ML17024A218
| ML17024A218 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 02/07/2017 |
| From: | Entergy Operations |
| To: | Keegan E Division of License Renewal |
| Elaine Keegan, NRR/DLR, 415-8517 | |
| Shared Package | |
| ML17018A143 | List:
|
| References | |
| Download: ML17024A218 (99) | |
Text
- ~ Entergy Entergy Services, Inc.
639 Loyola Avenue (70113}
P.O. Box 61000 New Orleans, LA 70161-1000 Tel 504 576 3101 Fax 504 576 5579 Edward R. Wi cker, Jr.
Senior Counsel Legal Sel'Vices - Regulatory Accessed at http://www.entergy-louisiana.com/content/irp/2015_0803_Louisiana_Final_IRP_Public.pdf August 3, 2015 Via Hand Delivery Ms. Terri Lemoine Bordelon Records and Recording Division Louisiana Public Service Commission Galvez Building, lih Floor 602 North Fifth Street Baton Rouge, Louisiana 70802 Re: 2015 Integrated Resource Planning ("IRP") Process for Entergy Louisiana, LLC and Entergy Gulf States Louisiana, L.L.C. Pursuant to the General Order No. R-30021, Dated April 20, 2012 LPSC Docket No. 1-33014
Dear Ms. Bordelon:
On behalf of Entergy Louisiana, LLC and Entergy Gulf States Louisiana, L.L.C.
(collectively, the "Companies"), enclosed please find the Companies' 2015 Integrated Resource Plan (the "2015 IRP"). Also enclosed is a red-lined version that reflects certain changes to the previously-filed draft report. Please retain an original and two copies for your files and return a date-stamped copy to our by-hand courier.
Appendix B submitted with the 2015 Draft IRP contains information that is designated Highly Sensitive Protected Materials ("HSPM"), which are being provided to you under seal pursuant to the provisions of the LPSC General Order dated August 31, 1992, and Rules 12.1 and 26 of the Commission's Rules of Practice and Procedure. The confidential materials included in the filing consist of confidential and market-sensitive financial information.
Please retain the original HSPM materials for your files and return a date-stamped copy to our by-hand courier. The HSPM materials are being produced only to the appropriate Reviewing Representatives in accordance with the Confidentiality Agreement in effect in this docket.
Ms. Bordelon August 3, 2015 Page2 If you have any questions, please do not hesitate to call me. Thank you for your courtesy and assistance with this matter.
Sincerely, Edward R. Wicker, Jr.
ERW/ttm Enclosures cc: Official Service List (via electronic and U.S. mail)
CERTIFICATE OF SERVICE LPSC Docket No. I-33014 I, the undersigned counsel, hereby certify that a copy of the above and foregoing has been served on the persons listed below by facsimile, electronic mail, hand delivery and/or by mailing said copy through the United States Postal Service, postage prepaid, and addressed as follows:
Melanie A. V erzwyvelt Tulin Koray Staff Attorney Economics Division Louisiana Public Service Commission Louisiana Public Service Conunission P.O. Box 91154 P.O. Box 91154 Baton Rouge, LA 70821-9154 Baton Rouge, LA 70821-9154 Donnie Marks James M. Ellerbe LPSC Utilities Division Marathon Petroleum Company LP Louisiana Public Service Commission 539 South Main Street P.O. Box 91154 Findlay, Ohio 45840-3295 Baton Rouge, LA 70821 Katherine W. King Kimberly A. Fontan J. Randy Young Entergy Services, Inc.
Carrie R. Tournillon 4809 Jefferson Highway Kean Miller LLP Mail Unit L-JEF-357 P.O. Box 3513 Jefferson, LA 70121 Baton Rouge, LA 70821 Kathryn J. Lichtenberg John H. Chavanne Karen H. Freese Chavanne Enterprises Edward R. Wicker, Jr. 111 West Main Street, Suite 2B Entergy Services, Inc. P.O. Box 807 639 Loyola A venue, 26th Floor New Roads, LA 70760-0807 P.O. Box 61000 Mail Unit L-ENT-26E New Orleans, LA 70161-1000 Chairman Eric F. Skrmetta Conunissioner Scott A. Angelle Office of the Commissioner Office of the Commissioner District I - Metairie District II - Baton Rouge 433 Metairie Road, Suite 406 Post Office Box 2681 Metairie, LA 70005 Baton Rouge, LA 70821 Commissioner Lambert C. Boissiere, III Vice-Chairman Clyde C. Holloway Office of the Commissioner Office of the Conunissioner District III - New Orleans District IV - Forest Hill 1450 Poydras Street, Suite 1402 11098 Hwy. 165 South New Orleans, LA 70112 Forest Hill, LA 71430
Conunissioner Foster L. Campbell Philip Hayet Office of the Commissioner Lane Kollen District V - Shreveport Randy A. Futral Post Office Drawer E J. Kennedy and Associates, Inc.
Shreveport, LA 71161 570 Colonial Park Drive, Suite 305 Roswell, GA 30075 Rebecca E. Turner Thomas W. Milliner Vice President Anzelmo, Milliner & Burke, LLC Regulatory Affairs & Market Design 3636 S. I~ l 0 Serv. Rd., Suite 206 Entegra Power Group LLC Metairie, LA 70001 100 South Ashley Drive, Suite 1400 Tampa, FL 33602 Casey DeMoss Roberts Michelle Bloodworth Executive Director Senior Director, Power Generation Alliance for Affordable Energy America's Natural Gas Alliance 2372 St. Claude Ave., #300A 710 8th Street NW, Suite 800 New Orleans, LA 70117 Washington, DC 20001 Gordon D. Polozola Robert P. Larson NRG Energy, Inc. Douglas A. Spaulding General Counsel- South Central Region Manager 112 Telly Street Nelson Energy LLC New Roads, LA 70760 8441 Wayzata Blvd., Suite 101 Golden Valley, MN 55426 Joshua Smith, Staff Attorney Haywood Martin Casey Austin Roberts Sierra Club Delta Chapter Chair Sierra Club Environmental Law Program P.O. Box 52503 85 Second St., Second Floor Lafayette, LA 70505 San Francisco, CA 94104 C. Tucker Crawford Mandy Mahoney President, GSREIA Abby Schwimmer 643 Magazine Street Southeast Energy Efficiency Alliance Suite 102 50 Hurt Plaza SE, Suite 1250 New Orleans, LA 70130 Atlanta, GA 30303 Mr. Simon A. Mahan Southern Wind Energy Association C/O SACE P .0. Box 1842 Knoxville, TN 37901 New Orleans, Louisiana, this 3rd day of August, 2015.
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20 015 Integgrateed Resou urcee Plan Entergyy Gulf Staates Lou uisiana, L.L.C.
and Entergy E Louisian L na, LLC LP PSC Dockket No. II33014 Draft Re uary 30, 2015 eport: Fiiled Janu on 1: Filed Aprill 15, 201 Drafft Reporrt Revisio 15 Final Report:
R Filed F Auggust 3, 22015
Louisiana stands at the e center of ann industrial re enaissance thaat offers residdents an opportunity to chhange the econo omic futures ofo their familiies and comm munities for g enerations to o come.
Attracted by lowcost natural gas, low electricityy prices, existting infrastruccture, and Louisianas business friendly climate, energgyintensive in ndustries aree investing bil lions to build d new plants or expand exxisting facilities and a creating thousands t off jobs for Lou uisiana residents..
Entergys Louisiana companies c are a committe ed to partneringg with the state to capitalizec on n this tremendo ous econom mic opportun nity by enssuring Louisiana has an amp ple supply off clean, afforrdable and reliab ble power. We call our plan Power to Grow, A Blueprin nt For Louisiaanas Bright Fuuture.
This Integgrated Resource Plan refle ects that commmitment to helping our sstate create needed jobs while also sustaaining compettitive energy prices and co ontinuing to sserve all custoomers reliably. Through th he IRP process, we conducte ed an extenssive study of o our custom mers needs over the neext 20 yearss. We evaluated d different fu uels and tecchnologies, including rennewable reso ources and aalternative eenergy programs, and analyze ed a variety of economicc scenarios too help determine how w we can best ssatisfy those requirements in this rapidly changing c environment.
Because of o this unpreccedented gro owth, Entergyys Louisiana ccompanies m must be prepaared to serve up to 1,600 MW W of increased d industrial lo oad through 2019.
2 Beyondd industrial grrowth, we project a need for at least another 8,000 MW M of generrating capacitty by 2034 tto meet grow wing demand d and to con ntinue modernizing our generration fleet.
Adding new, highly efficient e gene eration requiires significannt capital invvestment. However, a quickly expandingg economy willw allow thosse costs to be spread acrosss a growing vvolume of sales, which co oupled with othe er factors minimizes the raate effect to customers c an d helps keeping our rates among the lo owest in the cou untry.
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The IRP includes a fiveyear action plan that will allow us to ensure we are able to provide safe, reliable and economic service to all customers, existing and new. The action plan includes:
Obtaining regulatory approvals for Entergy Gulf States Louisiana to purchase two units of the Union Power Station near El Dorado, Arkansas.
Adding potential new resources:
o Seeking certification of selfbuild CCGT that was market tested in the 2014 Amite South RFP.
o Issuing the 2015 WOTAB RFP to solicit proposals for a new CCGT unit in the Lake Charles area in the 202021 timeframe.
o Determining whether a pair of CT units is needed in the Lake Charles area by 2020 to meet industrial load growth.
o Continuing to assess development of other CT units in Amite South and WOTAB areas for quick deployment if load growth exceeds projections and/or other supply options are not completed as planned.
Studying distributed solar and storage pilot projects to determine the viability and performance of the technologies in Louisiana.
Assessing power contracts as viable alternatives for meeting longterm needs.
Exploring opportunities for longterm gas supplies to mitigate price volatility and hedge against future price increases.
Evaluating the results of the Quick Start phase of Entergy Solutions: A Louisiana Program; and Working with regulators to develop rules for costeffective energy efficiency programs beyond the Quick Start phase.
This is an exciting time for Louisiana. Entergys Louisiana companies have a plan and are committed to meeting the power needs of our customers at a reasonable cost.
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CONTENTS Contents ........................................................................................................................................................ 3 Introduction .................................................................................................................................................. 5 Industrial Renaissance in Louisiana ................................................................................................. 6 MISO Integration.............................................................................................................................. 6 Business Combination of ELL and EGSL ........................................................................................... 7 System Agreement ........................................................................................................................... 7 Part 1: Planning Framework.......................................................................................................................... 8 Resource Adequacy Requirements .................................................................................................. 9 Transmission Planning ..................................................................................................................... 9 Area Planning ................................................................................................................................. 11 Part 2: Assumptions .................................................................................................................................... 13 Technology Assessment ................................................................................................................. 13 DemandSide Alternatives ............................................................................................................. 16 Natural Gas Price Forecast ............................................................................................................. 17 CO2 Assumptions ........................................................................................................................... 18 Market Modeling ........................................................................................................................... 18 Part 3 Current Fleet & Projected Needs ..................................................................................................... 20 Current Fleet ................................................................................................................................. 20 Load Forecast ................................................................................................................................. 21 Resource Needs ............................................................................................................................. 23 Types of Resources Needed ........................................................................................................... 27 Part 4: Portfolio Design Analytics................................................................................................................ 28 Market Modeling ........................................................................................................................... 28 Portfolio Design & Risk Assessment .............................................................................................. 29 Summary of Findings and Conclusions .......................................................................................... 37 Part 5: Final Reference Resource Plan & Action Plan ................................................................................. 38 Final Reference Resource Plan....................................................................................................... 38 Action Plan ..................................................................................................................................... 42 3
APPENDICES Appendix A ELL and EGSL Generation Resources Appendix B Actual Historic Load and Load Forecast Appendix C Response to Stakeholder Comments Appendix D Entergy Long Term Transmission Plan (ELL and EGSL Projects)
Appendix E 1st Stakeholder Meeting Charts Appendix F Aurora DSM Portfolios by Scenario Appendix G Wind Modeling Assumptions 4
INTRODUCTION This report, prepared in accordance with the Integrated Resource Planning rules promulgated by the Louisiana Public Service Commission (LPSC),1 describes the longterm integrated resource plan (IRP) of Entergy Gulf States Louisiana, L.L.C. (EGSL) and Entergy Louisiana, LLC (ELL) (collectively referred to as the Companies) for the period 2015 - 2034. The plan reflects important changes in the Companies planning and operations and gives consideration to the current and expected economic environment in Louisiana. It should be noted that the data and assumptions reflected in this IRP largely reflect the best information available during the initial development of the Data Assumptions for the draft report in late 2013early 2014.
During the 18 months over which this report was developed, some information, forecasts, and assumptions may have changed. While this report does not attempt to address all such changes, key changes have been noted throughout the document. As a longterm planning document, the IRP is intended to provide guidelines for resource planning and decisions, but actual decisions will be made based on the best information available at the time such decision is made.
In addition to the economic outlook for the state, three recently completed or forthcoming initiatives the Companies participation in the Midcontinent Independent System Operator (MISO) market beginning December 19, 2013, the Companies Joint Application to combine their respective assets and liabilities into a single operating company, and the proposed termination of the Companies participation in the Entergy System Agreement on February 14, 2019 have implications for the Companies resource needs and supply strategy. Given the significance of these changes on the Companies longterm capacity and resource needs, this IRP addresses how the Companies plan to meet their customers power needs, both economically and reliably.
As discussed in this report, residential, commercial, and industrial load growth, unit deactivations, and purchased power agreement (PPA) expirations, will require the Companies to add significant transmission and generation resources during the planning period, including multiple generators in the 20192021 time frame. While additional generation will require substantial capital commitments from the Companies, the Companies do not expect that the generation additions will cause customer rates to increase materially. This is a result of increased consumption (i.e., greater kWh sales over which to spread fixed costs), improved portfolio efficiency, and expiration of other customer charges, among other factors.
1 See, LPSC Corrected General Order No. R30021, In re: Development and Implementation of Rule for Integrated Resource Planning for Electric Utilities, dated April 20, 2012.
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Industrial Renaissance in Louisiana A unique set of circumstances has converged to give Louisiana the opportunity to develop and grow its economy in ways that can benefit its citizens for generations to come. A combination of factors, including low natural gas prices resulting from the development of shale natural gas, low electricity prices, access to worldclass energy infrastructure, including deep water ports, an extensive interstate pipeline network and related infrastructure, an experienced workforce, and a probusiness environment have resulted in an industrial renaissance in Louisiana that has seen more than $50 billion in new capital investment and the creation of over 83,000 new direct and indirect jobs since 2008.
This industrial renaissance is resulting in - and is projected to continue to result in - new or expanded industrial facilities concentrated in the Amite South2 and the West of the Atchafalaya Basin (WOTAB)3 planning areas, where there currently are substantial supply requirements that require local generation yet limited available inregion power sources. More specifically, the Companies expect up to 1,600 megawatts (MW) of industrial load growth in their service areas through 2019, and by 2034, after accounting for the deactivation of existing, older generation the Companies expect to require at least 8,000 MW of additional capacity to meet demand. This industrial load growth is in addition to expected load growth in the residential and commercial sectors. Through the Power to Grow initiative, the Companies are demonstrating their commitment to meeting todays needs and anticipating the power demands of the future so Louisiana has the ample supply of clean, affordable and reliable power needed to capitalize on this tremendous economic opportunity.
MISO Integration The Companies, along with their affiliate Entergy Operating Companies (EOC), became market participants in MISO on December 19, 2013. MISO is a regional transmission organization (RTO) allowing the Companies access to a large structured market that enhances the resource alternatives available to meet customers power needs. The availability and price of power in the MISO market affects the Companies resource strategy and portfolio design.
Despite the significance of the move to MISO for the Companies and their customers, the Companies retain responsibility for planning to meet their customers longterm power needs.
MISO considerations are an element of this IRP.
2 Amite South is the area generally east of the Baton Rouge, Louisiana, metropolitan area to the Mississippi state line and south to the Gulf of Mexico.
3 WOTAB is the area generally west of the Baton Rouge, Louisiana, metropolitan area to the westernmost portion of EGSLs service territory.
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Business Combination of ELL and EGSL On September 30, 2014, the Companies filed an application4 with the LPSC seeking approval of a proposal to combine their respective assets and liabilities into a single operating company.
This IRP assumes that the proposed combination will be approved and completed; 5 as such, the IRP analysis was conducted, and the results are reported herein, on a combined entity basis.
However, because the Companies currently use substantially identical planning criteria to one another and to those used for the combined entity, results of the IRP analysis would not be materially different had the analysis been performed separately for each operating company. A separately performed analysis for EGSL and ELL would result, over the longterm, in two portfolios that in combination would include similar elements to the final reference resource plan for the combined entity.
System Agreement The electric generation and bulk transmission facilities of the EOCs participating in the Entergy System Agreement are operated on an integrated, coordinated basis as a single electric system and are referred to collectively as the Entergy System.
The EOCs participating today in the System Agreement are EGSL, ELL, Entergy Mississippi, Inc.
(EMI), Entergy Texas, Inc. (ETI), and Entergy New Orleans, Inc. (ENO).6 On February 14, 2014, EGSL and ELL provided written notice to the other EOCs of the termination of their participation in the System Agreement.7 In light of the decision to terminate participation, this IRP was prepared under the assumption that EGSL and ELL will no longer participate in the System Agreement as of February 14, 20198. Although the effective date of the Companies termination of participation is uncertain, it is appropriate that current resource planning efforts acknowledge that standalone operations are on the horizon. This IRP is an assessment of the longterm resource needs of the Companies that may be used to develop strategic direction and guide the development of the future longterm resource portfolio.
4 Ex Parte: Potential Business Combination of Entergy Louisiana, LLC and Entergy Gulf States Louisiana, L.L.C.,
Docket No. U33244.
5 An uncontested stipulation recommending approval of the Business Combination was filed with the Commission on July 13, 2015, and a settlement hearing was held on July 24, 2015. The Commission is expected to consider the stipulation at the August 2015 Business and Executive Session.
6 Entergy Arkansas, Inc. (EAI), also an EOC, terminated its participation in the System Agreement effective December 18, 2013.
7 EMI provided notice to the EOCs that it would terminate its participation effective November 7, 2015. ETI has provided notice that it would terminate its participation on October 1, 2018 (subject to the FERCs ruling in Docket No. ER1475000 which is the FERC proceeding filed to amend the notice provisions of Section 1.01 of the System Agreement).
8 EGSLs and ELLs notice would be effective February 14, 2019 or such other date consistent with the FERCs ruling in Docket No. ER1475000. However, an earlier termination may be possible if agreed upon by the participating EOCs.
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PART 1: PLANNING FRAMEWORK The Companies planning process seeks to accomplish three broad objectives:
To serve customers power needs reliably; To reliably provide power at the lowest reasonable supply cost; and To mitigate the effects and the risk of production cost volatility resulting from fuel price and purchased power cost uncertainty, RTOrelated charges such as congestion costs, and possible supply disruptions.
Objectives are measured from a customer perspective. That is, the Companies planning process seeks to design a portfolio of resources that reliably meets customer power needs at the lowest reasonable supply cost while considering risk.
In designing a portfolio to achieve the planning objectives, the process is guided by the following principles:
Reliability - adequate resources to meet customer peak demands with adequate reliability.
Base Load Production Costs - lowcost base load resources to serve base load requirements, which are defined as the firm load level that is expected to be exceeded for at least 85% of all hours per year.
LoadFollowing Production Cost and Flexible Capability - efficient, dispatchable, load following resources to serve the timevarying load shape levels that are above the base load supply requirement, and also sufficient flexible capability to respond to factors such as load volatility caused by changes in weather or by inherent characteristics of industrial operations.
Generation Portfolio Enhancement - a generation portfolio that avoids an overreliance on aging resources by accounting for factors such as current operating role, unit age, unit condition, historic and projected investment levels, and unit economics, and taking into consideration the manner in which MISO dispatches units.
Price Stability Risk Mitigation - mitigation of the exposure to price volatility associated with uncertainties in fuel and purchased power costs.
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Supply Diversity Risk Mitigation - mitigation of the exposure to major supply disruptions that could occur from specific risks such as outages at a single generation facility.
Resource Adequacy Requirements As a load serving entity (LSE) within MISO, the Companies are and continue to be responsible for maintaining sufficient generation capacity to meet the minimum reliability requirements of their customers. Under the MISO Open Access Transmission, Energy, and Operating Reserve Markets Tariff (MISO Tariff), the Companies meet resource adequacy requirements by providing resources necessary to meet or exceed a minimum planning reserve margin established for the Companies by MISO. Resource Adequacy is the process by which MISO ensures that participating LSEs maintain sufficient reliable and deliverable resources to meet their anticipated peak demand plus an appropriate reserve margin.
Under MISOs Resource Adequacy process, MISO annually determines (by November 1 each year) the planning reserve margin applicable to each Local Resource Zone (LRZ) for the next planning year (June - May). LSEs are required to provide planning resource credits for generation or demand side capacity resources to meet their forecasted peak load coincident with the MISO peak load plus the planning reserve margin established by MISO. Generation planning resource credits are measured by unforced capacity (installed capacity multiplied by appropriate forced outage rate). The annual planning reserve margin for the LRZ which encompasses ELL and EGSL, as determined by MISO, sets the minimum required planning reserve margin9 the Companies must provide. For purposes of longterm planning, the Companies have determined that a 12% reserve margin based on installed capacity ratings and forecasted (noncoincident) firm peak load should be adequate to cover MISOs Resource Adequacy requirements and uncertainties such as MISOs future required reserve margins, generator unit forced outage rates, and forecasted peak load coincidence factors. Also, after the business combination, a 12% reserve margin provides enough capacity to cover loss of the Companies largest generating unit contingency.
Transmission Planning The Companies transmission planning ensures that the transmission system (1) remains compliant with applicable NERC Reliability Standards and related SERC and local planning criteria, and (2) is designed to efficiently deliver energy to enduse customers at a reasonable cost. Since joining MISO, the Companies plan their transmission system in accordance with the MISO Tariff. Expansion of, and enhancements to, transmission facilities must be planned well in 9
In MISO, Resource Adequacy reserve margin requirements are expressed based on unforced capacity ratings and MISO System coincident peak load. Traditionally, the Companies and other LSEs have stated planning reserve requirements based on installed capacity ratings and forecasted (noncoincident) peak load.
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advance of the need for such improvements given that regulatory permitting processes and construction can take years to complete. Advanced planning requires that computer models be used to evaluate the transmission system in future years taking into account the planned uses of the system, generation and load forecasts, and planned transmission facilities. On an annual basis, the Companies Transmission Planning Group performs analyses to determine the reliability and economic performance needs of the Companies portion of the interconnected transmission system. The projects developed are included in the Long Term Transmission Plan10 (LTTP) for submission to the MISO Transmission Expansion Planning (MTEP) process as part of a bottomup planning process for MISOs consideration and review. The LTTP consists of transmission projects planned to be inservice in an ensuing 10year planning period. The projects included in the LTTP serve several purposes: to serve specific customer needs, to provide economic benefit to customers, to meet NERC TPL reliability standards, to facilitate incremental block load additions, and to enable transmission service to be sold and generators to interconnect to the electric grid.
With regard to transmission planning aimed at providing economic benefit to customers, the Companies have played, and will continue to play, an integral role in MISOs topdown regional economic planning process referred to as the Market Congestion Planning Study (MCPS),
which is a part of the MTEP process. MISOs MCPS relies on the input of transmission owners and other stakeholders, both with regard to the assumptions and scenarios utilized in the analysis and the proposed projects intended to bring economic value to customers. Based on this stakeholder input, MISO evaluates the economic benefits of the submitted transmission projects, while ensuring continued reliability of the system. The intended result of the MCPS is a project or set of projects determined to be economically beneficial to customers and that is therefore submitted to the MISO Board of Directors for approval.
The Companies continued involvement in the MCPS began with the 2014 process and the Companies submission of a collection of projects for MISOs review. The result of the 2014 MCPS included the approval of a portfolio of four projects in southeast Louisiana, called the Louisiana Economic Transmission Project (LETP).11 The LETP was identified following a substantial amount of economic analyses performed by the Companies and MISO and is an example of the type of economic planning the Companies anticipate will continue as a part of MISO participation. The LETP, which the Companies presented to the Commission in a certification filing pursuant to LPSC General Order No. R26018, is anticipated to provide 10 The Companies most recent LTTP is included in Appendix D.
11 The MCPS also resulted in the identification of two economically beneficial projects in EAIs service territory, which were approved by the MISO Board of Directors.
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customers with benefits exceeding six times its estimated cost of $56.3 million - benefits that are directly related to the Companies participation in the MISO market.12 Additionally, EGSL recently filed an Application for certification pursuant to LPSC General Order No. R26018 for a portfolio of four transmission projects referred to as the Lake Charles Transmission Project (LCTP).13 Entergy Services, Inc. (ESI) and MISO have determined that the LCTP is the most effective project to meet the reliability needs of the Lake Charles area and will be necessary to serve the forecasted load growth there by the summer of 2018. The portfolio of transmission projects that comprise the LCTP is currently estimated to cost up to
$187 million and will provide the injection of a new 500 kilovolt (kV) transmission source into the area.
There are approximately 200 projects in the current LTTP, located throughout the four states of the Entergy service footprint, with approximately 80 projects planned for the state of Louisiana.
Area Planning Although resource planning is performed with the goal of meeting the planning objectives at the overall lowest reasonable supply cost, physical and operational factors dictate that regional reliability needs must be considered when planning for the reliable operation within the area.
Thus, one aspect of the planning process is the development of planning studies to identify supply needs within specific geographic areas, and to evaluate supply options to meet those needs.
12 Joint Application Of Entergy Gulf States Louisiana, L.L.C. And Entergy Louisiana, LLC For Certification Of The Louisiana Economic Transmission Project In Accordance With Louisiana Public Service Commission General Order Dated October 10, 2013, filed April 21, 2015, LPSC Docket No. U33605.
13 Application Of Entergy Gulf States Louisiana, L.L.C. For Certification Of The Lake Charles Transmission Project In Accordance With Louisiana Public Service Commission General Order Dated October 10, 2013, filed June 16, 2015, LPSC Docket No. U33645.
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Figure 1: Map of Louisiana Planning Areas For planning purposes, the region served by the Companies is divided into three major planning areas and one subarea. These areas are determined based on characteristics of the electric system including the ability to transfer power between areas as defined by the available transfer capability, the location and amount of load, and the location and amount of generation. The three major planning areas and subarea are listed below:
- West of the Atchafalaya Basin (WOTAB) - the area generally west of the Baton Rouge metropolitan area.
- Amite South - the area generally east of the Baton Rouge metropolitan area to the Mississippi state line, and the area south to the Gulf of Mexico.
- Downstream of Gypsy (DSG) - a subarea encompassing the Southeast portion of Amite South, generally including the area down river of the Little Gypsy plant including metropolitan New Orleans south to the Gulf of Mexico.
- Central - the remainder of Louisiana north of the WOTAB and Amite South areas, including the Baton Rouge metropolitan area.
As described later in this report, separate assessments of the Amite South and WOTAB planning areas indicate a need for additional resources in those planning areas early in the next decade.
The near term needs are largely driven by the increase in load resulting from the Louisiana 12
industrial renaissance and expiring PPAs, but resource needs over the planning horizon are also significantly influenced by unit deactivations.
PART 2: ASSUMPTIONS Technology Assessment As part of this IRP process, a 2014 Technology Assessment was prepared to identify potential supplyside resource alternatives that may be technologically and economically suited to meet customer needs. The initial screening phase of the Technology Assessment reviewed the supplyside generation technology landscape to identify resource alternatives that merited more detailed analysis. During the initial phase, a number of resource alternatives were eliminated from further consideration based on a range of factors including technical maturity, stage of commercial development, and economics. These resource alternatives will continue to be monitored for possible future development. The following resource alternatives were found appropriate for further analysis:
Pulverized CoalSupercritical Pulverized Coal with carbon capture (PC with CC)
Natural Gas Fired alternatives o Simple Cycle Combustion Turbines (CT) o Combined Cycle Gas Turbines (CCGT) o Small Scale Aeroderivatives o Large Scale Aeroderivatives Nuclear - (Generation III Technology)
Renewables o Biomass o On shore Wind Power o Solar Photovoltaic (PV)
Upon completion of the screening level analysis, more detailed analysis (including revenue requirements modeling of remaining resource alternatives) was conducted across a range of operating roles and under a range of input assumptions. The analysis resulted in the following conclusions:
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Among conventional generation resource alternatives, CCGT and CT technologies are the most attractive. The gasfired alternatives are economically attractive across a range of assumptions concerning operations and input costs.
New nuclear and new coal alternatives are not economically attractive nearterm options relative to gasfired technology. The low price of gas and the uncertainties around emissions regulation make coal technologies unattractive. Nuclear is currently unattractive due to both capital and regulatory requirements.
Despite recent declines in the capital cost and improvements of renewable generation alternatives, they are still less economically attractive compared to CCGT and CT alternatives due to:
o Declines in the longterm outlook for natural gas prices brought on by the shale gas boom; o Uncertainty about the renewal of production tax credits and investment tax credits that are applicable to resources completed before the end of 2016; and o The uncertain nearterm outlook for emissions regulation.
Among renewable generation alternatives, wind and solar are the most likely to become cost competitive. However, uncertainties with respect to various renewable generation tax credit extensions, capacity credits allowed for these resources by MISO, and implementation and timing of CO2 regulations for fossil fuel resource alternatives likely will affect the competitiveness of renewable resource alternatives. MISO determines the capacity value for wind generation based on a probabilistic analytical approach. The application of this approach resulted in a capacity value of approximately 14.1% for the 201415 planning year. Furthermore, the footprint of the Companies is not favorable for wind generation. The transmission cost to serve load with wind power from remote resources will further worsen the economics of wind compared to conventional resources. In MISO, solar resources receive no capacity credit within the first year of operation. Solarpowered resources must submit all operating data for the prior summer with a minimum of 30 consecutive days to have their capacity registered with MISO.
Table 1 summarizes the results of the Technology Assessment for a number of resource alternatives.
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Table 1: 2014 Technology Sensitivity Assessment Based on Generic Cost of Capital14 No CO2 ($/MWh) CO2 Beginning 2023 ($/MWh)
Capacity Reference Reference Technology High Fuel Low Fuel High Fuel Low Fuel Factor15 Fuel Fuel F Frame CT 10% $198 $224 $179 $204 $230 $184 F Frame CT w/ Selective Catalytic Reduction 20% $141 $167 $121 $146 $173 $126 E Frame CT 10% $240 $274 $215 $247 $281 $222 Large Aeroderivative CT 40% $108 $131 $91 $113 $136 $95 Small Aeroderivative CT 40% $125 $150 $106 $130 $156 $112 Internal Combustion 40% $115 $137 $99 $120 $141 $104 2x1 F Frame CCGT 65% $79 $97 $67 $83 $100 $70 2x1 F Frame CCGT w/ Supplemental 65% $75 $93 $61 $78 $97 $65 2x1 G Frame CCGT 65% $76 $93 $63 $79 $96 $67 2x1 G Frame CCGT w/ Supplemental 65% $72 $90 $59 $76 $94 $63 1x1 F Frame CCGT 65% $82 $100 $69 $86 $104 $73 1x1 J Frame CCGT 65% $73 $90 $61 $77 $93 $65 1x1 J Frame CCGT w/ Supplemental 65% $72 $132 $59 $76 $136 $63 Pulverized Coal w/ Carbon Capturing Sequestration 85% $163 $230 $94 $165 $232 $96 Biomass 85% $175 $321 $142 $175 $321 $142 Nuclear 90% $157 $169 $157 $157 $169 $157 Wind16 34% $109 $109 $109 $109 $109 $109 Wind w/ Production Tax Credit 34% $102 $102 $102 $102 $102 $102 Solar PV (fixed tilt)17 18% $190 $190 $190 $190 $190 $190 Solar PV (tracking)18 21% $179 $179 $179 $179 $179 $179 Battery Storage19 20% $217 $217 $217 $217 $217 $217 14 A general discount rate (7.656%) was used in order to accurately model these resources in the Market Modeling stage of the IRP.
15 Assumption used to calculate life cycle resource cost.
16 Includes capacity matchup cost of $18.76/MWh due to winds 14.1% capacity credit in MISO.
17 Includes capacity matchup cost of $30.93/MWh assuming a 25.0% capacity credit in MISO.
18 Includes capacity matchup cost of $26.51/MWh assuming a 25.0% capacity credit in MISO.
19 Includes cost of $25/MWh required to charge batteries.
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DemandSide Alternatives The Companies engaged the services of ICF International to assess the marketachievable potential for Demand Side Management (DSM) programs that could be deployed over the planning horizon. In total, 1,097 measures were evaluated, of which 896 were considered cost effective with a Total Resources Cost (TRC) test result of 1.0 or better. These measures were then collected into 24 DSM programs to be assessed in the IRP process. The Potential Study estimated the peak load, annual energy reduction, and program costs that result from a low, reference, and high level of spending on program incentives. The reference case estimate of DSM potential indicates approximately 673 MW of peak demand reduction could be achieved by 2034 if the Companies investment in DSM was sustained for a 20 year period.
The methodology of the Potential Study was consistent with a primary objective to identify a wide range of DSM alternatives available to meet customers needs. In this way, the study results helped ensure that more DSM programs would be identified for further evaluation in the IRP.
DSM program costs utilized in the IRP include incentives paid to participants and program delivery costs such as marketing, training, and program administration. Program delivery costs were estimated to reflect average annual costs over the 20 year planning horizon of the DSM Potential Study. The costs reflect an assumption that over the planning horizon, program efficiencies will be achieved resulting in lower expected costs. That is, as experience is gained with current and future programs, actual cost may decrease over time. As such, actual near term costs associated with current and future programs may be higher than the assumptions used to determine the optimal costeffective level identified in the Companies Final Reference Resource Portfolio Plan. Therefore, future DSM program goals and implementation plans should reflect this uncertainty. The IRP assumptions for the DSM program cost estimates as compared to the cost of typical supplyside alternatives are included in the DSM Technical Supplement to the IRP.
16
Natural Gas Price Forecast System Planning and Operations20 (SPO) prepared the natural gas price forecast21 used in the 2015 IRP. The near term portion of the natural gas forecast is based on NYMEX Henry Hub forward prices, which serve as an indicator of market expectations of future prices. Because the NYMEX futures market becomes increasingly illiquid as the time horizon increases, NYMEX forward prices are not a reliable predictor of future prices in the longterm. Due to this uncertainty, SPO prepares a long term pointofview (POV) regarding future natural gas prices utilizing a number of expert consultant forecasts to determine an industry consensus regarding longterm prices.
The longterm natural gas forecast used in the IRP includes sensitivities for high and low gas prices to support analysis across a range of future scenarios. In developing high and low gas price POVs, SPO utilizes several consultant forecasts to determine long term price consensus.
These forecasts are shown in the Table below.
Table 2: Henry Hub Natural Gas Price Forecasts Henry Hub Natural Gas Prices Nominal $/MMBtu Real 2014$/MMBtu Low Reference High Low Reference High Real Levelized,22 $4.57 $5.77 $9.72 $3.84 $4.87 $8.17 (20152034)
Average (2015 $4.82 $6.28 $10.79 $3.66 $5.00 $8.08 2034) 20Year CAGR 2.5% 3.1% 6.2% 0.4% 1.0% 4.1%
20 System Planning and Operations is a department within ESI tasked with: (1) the procurement of fossil fuel and purchased power, and (2) the planning and procuring of additional resources required to provide reliable and economic electric service to the EOCs customers. SPO also is responsible for carrying out the directives of the Operating Committee and the daily administration of aspects of the Entergy System Agreement not related to transmission.
21 The forecast was prepared from the July 2014 gas price forecast which is the Companies latest official forecast and was included in the Companies November 3, 2014 Updated IRP Inputs filing.
22 Real levelized prices refer to the price in 2014$ where the NPV of that price grown with inflation over the 20152034 period would equal the NPV of levelized nominal prices over the 20152034 period.
17
The natural gas forecasts above do not attempt to forecast the effects of the shortterm natural gas hedging programs currently employed by the Companies. The current gas hedging program attempts to mitigate shortterm gas price volatility. However, given the short term nature of the gas hedging program, there is no effect on the longterm gas prices experienced by the Companies. The Companies have evaluated and continue to evaluate opportunities that would, on a longer term basis, help stabilize gas prices and offer the potential for savings relative to gas prices that may exist in the future. The Companies also note that the Commission has approved a longterm gas hedging pilot program in General Order No. R32975. However, no adjustments are warranted to the Companies longterm natural gas forecasts at this time. If the Commission approves any longterm gas transactions for the Companies, the expected price from such transactions will be considered in the Companies future resource planning decisions.
CO2 Assumptions At this time, it is not possible to predict with any degree of certainty whether national CO2 legislation will eventually be enacted, and if it is enacted, when it would become effective, or what form it would take. In order to consider the effects of carbon regulation uncertainty on resource choice and portfolio design, the IRP process relied on a range of projected CO2 cost outcomes. The low case assumes that CO2 legislation does not occur over the 20year planning horizon. The reference case assumes that a cap and trade program starts in 2023 with an emission allowance cost of $7.54/U.S. ton and a 20152034 levelized cost in 2014$ of
$6.83/U.S. ton.23 The high case assumes that a cap and trade program starts in 2023 at
$22.84/U.S. ton with a 20152034 levelized cost in 2014$ of $14.61/U.S. ton.
Market Modeling Aurora Model The development of the IRP relied on the AURORAxmp Electric Market Model (AURORA) to simulate market operations and produce a longterm forecast of the revenues and cost of energy procurement for the Companies.24 AURORA25 is a production cost model and resource capacity expansion optimization tool that uses projected market economics to determine the optimal longterm resource portfolio under 23 Includes a discount rate of 7.656%.
24 The AURORA model replaces the PROMOD IV and PROSYM models that the Companies previously used.
25 The AURORA model was selected for the IRP and other analytic work after an extensive analysis of electricity simulation tools available in the marketplace. AURORA is capable of supporting a variety of resource planning 18
varying future conditions including fuel prices, available generation technologies, environmental constraints, and future demand forecasts. AURORA estimates price and dispatch using hourly demands and individual resourceoperating characteristics in a transmissionconstrained, chronological dispatch algorithm. The optimization process within AURORA identifies the set of resources among existing and potential future demand and supplyside resources with the highest and lowest market values to produce economically consistent capacity expansion. AURORA chooses from new resource alternatives based on the net real levelized values per MW (RLV/MW) of hourly market values and compares those values to existing resources in an iterative process to optimize the set of resources.
Scenarios26 IRP analytics relied on four scenarios designed to assess alternative portfolios across a range of outcomes. The four scenarios are:
- Industrial Renaissance (Reference) - Assumes the U.S. energy market (particularly as it affects the Gulf Coast region and Louisiana) continues with reference fuel prices.
Current fuel prices drive considerable load growth and economic opportunity especially in the industrial class. The Industrial Renaissance scenario assumes reference load, reference gas, and no CO2 costs.
- Business Boom - Assumes the U.S. energy boom continues with low gas and coal prices.
Low fuel prices drive high load growth especially in the industrial class, but with residential and commercial class spillover benefits. As a result of the industrial load growth and low fuel prices, power sales increase significantly. A modest CO2 tax or cap and trade program is implemented and is effective in 2023.
- Distributed Disruption - Assumes states continue to support distributed generation.
Consumers and businesses have a greater interest in installing distributed generation, which leads to a decrease in energy demand. Overall economic conditions are steady with moderate GDP growth, which enables investment in energy infrastructure.
However, natural gas prices are driven higher by EPA regulation of hydraulic fracturing.
Congress or the EPA also implements a moderate CO2 tax or cap and trade program.
activities and is well suited for scenario modeling and risk assessment modeling. It is widely used by load serving entities, consultants, and independent power producers.
26 The four scenarios and their general assumptions have remained constant throughout the IRP process. However, in the November 2014 filing, two of the scenarios were renamed from the May 2014 filing. Scenario One was renamed Industrial Renaissance. The Industrial Renaissance Scenario in the May 2014 was renamed Business Boom in the November 2014 filing.
19
- Generation Shift - Assumes government policy and public interest drive support for government subsidies for renewable generation and strict rules on CO2 emissions. High natural gas exports and more coal exports lead to higher fuel prices.
Each scenario was modeled in Aurora. The resulting market modeling, which included projected power prices, provided a basis for assessing the economics of longterm (here, twenty years) resource portfolio alternatives.
Table 3: Summary of Key Scenario Assumptions Summary of Key Scenario Assumptions Industrial Distributed Generation Renaissance Business Boom Disruption Shift (Ref. Case)
Electricity CAGR
~1.45% ~1.70% ~0.90% ~1.20%
(Energy GWh)27 Peak Load Growth
~1.05% ~1.10% ~0.75% ~0.85%
CAGR Henry Hub Natural Reference Case Low Case Reference Case High Case Gas Price ($/MMBtu) ($4.87 levelized ($3.84 levelized ($4.87 levelized ($8.17 levelized 2014$) 2014$) 2014$) 2014$)
CO2 Price ($/short Reference Case:
Cap and trade Cap and trade ton) Cap and trade Low Case: starts in 2023 starts in 2023 starts in 2023 None $6.83 levelized $14.61 levelized
$6.83 levelized 2014$ 2014$
2014$
PART 3: CURRENT FLEET & PROJECTED NEEDS Current Fleet Currently, the Companies together control approximately 10,561 MW of generating capacity either through ownership or longterm power purchase contract. Appendix A provides an overview of the Companies current active generation portfolio. Table 4 shows the supply resources by fuel type measured in installed MW with percentages for ELL and EGSL separately and for the combined company. It is important to note that some of the amounts below represent resources that are not owned by the Companies but instead are under contract through PPAs. As reflected on Table 4 and Appendix A, roughly onehalf of the current combined resource portfolios are from legacy gas generation which has been inservice for 40 27 All compound annual growth rates (CAGRs) in this table: 20152034 (20 Years) for the market modeled in AURORA.
20
60 years. While the Companies have made and will continue to make economic investments to extend the service life of these generators, many of these generators are assumed to deactivate over the planning horizon and these unit deactivations are a significant driver of the Companies need for additional generation regardless of any assumed load growth.
Table 4: 2014 EGSL and ELL Combined Resource Portfolio 2014 EGSL and ELL Combined Resource Portfolio ELL EGSL Combined MW % MW % MW %
Coal 32 1 367 9 399 4 Nuclear 1,609 24 390 9 1,999 19 Combined Cycle Gas 1,289 20 1,036 26 2,325 22 Turbine (CCGT)
Other Gas 3,479 53 2,173 54 5,652 54 Hydro & Other 125 2 61 2 186 2 Total 6,534 4,027 10,561 28 In addition, the Companies added a new CCGT facility, Ninemile 6, to the portfolio in December 2014. Ninemile 6 is a 561 MW CCGT resource located in Westwego, Louisiana at the Ninemile Point Station in Jefferson Parish. The Companies received Commission approval to construct this new CCGT generating facility, the currently estimated cost of which is $655 million.29 Load Forecast A wide range of factors likely will affect electric load in the longterm, including:
- Levels of economic activity and growth;
- The potential for technological change to affect the efficiency of electric consumption;
- Potential changes in the purposes for which customers use electricity (e.g., the adoption of electric vehicles);
28 Total resources include the addition of Ninemile 6.
29 Ex Parte: Joint Application of Entergy Louisiana, LLC for Approval to Construct Unit 6 at Ninemile Point Station and of Entergy Gulf States Louisiana, L.L.C. for Approval to Participate in a Related Contract for the Purchase of Capacity and Electric Energy, for Cost Recovery and Request for Timely Relief, Order No. U31971 (April 5, 2012).
21
- The potential adoption of enduse (behindthemeter) selfgeneration technologies (e.g., rooftop solar panels); and
- The level of energy efficiency, conservation measures, and distributed generation (e.g., rooftop solar panels) adopted by customers.
Such factors may affect both the level and shape of load in the future. Peak loads may be higher or lower than projected levels. Similarly, industrial customer load factors may be higher or lower than currently projected. Uncertainties in load may affect both the amount and type of resources required to efficiently meet customer needs in the future.
In order to consider the potential implications of load uncertainties on longterm resource needs, four load forecast scenarios were prepared for the IRP, which are described below:
Industrial Renaissance - Reference load Assumes Industrial Renaissance will have a multiplier effect that will spur load growth in residential, commercial, and government classes (referred to as an economic multiplier) and includes additional industrial growth stemming from the regional Industrial Renaissance.
Business Boom Assumes higher economic multiplier effect, a lower risk adjustment to future industrial projects, and an increase in the number of industrial projects that are included in forecast.
Distributed Disruption Decrements the Reference load scenario for Combined Heat and Power (CHP) impact and distributed solar photovoltaic system (PV) impact.
Generation Shift Assumes no economic multiplier effect, no commercial conversions, and fewer industrial projects.
Methodology SPO used the same load forecasting process as described in previous IRPs developed for the Companies. That process uses computer software from Itron to develop a 20year, hourby hour load forecast. The MetrixND30 and the MetrixLT'31 programs are used widely in the 30 MetrixND by ITron is an advanced statistics program for analysis and forecasting of time series data.
22
utility industry, to the point where they may be considered an industry standard for energy forecasting, weather normalization, and hourly load and peak load forecasting.
To develop the load forecast, SPO allocates the Retail Energy Forecast (by month) and the Wholesale Energy Forecast (by month) to each hour of a 20year period based on historical load shapes developed by ESIs Load Research Department. Fifteenyear typical weather is used to convert historic load shapes into typical load shapes. For example, if the actual sales for an EOCs residential customers occurred during very hot weather conditions, the typical load shape would flatten the historic load shape. If the actual weather were mild, the typical load shape would raise the historic load shape. Each customer class in each EOC responds differently to weather, so each has its own weather response function. MetrixND is used to adjust the historical load shapes by typical weather, and MetrixLT' is used to create the 20year, hourly load forecast.
The load forecast is grossed up to include average transmission and distribution line losses. The Companies have unique loss factors that are applied to each revenue class after the forecast is developed and after accounting for energy efficiency. For example, when line losses are added into the Companies forecasts ELLs residential class is grossed up by a different amount than EGSLs residential class.
Cogeneration loads are included in the Industrial revenue class and a separate peak is not developed for these customers as their loads can be irregular. Econometric models are used to develop the energy forecast for cogeneration loads which are then combined with both large and small industrial customers to create the Industrial energy forecast. Interruptions are in historical data that the forecast models use, but customer specific interruptions are not forecasted as the interruptions are irregular.
Energy savings from companysponsored DSM programs are decremented from the Retail energy forecast. The load forecast uses the decremented energy forecast to develop annual peaks that reflect the savings from such programs.
Resource Needs Over the IRP period, the Companies will need to add resources. The longterm resource needs are primarily driven by load growth expectations, unit deactivation assumptions, and existing PPA contract terminations and expirations. For the purpose of developing this IRP, assumptions must be made about the future of generating units currently in the portfolio.
31 MetrixLT' by ITron is a specialized tool for developing medium and long run load shapes that are consistent with monthly sales and peak forecasts.
23
Assumptions made for the IRP are not final decisions regarding the future investment in resources. Unitspecific portfolio decisions, such as sustainability investments, environmental compliance investments, or unit retirements, are based on economic and technical evaluations considering such factors as projected forward costs, anticipated operating roles, and the cost of supply alternatives. These factors are dynamic, and as a result, actual decisions may differ from planning assumptions as greater certainty is gained regarding requirements of legislation, regulation, and relative economics.
Based on current assumptions, a number of the Companies existing fossil generating units may be deactivated during the IRP planning period. In addition, various PPAs that the Companies have previously entered into will expire. In the years 20152034, the total net reduction in the Companies generating capacity from these assumed unit deactivations and PPA terminations and expirations is approximately 6,859 MW relative to the Companies current combined resources of approximately 10,561 MW.
Included in this amount is the effect of the termination of the PPAs entered between EGSL and ETI pursuant to the Jurisdictional Separation Plan (JSP) that led to the separation of Entergy Gulf States, Inc. into EGSL and ETI. Those PPAs are referred to herein as the JSP PPAs.32 This IRP assumes that the JSP PPAs will terminate when ETI or EGSL terminates participation in the System Agreement, as provided for in the LPSCs order regarding the JSP.33 The overall net effect would reduce EGSLs portfolio position by roughly 700 MW in 2018 based on ETIs terminating participation34 in the System Agreement on October 18, 2018.
Moreover, in the coming years, the Companies will face the need for additional resources to meet load growth. The load forecast necessarily has changed during the 18 month period in which this IRP was developed and can be expected to change in the future. As contemplated 32 As a result of the implementation of the JSP to separate Entergy Gulf States, Inc. (EGSI) into separate Texas and Louisiana companies, ETI and EGSL (successorsininterest to EGSI) currently share certain capacity in Texas and Louisiana. This capacity is shared through costbased purchases and sales made pursuant to purchased power agreements under Service Schedule MSS4 of the Entergy System Agreement. Specifically, EGSL sells to ETI 42.5%
of the capacity and related energy of the following resources: (1) Willow Glen and Nelson; (2) Calcasieu; (3)
Perryville; and (4) River Bend. ETI sells to EGSL: (1) 57.5% of the capacity and related energy associated with its Lewis Creek and Sabine resources; and (2) 50% of the capacity and related energy associated with the Carville resource. A subset of these PPAs, referred to as the JSP PPAs, will terminate upon ETIs termination of its participation in the System Agreement. These JSP PPAs include the MSS4 PPAs associated with the Willow Glen, Nelson gas, Lewis Creek, Sabine, and Calcasieu generating units. See also LPSC Order Nos. U21453, U20925, and U22092 Subdocket J, In re: Request for the Approval of the Jurisdictional Separation Plan for Entergy Gulf States, Inc., dated January 31, 2007, at 20.
33 In re: Request for the Approval of the Jurisdictional Separation Plan for Entergy Gulf States, Inc., Order Nos. U 21453, U20925 and U22092 (Subdocket J), Order at p. 20 (Jan. 31, 2007).
34 ETI provided notice to the EOCs of its intent to terminate its participation in the System Agreement effective October 18, 2018.
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by the Industrial Renaissance Scenario (reference case), the areas served by the Companies are experiencing a heightened level of economic development activity stemming from the availability of lowcost natural gas and efforts by the State of Louisiana to add jobs and grow the economy through attracting new and expanded industrial facilities. As such, in the reference case, the Companies loads are projected to reach approximately 11,200 MW by 2019 (a 15% increase over the current combined level of approximately 9,600 MW), which reflects the addition of approximately 1,600 MW of industrial facilities by 2019. By 2025, the Companies total reference load is projected to increase approximately 1,760 to 2,200 MW from the present combined level. The following Table summarizes the projected peak forecast increase for the Companies over the next 20 years (20152034) by scenario.
Table 5: ELL and EGSL Projected Peak Forecast Increase from 2015 Industrial Business Boom Distributed Generation Shift Renaissance (MWs) Disruption (MWs) (MWs)
(MWs)
By 2034 2,226 2,626 1,507 1,751 In both Amite South and WOTAB, current supply needs require local generation, yet there are limited available power sources that exist within each of the regions. Amite South is a supply constrained region that, based on projected load growth, unit retirements, and PPA expirations, may require new resources every five years in order to continue meeting reliability needs within its load pocket.35 The industrial load growth in the region further increases this need. In the Industrial Renaissance Scenario, the Amite South regions peak load is expected to grow by approximately 10% (500 MW) to a total of approximately 6,000 MW by 2019. In other words, resources need to be planned and brought online in an orderly sequence to maintain adequate capacity and stability and support the regions growing load.
Separate from the Amite South region, the WOTAB region is expected to experience significant industrial load growth under the Industrial Renaissance Scenario. EGSLs load in WOTAB is anticipated to increase by approximately 70% (800 MW) to a total of approximately 1,900 MW by 2019. A substantial portion of the expected growth in load will be centered around Lake Charles. The concentration of load within the Lake Charles area is expected to result in the creation of a load pocket within the planning region, which will require additional resources as load continues to grow.
35 Load pockets are areas of the system where local generation along with transmission import capability is needed to serve the load reliably within the area.
25
As discussed later in this report, these increases in residential, commercial, and industrial load, and unit deactivations and PPA expirations will require the Companies to add resources to meet the load and maintain reliability. There is expected to be a limited effect on customer rates, however, because of the increase in customer kWh usage over which the fixed costs of the new resources are spread, portfolio efficiency improvements, and expiration of other customer charges among other factors.
As shown in Tables 6 and 7 below, by 2034, the combination of load growth, resource deactivations and PPA contract expirations may result in approximately 9.5 GW of capacity needed for the Industrial Renaissance Scenario. By 2024, the capacity deficit could be as high as 3.6 GW under the current load forecasts and resource deactivation and expiration assumptions.
Table 6: Resource Needs by Scenario (MWs)
Capacity Surplus/(Need) (Before IRP Additions)
Industrial Distributed Generation Business Boom Renaissance Disruption Shift By 2024 (3,601) (4,039) (3,173) (2,980)
By 2034 (9,536) (9,999) (8,695) (8,913)
- Includes 12% planning reserve margin 26
ndustrial Ren Table 7: In naissance 20Year Projecte ed Capacity N Need (GW)
There are e a number of alternativves to address the resouurce needs, including:
In ncremental longterm re esource addiitions includ ing:
o SelfSupply altern natives o Acquisitions o Long Term PPAs and a renewals Demand D Sidee alternativess Shortterm capacity c pu urchases in MISO Pla nning Reso ource Auctio on or bilaateral trransactions.
Types ofo Resource es Needed d In order to reliably meet the power p needss of custommers at the lowest reassonable costt, the Companiies must maaintain a portfolio of ge eneration reesources thaat includes tthe right am mount and type es of capacitty. With resspect to the amount of capacity, th he Companiees must maintain sufficientt generatingg capacity to meet their peak loadds plus a planning reseerve margin n. As described d above, thee Companiess need to plaan for resouurces to meeet the annuaal reserve m margin 27
mandated by MISO, which is assumed to be 12% for longterm planning. In general, the Companies supply role needs include:
Base Loadexpected to operate in most hours.
LoadFollowingcapable of responding to the timevarying needs of customers.
Peaking and Reserveexpected to operate relatively few hours, if at all.
Table 8: Projected Resource Needs in 2034 by Supply Roles (without Planned Additions) in Industrial Renaissance Scenario Surplus/
Need Resources (Deficit)
Base Load (MW) 7,948 2,399 (5,549)
Load Following (MW) 2,257 1,270 (987)
Peaking & Reserve (MW) 3,341 341 (3,000)
Totals 13,546 4,010 (9,536)
Table 8 shows that for both Companies, the supply role with the greatest need is base load.
Peaking resources will also be needed within the 20 year planning horizon.
PART 4: PORTFOLIO DESIGN ANALYTICS The IRP utilized a twostep approach to construct and assess alternative resource portfolios to meet the customer needs:
- 1. Market Modeling
- 2. Portfolio Design & Risk Assessment Market Modeling The first step to develop within the AURORA model is a projection of the future power market for each of the four scenarios. This projection looks at the power market for the entire MISO footprint excluding Louisiana to gain perspective on the broader market outside the state. The purpose of this step was to provide projected power prices to assess potential portfolio strategies within each scenario. In order to achieve this, assumptions were required about the future supply of power. The process for developing those assumptions relied on the AURORA 28
Capacity Expansion Model to identify the optimal set of resource additions in the market to meet reliability and economic constraints. Resulting assumptions regarding new capacity additions in each scenario are summarized in Table 9.
Table 9: Results of MISO Market Modeling Results of MISO Market Modeling (MISO Footprint, excluding Louisiana)
Incremental Capacity Mix by Scenario Industrial Business Distributed Generation Renaissance Boom Disruption Shift (Ref. Case)
CCGT 52% 91% 98% 53%
CT 48% 9% 2% 1%
Wind 0% 0% 0% 31%
Solar 0% 0% 0% 0%
Year of First Addition 2020 2020 2020 2020 Total GWs Added (through 2034) 117 127 73 226 Results of the Capacity Expansion Modeling that supported conclusions from the Technology Assessment, as discussed earlier, were reasonably consistent across scenarios. These results, as summarized below, are the output of the model based on the market conditions that the model analyzed:
In general, new build capacity is required to meet overall reliability needs.
Gasfired, CTs and CCGTs, are the preferred technologies for new build resources in most outcomes.
The model did not select new nuclear or new coal for any scenario.
The model did not select solar PV or biomass for any scenario.
Wind generation has a significant role in only one of the scenarios that involves high gas and carbon prices.
Portfolio Design & Risk Assessment The AURORA Capacity Expansion Model analyzes least cost portfolios to meet the Companies resource needs using the screened demand and supplyside resource alternatives. Through this 29
analysis, the Companies sought to assess the relative performance of the highest ranking resource alternatives from the screening assessments when included with the Companies existing resources and to test their performance across a range of outcomes as provided by the scenarios. This analysis seeks to identify the portfolio that produces the lowest total supply cost to meet the identified needs, but does not take into account rate design or rate effects.
In total, four portfolios (described below) were constructed and assessed. The AURORA Capacity Expansion Model was used to develop a portfolio for each of the scenarios in a two step process, which first assessed DSM programs, and then supplyside alternatives. DSM programs were evaluated first without consideration of supplyside alternatives by allowing the AURORA Capacity Expansion Model to determine which of the DSM programs may be able to provide capacity and energy benefits in excess of their costs. All economic DSM programs were included in each portfolio.36 Once the level of economic DSM was determined within each scenario/portfolio combination, the AURORA Capacity Expansion Model was used to identify the most economic level and type of supplyside resources needed to meet reliability requirements. The result of this process was an optimal portfolio for each scenario consisting of both DSM and supplyside alternatives.
Table 10: Portfolio Design Mix Portfolio Design Mix IR Portfolio BB Portfolio DD Portfolio GS Portfolio DSM Programs 18 Programs 14 Programs 16 Programs 20 Programs DSM 497 407 539 467 Maximum (MWs)37 CTs/CCGTs 7,348 8,404 6,876 6,512 (MWs)
Wind (MWs) 0 0 0 4,00038 36 In evaluating the economics of DSM programs, the model evaluates the cost and benefit of the DSM programs, but does not take into consideration ratemaking and policy issues implicated by DSM programs, which must be appropriately addressed as part of DSM implementation.
37 Demand Side Management (DSM) total is grossed up for Planning Reserve Margin (12%) and transmission losses (2.4%).
38 Wind was limited to 20 resources annually at 200 MWs each, which provides 564 MW of capacity credit based on MISOdetermined wind capacity credit of 14.1%.
30
Each portfolio was modeled in AURORA and tested in the four scenarios described earlier for a total of 16 cases. The results of the AURORA simulations were combined with the fixed costs of the incremental resource additions to yield the total forward revenue requirements excluding sunk costs of the portfolio. The total forward revenue requirement results and rankings by scenario are provided in the following tables.
Table 11: PV of Forward Revenue Requirements by Scenario39 40 PV of Forward Revenue Requirements ($B) (20152034)
IR Scenario BB Scenario DD Scenario GS Scenario Industrial Renaissance $36.0 $32.5 $36.1 $46.4 Portfolio Business Boom Portfolio $36.2 $32.2 $36.3 $46.3 Distributed Disruption $36.0 $32.2 $36.2 $46.3 Portfolio Generation Shift Portfolio $37.9 $35.1 $37.4 $43.1 The revenue requirements shown above include the total cost to serve total load over the 20 year planning period. It is important to note that the revenue requirements shown are reflective of the total fuel costs and the incremental resource cost to deliver the portfolios under different scenarios and are not reflective of customer rate effects as they do not consider changes in load and other factors affecting rates.
Table 12, below, breaks down the forward revenue requirements for each portfolio in the Industrial Renaissance Scenario (the first column of Table 11) into the component costs. The pie charts show the percentages of incremental fixed, variable, and DSM costs of the total PV forward revenue requirements shown in Table 11.
39 The forward revenue requirements are intended to provide the best available estimate of overall portfolio cost given the long term nature of the IRP process and the fact that customer class bill and rate effects will be determined through certification proceedings associated with particular resources.
40 The table reflects the correct input of nominal DSM program costs as opposed to levelized DSM program costs.
31
Table 12: Portfolios byy Cost Compo onents in the Industrial Reenaissance Sccenario (2015 52034)41 42 433 The columns in Table 13, below w, show the rankings off each of thee four modeeled portfoliios in each of the scenarioss.
41 Variable cost represents the load payyment net of generation g eneergy margins.
42 Incremental fixed cost is the fixed co ost revenue req quirement of thhe incrementaal supplyside rresource additiions in each portfolio.
43 The table reflects the correct c input of o nominal DSM M program costts as opposed to levelized DSSM program co osts.
32
Table 13: Portfolio Ranking by Scenario Portfolio Ranking by Scenario (20152034)
IR Scenario BB Scenario DD Scenario GS Scenario Industrial Renaissance 1 3 144 4 Portfolio Business Boom Portfolio 3 145 3 3 Distributed Disruption 2 2 2 2 Portfolio Generation Shift Portfolio 4 4 4 1 The next step was to perform sensitivity analyses on each portfolio by adjusting one variable at a time46 and computing the PV of forward revenue requirements. Each portfolio was tested across the range of assumptions for:
Natural Gas Prices Coal Prices Capital Cost for New Generation General Inflation and Resulting Cost of Capital CO2 Costs Natural Gas Prices and CO2 Costs Combinations 44 Total supply cost for the Industrial Renaissance Portfolio was lower than the Distributed Disruption Portfolio; however, the difference was not significant (0.3%) and the variable supply cost of the Distributed Disruption Portfolio was lower.
45 As with Tables 11 and 12 above, this table reflects the correct input of nominal DSM program costs as opposed to levelized DSM program costs. This correction resulted in the Business Boom Portfolio having the lowest total supply cost in the Business Boom Scenario.
46 A combination of natural gas prices and CO2 costs involved adjustment of two variables at the same time.
33
The rangge of total forward revenuer reqquirements results by portfolio in the Indu ustrial Renaissance Scenario o is provided d in the follo owing five taables.
Table 14: Natural Gas Sensitivity in n the Industrial Renaissancce Scenario 34
Table 15: CO2 Price Se ensitivity in th he Industrial Renaissance Scenario Table 16: Natural Gas and CO2 Com mbination Sen nsitivity in th e Industrial Renaissance SScenario 35
Table 17: Cost of Capittal Sensitivityy in the Indusstrial Renaisssance Scenariio Table 18: Installed Cosst Sensitivity in the Industtrial Renaissaance Scenarioo 36
Results of the sensitivity assessments indicate that the installed cost, cost of capital, and coal prices47 have less of an impact on the variability of total forward revenue requirements results across all portfolios in comparison to natural gas prices, CO2 prices, and the combination of natural gas price and CO2 price. The Industrial Renaissance, Business Boom, and Distributed Disruption portfolios are similarly sensitive to natural gas prices, CO2 prices, and the combination of natural gas and CO2 prices, whereas the Generation Shift portfolio is relatively less sensitive to these variables. Conversely, the Generation Shift portfolio is more sensitive to installed cost and cost of capital as compared to the Industrial Renaissance, Business Boom, and Distributed Disruption portfolios. This is a result of the Generation Shift portfolios higher incremental fixed costs relative to the other three portfolios, which is indicated in the accompanying Table. Results of the sensitivity analysis are consistent with the resource type and amount that comprise each of the portfolios.
Summary of Findings and Conclusions Results of the scenario assessment indicate:
Supplyside economics were consistent with technology screening analysis.
Some level of DSM was economic48 in every scenario.
Renewables are not economic under most assumptions. Renewable resources depend on high gas and carbon prices to be economic relative to CT and CCGT resources.
CT and CCGT resources perform well across most scenarios. The choice between CCGT and CT technologies is sensitive to external factors as demonstrated by the narrow range of outcomes for the portfolios comprised primarily of these resources.
47 Coal price sensitivity results are not shown in the sensitivity charts because coal resources are not added as a new resource to any of the portfolios and the existing resource portfolio only has approximately 4% of coal resources.
48 See note 32, supra.
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PART 5: FINAL REFERENCE RESOURCE PLAN & ACTION PLAN Final Reference Resource Plan The IRP process resulted in the identification of a Final Reference Resource Plan that represents the Companies best available strategy for meeting customers longterm power needs at the lowest reasonable supply cost, while considering reliability and risk. The Final Reference Resource Plan is based on the following assumptions:
The industrial renaissance underway in Louisiana, coupled with residential and commercial load growth, is driving significant growth in utility load with up to 1,600 MW of industrial load growth expected in the Companies service areas through 2019. By 2034, the Companies expect to require at least 8,000 MW of additional capacity to meet demand.
For purposes of planning capacity, the Companies have assumptions regarding the deactivation of approximately 5,950 MW of older gas fired steam generators over the planning period. This aging fleet is increasingly susceptible to accelerated deactivation as decisions are made regarding unit economics associated with unexpected maintenance costs and ongoing evaluation of unit availability. Actual decisions to continue to invest in and operate these units have not been made and will be subject to ongoing assessments of economics and technical feasibility.
In order to reliably meet the power needs of their respective customers at the lowest reasonable cost, the Companies will maintain a portfolio of generation resources that includes the right amount and types of capacity.
o With respect to the amount of capacity, the Companies must maintain sufficient generating capacity to meet their peak loads plus a planning reserve margin. The Companies will plan resources to a 12% reserve margin. The Companies will need to add capacity for three reasons: 1) to meet load growth; 2) to replace existing resources that will reach the end of their useful lives (unit deactivations);
and 3) to replace PPAs that will expire.
o With respect to the type of capacity, the Companies seek to add modern, efficient generating capacity, which will predominantly be CCGTS and CTs.
38
The Companies will continue to meet the bulk of their reliability requirements with either owned assets or longterm PPAs. The emphasis on longterm resources mitigates exposure to capacity price volatility and ensures the availability of resources sufficient to meet longterm reliability needs.
A portion of reliability requirements may be met through a reasonable reliance on limitedterm power purchase products including zonal resource credits, to the extent these are economically available when considering risk.
Some level of DSM is considered economically attractive but presents ratemaking and policy issues that must be addressed in connection with adoptions of such programs. A variety of factors, many of which are highly uncertain, will affect the amount of DSM that can and will be achieved over the planning horizon.
All existing coal and nuclear units will continue operating throughout the planning horizon. All nuclear units are assumed to receive license extensions from the Nuclear Regulatory Commission (NRC) to operate up to 60 years.
New build capacity, when needed in 2020 and beyond, comes from a combination of CT and CCGT resources. New build capacity may be obtained through owned resources or longterm power purchase contracts. For the purpose of preparing the IRP, the economics were assumed to be equivalent.
No new solid fuel capacity is added, and new nuclear development remains in the monitoring phase.
Renewable resources are not economically attractive relative to conventional gas turbine technology (whether in simple or combined cycle) as solely a capacity resource.
However, renewable cost and performance - in particular, solar - continues to improve as a source of zero emission generation. Due to potential state and federal incentives, potential environmental requirements, and as general cost and technology performance improve, it is conceivable that the Companies and their customers could incorporate solar or other intermittent, renewable resources at distributed or utility scale magnitude. These possibilities warrant further analysis.
The Final Reference Resource Plan shown in Table 19 includes assumptions regarding future major resource additions, such as the Union Power acquisition, the 2020 Amite South CCGT, 39
2020 WOTAB CTs, and the 202021 WOTAB CCGT, as well as assumptions regarding implementation of costeffective DSM programs. The actual resources deployed (including the amount and timing of technology and power purchase products) and DSM implemented, will depend on factors which may differ from assumptions used in the development of the IRP. Such long term uncertainties include, but are not limited to:
Load growth (magnitude and timing), which will determine actual resource needs The relative economics of alternative technologies, which may change over time Environmental compliance requirements Practical considerations that may constrain the ability to deploy resource alternatives such as the availability of adequate sources of capital at reasonable cost Condition of existing units and ongoing assessments of those units There are two important points to consider when reviewing the Final Reference Resource Plan.
First, the decision to procure a given resource will be contingent upon a review of available alternatives at that time, including the economics of any viable transmission alternatives available that would be coupled with a purchase of capacity and/or energy. In addition, the decision to procure a specific resource in a specific location must reflect the specific lead time for that type of resource, which will vary by resource type, and the time required for obtaining regulatory approvals. By deferring specific resource decisions until deployment is needed, the Companies retain the flexibility to respond to changes in circumstance up to the time that a commitment is made.
Second, a variety of factors, many of which are highly uncertain, will affect the amount of DSM that can and will be implemented over the planning horizon. DSM assumptions, including the level of costeffective DSM identified through the IRP process, are not intended as definitive commitments to particular programs, program levels or program timing. The implementation of costeffective DSM requires consistent, sustained regulatory support and approval. The Companies investment in DSM must be supported by a reasonable opportunity to timely recover all of the costs, including lost contribution to fixed cost, associated with those programs. It is important that appropriate mechanisms be put into place to ensure the DSM potential actually accrues to the benefit of customers and that utility investors are adequately compensated for their investment through opportunity to earn performancebased incentives.
40
Table 19: Final Reference Resource PlanLoad & Capability 20152034 (All values in MW)
Load & Capability 20152034 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 Requirements Peak Load 9,869 10,081 10,495 10,896 11,172 11,090 11,162 11,231 11,303 11,376 11,452 11,526 11,599 11,672 11,743 11,811 11,882 11,952 12,024 12,095 Reserve Margin (12%) 1,184 1,210 1,259 1,307 1,341 1,331 1,339 1,348 1,356 1,365 1,374 1,383 1,392 1,401 1,409 1,417 1,426 1,434 1,443 1,451 49 Total Requirements 11,053 11,290 11,754 12,203 12,513 12,421 12,502 12,578 12,659 12,741 12,826 12,909 12,991 13,073 13,152 13,229 13,308 13,387 13,466 13,546 Resources Existing Resources 50 Owned Resources 9652 9549 9549 8826 8826 8814 8814 8688 8688 8688 8688 8277 7616 7616 7095 6528 5571 4419 3702 3702 PPA Contracts 909 909 866 386 386 386 386 144 144 144 144 144 144 144 144 144 39 9 LMRs 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 308 Identified Planned Resources 51 Union 816 816 816 816 816 816 816 816 816 816 816 816 816 816 816 816 816 816 816 52 Amite South CCGT 560 560 560 560 560 560 560 560 560 560 560 560 560 560 560 Other Planned Resources 53 DSM 19 44 77 105 151 220 266 299 329 334 403 413 414 471 457 532 539 423 456 538 CTs (2) 388 388 388 388 388 388 388 388 388 388 388 388 388 388 388 CCGT 1 764 764 764 764 764 764 764 764 764 764 764 764 764 764 764 CCGT 2 764 764 764 764 764 764 764 764 CCGT 3 764 764 764 764 764 764 764 CCGT 4 764 764 764 764 764 764 CCGT 5 764 764 764 764 764 CCGT 6 764 764 764 764 CCGT 7 764 764 CCGT 8 764 Market Purchase 165 138 1,762 2,026 165 200 611 663 739 755 1,239 1,218 478 328 133 503 1,881 1,889 1,122 Total Resources 11,053 11,625 11,754 12,203 12,513 12,421 12,502 12,578 12,659 12,741 12,826 12,909 12,991 13,073 13,152 13,229 13,308 13,387 13,466 13,546 49 Total load requirement adjusts for the peak load diversity between the two companies.
50 The JSP PPAs are included in the Owned Resources row.
51 Union plant acquisition is completed pending regulatory approvals. 816 MW is two trains of the facility less 20% allocation to ENO. Given changes to the ownership of the other trains, it is expected that EGSL will retain 100% of its two trains.
52 ELL/EGSL share of Amite South RFP is presently estimated at 560 MW. RFP responses are currently being evaluated; actual capacity of selected resource could range between 650 to 1,000 MW and a portion of that capacity may be shared with another Entergy operating company. As a result, actual capacity may exceed 560 MW. Given changes to the ownership of the other trains, it is expected that ELL/EGSL will retain 100% of the resource selected through this RFP.
53 Demand Side Management (DSM) total is grossed up for Planning Reserve Margin (12%) and transmission losses (2.4%).
41
Action Plan The Companies have developed the following Action Plan for pursuing the Final Reference Resource Plan described above over the first five years of the planning period. The Action Plan recognizes that there are numerous uncertainties that will be encountered over the 20year IRP period, the outcome of which will significantly influence the resulting supply portfolio.
Table 20: Action Plan Category Item Action to be taken SupplySide Union Obtain regulatory approval and complete the acquisition of Alternatives Acquisition Power Blocks 3 and 4 of the Union Plant near El Dorado, Arkansas. Net of a 20% PPA to ENO, Union Plant would add approximately 816 MWs to the Companies current capacity in 2016; however, given changes to the ownership of the other Union Power units, it is expected that EGSL will retain 100% of its two trains.
Renewables The energy and capacity performance of utility scale intermittent resources and locational impacts on distribution feeders of distributed renewables at the residential or small utility scale will need to be determined to reliably and economically incorporate these resources over time. Long term investments in the system operations and utility distribution infrastructure might be required to reliably interconnect these technologies at a large scale. The Companies will evaluate distributed pilot projects (<5MW) for solar and storage technology in order to assess energy and capacity based plant performance, verify forecast integration of intermittent renewables for system reliability, and evaluate distributed solar PV locational impacts and economics on distribution feeders.
Legacy Fleet Evaluate costs and benefits of investing in existing resources in order to support safe, reliable operation beyond the currently assumed deactivation dates.
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PPAs Evaluate costs and benefits of PPAs as viable alternatives to meet longterm needs.
New Resources Continue to assess the development of a CT option (approximately 380 MWs) that could be deployed in the Lake Charles area in 2020 to meet the industrial load growth expected in that area; however, the timing of this resource is uncertain and subject to change based on changes in load additions, implementation of other supply additions, and changes in transmission topography.
In Q3 2015, file an application and supporting testimony with the Commission seeking certification for the St.
Charles Power Station selfbuild CCGT resource selected through the 2014 Amite South RFP. Complete the certification process in order to support an inservice date by 2020.
In September 2015, issue the WOTAB RFP to solicit proposals for a new CCGT facility (approximately 8001000 MWs) in the Lake Charles area by 2020 to maintain reliable and economic service to customers given the industrial load growth, PPA expirations and terminations, and anticipated unit deactivations expected in that area.
Obtain certification for any resource selected through the RFP in order to facilitate an inservice date by 2020.
Continue to assess development of additional options for CT additions in the Amite South and WOTAB areas that could be deployed quickly if load growth is higher than expected and/or supply alternatives are not completed as planned.
Gas Supply Explore opportunities for longterm gas supplies that could mitigate price volatility and/or reduce the cost of gas relative to future market conditions.
Demand DSM and Energy Evaluate the results of the Quick Start Energy Efficiency Side Efficiency programs in Louisiana.
43
Alternatives Programs Work with regulators to develop rules that would provide a framework for implementing cost effective DSM programs beyond the Quick Start phase and provide appropriate cost recovery.
44
Rev. 1April 2015 APPENDIX A: ELL & EGSL GENERATION RESOURCES Generating Assets Owned or Controlled by ELL as of 1/1/15 Megawatt Plant Unit Fuel COD Region Capability ANO 1 23 Nuclear 12/19/1974 North ANO 2 27 Nuclear 3/25/1980 North Acadia 2 367 Gas 7/3/2002 WOTAB Buras 8 12 Gas 1/30/1971 DSG Grand Gulf 209 Nuclear 7/1/1985 Central Independence 1 7 Coal 1/18/1983 North Little Gypsy 2 411 Gas 4/18/1966 Amite South Little Gypsy 3 520 Gas 3/21/1969 Amite South Ninemile Point 3 103 Gas 11/5/1955 DSG Ninemile Point 4 699 Gas 5/1/1971 DSG Ninemile Point 5 717 Gas 6/12/1973 DSG Ninemile Point 6 308 Gas 12/24/2014 DSG Perryville 1 133 Gas 7/1/2002 Central Perryville 2 36 Gas 7/1/2001 Central Sterlington 7 126 Gas 1/1/1986 Central Riverbend 1 195 Nuclear 1/1/1986 Central Waterford 1 411 Gas 6/27/1974 Amite South Waterford 2 411 Gas 9/13/1975 Amite South Waterford 3 1,156 Nuclear 9/24/1985 Amite South Waterford 4 33 Oil 9/24/1985 Amite South White Bluff 1 13 Coal 8/22/1980 North White Bluff 2 12 Coal 7/23/1981 North Total Owned 5,929 605 Unaffiliated PPAs Total Capacity 6,534
Rev. 1April 2015 Generating Assets Owned or Controlled by EGSL as of 1/1/15 Megawatt Plant Unit Fuel COD Region Capability Acadia 2 184 Gas 7/3/2002 WOTAB Big Cajun 2 3 146 Coal 1/1/1983 Central Calcasieu 1 82 Gas 5/30/2000 WOTAB Calcasieu 2 91 Gas 5/1/2001 WOTAB Lewis Creek 1 133 Gas 12/1/1970 WOTAB Lewis Creek 2 132 Gas 5/1/1971 WOTAB Ninemile Point 6 140 Gas 12/24/2014 DSG Ouachita 3 241 Gas 8/1/2002 Central Perryville 1 228 Gas 7/1/2002 Central Perryville 2 63 Gas 7/1/2001 Central Roy Nelson 4 244 Gas 7/1/1970 WOTAB Roy Nelson 6 222 Coal 5/1/1982 WOTAB Riverbend 1 389 Nuclear 1/1/1986 Central Sabine 1 122 Gas 3/1/1962 WOTAB Sabine 2 122 Gas 12/1/1962 WOTAB Sabine 3 228 Gas 11/1/1964 WOTAB Sabine 4 306 Gas 8/1/1974 WOTAB Sabine 5 270 Gas 12/1/1979 WOTAB Willow Glen 2 104 Gas 1/1/1962 Central Willow Glen 4 276 Gas 7/1/1973 Central Total Owned 3,723 Unaffiliated PPAs 304 Total Capacity 4,027
APPENDIX B: ACTUAL HISTORIC LOAD AND LOAD FORECAST Historic Peak Demand and Energy1 Table 1: Historic Total Annual Energy (MWh)
ELL EGSL 2004 29,718,031 21,149,604 2005 28,303,405 20,541,702 2006 29,080,987 20,732,221 2007 29,773,354 20,964,467 2008 29,198,107 21,537,359 2009 29,894,169 21,395,660 2010 32,085,692 22,224,858 2011 33,164,859 21,531,721 2012 32,989,327 21,074,484 2013 33,456,578 21,400,699 2014 33,859,482 22,460,701 Table 2: Historic Total Monthly Energy (MWh)2 Month/Year ELL EGSL 01/2004 2,311,537 1,601,028 02/2004 2,136,717 1,524,442 03/2004 2,164,832 1,577,645 04/2004 2,176,831 1,593,903 05/2004 2,596,835 1,781,548 06/2004 2,741,239 1,864,531 07/2004 2,932,780 2,024,939 08/2004 2,881,298 2,012,446 09/2004 2,593,513 1,862,491 10/2004 2,624,031 1,996,075 11/2004 2,168,018 1,596,355 12/2004 2,390,400 1,714,201 01/2005 2,255,883 1,672,997 02/2005 2,031,011 1,453,530 03/2005 2,235,818 1,548,045 04/2005 2,261,162 1,553,197 05/2005 2,559,331 1,784,569 06/2005 2,769,785 1,904,194 1
Actuals are not available for revenue classes.
2 Data for November and December 2014 is preliminary and subject to change.
1
07/2005 2,906,955 2,008,777 08/2005 2,834,534 2,037,849 09/2005 2,087,842 1,806,263 10/2005 2,211,131 1,597,883 11/2005 2,001,850 1,554,430 12/2005 2,148,103 1,619,968 01/2006 2,033,144 1,556,821 02/2006 1,980,652 1,385,554 03/2006 2,117,934 1,571,043 04/2006 2,221,653 1,653,726 05/2006 2,537,231 1,816,740 06/2006 2,789,737 1,940,443 07/2006 2,875,996 2,023,795 08/2006 2,997,500 2,097,955 09/2006 2,646,658 1,873,176 10/2006 2,398,857 1,677,934 11/2006 2,169,848 1,527,102 12/2006 2,311,777 1,607,932 01/2007 2,371,678 1,703,012 02/2007 2,162,670 1,500,588 03/2007 2,221,530 1,601,057 04/2007 2,190,694 1,608,715 05/2007 2,492,526 1,913,330 06/2007 2,734,552 1,902,830 07/2007 2,816,853 1,938,451 08/2007 3,099,329 2,107,737 09/2007 2,697,947 1,876,642 10/2007 2,455,856 1,687,020 11/2007 2,170,803 1,521,490 12/2007 2,358,917 1,603,595 01/2008 2,432,139 1,852,720 02/2008 2,118,960 1,603,295 03/2008 2,236,831 1,690,728 04/2008 2,291,841 1,668,177 05/2008 2,626,717 1,954,253 06/2008 2,786,255 2,080,007 07/2008 2,995,936 2,259,714 08/2008 2,842,596 2,158,308 09/2008 2,078,546 1,467,917 10/2008 2,350,752 1,750,564 11/2008 2,144,427 1,474,222 12/2008 2,293,108 1,577,453 2
01/2009 2,343,883 1,690,184 02/2009 1,985,991 1,411,601 03/2009 2,172,280 1,587,727 04/2009 2,298,941 1,572,658 05/2009 2,616,182 1,823,800 06/2009 2,837,246 2,124,410 07/2009 2,963,590 2,173,590 08/2009 2,891,459 2,215,597 09/2009 2,685,899 1,907,629 10/2009 2,461,316 1,735,890 11/2009 2,201,431 1,478,599 12/2009 2,435,951 1,673,975 01/2010 2,623,187 1,759,164 02/2010 2,276,565 1,646,248 03/2010 2,342,863 1,666,681 04/2010 2,336,778 1,679,509 05/2010 2,832,878 2,025,872 06/2010 3,032,288 2,129,334 07/2010 3,106,097 2,091,799 08/2010 3,161,069 2,140,429 09/2010 2,921,662 1,993,046 10/2010 2,554,847 1,760,973 11/2010 2,300,971 1,596,121 12/2010 2,596,486 1,735,682 01/2011 2,653,798 1,740,261 02/2011 2,412,060 1,562,619 03/2011 2,407,898 1,614,158 04/2011 2,508,947 1,740,579 05/2011 2,794,626 1,909,373 06/2011 3,089,584 2,021,022 07/2011 3,248,003 2,079,774 08/2011 3,488,051 2,185,171 09/2011 2,874,991 1,793,410 10/2011 2,579,222 1,649,351 11/2011 2,410,048 1,600,386 12/2011 2,697,629 1,635,616 01/2012 2,531,135 1,608,977 02/2012 2,412,094 1,454,687 03/2012 2,593,042 1,631,738 04/2012 2,574,452 1,696,105 05/2012 2,982,002 1,957,034 3
06/2012 3,111,340 1,922,590 07/2012 3,245,996 2,024,525 08/2012 2,991,951 2,024,343 09/2012 2,841,400 1,832,743 10/2012 2,639,342 1,735,547 11/2012 2,404,111 1,525,234 12/2012 2,662,463 1,660,961 01/2013 2,746,176 1,615,504 02/2013 2,340,010 1,461,945 03/2013 2,549,999 1,631,898 04/2013 2,510,550 1,673,465 05/2013 2,846,703 1,817,896 06/2013 3,105,051 2,006,778 07/2013 3,111,886 2,049,357 08/2013 3,307,459 2,106,366 09/2013 3,056,761 1,938,448 10/2013 2,539,617 1,741,513 11/2013 2,513,983 1,609,732 12/2013 2,828,381 1,747,795 01/2014 2,918,373 1,861,032 02/2014 2,457,101 1,626,956 03/2014 2,558,374 1,752,514 04/2014 2,533,237 1,707,600 05/2014 2,810,857 1,892,237 06/2014 3,067,230 2,073,054 07/2014 3,237,304 2,077,909 08/2014 3,265,719 2,170,383 09/2014 3,008,222 1,997,183 10/2014 2,745,633 1,841,000 11/2014 2,567,031 1,721,727 12/2014 2,690,401 1,739,106 4
Table 3: Historic Total Summer & Winter Peaks (MW)3 ELL EGSL 4
Winter 2004 4,636 3,119 Summer 2004 5,091 3,555 Winter 2005 4,943 3,314 Summer 2005 5,236 3,583 Winter 2006 4,550 3,311 Summer 2006 5,257 3,639 Winter 2007 4,395 3,383 Summer 2007 5,341 3,676 Winter 2008 4,653 3,609 Summer 2008 5,234 3,912 Winter 2009 4,558 3,256 Summer 2009 5,252 4,046 Winter 2010 5,060 3,496 Summer 2010 5,492 3,747 Winter 2011 5,174 3,400 Summer 2011 5,766 3,787 Winter 2012 5,343 3,412 Summer 2012 5,706 3,694 Winter 2013 5,045 3,386 Summer 2013 5,773 3,776 Winter 2014 5,382 3,459 Summer 2014 5,518 3,752 3
Summer is defined as JuneNovember. Winter is defined as DecemberMay.
4 Winter 2004 is defined as January 2004May 2004.
5
Load Forecast Table 4: EGSL Monthly Energy Forecast (GWh), Industrial Renaissance Case REDACTED MATERIAL 6
REDACTED MATERIAL 7
REDACTED MATERIAL 8
REDACTED MATERIAL 9
REDACTED MATERIAL 10
REDACTED MATERIAL 11
Table 5: ELL Retail Monthly Energy Forecast (GWh), Industrial Renaissance Case REDACTED MATERIAL 12
REDACTED MATERIAL 13
REDACTED MATERIAL 14
REDACTED MATERIAL 15
REDACTED MATERIAL 16
REDACTED MATERIAL 17
Table 6: Forecasted Retail Summer & Winter Peaks (MWs)5 ELL EGSL Winter 2015 5,294 3,666 Summer 2015 5,863 3,861 Winter 2016 5,382 3,766 Summer 2016 5,950 3,983 Winter 2017 5,548 3,933 Summer 2017 6,115 4,232 Winter 2018 5,619 4,345 Summer 2018 6,174 4,567 Winter 2019 5,752 4,501 Summer 2019 6,292 4,723 Winter 2020 5,784 4,372 Summer 2020 6,332 4,601 Winter 2021 5,828 4,402 Summer 2021 6,372 4,630 Winter 2022 5,869 4,428 Summer 2022 6,413 4,658 Winter 2023 5,909 4,455 Summer 2023 6,456 4,688 Winter 2024 5,950 4,484 Summer 2024 6,492 4,719 Winter 2025 5,990 4,515 Summer 2025 6,532 4,752 Winter 2026 6,029 4,544 Summer 2026 6,574 4,785 Winter 2027 6,069 4,573 Summer 2027 6,614 4,816 Winter 2028 6,108 4,601 Summer 2028 6,659 4,847 Winter 2029 6,146 4,628 Summer 2029 6,693 4,877 Winter 2030 6,185 4,655 Summer 2030 6,732 4,905 Winter 2031 6,223 4,683 Summer 2031 6,771 4,935 Winter 2032 6,261 4,710 Summer 2032 6,810 4,965 Winter 2033 6,299 4,738 Summer 2033 6,851 4,995 5
Summer and winter coincident peak demands for each customer class are not developed.
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Winter 2034 6,337 4,766 Summer 2034 6,893 5,026 Table 7: Forecasted Load Factors ELL EGSL 2015 69% 69%
2016 70% 70%
2017 70% 72%
2018 70% 76%
2019 71% 78%
2020 71% 76%
2021 71% 76%
2022 71% 77%
2023 71% 77%
2024 71% 77%
2025 71% 77%
2026 71% 77%
2027 71% 77%
2028 71% 77%
2029 71% 77%
2030 71% 77%
2031 71% 77%
2032 71% 77%
2033 71% 77%
2034 71% 77%
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APPENDIX C: RESPONSE TO STAKEHOLDER COMMENTS General Comment Response (January 2015)
Staff Provide rationale for selection MISO does not have projected longterm capacity of the proxy generating unit used for prices; only annual market capacity prices are the projected longterm capacity developed. For longterm planning, a CT is used as the prices and describe how that proxy generating unit for projectedlong term capacity compares to other market capacity prices as it is the lowest cost source of capacity.
prices for MISO RTO Staff Identify units selected for For the purpose of developing this IRP, assumptions deactivation and reason for must be made about the future of generating units deactivation and when currently in the Companies portfolio. Assumptions made for the IRP are not final decisions regarding the future investment in resources. Unitspecific portfolio decisions such as, sustainability investments, environmental compliance investments, or unit retirements, are based on economic and technical evaluations considering such factors as projected forward costs, anticipated operating roles, and the cost of supply alternatives. These factors are dynamic, and as a result, actual decisions may differ from planning assumptions as greater certainty is gained regarding requirements of legislation, regulation, and relative economics. Based on current assumptions, a number of the Companies existing fossil generating units may be deactivated during the IRP planning period. In the years 20152034, the total assumed reduction in the Companies generating capacity from these unit deactivations and PPA terminations is approximately 6,100 MW, which considers the addition of Ninemile Point 6, relative to the Companies current combined resources of approximately 10,915 MW.
Sierra Club Not clear how the Throughout the planning period all Entergy coal units Company will model the possible are assumed to continue to operate. These units will retirement of existing coal resources. continue to operate as long as it is economic to do so.
Moreover, it appears Entergy has ignored the possibility of retiring any of its coalfired facilities.
Page 1 of 16
Staff Identify and describe future There are no known future and/or planned changes in known and/or planned changes in the capacity and the availability of existing resources.
capacity, availability, etc.
Staff Identify and describe new As described in the Action Plan, EGSL is in the process resources the company plans to build of obtaining regulatory approval to acquire two units or acquire, including those planned of the Union Plant near El Dorado, Arkansas. This for WOTAB transmission region. acquisition would add approximately 816 MWs net of a 20% PPA to ENO to the Companies current capacity.
Similarly, the Companies are currently conducting the Amite South RFP to obtain a new CCGT by 2020.
Staff Identify and describe future This information is available under the Transmission known and/or planned changes in Planning Section in the IRP. Specific details about transmission capacity, including new future changes in transmission is in Appendix A.
lines and upgrades, and effect on new resources.
Sierra Club Disclose how ELL and As part of the IRP, an Action Plan was developed that EGSL will affect resource plans describes the Companies plan for specific resources at certain times.
SWEA Recommends that data All relevant costs are included in the IRP, which assumptions regarding O&M only use includes both fixed and variable O&M. The IRP is fixed O&M costs, instead of fixed and developed from a customer perspective. That is, the variable O&M costs together. Companies planning process seeks to design a portfolio of resources that reliably meets customer power needs at a reasonable cost while considering risk, which is why it is necessary to include variable O&M costs.
SWEA Data assumptions should All input assumptions were filed with the LPSC through include greater transparency and a series of filings in 2014, with the most recent in citation so all stakeholders can October.
conduct data quality control.
Sierra Club Entergy should treat The effect of distributed generation is accounted for in distributed generation like any other the load forecast. Currently, this is the best available available resource and pursuing method to account for distributed generation given its programs that are available and nondispatchable nature.
beneficial to ratepayers.
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Comment on Draft IRP Report Response (August 2015)
Alliance for Affordable Energy - Were Upgrade costs for nuclear were not modeled. New upgrade costs for nuclear modeled in nuclear was evaluated in the screening level analysis AURORA or were new nuclear costs phase of the Technology Assessment and found to be a modeled? viable technology, but was not selected by AURORA as a cost competitive resource in the detailed analysis phase.
Alliance for Affordable Energy - Was Union Power Station was included in the AURORA generation from the Union Power modeling as a resource.
Station included in the modeling or after the modeling was complete?
Alliance for Affordable Energy - The match up reflects the fact that wind receives Please explain the match up fee used partial capacity value in MISO due to winds in connection with wind resources. intermittent nature. The capacity matchup fee was only applied in the initial screening analysis phase of supplyside resources in the technology assessment.
Once it was selected for further analysis and modeling in AURORA, wind was evaluated relative to other resources without the capacity match up fee added.
LEUG - Explain the process by which For the purpose of developing the IRP, assumptions the companies continue to evaluate are made about the future of the units in the current unit deactivations. portfolio. Unitspecific portfolio decisions such as sustainability investments, environmental compliance investments, or unit retirements are based on economic and technical evaluations considering such factors as projected forward costs, anticipated operating roles, and the cost of supply alternatives. In the IRP, a total assumed net reduction in the Companies generating capacity from unit deactivations and PPA terminations is approximately 6,100 MW over the planning horizon. This assumption has not changed since the November 3, 2014 Inputs filing.
LEUG - Provide additional information Transmission alone is not an alternative to generation, on the process for evaluation of new but rather transmission in conjunction with generation transmission options to ensure lowest allows customers to be served reliably and reasonable costs. economically. The Companies and other load serving entities in MISO are required to provide generation capacity equal to their load obligation plus a MISO determined reserve margin to comply with MISO Resource Adequacy requirements. Therefore, when the Companies need to add a new generating unit, the location is chosen to best meet the planning objectives Page 3 of 16
based on consideration of factors needed to support new generation including, but not limited to fuel supply, transmission, water supply, environmental permitting, and proximity to load. This process considers both generation and transmission and allows the Companies to meet the planning objectives of serving its customers reliably at the lowest reasonable cost while considering risk.
StaffDiscuss whether there are any The Companies favorable commercial and industrial economic opportunities to include rates makes CHP deployment uneconomic for most CHP in the portfolio and reduce need existing customers except those with over 20 MW of for other capacityrelated capital load that also have an operational need for process expenditures steam. Even if CHP is economic, many industrial customers prefer to utilize the Companies reliable and competitively priced electrical power rather than commit their limited capital resources to constructing their own power generation projects that have a mid to longterm payback and are a noncore business.
This is very much the case when the industrial customers cost of electricity is small compared to its total cost of doing business. The considerable amount of industrial CHP already connected to the Companies electrical grid indicates that the base of existing industrial customers for whom that technology makes economic sense have already elected to deploy CHP.
StaffRegarding Action Plan, provide Additional information regarding timelines has been information on timelines for acquiring provided in the Action Plan in the report.
the New Resources discussed as well as any reasons why competitive solicitation might not be used.
StaffExplain whether analysis has Because LPSC Consolidated Order Nos. U21453, been performed to determine if it U20925 and U22092 (Subdocket J) requires the would be beneficial to EGSL termination of these PPAs upon removal of the JSP customers for JSP PPAs to remain in PPA resources from Entergy System dispatch, such effect and how that would affect the analysis has not been performed in developing the Reference Plan. Companies IRP. In general, the termination of the JSP PPAs would cause EGSL, on a net basis, to lose approximately 700 MW of capacity from legacy gas generation resources. This assumption is reflected in the Reference Plan. There is no basis to assume a different outcome given the LPSC Order.
Page 4 of 16
Load Comment Response (January 2015)
Staff Identify and describe known or Load additions include individual customer anticipated major load additions information, which is confidential.
Staff Address how price elasticity Price elasticity is an input into the energy forecasting incorporated in projected peak loads models. The peak load forecast uses the output from and energy, and how this effects the energy models as an input so the impacts of price resource portfolio elasticity indirectly influence the peak load. Resource portfolios are then developed after the load forecast is complete.
Comment Response (August 2015) on Draft IRP Report StaffHow The following table provides a comparison of actual annual energy sales, or did actual cumulative hourly load, to the 2012 IRP forecast.
load compare to Amounts in GWh the load EGSL ELL forecast in 2012 2013 2014 2012 2013 2014 1
IRP Forecast 19,298 19,659 19,925 31,373 32,130 32,482 the Weather Adjustment 124 48 87 178 142 275 Companies Non Weather Adjusted Actuals 19,581 19,663 20,823 31,710 32,220 32,905 2012 IRP Forecast Error % 1.5% 0.0% 4.5% 1.1% 0.3% 1.3%
filings?
Weather Adjusted Error % 2.1% 0.3% 4.1% 1.6% 0.7% 0.5%
1 Final Retail Forecast from the 2012 IRP Base Case; Assumes normal weather Staff - Add a Rooftop solars forecasted growth is based on a 12 month average of installation more rates and average system size. No specific additional growth is assumed after detailed 2017 due to the expiration of investment tax credits; however, growth in solar description along with other items is embedded in the reduction of sales within organic of the energy efficiency assumptions.
assumptions used to develop the load forecast and distributed generation.
Staff - Add a In an effort to avoid longterm resource shortages, projects within the more Companies Economic Development pipeline were added to the forecast. In Page 5 of 16
detailed recognition of the uncertainty inherent in forecasting new load, the added description projects were risk adjusted to reflect an internally assigned probability of the of the new customer completing the pending project. For example, assume that assumptions customer ABC has informed Entergy of a new 80 MW project being considered used to in Entergys service territory. Based upon conversations with the customer and develop the previous experiences, the Companies Account Manager assigned a probability load of 50% to this project being completed. Thus, the load forecast would assume a forecast, 40 MW (80 MW x 50% = 40 MW) project is added. Projects for which the including customer has executed an electric service agreement are not riskadjusted and major load would be included in the load forecast at the full projected MW load. A large additions. industrial addition of approximately 10 MW was also included in Louisiana to account for projects that had not been explicitly identified.
The capacity of the large industrial load additions assumed in the forecast is identified in the chart below.
Alliance for Historic data is used in the weather forecasting.
Affordable Energy -
Does weather forecasting used by SPO and Metrix use historic data or climate impacted projections?
Page 6 of 16
Fuel Inputs Comment Response (January 2015)
Staff Use consistent assumptions for The Delivered Plant Coal Prices were developed using coalprice input. If there are two different methodologies: Entergy Operating discrepancies between plants, explain. Company (EOC) and Market Plants. The SPO Delivered to EOC Units Coal Price Forecast is a long term delivered price forecast created from consultant commodity price forecast, forecasted burn, transportation costs, and contract information. The delivered prices for Market Resources were derived from a consultant forecast. Different plants may have Delivered Coal Price Forecasts because of differences in the timing and volumes for commodity and transportation contracts. Moreover, it is expected that various scenarios have different coal price inputs as a result of different fuel assumptions (e.g., low, reference, and high).
Sierra Club Assumptions are biased The sensitivity analysis conducted in the IRP evaluated towards natural gas, instead of lower a range of natural gas prices across each scenario to cost options; Entergy should consider capture the risk related to fluctuating natural gas a gas price volatility adder to reflect prices.
risk of price fluctuation MISO Comment Response (January 2015)
Entegra Coordinate with MISO on generation unit retirement assumptions and transmission studies (e.g. for Amite South and WOTAB areas)
Entegra Perform a transmission topology sensitivity analysis of its There are established procedures for the Companies preliminary IRP results once MISO work with MISO, which is beyond the scope of the IRP makes recommendations process.
Louisiana Energy Users Group Coordinate with MISO on generation unit retirement assumptions and Page 7 of 16
transmission projects (e.g., Amite South and WOTAB)
Louisiana Energy Users Group Compare AURORA modeling to MISO recommendations; perform a transmission topology sensitivity analysis Energy Efficiency Comment Response (January 2015)
Alliance for Affordable Energy DSM benefits should include indirect utility system benefits resulting from lower capacity and energy loads, reduced reserve requirements, marginal line losses instead of average, and avoided T&D expenses.
Southeast Energy Efficiency Alliance (SEEA) Need to disclose As part of the IRP process, the Companies engaged ICF assumptions for cost and availability to prepare a demand side management potential of energy efficiency for DSM study for use in the IRP. The study was filed in (Demand Side Management) study October. All programs that had a TRC ratio of 1.0 or
- such as direct savings from installed greater were evaluated in the AURORA Market Model measures and system benefits, lower before consideration of supply side resource options.
capacity and energy loads, reduced reserves requirements, reduction in marginal line losses, and avoided transmission and distribution expenses SEEA Energy efficiency is not only a leastcost resource, but also a mechanism for deferring additional supplyside generation, avoiding new transmission and distribution infrastructure, and buffering against compliance costs from future environmental regulations.
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Sierra Club Treat energy efficiency as a resource, or par with supplyside resources.
Sierra Club - Energy Efficiency should be accounted as a resource.
Sierra Club Model distributed In the IRP, distributed generation is accounted for in generation and energy efficiency as the load forecast for the Companies. Moreover, energy supplyride resources. efficiency is evaluated as a resource alternative in the IRP.
Comments on the Draft IRP Report Response (August 2015)
Alliance for Affordable Energy - ICF The incentive level varied by program. The incentive modeled three cases based on level with the highest TRC ratio for each program was incentive level. Which one of these selected to be modeled in AURORA. As such, the cases was modeled in AURORA? incentive level varied for each program. However, the reference program tended to have the highest TRC ratio for most programs.
Alliance for Affordable Energy - Why ENO and the ELL/EGSL service territories have didnt ICF include ENO in the significantly different customer bases. ELL/EGSL are benchmarking data? heavily industrial, while ENO has very little industry. As such, comparing performance at the portfolio level between ENO and ELL/EGSL is problematic.
Alliance for Affordable Energy - Why The same set of payback acceptance curves was used are the payback acceptance curves to estimate participation for ELL/EGSL as was used for different from the New Orleans data? ENO for the Entergy Study.
Alliance for Affordable Energy - Why The same set of program nettogross ratios were used are the net to gross ratios different for ELL/EGSL as were used for the ENO study.
from ENO?
Alliance for Affordable Energy -In Yes, fuel is included in the avoided costs in Appendix F.
Appendix F [of the November 3, 2014 Inputs Filing], it looks like avoided costs do not include fuel.
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Environmental Regulation Comment Response (January 2015)
Staff - Address how [CSAPR] affects The Companies continue to evaluate the recent amount and timing of planned Supreme Court decision to allow the EPA to enforce deactivations. CSAPR, but to date, none of the Companies units have been identified for deactivation because of this rule.
However, there are different assumptions for other load serving entities in the market based upon the different scenarios. Industrial Renaissance and Distributed Disruption assume nonEntergy units retire at the age of 60 years; Business Boom assumes 70 years; and Generation Shift assumes 50 years.
Sierra Club - Unclear how The IRP does evaluate a range of environmental environmental compliance costs compliance costs in regards to CO2, SO2, and NOx.
regarding carbon pollution and other environmental regulations will be incorporated.
Gulf States Renewable Energy The IRP does consider all known and expected Industries Association (GSREIA) environmental cost of resources including carbon.
Fails to recognize inherent problems with traditional sources such as price volatility and reduced capacity of life; sustainability and environmental impact are other issues.
Alliance for Affordable Energy Use one robust reference case that includes CO2 and Section 111(d) compliance with more focus on sensitivities instead of multiple scenarios. A range of CO2 price assumptions are included in the SEEA - Assumptions regarding CO2 IRP across the four scenarios. Moreover, the sensitivity policy are unrealistic. analysis evaluates the effects of different CO2 prices Sierra Club - Ignores the costs of for each scenario.
new EPA regulations in Section 111(d) regarding carbon pollution standards coming in June 2014.
Sierra Club - Use nonzero CO2 price Page 10 of 16
Comment Response (August 2015)
Staff Include an evaluation of the ESI coordinates internally to identify, assess, and effects of environmental regulations respond to environmental issues arising from federal or future regulations on the operation regulatory and legislative proceedings. ESI tracks of the Companies existing Units. issues and analyzes impacts using a combination of internal corporate and business function staff and external organizations. Subject matter experts participate in industry associations and organizations, interact with federal and state agency staff, and monitor the trade press regarding environmental issues. Information gathered is shared through technical peer groups and the Environmental Lead Team, and a consolidated pointofview is formed based on Entergys overall business strategy, as needed. Unless otherwise noted below, expected capital expenditures and increases to O&M costs from many of these proposals are not yet fully developed due to uncertainty regarding the outcome of regulatory, legislative, and litigation proceedings. A brief summary of issues which potentially have the highest operational impact on the Companies follows:
Clean Air Act Regulations - Consistent with the Presidents Clean Power Plan announced in June 2013, EPA is expected to finalize in August 2015 regulations for new, existing, and modified/reconstructed sources of CO2 under the Clean Air Act. ESI developed an engagement plan and is actively engaged with industry groups, regulatory agency staff, and other external parties to analyze the impact of these proposed rules, comment on policy and technical issues, and advocate for reasonable approaches. Performance standards for existing sources, once final, will initiate state plans for compliance which could be due as early as September 2016. Regulations to address traditional pollutants have evolved due to court rulings, state implementation planning, and EPA actions. EGSL installed controls at the R.S. Nelson power plant pursuant to EPA regulations regarding mercury and other air toxics, but a recent Supreme Court ruling remanding this rule may result in a different compliance requirement. ESI also is implementing compliance measures for the Cross State Air Pollution Rule (CSAPR) and continues to monitor issues Page 11 of 16
regarding regional haze and National Ambient Air Quality Standard (NAAQS) development.
Solid/Hazardous Waste Regulations - EPA finalized regulations for coal ash and management structures in December 2014. The rule regulates coal ash disposal and impoundments/landfills under the nonhazardous section of the solid waste regulations. The R.S. Nelson power plant is the only EGSLowned facility affected by the rule. ESI continues to participate with industry groups to advocate for reasonable implementation approaches in order to minimize compliance costs. Litigation on this rule may result in a different compliance strategy.
Aquatic Protection Regulations - EPA finalized the 316(b) rule in May 2014. The final rule affects several EGSL/ELL facilities and provides flexibility on both the schedule and technology approaches for complying with the standards for impingement and entrainment. ESIs Environmental Strategy & Policy group has coordinated between the Entergy Fossil and Nuclear organizations to assess plant needs for responding to the new regulation. Consultants have been retained and compliance activities are underway to conduct the necessary technical studies and compile the existing technical data for submission to the appropriate regulatory agencies. EPA also has proposed new effluent (discharge) guidelines for electric generating units that may require modified waste water treatment procedures; these guidelines are not expected to be finalized until late 2015.
Staff Include more clarification on The reference case price stream is based on a the methodology of the CO2 forecast, probabilityweighted forecast of a utilityonly sector particularly around why the carbon cap and trade program being implemented starting in costs start in 2023. Include supporting 2023. The utility program is based on the reductions studies from other organizations. required under the KerryLieberman legislative proposal, and prorated to the power sector emissions levels. Offsets are also allowed. The assumed probability of a national, utilityonly program is 33 percent in 2023 and 66 percent by 2040.
The forecast is updated annually by the ESI Environmental Strategy and Policy group, or more Page 12 of 16
often as conditions warrant. The updated forecast is reviewed by the Companies Environmental Lead Team with their recommendation being used as the Companies CO2 Point of View.
The forecast is based on the Q1 2014 Strategic Outlook (formerly the Integrated Energy Outlook) dated January 2013 by ICF International.
Renewable Resources Comment Response (January 2015)
Sierra Club - Solar and wind installation costs will decrease.
GSREIA Common expectation for The Technology Assessment indicates that solar cost solar and wind energy leveled costs to are likely to decline over the next five years, however, reach grid parity in many areas within wind cost and performance are not expected to 510 years. A lack of early firsthand materially improve or decline over this time period. If experience by EGSL and ELL with wind and solar cost and performance improve more integration, these technologies will be than expected in this IRP, then future IRPs will capture a liability to ratepayers, keeping costs that. LA IRP cycle time is every four years.
and volatility high unnecessarily.
Declining price of renewable energy sources must be included in the modeling of any forwardlooking resource plan.
Alliance for Affordable Energy Wind resources: model Louisiana coastal, upland, and out of region projects separately and use 40%+ capacity factor.
The Companies prefer technologies that are proven on Alliance for Affordable Energy - a commercial scale. Some technologies lack the Renewable resource: in state and out commercial track record to demonstrate their of state and a broad range of project technical and operation feasibility. A cautious sizes should be considered. approach to technology development and deployment is therefore reasonable and appropriate in order to Page 13 of 16
SWEA Consider importing maintain System reliability and to protect Operating Southwest Power Pool [SPP] wind at Company customers from undue risks. The Entergy low cost. Operating Companies generally do not plan to be the first movers for emerging, unproven technologies.
Recommends MISO West wind The IRP seeks to identify generation technologies that energy resources be modeled in IRP are technologically mature and could reasonably be process as a separate resource. If expected to be operational in or around the possible, EGSL/ELL should model Companies regulated service territory. The Companies transmission interconnections and use a 34% capacity factor assumption for wind upgrades that may grant greater resources that could be developed in or around the flexibility in accessing low cost energy Entergy regulated service territory.
resources, like SPP or MISO wind energy. Entergy could also procure As part of MISO, the Companies are required to wind resources in Northern MISO. adhere to MISOs capacity values for wind, which is 14.1% as outlined in MISOs Resource Adequacy Tariff Within Louisiana, wind farms can be (Module E) and Resource Adequacy Business Practice constructed in the coastal zone Manual.
offshore and can be considered resources for MISO South Price points The Companies use of a capacity match up reflects and capacity factors are different for the fact that wind receives partial capacity value in Louisianabased resources and must MISO due to winds intermittent nature. The capacity be modeled as a separate resource in matchup is only used in the screening analysis of this IRP process. supplyside resources in the technology assessment.
When modeled in AURORA, wind is evaluated without Encourage a clearer explanation of the capacity match up relative to other resources.
how EGSL/ELL plans to conduct capacity value analyses for all generation resources. Currently, the capacity value provided to wind energy in the MISO system is 14.1%,
and because EGSL/ELL is now a member of MISO, this is a reasonable figure for inclusion in the IRP process.
Even so, this value may be conservative. Analysis of wind resources available in SPP and for HVDC transmission suggests a capacity value of 40% based on TVAs capacity value methodology.
Used wind costs that are too high: A major reason for EGSL/ELLs unrealistically high LCOE [Levelized Cost of Energy] for wind energy is a Page 14 of 16
spurious use of a match up fee It is recommended that the total all in, delivered costs of wind energy for outofstate resources be roughly $40 50/MWh and approximately
$44/MWh for resources within Louisiana Comment on Draft IRP Report Response (August 2015)
StaffConcerned about lack of fuel The 2009 System SRP included the statement on page diversity in the Reference Case. 110 that renewable generation has a place in the Should discuss fuel diversity and portfolio. Inclusion of modest levels of the most comments from the 2009 SRP economically priced renewable generation alternatives regarding appropriateness of can reduce cost and minimize total supply cost risk including renewables in the System especially in light of the potential RPS and carbon portfolio. legislation. However, the amount of renewable generation that can be cost effectively added is limited. The expected gas forecast shown on Figure 4:3 of that SRP over the 20 year horizon (ending 2030) in real 2008$ was $8.66/MMBTU, significantly above the Reference Case Real Levelized forecast of $4.87 in this 2015 IRP.
Based on that point of view, it was possible to foresee 2 GW of costeffective renewables being added to the Entergy System portfolio (as stated on page 111) and a System renewables RFP being issued in the 2009 2010 timeframe (in fact, the RFP issued in 2010 was limited to ELL/EGSL).
While renewables would increase fuel diversity in the portfolio, the analysis conducted for the 2015 IRP shows that the cost of renewables compared to natural gas generation is such that they are not competitive in the absence of a RPS. Likewise, the costs associated with new nuclear and coal render them uncompetitive with natural gas at this time.
While fuel diversity is a concern of the IRP process, natural gas generation offers the best way to provide the lowest reasonable cost portfolio that can reliably serve the customers needs.
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Hydroelectric Comment Response (January 2015)
Nelson Fails to recognizethat conventional hydroelectric generation is an option for Entergy, from new hydroelectric projects that would be located in or near the Companies service areas. Hydroelectric is a site specific resource that has limited development opportunities in Louisiana. As a result, it Hydroelectric generation resources is not appropriate to assess conventional hydroelectric are well below costs of other resources (or any other specific resource) in the renewable options context of the IRP. Such analysis would be conducted as part of the evaluation of responses to a Request for Should study hydroelectric generation Proposals (RFP) or of an unsolicited offer for a as part of IRP particular resource.
Sierra Club - Entergy should include hydroelectric projects.
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APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)
Report Date: January 19, 2015 Project Current Included in Entergy Project MTEP MTEP Operating Proposed ISD Project Driver Project Name Funding Project Status Project Status Comments Projected Actual ISD Mitigation Plan if required Model?
ID Project ID Designation Company (Planning)
Status ISD (Yes/No) 11-EGL-007 4602 Appendix B Transmission Reliability - Meeting Moril to Delcambre 138 kV line: Upgrade station EGSL Summer 2016 Proposed & Scoping Scoping to begin 3rd Quarter 2014 Summer 2016 N/A Planning Criteria equipment In Target 11-EGL-016-02 N/A Pre-Planned Transmission Reliability - Meeting Mossville to Canal - Phase 2: Upgrade 69 kV Line EGSL Winter 2014 Approved Construction Construction started 12/15/14. 2/14/15 N/A Planning Criteria Outages have been approved 11-EGL-017 4608 Appendix B Transmission Reliability - Meeting Five Points to Line 281 Tap to Line 247 Tap- Upgrade EGSL Summer 2019 Proposed & Scoping Summer 2019 N/A Planning Criteria 69 kV line In Target 11-EGL-018 4630 Target Appendix A in Transmission Reliability - Meeting Francis to Marydale: Upgrade 69 kV line EGSL Summer 2017 Proposed & Scoping Accelerated Need By Date from 2023 Summer 2017 N/A MTEP15 Planning Criteria In Target to Summer 2017 12-EGL-004 4603 Appendix B Transmission Reliability - Meeting McManus to Brady Heights - Upgrade 69 kV line EGSL Winter 2023 Conceptual Conceptual Conceptual Winter 2023 N/A Planning Criteria Moved out from 2016 to 2023 12-EGL-010 N/A Pre-Planned Transmission Reliability - Meeting Kirk Substation: Construct new 138-69 kV substation EGSL Summer 2015 Proposed & Scoping PEP is under review to evaluate a Spring 2016 NCLL Planning Criteria near St. Martinville In Target proposed change in the station (Formerly New Iberia: Add 138-69 kV substation) configuration.
14-EGL-002 4611 Target Appendix A in Transmission Reliability - Meeting Construct new Waddill 230-69 kV Substation (formerly EGSL Summer 2017 Proposed & Scoping Accelerated Need By Date from 2020 Summer 2017 N/A MTEP15 Planning Criteria referred to as Flannery Area Project) In Target to 2017 Also reconfigure 69 kV lines 340 and 749 14-EGL-003 N/A Pre-Planned Transmission Reliability - Meeting Willow Glenn: Upgrade 500-230 kV single phase EGSL Summer 2016 Approved Design/Construction Autotransformer and breakers have Summer 2016 Planned NCLL until project completed Planning Criteria transformer bank with 1200 MVA single phase bank been ordered and are scheduled to be delivered to support EGSL Construction; January 2016 (Auto) and March 2015 (breakers).
14-EGL-004 4606 Target Appendix A in Transmission Reliability - Meeting Fancy Point: Add 2nd 500-230 kV, 1200 MVA EGSL Summer 2017 Proposed & Scoping Detailed scoping to begin 3rd Quarter Summer 2017 Planned NCLL until project completed MTEP15 Planning Criteria transformer In Target 2014 14-EGL-005 4625 A in MTEP14 Transmission Reliability - Meeting Nelson: Upgrade 500-230 kV single phase transformer EGSL Winter 2015 Approved Design Autotransformer has been ordered. Spring 2015 N/A Planning Criteria bank with 1200 MVA transformer bank Design complete 14-EGL-006 N/A Pre-Planned Transmission Reliability - Meeting LeBlanc - New Cap Bank #1 EGSL Summer 2015 Proposed & Construction Permanent and Temporary Servitudes Summer 2015 N/A Planning Criteria In Target are being finalized 14-EGL-007 4610 Appendix B Transmission Reliability - Meeting Chlomal to Lacassine - Upgrade Line EGSL Winter 2023 Conceptual Conceptual Conceptual Winter 2023 N/A Planning Criteria Moved out from 2019 to 2023 14-EGL-008 4609 Target Appendix A in Transmission Reliability - Meeting Krotz Springs - New Cap Bank EGSL Summer 2016 Proposed & Scoping Alternative locations for the capacitor Summer 2016 N/A MTEP15 Planning Criteria In Target bank are being evaluated based on constructability issues.
14-EGL-010 4626 Appendix B Transmission Reliability - Meeting Meaux to Abbeville - Upgrade Meaux Line bay bus EGSL Summer 2024 Conceptual Conceptual Conceptual Summer 2024 N/A Planning Criteria Project need date moved out from 2020 to 2024 14-EGL-012 4628 Appendix B Transmission Reliability - Meeting LeBlanc - New Cap Bank #2 EGSL Summer 2021 Conceptual Conceptual Conceptual Summer 2021 N/A Planning Criteria Accelerated one year from 2022 to 2021 Long Term Projects Page 1 of 7
APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)
Report Date: January 19, 2015 Project Current Included in Entergy Project MTEP MTEP Operating Proposed ISD Project Driver Project Name Funding Project Status Project Status Comments Projected Actual ISD Mitigation Plan if required Model?
ID Project ID Designation Company (Planning)
Status ISD (Yes/No) 14-EGL-016 4604 Target Appendix A in Transmission Reliability - Meeting Port Hudson to Zachary REA 69 kV Line Reconductor EGSL Summer 2016 Proposed & Scoping Accelerated Need By Date to Summer Summer 2016 N/A MTEP15 Planning Criteria In Target 2016 14-EGL-017 4605 A in MTEP14 Transmission Reliability - Meeting Horseshoe Substation (Crown Zellerbach Area): EGSL Summer 2017 Proposed & Scoping Changed name to reflect new Summer 2017 N/A Planning Criteria Construct new 230-138 kV substation on the Fancy In Target substation name and line connection in Point to Enjay 230 kV line title 14-EGL-019 N/A Pre-Planned Transmission Reliability - Meeting Mud Lake 230 kV Substation: Loop Sabine to Big 3 230 EGSL Fall 2016 Approved Scoping Detailed scoping in progress. Currently Summer 2016 N/A Planning Criteria kV Line into new Mud Lake 230 kV substation and add projected to be complete in the (2) 230 kV capacitor banks at Mud Lake Summer 2016.
14-EGL-020 4719 A in MTEP14 Transmission Service PPG to Rosebluff 230 kV Line: Upgrade line to increase EGSL Summer 2015 Approved Design Scoping complete. Design has begun. 7/1/15 N/A capacity Current project schedule is targeting a 7/1/15 ISD.
14-EGL-022-1 4761 A in MTEP14 Transmission Reliability - Meeting EGSL SPOF Projects: Modify relaying at Willow Glen EGSL Summer 2015 Proposed & Scoping Definition Phase underway. Site visits 12/31/2016 N/A N/A Planning Criteria 500 kV In Target completed. Review and updating of drawings by PCS will be completed by March 2015. PEP will also be completed by the end of February 2015. Due to the need to change 21 panels, add new relay room, replacement of transformer under another capital project, etc. and uncertainty in availability of outages, ISD would likely be by December 2016 or beyond this date. After PEP and outage planning is done, a schedule will be developed and ISD identified.
14-EGL-022-2 4762 A in MTEP14 Transmission Reliability - Meeting EGSL SPOF Projects: Modify relaying at Fancy Point EGSL Summer 2015 Proposed & Scoping Scope to be determined Summer 2015 N/A N/A Planning Criteria 500kV In Target 14-EGL-023 4720 A in MTEP14 Customer Driven Michigan 230 kV substation: Construct new Michigan EGSL Summer 2015 Approved Design Design complete. Material has been Fall 2015 N/A 230 kV substation and cut in to the Nelson to Verdine ordered. Awaiting customer to prep 230 kV line the site. Expected mobilization is 01/05/2015.
14-EGL-024-1 4763 A in MTEP14 Transmission Reliability - Meeting EGSL Underrated Breaker Project: Jaguar 69 kV 20940- EGSL Winter 2016 Proposed & Scoping Under Review Winter 2016 N/A N/A Planning Criteria CO In Target 14-EGL-024-2 4764 A in MTEP14 Transmission Reliability - Meeting EGSL Underrated Breaker Project: Jaguar 69 kV 20905- EGSL Winter 2016 Proposed & Scoping Under Review Winter 2016 N/A N/A Planning Criteria CO In Target 14-EGL-024-3 4765 A in MTEP14 Transmission Reliability - Meeting EGSL Underrated Breaker Project: Blount 69 kV 14105- EGSL Winter 2016 Proposed & Scoping Under Review Winter 2016 N/A N/A Planning Criteria TC In Target 14-EGL-024-4 4766 A in MTEP14 Transmission Reliability - Meeting EGSL Underrated Breaker Project: Coly 230 kV 21825- EGSL Winter 2016 Proposed & Scoping Under Review Winter 2016 N/A N/A Planning Criteria C In Target 14-EGL-024-5 4767 A in MTEP14 Transmission Reliability - Meeting EGSL Underrated Breaker Project: Coly 230 kV 21830- EGSL Winter 2016 Proposed & Scoping Under Review Winter 2016 N/A N/A Planning Criteria C In Target 14-EGL-026 8284 A in MTEP14 Economic LETP: Coly - Add 2nd 500-230 kV, 1200 MVA EGSL Summer 2018 Approved Scoping New project (Economic MTEP 14) Summer 2018 N/A N/A Autotransformer Long Term Projects Page 2 of 7
APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)
Report Date: January 19, 2015 Project Current Included in Entergy Project MTEP MTEP Operating Proposed ISD Project Driver Project Name Funding Project Status Project Status Comments Projected Actual ISD Mitigation Plan if required Model?
ID Project ID Designation Company (Planning)
Status ISD (Yes/No) 15-EGL-001 7917 Target Appendix A in Transmission Reliability - Meeting Gillis 230 kV Substation: Add 61 MVAR capacitor bank EGSL Summer 2016 Proposed & Scoping New Project Summer 2016 MTEP15 Planning Criteria In Target 15-EGL-002 7919 Target Appendix A in Transmission Reliability - Meeting Pecan Grove 230 kV Substation: Add 61 MVAR EGSL Summer 2016 Proposed & Scoping New Project Summer 2016 MTEP15 Planning Criteria capacitor bank In Target 15-EGL-003 7920 Target Appendix A in Transmission Reliability - Meeting Carlyss to Boudoin 230 kV Line: Upgrade station EGSL Summer 2016 Proposed & Scoping New Project Summer 2016 MTEP15 Planning Criteria equipment at Carlyss In Target 15-EGL-004 7921 Target Appendix A in Transmission Reliability - Meeting Nelson to Michigan 230 kV line: Upgrade line to EGSL Summer 2016 Proposed & Scoping New Project Summer 2016 MTEP15 Planning Criteria minimum of 2000A In Target 15-EGL-005 7923 Target Appendix A in Transmission Reliability - Meeting Lake Charles Bulk to Chlomal 69 kV Line: Reconductor EGSL Summer 2017 Proposed & Scoping New Project Summer 2017 MTEP15 Planning Criteria line In Target 15-EGL-006 7924 Target Appendix A in Transmission Reliability - Meeting Goosport Substation: Install 138-69 kV autotransformer EGSL Summer 2017 Proposed & Scoping New Project Summer 2017 MTEP15 Planning Criteria In Target 15-EGL-008 7929 Target Appendix A in Transmission Reliability - Meeting Solac: Upgrade 69 kV switch on Autotransformer EGSL Summer 2016 Proposed & Scoping New Project Summer 2016 MTEP15 Planning Criteria In Target 15-EGL-009 7948 Target Appendix A in Transmission Reliability - Meeting Scott to Carencro 69 kV line: Reconductor Line EGSL Summer 2017 Proposed & Scoping New Project Summer 2017 MTEP15 Planning Criteria In Target 15-EGL-010 7949 Appendix B Transmission Reliability - Meeting Solac: Add 3rd Autotransformer EGSL Summer 2023 Conceptual Conceptual New Project Summer 2023 Planning Criteria 15-EGL-011 7950 Appendix B Transmission Reliability - Meeting East Broad to Ford 69 kV line: Reconductor line EGSL Summer 2020 Proposed & Scoping New Project Summer 2020 Planning Criteria In Target 15-EGL-012 7952 Appendix B Transmission Reliability - Meeting Contraband to Solac 69 kV line: Reconductor line EGSL Summer 2023 Conceptual Conceptual New Project Summer 2023 Planning Criteria 15-EGL-013 7954 Appendix B Transmission Reliability - Meeting Mossville to Alfol 69 kV line: Reconductor line EGSL Summer 2023 Conceptual Conceptual New Project Summer 2023 Planning Criteria 15-EGL-014 7960 Appendix B Transmission Reliability - Meeting Chlomal to Iowa 69 kV line: Reconductor line EGSL Summer 2024 Conceptual Conceptual New Project Summer 2024 Planning Criteria 15-EGL-015 7965 Appendix B Transmission Reliability - Meeting Lake Charles Bulk to L673 TP 69 kV line: Reconductor EGSL Summer 2025 Conceptual Conceptual New Project Summer 2025 Planning Criteria line 15-EGL-016 8585 Target Appendix A in Transmission Reliability - Meeting LCTP: Construct new Sulphur Lane 500 kV switching EGSL Summer 2018 Approved Scoping New Project to address reliability needs Summer 2018 MTEP15 (OOC) Planning Criteria station in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycle 15-EGL-017-01 8586 Target Appendix A in Transmission Reliability - Meeting LCTP: Construct new 500-230 kV Bulk Substation west EGSL Summer 2018 Approved Scoping New Project to address reliability needs Summer 2018 MTEP15 (OOC) Planning Criteria of Carlyss. Install new 500-230 kV, 1200 MVA in the Lake Charles area due to autotransformer composed of three single phase units. projected growth. Being submitted to MISO as out of cycle Long Term Projects Page 3 of 7
APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)
Report Date: January 19, 2015 Project Current Included in Entergy Project MTEP MTEP Operating Proposed ISD Project Driver Project Name Funding Project Status Project Status Comments Projected Actual ISD Mitigation Plan if required Model?
ID Project ID Designation Company (Planning)
Status ISD (Yes/No) 15-EGL-017-02 8587 Target Appendix A in Transmission Reliability - Meeting LCTP: Construct new 500 kV transmission line from EGSL Summer 2018 Approved Scoping New Project to address reliability needs Summer 2018 MTEP15 (OOC) Planning Criteria Sulphur Lane to new 500/230 kV Bulk Substation west in the Lake Charles area due to of Carlyss projected growth. Being submitted to MISO as out of cycle 15-EGL-017-03 8588 Target Appendix A in Transmission Reliability - Meeting LCTP: Construct new 230 kV line from new Bulk EGSL Summer 2018 Approved Scoping New Project to address reliability needs Summer 2018 MTEP15 (OOC) Planning Criteria Substation to Carlyss 230 kV substation in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycle 15-EGL-018 8589 Target Appendix A in Transmission Reliability - Meeting LCTP: Reconfigure Carlyss 230 kV substation into a EGSL Summer 2018 Approved Scoping New Project to address reliability needs Summer 2018 MTEP15 (OOC) Planning Criteria breaker and a half configuration in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycle 15-EGL-019 8590 Target Appendix A in Transmission Reliability - Meeting LCTP: Construct new 12 mile 230 kV line from Carlyss EGSL Summer 2018 Approved Scoping New Project to address reliability needs Summer 2018 MTEP15 (OOC) Planning Criteria to new 230 kV substation adjacent to Graywood. in the Lake Charles area due to projected growth. Being submitted to MISO as out of cycle 15-EGL-020 TBD Target Appendix A in Customer Driven Intracoastal 69 kV Substation: Install 150 MVA, 230- EGSL Summer 2016 Approved Scoping New customer requested project to Summer 2016 N/A MTEP15 (OOC) 69 kV autotransformer at Intracoastal and connect to provide an additional source into the Mud Lake 230 kV substation Intracoastal 69 kV substation 15-EGL-021 TBD Target Appendix A in Transmission Reliability - Meeting Carlyss to Sweet Crude Tap (L-238): Reconductor 69 EGSL Summer 2016 Approved Scoping New customer requested project to Summer 2016 N/A MTEP15 (OOC) Planning Criteria kV line (0.94 miles) to a minimum of 1200A. provide an additional source into the Intracoastal 69 kV substation 14-EGL-027 8284 A in MTEP14 Economic LETP: Richardson to Iberville - Construct new EGSL/ELL Winter 2018 Approved Scoping New project (Economic MTEP 14) Winter 2018 N/A N/A Richardson 230 kV substation new Dow Meter and construct new 230 kV line from Richardson to Iberville 230 kV substation. (EGSL Portion of project) 14-ELL-019 8284 A in MTEP14 Economic LETP - Richardson to Iberville - Construct new EGSL/ELL Winter 2018 Approved Scoping New project (Economic MTEP 14) Winter 2018 N/A N/A Richardson 230 kV substation new Dow Meter and construct new 230 kV line from Richardson to Iberville 230 kV substation. (ELL Portion of project)
Long Term Projects Page 4 of 7
APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)
Report Date: January 19, 2015 Project Current Included in Entergy Project MTEP MTEP Operating Proposed ISD Project Driver Project Name Funding Project Status Project Status Comments Projected Actual ISD Mitigation Plan if required Model?
ID Project ID Designation Company (Planning)
Status ISD (Yes/No) 10-ELL-008 N/A Pre-Planned Transmission Reliability - Meeting Southeast LA Coastal Improvement Plan: Phase 3 ELL Summer 2013 Approved Scoping Oakville Substation expansion placed 6/1/18 Planned NCLL until project completed Planning Criteria Construct Oakville to Alliance 230kV Line into service 9/3/12. Alliance Substation Add 230 - 115 kV Autotransformer at Alliance expansion and 230/115kV Auto placed Substation into service 1/16/14. T-Line routing challenges continue to delay start of ROW acquisition. Projected ISD delayed from 6/1/15 to 6/1/18. Awaiting conditional permit approval from LADOTD to construct line within their ROW for Hwy 23. Identifying location of two Parish water lines along west side of Hwy, continue discussions on ti f l ti li 11-ELL-001 N/A Pre-Planned Enhanced Transmission Reliability Golden Meadow to Leeville 115 kV - Rebuild/relocate ELL Spring 2014 Approved Construction T-Line ROW acquisition completed Dec- 3/31/15 N/A 115 kV transmission line 2013. The DNR-OCM permit was received in Nov-2013, and the USACE permit was received in Feb-2014.
Construction of driveway pads needed for the T-Line structures completed Oct-2014. T-Line construction is in 11-ELL-004 N/A Pre-Planned Transmission Reliability - Meeting Northeast LA Improvement Project Phase 3 ELL Summer 2015 Approved Construction Pre-Construction meeting held on 12/30/15 Planned NCLL until project completed Planning Criteria Upgrade Sterlington to Oakridge to Dunn 115 kV Line 1/09/15. Construction to start 1/15/2015 11-ELL-012 N/A Pre-Planned Transmission Reliability - Meeting Valentine to Clovelly 115 kV upgrade ELL Summer 2015 Approved Construction Design, material procurement, 5/1/15 Planned NCLL until project completed Planning Criteria permitting, and ROW access improvements complete. T-Line 12-ELL-004 4769 A in MTEP14 Load Growth Schriever: Construct new 230 kV substation ELL 2017 Proposed & Scoping Under Review 3/31/17 N/A In Target 13-ELL-004 N/A Pre-Planned Transmission Reliability - Meeting Minden Improvement Project Ph. 1-Place cap bank at ELL Summer 2015 Proposed & Scoping Will require co-ordination with Lagen on Summer 2015 N/A Planning Criteria Minden REA In Target final design and operation 13-ELL-006 4634 Appendix B Transmission Reliability - Meeting Ninemile to Westwego 115 kV: Reconductor Line ELL Summer 2020 Conceptual Conceptual Conceptual Summer 2020 N/A Planning Criteria 14-ELL-002 4635 Appendix B Transmission Reliability - Meeting Sterlington 115 kV Substation: Upgrade jumpers on the ELL Summer 2024 Conceptual Conceptual Conceptual Summer 2024 N/A Planning Criteria Sterlington to Walnut Grove 115 kV line (line 107) 14-ELL-006 4639 Appendix B Transmission Reliability - Meeting Ninemile to Harvey2 115 kV: Reconductor line and ELL Summer 2025 Conceptual Conceptual Conceptual Summer 2025 N/A Planning Criteria change station limiting elements Moved ISD back to from 2022 to 2025 14-ELL-008-1 4770 A in MTEP14 Transmission Reliability - Meeting ELL Underrated Breaker Project: Waterford 230 kV ELL Winter 2016 Proposed & Scoping Under Review Winter 2016 N/A N/A Planning Criteria S7145-CO In Target 14-ELL-008-2 4771 A in MTEP14 Transmission Reliability - Meeting ELL Underrated Breaker Project: Waterford 230 kV ELL Winter 2016 Proposed & Scoping Under Review Winter 2016 N/A N/A Planning Criteria S7154-CO In Target 14-ELL-009-1 4773 A in MTEP14 Transmission Reliability - Meeting ELL SPOF Projects: Modify relaying at Ninemile 230 ELL Summer 2015 Proposed & Design Project is in Design Phase - Kickoff Summer 2016 N/A N/A Planning Criteria kV In Target meeting to commence project has been held and schedule developed.
Currently scheduled to be completed by Summer 2016 barring availability of outages.
Long Term Projects Page 5 of 7
APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)
Report Date: January 19, 2015 Project Current Included in Entergy Project MTEP MTEP Operating Proposed ISD Project Driver Project Name Funding Project Status Project Status Comments Projected Actual ISD Mitigation Plan if required Model?
ID Project ID Designation Company (Planning)
Status ISD (Yes/No) 14-ELL-009-2 4774 A in MTEP14 Transmission Reliability - Meeting ELL SPOF Projects: Modify relaying at Southport 230 ELL Summer 2015 Proposed & Design Project is in Design Phase - Kickoff Summer 2016 N/A N/A Planning Criteria kV In Target meeting to commence project has been held and schedule developed.
Currently scheduled to be completed by Summer 2016 barring availability of outages.
14-ELL-009-3 4775 A in MTEP14 Transmission Reliability - Meeting ELL SPOF Projects: Modify relaying at Labarre 230 kV ELL Summer 2015 Proposed & Design Project is in Design Phase - Kickoff Summer 2016 N/A N/A Planning Criteria In Target meeting to commence project has been held and schedule developed.
Currently scheduled to be completed by Summer 2016 barring availability of outages.
14-ELL-009-4 4776 A in MTEP14 Transmission Reliability - Meeting ELL SPOF Projects: Modify relaying at Harahan 230 ELL Summer 2015 Proposed & Design Project is in Design Phase - Kickoff Summer 2016 N/A N/A Planning Criteria kV In Target meeting to commence project has been held and schedule developed.
Currently scheduled to be completed by Summer 2016 barring availability of outages.
14-ELL-009-5 4777 A in MTEP14 Transmission Reliability - Meeting ELL SPOF Projects: Modify relaying at Paris 230 kV ELL Summer 2015 Proposed & Design Project is in Design Phase - Kickoff Summer 2016 N/A N/A Planning Criteria In Target meeting to commence project has been held and schedule developed.
Currently scheduled to be completed by Summer 2016 barring availability of outages 14-ELL-016 4783 A in MTEP14 Customer Driven Haute 115 kV Substation: Construct new substation ELL Summer 2014 Approved Construction The Haute Substation is complete. 4/1/2015 N/A N/A and cut into existing Lutcher to Belle Point 115 kV line Project team has accelerate schedule to complete by 12/18/14 . Energization pending legal transfer of ownership.
14-ELL-018 7841 A in MTEP14 Customer Driven Reese Substation: Construct new 115 kV substations ELL Spring 2015 Approved Complete In-Service Spring 2015 12/17/14 N/A Yes 14-ELL-020 8284 A in MTEP14 Economic LETP: Panama Substation: Cut-in Bagatelle to ELL Winter 2018 Approved Scoping New project (Economic MTEP 14) Winter 2018 N/A N/A Sorrento 230 kV line 14-ELL-021 8284 A in MTEP14 Economic LETP: Romeville Substation: Upgrade line bay bus. ELL Winter 2017 Approved Scoping New project (Economic MTEP 14) Winter 2017 N/A N/A 15-ELL-001 7988 Target Appendix A in Transmission Reliability - Meeting Terrebonne to Gibson: Construct new 230 kV line and ELL Summer 2018 Proposed & Scoping New Project Summer 2018 MTEP15 Planning Criteria operate at 115 kV In Target 15-ELL-002 7970 Appendix B Transmission Reliability - Meeting Minden Area Improvement Ph. 2: Construct new 115 ELL Summer 2020 Proposed & Scoping New Project Summer 2020 Planning Criteria kV substation east of Minden REA and cut-in Minden In Target REA to Arcadia 115 kV line and construct new 115 kV lines to cut the Minden to Sailes 115 kV line in and out of the new substation Long Term Projects Page 6 of 7
APPENDIX D Entergy Long Term Transmission Plan (ELL and EGSL Projects)
Report Date: January 19, 2015 Project Current Included in Entergy Project MTEP MTEP Operating Proposed ISD Project Driver Project Name Funding Project Status Project Status Comments Projected Actual ISD Mitigation Plan if required Model?
ID Project ID Designation Company (Planning)
Status ISD (Yes/No) 15-ELL-003 7990 Appendix B Load Growth Luna: Construct new 115 kV substation ELL Winter 2017 Proposed & Scoping New Project Winter 2017 In Target 14-ELL-012 4779 A in MTEP15 (OOC) Transmission Reliability - Meeting Ninemile to Derbigny: Upgrade 230 kV line ELL/ENOI Summer 2016 Proposed & Scoping Project currently accelerated and 6/1/2016 N/A Planning Criteria In Target targeted for June 1, 2016 ISD. Lattice structure inspections to take place Spring 2015. Team meeting with conductor vendor, 3M, on 01.14.15 to determine installation logistics. Project may require funding out of process to support ISD.
14-ELL-013 4780 Appendix B Transmission Reliability - Meeting Ninemile to Napoleon: Upgrade 230 kV line ELL/ENOI Summer 2017 Proposed & Scoping New Project. Project currently 6/1/2017 N/A Planning Criteria In Target accelerated for targeted for June 1, 2017 ISD. Lattice structure inspections to take place Spring 2015.
Team meeting with conductor vendor, 3M, on 01.14.15 to determine installation logistics.
15-EMI-003 7904 Target Appendix A in Transmission Reliability - Meeting Natchez SES - Redgum: Rebuild 115 kV line EMI/ELL Summer 2018 Proposed & Scoping Under Review Summer 2018 N/A MTEP15 Planning Criteria In Target Long Term Projects Page 7 of 7
APPEENDIX E: 1ST S STAKEHO OLDER MEETING CHA ARTS1 Table 1: Scenaario Storylines 1
As requeested by Staff in th heir comments on the t Draft IRP Reporrt, the following th hree charts from the first IRP stakeho lder meeting held January 22, 2014, have been provide ed.
Since thesse charts were pro oduced the Scenario o names have beenn modified. Scenaario One was renamed to Industriall Renaissance in thhe November 2014 4 filing. The Industtrial Renaissannce scenario from the May 2014 filinng (Scenario Two) was w renamed to B Business Boom.
Table 2: 20 Year Market Modeling Inputs (20152034)
Scenario 1 Industrial Renaissance Distributed Disruption Resource Shift Electricity CAGR (Energy GWh) ~0.8% ~TBD% ~TBD% ~TBD%
Peak Load Growth CAGR ~0.8% ~TBD% ~TBD% ~TBD%
Low Case Same as Reference Case High Case ($8.18 levelized Henry Hub Natural Gas Prices ($/MMBtu) $4.89 levelized 2013$
$3.84 levelized 2013$ ($4.89 levelized 2013$) 2013$)
Low Case Medium High ($109.12 High Case ($173.71 levelized WTI Crude Oil ($/Barrel) $73.99 levelized 2013$
$69.00 levelized 2013$ levelized 2013$) 2013$)
Cap and trade starts in 2023 Cap and trade starts in 2023 Cap and trade starts in 2023 CO2 ($/short ton) None
$6.70 levelized 2013$ $6.70 levelized 2013$ $14.32 levelized 2013$
Conventional Emissions Allowance Markets CAIR & MATS CAIR & MATS CAIR & MATS CAIR & MATS Delivered Coal Prices - Entergy Owned Plants Reference Case Low Case Same as Reference Case (Vol. High Case (Plant Specific Includes Current Contracts) (Vol. Weighted Avg. (Vol. Weighted Avg. Weighted Avg. (Vol. Weighted Avg.
$/MMBtu $2.69 levelized 2013$) $TBD levelized 2013$) $2.69 levelized 2013$) $TBD levelized 2013$)
Delivered Coal Prices - Non Entergy Plants In Mapped to similar Mapped to Similar Entergy Mapped to Similar Entergy Mapped to Similar Entergy Plant Entergy Region Entergy Plant Plant Plant Reference Case Varies Low Case Same As Reference Case -
Delivered Coal Prices - Non Entergy Regions High Case - Varies By Region By Region Varies By Region Varies By Region Coal Retirements Capacity (GW)* TBD TBD TBD TBD New Nuclear Capacity (GW)* TBD TBD TBD TBD New Biomass (GW)* TBD TBD TBD TBD New Wind Capacity (GW)* TBD TBD TBD TBD New Solar Capacity (GW)* TBD TBD TBD TBD
Table 3: Proposed d Sensitivities fo or the LA IRP
APPENDIX F: AURORA DSM PORTFOLIOS BY SCENARIO AURORA DSM Portfolios by Scenario Industrial Renaissance Business Boom Distributed Disruption Generation Shift DSM1 - Residential Lighting & Appliances DSM1 - Residential Lighting & Appliances DSM1 - Residential Lighting & Appliances DSM1 - Residential Lighting & Appliances DSM3 - ENERGY STAR Air Conditioning DSM3 - ENERGY STAR Air Conditioning DSM3 - ENERGY STAR Air Conditioning DSM3 - ENERGY STAR Air Conditioning DSM4 - Appliance Recycling DSM4 - Appliance Recycling DSM4 - Appliance Recycling DSM5 - Home Energy Use Benchmarking DSM5 - Home Energy Use Benchmarking DSM5 - Home Energy Use Benchmarking DSM8 - Multifamily DSM8 - Multifamily DSM8 - Multifamily DSM8 - Multifamily DSM9 - Water Heating DSM10 - Pool Pump DSM12 - Dynamic Pricing DSM12 - Dynamic Pricing DSM12 - Dynamic Pricing DSM13 - Commercial Prescriptive & Custom DSM13 - Commercial Prescriptive & Custom DSM13 - Commercial Prescriptive & Custom DSM13 - Commercial Prescriptive & Custom DSM14 - Small Business Solutions DSM14 - Small Business Solutions DSM14 - Small Business Solutions DSM14 - Small Business Solutions DSM15 - NonResidential Dynamic Pricing DSM15 - NonResidential Dynamic Pricing DSM15 - NonResidential Dynamic Pricing DSM15 - NonResidential Dynamic Pricing DSM16 - Retro Commissioning DSM16 - Retro Commissioning DSM16 - Retro Commissioning DSM17 - Commercial New Construction DSM17 - Commercial New Construction DSM17 - Commercial New Construction DSM17 - Commercial New Construction DSM18 - Data Center DSM18 - Data Center DSM18 - Data Center DSM19 - Machine Drive DSM19 - Machine Drive DSM19 - Machine Drive DSM19 - Machine Drive DSM20 - Process Heating DSM20 - Process Heating DSM20 - Process Heating DSM20 - Process Heating DSM21 - Process Cooling and Refrigeration DSM21 - Process Cooling and Refrigeration DSM21 - Process Cooling and Refrigeration DSM21 - Process Cooling and Refrigeration DSM22 - Facility HVAC DSM22 - Facility HVAC DSM22 - Facility HVAC DSM22 - Facility HVAC DSM23 - Facility Lighting DSM23 - Facility Lighting DSM23 - Facility Lighting DSM23 - Facility Lighting DSM24 - Other Process/NonProcess Use DSM24 - Other Process/NonProcess Use DSM24 - Other Process/NonProcess Use DSM24 - Other Process/NonProcess Use
APPENDIX G: WIND MODELING ASSUMPTIONS In response to stakeholder comments regarding the assumptions used to evaluate wind resources in the IRP, the Companies have prepared this Appendix.
For purposes of the 2015 ELL/EGSL IRP, the delivered cost of energy from a wind resource developed in or near ELL or EGSLs service area (local) is judged to be comparable to the cost of energy from a remote1 wind resource (remote). While the capacity factors of remote resources are generally higher, the additional costs associated with transmission service and the differences in Locational Marginal Prices (LMPs) combine to generally equalize energy prices between local and remote resources. Additionally, all remote resources located outside of MISO carry an increased risk of unavailability compared to resources located in MISO due to MISOs emergency curtailment procedures of external systems. Risk associated with potential changes in rules, transmission, and market structures are inherently greater for a remote resource relative to a local resource based on intervening entities that would be involved in conjunction with the longterm nature of these resources.
For some factors, it is reasonable to apply the same assumptions for local and remote wind resources because they are not expected to be materially different. For instance, the installed cost is assumed to be the same. In addition, the nondispatchable, intermittent nature is expected to be similar and is expected to result in similar capacity credit awarded by MISO. The transmission interconnection cost to connect the resource to a nearby substation is unknown and would be dependent on the specific location regardless of whether the wind resource is local or remote; therefore, it is reasonable to ignore that cost because it is unknown, but expected to be comparable.
Other factors are expected to be different for local as compared with remote wind resources.
Key differences include capacity factor, transmission service cost, and LMPs. Assessment of each of these factors is discussed in turn.
Wind quality and speed in the midwest is expected to yield higher capacity factors as compared to local wind resources. Based on a National Renewable Energy Laboratory (NREL) cost and performance study published in 20102, the capacity factor for a wind resource in the midwest is assumed to be 50%; whereas, based on the same study, a local wind resource is only expected to be 34%. Thus, remote wind resources have an advantage over local wind resources with respect to energy production potential.
It is important to draw a distinction between transmission interconnection costs as described above and the transmission service cost necessary to make the wind resource deliverable to the Companies load. A local resource is not expected to require additional transmission service 1
For example, a wind resource located in Kansas or Oklahoma or other midwest location.
2 http://www.nrel.gov/docs/fy11osti/48595.pdf (Figure 96)
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charges to make it deliverable. However, a remote wind resource may require SPP pointto point transmission service to the MISO border and MISO pointtopoint transmission service to ELL / EGSLs load. Based on current MISO and SPP tariff rates, the combined cost of transmission service could be approximately $$5/MWh for offpeak hours4, $10/MWh for on peak hours4, or when adjusted to a wind generation profile, a weighted average of $7.11/MWh.
This transmission service cost and risk is not incurred by a local wind resource.
Wind generation is paid the hourly LMP at the generator bus while customers pay for energy based on the hourly loadweighted average LMP for the load zone. The difference between the load LMP and generator LMP is an estimate of the risk that customers are exposed to by having a remote resource as opposed to a local resource. To estimate the potential LMP differential risk, three representative SPP wind resources3 for 2014 were assessed, assuming a generic SPP wind profile. The LMP differentials in 2014 between these three nodes and ELL / EGSLs load (loadweighted average of EES.ELILD and EES.EGILD) are $12.92/MWh, $13.84/MWh, and
$17.07/MWh respectively, or approximately $14.60/MWh on average. A local wind resource is not subject to this potential LMP differential risk.
In summary, the table below shows a comparison of the cost of electricity of a local wind resource with a remote resource taking the differences in capacity factor, transmission cost, and LMP into consideration. In this example, the capacity factor advantage of a remote wind resource is almost completely offset by additional transmission service costs and LMP differential risk, which results in similar Levelized Cost of Electricity (LCOE) estimates for both remote and local wind resources.
Location Installed Fixed Charge Capacity Transmission LMP Differential LCOE ($/MWh)
Cost ($/kW) Rate (%) Factor (%) Cost ($/MWh) ($/MWh)
Local $2000 10.5% 34% $0 $0 $70.51 Remote $2000 10.5% 50% $7.11 $14.60 $69.65
= [A] = [B] = [C] = [D] = [E] = [F]
[F] = [A] x [B] x (1/([C] x 8760)) x 1000 (kW/MW) + [D] + [E]
From this assessment, the expected cost difference is approximately 1% between modeling potential wind resources with local assumptions as compared with remote assumptions. If inflation in the transmission service cost and LMP differential were taken into consideration, the local wind resource would have a lower LCOE as compared to the remote wind resource.
3 Keenan Wind Farm (Oklahoma Gas & Electric, OKGEWDWRDEHVUNKEENAN_WIND_RA), Centennial Wind Farm (Oklahoma Gas & Electric, OKGECENTWINDUNCENTWIND_RA), Spearville Wind Farm (Kansas City Power & Light, KCPLSPEARVILUNWINDFARM_RA). Historical LMPs by location obtained from SPP Integrated Marketplace (https://marketplace.spp.org/web/guest/lmpbylocation).
4 MISO transmission cost estimates calculated based on MISO OATT Schedule 7 year 2015 rates, as of July 2015. SPP transmission cost estimates calculated based on SPP OATT Schedule 7 Attachment T, as of July 2015.
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