy grid? a. ENO is unable to respond to this question because there is no explanation of the difference between the terms power grid and energy grid. 8) Does the Integrated Resource Plan include implementation of a smart grid, transition to a renewable energy portfolio, or phasing out carbon intensive fuels (mainly coal)? a. The Integrated Resource Plan includes the review of measures and programs dependent upon smart grid technology. Participation in some demand response options, such as dynamic pricing, requires smart meter technology. For purposes of the Potential Study, a full deployment of smart grid technology was assumed. However, the cost of smart grid infrastructure, meters, installation, IT costs and related O&M are not included in DSM program costs. A discussion of smart grid technology assumptions utilized in the IRP can be found in the ENO DSM Potential Study. The 2012 ENO IRP evaluated the potential for integration of renewables into the generation portfolio. Although the IRP does not seek to eliminate fossil-fuel based sources of generation from the set of supply-side alternatives considered, only 4% of ENO s energy needs were met by coalfired generation in 2011 and the IRP preferred portfolio reflects that this relatively minor source of generation would not increase by the end of the 20 year planning horizon. For information regarding Entergy s position on the environment, please see the links provided under the Q&A section of the IRP website located at 9) Why is hydro not an option for supply-side renewables? a. There are several different types of hydro technologies considered for further evaluation in the IRP. The most commonly thought of example are large hydro-electric dams. ENO is not aware of any suitable large scale hydro-electric dam sites in or around the Entergy System. In addition, in-stream hydrokinetic power was considered as a supply-side option available to meet customers future needs; however, the technology is still in the early stages of development. As a result it did not meet the threshold set for inclusion in the IRP and was eliminated from more detailed consideration at this time. ENO will continue to monitor in-stream hydro for possible inclusion in future IRPs. 2

3 10) The report makes little reference to distributed generation. Would you please address the potential for distributed generation, including Combined Heat and Power (CHP/WHR) as a component of the overall power supply and demand-reduction mix? a. Distributed Generation was considered as an option in the development of supply-side alternatives; however, as stated in the Technology Assessment Technical Supplement to the IRP, given the magnitude of customers needs, ENO seeks central station electric generation technologies with capacity ratings above two megawatts as supply-side options. All of the IRP materials filed with the Council on October 30 th, 2012, including the Technology Assessment Technical Supplement, are publicly available on ENO s website at 11) What if we develop more renewable energy leading up to 2022 & 2027 could we avert another carbon based or nuclear power plant? a. The IRP evaluation considered the potential for renewable energy sources to meet customers future needs, including in 2022 and Although the preferred portfolio does not currently include renewable (e.g. wind, solar, biomass, etc.) or new nuclear resources due to their higher cost, ENO continues to monitor the technology landscape and market dynamics should those resources become more feasible and economic in the future. ENO could deploy renewables at a later date if found to be economic. It should be noted, however, that once fully integrated with MISO, ENO expects that additional renewable energy opportunities could become available as it participates in the Day 2 energy markets administered by MISO. 12) Why is New Orleans not considered a strong solar location? Look at Germany! a. Renewable Technology options, including solar photovoltaic (PV) technology, were considered as supply-side options available to meet customers future needs; however, gas-fired technologies coupled with DSM were more economic based on the long-term outlook for natural gas prices and the higher capital cost and lower capacity factor of solar PV panels. In regard to the comparison with Germany, there are more rated hours of sunlight and a higher cost of electricity in Germany when compared to the Entergy service territory, so while the economics of solar may be attractive in Germany, they are not yet as attractive in ENO s service territory. Despite the fact that solar was not selected in the preferred portfolio, ENO will continue to monitor its cost competitiveness. ENO could deploy renewables at a later date if found to be economic. 13) Why were renewables removed from the preferred portfolio? a. Many renewables were screened out during the technology assessment phase of the IRP. This was generally because their cost was high or the technology was not proven in the utility industry. Wind resources, however, were carried forward and modeled as supply alternatives in the detailed evaluation phase of the IRP. Wind was found to be 3

4 economic in the Economic Rebound and Green Growth scenarios starting in 2028 and 2031 respectively. The preferred portfolio sought resources that were economic in most or all of the scenarios. Despite the fact that renewables were not selected in the preferred portfolio, ENO will continue to monitor their cost competitiveness. ENO could deploy renewables at a later date if found to be economic. 14) What price did you assume for on-shore wind energy? What was the integration charge assessed? a. As shown in the Technology Assessment, the installed capital cost for on-shore wind power is $2,000 per kw, in 2011 dollars. Integration charges, represented by capacity matchup and flexible capability cost, for intermittent renewable resources are estimated at $49 per MWh, at a 39% capacity factor, for on-shore wind power. These costs will vary based on assumed capacity factor. All of the IRP materials filed with the Council on October 30 th, 2012, including the Technology Assessment Technical Supplement, are publicly available on ENO s website at 15) Would it be possible to maybe install a small wind farm? a. The goal of the IRP is to develop a preferred portfolio of resources capable of meeting customers future needs at the lowest reasonable cost while maintaining reliability of the electric system. This is the foundation of the IRP and is consistent with the Council s requirements for development of an IRP as contained in Resolution R Wind was not found to be a cost effective resource when compared to the other available options. This is in part due to the fact that Louisiana is not optimally located for on-shore wind production. Please see the link from the National Renewable Energy Laboratories website for a U.S Wind map for further evidence of U.S. wind production. 16) Why was Entergy so quick to write off solar when New Orleans is one of the top U.S. cities for solar and we're seeing bills of around $30/mo. for highly energy efficient homes paired with solar panels? a. Entergy is not quick to write off solar, which was considered as a supply-side option available to meet customers future needs. It simply is not the most cost-effective alternative at this point in time when compared to other sources of utility scale generation or DSM. While electric bills for highly efficient homes with solar PV panels installed may be lower than average, most homes in New Orleans are not highly efficient and therefore it is more cost-effective to fund investments to increase the efficiency of the home rather than to further incentivize residential solar panel installation. It should be noted that Entergy has provided shareholder grant funding for solar installations on four New Orleans public schools. 4

5 As shown on page 10 of the IRP and throughout the technical supplements, solar does not pass the Total Resource Cost test (scores <1). Despite the fact that solar was not selected in the preferred portfolio, ENO will continue to monitor its cost competitiveness especially in light of the fact that solar costs have decreased dramatically in recent years and are expected to continue to fall. ENO could deploy solar at a later date if found to be economic. 17) Why wasn't there more consideration/discussion of CHP? a. Please see response to question 10 above. 18) If electric cars become common they can be expected to significantly lower peak demand... Why isn't this considered? a. Electric vehicles effect on peak demand was considered in the IRP. However, adoption rates in ENO s service territory are expected be modest over the next five to ten years and therefore not expected to contribute significantly to reductions in peak demand. It should be noted that adoption of electric vehicles is not ENO s decision. Furthermore, in order for electric vehicles to reduce peak demand, owners must be willing to send stored energy back to the grid at times of peak need. Given the state of battery technology and electric charging infrastructure, the potential for electric vehicles to offer peak reduction services is not anticipated for many years. Therefore, this was not considered as a viable resource in the IRP. As with other developing technologies, ENO will continue to monitor adoption of electric vehicles. 19) Considering that uninstalled PV is about $.5 / W... how can you justify the assertion that PV energy costs $.3/kWh? a. Uninstalled solar is not the appropriate comparison for purposes of this analysis. It is more appropriate to look at the installed cost of solar. In addition, $0.5 per watt does not represent the average cost of uninstalled solar. Based on information contained in the Technology Assessment Technical Supplement to the ENO IRP, the installed cost for utility-scale solar PV is $5,000 per kilowatt, or $5 per watt, in 2011 dollars. Annual revenue requirements associated with this capital cost, investment tax credit, and integration charges using an assumed 20% annual capacity factor results in the levelized cost of $326/MWh, or $0.326 per kwh, as shown in Table 16 of the ENO IRP. 20) Why is there no investment in renewable/clean energy sources? a. Please see response to questions 8 13 and ) With utilities across the country quickly ramping up clean energy deployment, why is Entergy failing to do so? a. ENO s IRP appropriately analyzes the potential use of renewable resources as a supply side option. However, the goal of the IRP is to develop a set of future resource additions (demand- and supply-side) that result in the lowest reasonable cost while maintaining 5

6 reliability of the electric system. Also, ENO s particular circumstances do not necessarily match those of other utilities that the question may refer to. In general, those utilities that are increasing their investments in renewable energy resources are in large part located in states that require a minimum level of energy be sourced from renewable sources as part of a Renewable Portfolio Standard or similar requirement mandated by law, or they are located in states where renewables may be more economical to deploy based on higher costs of power or with more renewable resource potential (i.e. more rated hours of sunlight, greater wind production) so that the capacity factor is increased. However, ENO has and continues to evaluate the economics of renewable resources for future deployment. 22) Your plan acknowledges the uncertainty around future natural gas prices. Why would you invest so heavily in natural gas plants that are likely to quickly become uneconomical? a. While the preferred portfolio does identify combined-cycle gas turbine technology as the preferred technology to meet customers future needs, including addressing the aging fleet in Amite South and Downstream of Gypsy, it also includes a plan to invest in existing nuclear and solid fuel baseload generation resources that currently supply over half of ENO s annual energy requirements, and are expected to continue doing so during the 20 year IRP planning horizon. This is illustrated in Figure 1 on page 12 of the ENO IRP. At this point in time, the preferred portfolio represents the lowest reasonable cost set of demand- and supply-side resources capable of meetings customers future needs. The IRP assumptions and inputs, as well as the decision to make future investments are reevaluated prior to actual investment decisions. All of the IRP materials filed with the Council on October 30 th, 2012, are publicly available on ENO s website at 23) How can you create a plan that will only continue to rely on dwindling, ultimately harder to obtain fuel sources? a. As part of the IRP process, price forecasts for fossil fuel sources included in the IRP were developed. The price forecasts take into account the available supply of those fuel sources, and reflect the fact that those resources are expected to be readily available during the 20 year IRP planning horizon. In addition, the company updates its integrated resource plan on a routine basis and would incorporate any changes in longterm supplies of fossil fuels into future resource plans. 24) Why make a long-term plan based so heavily around methane gas when the pricing for it is already projected as being incredibly unstable? a. Please see response to question 22. 6

7 25) Why aren't thorium wave reactors or a series of thorium micro-reactors being considered as a possible energy alternative? a. The Entergy System desires to maintain readiness to execute new nuclear projects when and if they appear viable and economic, however, the current market assessment shows that no Generation IV fast reactors, of which thorium wave reactors are a sub-set, will be available for commercial delivery during most if not all of the IRP planning horizon. 26) Louisiana has a virtually unlimited supply and sun and wind. When can we expect to see these harvested on a large scale to generate our power? a. Please see response to questions 8 13 and ) I have no problem with nuclear power or with natural gas fired generation; however, is there a "green" replacement to coal that will be available within your 20 year plan. a. Please see response to question 8. 28) Has the company considered Hydrokinetic power solutions? a. Yes. Please see response to question 9. 29) What resources did ENO use to establish the 39% capacity factor for onshore wind resources? a. The 39% capacity factor for onshore wind resources was based on a study prepared by the Electric Power Research Institute (EPRI). The technology related assumptions used in the IRP were provided in the Technology Assessment Technical Supplement, and includes general industry-wide assumptions appropriate for use in an IRP where no specific investment decisions are being considered. ENO expects that individual generation projects may experience varying operating conditions and cost more or less than the industry-wide assumptions used in the IRP. The evaluation of specific alternatives for purposes of investment decisions would be performed using verifiable project-specific information. 30) Per note 35 provided on page 44 of the IRP report, ENO states that wind resources are penalized with additional charges for the cost of integration and match-up capacity. What portion of Onshore Wind s $111 per MWh levelized cost, as indicated in Table 16, is attributed to Entergy s cost of integration? What is the expected cost of integration for wind resources if Entergy ultimately joins MISO? a. The cost of onshore wind resource integration into the electrical system grid was estimated at $14 per MWh levelized, using the 39% capacity factor. The expected cost of integration once Entergy enters MISO is undetermined at this time. 31) Per note 35 provided on page 44 of the IRP report, ENO states that wind resources are penalized with additional charges for the cost of integration and match-up capacity. What portion of Onshore Wind s $111 per MWh levelized cost, as indicated in Table 16, is attributed to Entergy s levelized capacity matchup charge? Is this charge expected to change if Entergy joins MISO? 7

8 a. The cost of capacity match-up for onshore wind resource was estimated at $33 per MWh levelized, using the 39% capacity factor. MISO annually performs a Wind Capacity Credit Report and assigns system and zonal wind resource capacity credits based on historical hourly wind resource output for resources in the MISO region. Given capacity credits are assigned at the Local Resource Zone level for determining zonal resource credits, it is unknown at this time how the capacity match-up charge will change once Entergy enters MISO. 32) When determining the levelized capacity matchup charge for wind resources, did Entergy assign any capacity value to Onshore Wind resources? What capacity value does MISO presently assign to wind resources? a. Entergy did assign a capacity value to onshore wind resources in determining the capacity match-up charge. The current MISO 2013 Wind Capacity Credit Report assigns a MISO-wide average capacity credit of 13.3% for wind resources integrated into the MISO system, with Local Resource Zone capacity credits ranging from 7.6% to 15.2%. 33) For Onshore Wind resources, did ENO apply the levelized capacity matchup charge during the entire 20-year period of the IRP planning period? If yes, why were wind resources assessed a capacity matchup charge during periods that ENO is expected to possess excess capacity? Shouldn t capacity matchup charges only be applied to non-capacity resources whenever there is an actual need for capacity? a. The application of levelized capacity match-up charges are used only for screening and comparison purposes with other resource options and is levelized for each year of the wind resources expected useful life. When considering resources to meet future customer needs, resources, such as onshore wind, would only be considered for addition to the preferred portfolio when a need was identified. 34) Since the purpose of an IRP is to determine the lowest cost long-term energy solutions for retail customers, why did ENOs 2012 Generation Technology Assessment not quantify the energy cost advantages associated with larger wind resources (e.g. 200 MW or larger)? Does ENO agree that a 200 MW wind resource would result in a much lower levelized energy cost, as opposed to the small 75 MW facility used in the Generation Technology Assessment? Does ENO agree that making this single change could lower the levelized cost of wind resources by 10-20%? a. As a clarifying matter, the market modeling conducted as part of the IRP took the existing wind generation in the Midwest area into account. Regarding new wind resources ENO determined that 75 MW was the most likely capacity for wind resources in and around the Entergy region given wind speed class and terrain. ENO does not agree there would be significant cost advantages of a 200 MW resource in the Entergy region; while there may be minimal economies of scale, additional tower height and rotor diameter needed to capture limited wind supply and site terrain would likely offset such savings. As demonstrated in the U.S. Department of Energy 2011 Wind Technologies Market Report 8

9 the project cost where capacity exceeded 200 MW was over $2,000 per kw (page 35 Figure 21), which is the capacity cost incorporated into the Technology Assessment technical supplement to the ENO IRP. 35) Since the purpose of an IRP is to identify long-term low-cost energy resources, why didn t ENO consider wind projects located in the Midwest that presently achieve 45-50% capacity factors and are only one transmission wheel from the Entergy system? Does ENO agree that its model assumption of 36% in the first ten years of the IRP undervalues the realistic capacity factor of Onshore Wind resources located in the Midwest? a. As discussed in the Technology Assessment Technical Supplement to the ENO IRP, the IRP seeks to identify long-term resources which are expected to be operational in and around the Entergy service areas. Wind resources remote to the Entergy service areas are expected to be at increased risk of curtailment and/or require additional transmission investment cost not included in the cost estimates. ENO believes its capacity factor is appropriate, as demonstrated in Figures 26, 27, and 29 in the referenced report, and the average capacity factors of wind resource by year, vintage date, and region of the country remains in the mid-30% range. 36) Why did ENO s IRP model capture the benefits of joining MISO, the core of which lies approximately 900 miles from the ENO region, but failed to consider 45% capacity factor wind resources located in Oklahoma? Isn t it true that Entergy s wholesale marketing personnel buy and sell energy with entities located in the Southwest Power Pool on a daily basis? If so, why are SPP-based wind resources not given due process in the ENO IRP? a. See response to question 34 and ) How does Entergy Services justify the $111 per MWh charge assigned to Onshore Wind resources in the ENO IRP? As part of the ENO IRP, did Entergy Services or ENO contemplate the lower cost supply alternative that can be achieved by contracting with wind developers via longterm Power Purchase Agreements? a. Please see response to questions ) In question #5 posted on ENOs Q&A website, it is asked: What does the IRP consider to be the useful life of a generator? The response from ENO indicates that wind resources possess a 25 year life. Question: If wind resources have a 25 year life, why does the 2012 Generation Technology Assessment apply a shorter 20-year life to wind resources? If wind resources were evaluated in the IRP using a longer 25-year resource life, wouldn t such change lower the $111 per MWh levelized cost presently assigned to Onshore Wind resources? a. The question and response referenced was from the 2009 integrated resource planning process and is no longer applicable as the technological assumptions have been updated as part of the 2012 ENO IRP consistent with a study prepared by Electric Power Research Institute (EPRI). 9

10 39) How will you half the typical residential customer's bill while reducing carbon footprint? a. The purpose of the integrated resource planning process is to identify a plan that meets customers future needs at the lowest reasonable cost while maintaining reliability of the electric system. As part of this process, ENO sought to balance the objectives of the IRP and sought input from stakeholders. These planning guidelines are consistent with the Council s requirements as outlined in Resolution R Neither the Council s requirements nor ENO s planning principles have claimed to plan for cutting customer bills in half while reducing carbon footprint. The IRP is a planning framework and is not utilized to meet arbitrary goals such as those suggested by the question. Entergy was the first utility to voluntarily commit to stabilizing its greenhouse gas emissions, but acknowledges that substantial decreases in carbon footprint will come at an increased cost to customers. DSM 40) How did you determine the technologies to reduce demand side? a. A detailed explanation of the technology assessments, the DSM screening process and the DSM optimization process can be found in the IRP documents at 41) Where is the modeling to support the decision to not utilize change in rates: structure, inclining, time of day, virtual net-metering, etc. to reduce consumption and or demand? a. Time of Use rates were considered in the analysis. There were four programs in the ICF Potential Study that considered Time of use metering. These programs were: nonenabled dynamic pricing residential, non-enabled dynamic pricing non-residential, enabled dynamic pricing residential, and enabled dynamic pricing non-residential. For a more detailed explanation of these programs please see Appendix D of the ICF DSM Potential Study to the 2012 ENO IRP. These programs were considered in the detailed DSM optimization modeling conducted by ENO. These programs were not found to be economic in three of the four IRP scenarios modeled, nor in the final risk assessment. As such they were not included in the preferred portfolio. Virtual net metering was not specifically considered, however, solar was considered and was not found to be cost effective. 42) In ICF s presentation, the Reference advertised = $20 million per year DSM investment, so why then does Entergy s proposal come out at $4 million DSM investment annually? a. The ICF potential study evaluated the effectiveness of 22 DSM programs. A reference level of spending on all these programs reaches $20.4 Million in the tenth year (2021). When modeled over the twenty year planning horizon, all of these programs were not 10

11 found to be cost effective when compared against other resource alternatives. In the preferred portfolio 10 of the 22 programs identified by ICF were selected. The IRP preferred portfolio of DSM was based on a low level of spend for eight and a high level of spend for 2 of the 10 programs. This results in an annual ENO projected spend of $5.24 million in year ten (2021) and $5.92 million by year 20 (2031). The average of the preferred portfolio spend was $4.7 million per year. 43) Can you walk us through the budgets and proposed saving figures for DSM between the ICF report and ENO preferred portfolio? a. Please see response to question 42 above. 44) What percent of total demand (per year and cumulative) will DSM fulfill and at what average cost per kwh? a. As noted on page 22 in the DSM Technical Supplement to the 2012 ENO IRP, the levelized cost per MWh of DSM in the preferred portfolio is $21.85/MWh. The preferred portfolio assumes a Flight 5 level of spending in order to obtain this level of DSM. Page 23 of the same report provides the annual energy and peak reduction benefits from DSM along with the annual cost. Cumulative cost and energy savings can be obtained by adding the annual values together. All of the IRP materials filed with the Council on October 30 th, 2012, including the DSM Technical Supplement, are publicly available on ENO s website at 45) Notwithstanding the prior modeling calculations, have the recommended supply additions been compared from a cost per kwh basis head to head with adding more DSM? a. Yes. For a comparison of DSM cost per MWh as compared to the marginal cost of supply side resource alternatives on a dollar per MWh basis, please see page 22 in the DSM Technical Supplement to the 2012 ENO IRP. It should be noted that the levelized cost per MWh of DSM in the preferred portfolio is $21.85/MWh which is Flight #5 on page 22 of this report. All of the IRP materials filed with the Council on October 30 th, 2012, including the DSM Technical Supplement, are publicly available on ENO s website at 46) Regarding time of use metering, how would it affect base and peak demand, was this issue studied, and why is it not part of the strategy? a. Please see response to question 41 above. 47) The DSM analysis presented seems to be predicated on technology substitutions entirely no change in use patterns. It then looks at how much to incent/subsidize a given technology substitution. Why not look at policies that reward less use or peak demand (bill disclosure, time of use rates, rates that go up with higher use, building labeling)? a. As indicated in the response to question 41 above, the DSM Potential Study evaluated programs designed to change customer usage patterns. Also, ENO recently completed a 11

12 pilot study of Advanced Metering Infrastructure installed in New Orleans area homes and plans to file a report with the Council in 2013 on the results. The results of the IRP modeling as well as the AMI pilot study will be taken into consideration in developing future DSM programs. 48) What role does cost to the utility (ENO) play in the IRP decisions? Please explain how DSM only eventually results in costing the customer more. a. The IRP uses total relevant customer revenue requirements as the cost benchmark. The IRP seeks to meet customers long-term needs at the lowest reasonable cost, while maintaining reliability of the electric system. Different DSM programs have different costs and benefits. This is articulated in the DSM Technical Supplement to the 2012 ENO IRP. Please see in particular page 22. The 22 DSM programs listed there are from the ICF DSM Potential Study and represent varying levels of spending grouped into 18 DSM flights. Each flight included more DSM programs and/or a higher level of spending than the flight before. The flights are ranked from lowest to highest cost. At some point adding more DSM comes at a cost above available supply side alternatives. In most scenarios analyzed in the IRP, the cost-effective DSM spending in the preferred portfolio (Flight #5) coupled with economic supply side resource additions produced the lowest overall cost to ENO customers. 49) What are the savings from not having to build a new plant due to Energy Efficiency? a. In the ICF DSM Potential Study, the savings associated with peak energy reductions are shown on a year by year basis. These include the benefit of having to provide lower generation capacity to meet planning reserves. The ICF Potential Study identified the following savings opportunities from DSM peak reductions: the cost to construct a new combustion turbine natural gas plant, the plant s fixed annual operating cost, line loss reductions, and cost savings from having to build and maintain fewer transmission and distribution lines. Please see page 1 of Appendix C of the ICF DSM Potential Study. For example, the savings in 2012 is $157.90/kW. It should be noted; however, in practice the alternative supply side resource capacity cost might be lower than a new build combustion turbine natural gas plant. By modeling a higher-cost alternative in the DSM Potential Study, the DSM programs were given the benefit of the doubt resulting in more programs being brought forward for further evaluation in the DSM Optimization. The optimization modeling conducted by ENO considered other lower cost supply side alternatives when available, such as spending to extend the reliability of an existing supply side resource. 50) The DSM numbers showed energy savings of 0.8%-1.6% on the ENO system, which is approximately 5.1 million MWh per year. This equates to 40,800 MWh to 81,600 MWh saved each year at a cost of $7.6M to $34M, annually. Isn t this very expensive? ($186-$416/MWh) a. The 2012 ENO IRP Scenario 1 load forecast in 2021 is 5,836 million MWh. The ICF DSM Potential Study projected the potential to save up to 1.1% of sales in 2021 under the 12

13 reference case annual level of DSM spending at $20.4 million. The spending also results in other benefits related to reduction in peak load, which are not captured if looking only at energy savings. Those benefits were incorporated into the 2012 ENO IRP DSM Optimization, which led to the optimal level of DSM spending identified in the preferred portfolio. 51) It looks as though your proposals will save money and generation cost, but your residential programs (proposed) will not benefit individual homeowners much. Are you considering the micro aspects (helping Orleans Parish people) or just macro effects (total $ saved)? If not, why not? a. The IRP does not represent a detailed DSM program plan. It is a high level view of the savings and costs associated with an optimal level of cost effective DSM. The goal of the IRP as well as the DSM Optimization were to develop a set of future resource additions (demand- and supply-side) that result in the lowest reasonable cost while maintaining reliability of the electric system. A more detailed DSM program implementation plan is currently being developed. The Energy Smart Plan currently offers both residential and commercial energy efficiency programs, was developed by the City Council, and is administered by Entergy New Orleans. The current residential programs offer benefits including cash incentives to homeowners at all income levels. These programs are also designed to allow individual homeowners to take advantage of incentives on a wide range of projects. It is envisioned that new programs considered for the next phase of Energy Smart will expand and enhance the programs currently being offered. To learn more about the current Energy Smart Plan, please visit New programs will be proposed for consideration by the City Council on April 1 st as part of the Implementation Plan and Cost Recovery filing. 52) What savings are included by not having to build new facilities due to increased DSM/Energy Efficiency? a. Please see question 49 above. 53) From the data presented at the public technical conference there appears to be an enormous discrepancy between the DSM Potential Study annual investment figures of $20.4 million (10 year) to $23.3 million (20 year) for the middle of the road Reference scenario and Entergy s Optimized figure of $4.7 million (20 year). Even the Low scenario in the Potential Study cites figures of $7.6 million (10 year) to $8.3 million (20 year). Could Entergy and the Council please expand with further specific details on the issue of DSM decisions arrived at in this proposed IRP? a. It is important to understand that the Council has not yet made a decision regarding the level of future spending on DSM programs in this proceeding or with respect to the 2012 ENO IRP. Please also see the response to Question 42 above. 13

14 54) Please explain how DSM eventually ends up costing the customer more over time or point out exactly where in the supplemental materials I can find this information. a. Please see slide 5, 12, 13 and 22 of the DSM Technical Supplement to the IRP. All of the IRP materials filed with the Council on October 30 th, 2012, including the DSM Technical Supplement, are publicly available on ENO s website at 55) The DSM Program Model addresses "low income weatherization"; however, has there been any consideration to make weatherization more affordable or income based for residential customers that wish to have their historic homes weatherized, but do not qualify as "low income"? a. Please see response to question ) You mentioned often a priority being lowest cost. What role does lowest cost (and highest profit) play in the decisions particularly relating to DSM? a. In the IRP process, the objective to identify the set of resources necessary to meet customers future needs at the lowest reasonable cost subject to maintaining reliability is not a profit driven decision. Furthermore, this objective is consistent with the Council s requirements for the IRP process contained in Resolution R ) Why is cost-effective DSM predicated only upon lower energy bills or demand? This is relatively minor importance to a building owner? a. Energy Efficiency programs are paid for by customers and it appears very important to a majority of customers to utilize cost-effective DSM specifically to lower their energy bills and to recoup their investment in energy efficiency over a reasonable payback period. It may not be as important to a building owner if he is not the customer paying the utilities for a building. 58) Why are all of the DSM tools incentive payments? a. Not all of the programs evaluated and included in the preferred portfolio are technology substitutions. It is also important to understand that the programs in the IRP are merely a guide for use in developing more detailed program designs for the successor to the current Energy Smart programs. The IRP simply provides an indication of the range of spending and savings which can be expected from cost effective DSM. Please also see response to question ) Since the largest sector of the largest sector is lighting... why under-sell improved productivity? a. ENO is unable to respond to this question because its meaning is unclear. 60) Why isn't PV in the DSM? a. PV was considered and it was found to be uneconomic at this time. Please see the response to Question

15 61) Why aren't batteries in the DSM? a. Batteries, in and of themselves, are not DSM measures. Solar with battery backup was not screened. Solar without battery backup did not pass the cost effectiveness testing. 62) The commercial efficiency potential extrapolated from the national building data set. With what confidence can a national data set speak the energy usage of New Orleans buildings? a. Available data from the current Energy Smart commercial programs was analyzed along with other data sources. For purposes of the IRP and the development of a high level long term plan, the data sources are believed to be appropriate. 63) Have you investigated any findings from the Nola wise programs or other energy efficiency efforts from regional climate zones? a. Data from the current Energy Smart programs was analyzed. Energy Smart has the same data as NOLA Wise as the NOLA Wise program utilizes Energy Smart certified contractors and incentives. 64) Why weren t the industrial efficiency measures assumptions updated? a. ENO is unable to respond to this question because its meaning is unclear. Generation and Transmission 65) I heard no mention of efficiency improvements between supply and demand sides. Does Entergy have a plan to invest in transmission infrastructure within the IRP? a. As a point of clarification, it is important to note that investments in transmission infrastructure do not generally affect the relationship between supply and demand-side resources, as the latter is typically connected to the distribution system. Regardless, ENO has and continues to make the investments necessary to ensure that reliability is maintained and customers needs are met at the lowest reasonable cost. Additional discussion regarding the integration of transmission planning into the IRP can be found on pages 6 and 19 of the 2012 ENO IRP. 66) Baseload and Savings Prices? a. ENO is unable to respond to this he question because its meaning is unclear. 67) Full cycle cost per kilowatt-hour for your various electrical generation base fuels? a. For a complete discussion of the bus bar cost per MWh (per KWh times 1,000) of various generation technologies please see the Technology Assessment to the 2012 ENO IRP. All of the IRP materials filed with the Council on October 30 th, 2012, including the Technology Assessment Technical Supplement, are publicly available on ENO s website 15

16 at 68) How did Entergy treat the transmission link from MISO, which is rated at approximately 1,000 MW, in the IRP model? a. The impact of the approximate 1,000 MW direct transmission link between Entergy Arkansas and MISO was part of the hour by hour modeling conducted by ENO. In addition, modeling considered indirect access to MISO via intermediate points such as the Southwest Power Pool. 69) An Entergy system peak of 22,000 MW was shown. Is this the entire Entergy 12-month coincident peak? a. No. The Entergy system s peak load varies by month. For capacity planning purposes, however, the annual firm coincident Entergy System peak plus planning reserves is the relevant measure. The annual firm peak generally occurs in July or August of each year, but can occur in other months (e.g. June or September). Once the Entergy Operating Companies join MISO the annual firm peak plus reserves coincident with the overall MISO peak will become the relevant metric. The IRP contemplates the latter metric to be approximately equal to the Entergy System annual firm coincident peak plus a 12% reserve margin. 70) What is Entergy s ROE on transmission plant? What would be the new ROE under ITC? a. Entergy s current FERC approved return on equity for transmission plant is 11%. The return on equity for Entergy s transmission assets that transfer to ITC as part of the pending spin-merge transaction has not yet been determined. 71) How close is Entergy to a 4 th Generation-Fast Reactor Power Plant going online? a. The Entergy System desires to maintain readiness to execute new nuclear projects when and if they appear viable and economic; however, the current market assessment shows that no Generation IV fast reactors will be available for commercial delivery during most if not all of the IRP planning horizon. 72) Will MISO transition process interrupt timing of local IRP process and/or state QuickStart program? a. The MISO transition process will not interrupt or interfere with the Council s IRP process as outlined in Resolution R The state QuickStart program is not applicable to Entergy New Orleans or the 2012 ENO IRP. 73) Why should ENO stay in the System? a. ENO is unable to respond to this question because its meaning is unclear. 16