PSEG Long Island Long Island Power Authority Rate Plan. Technical Conference March 3, 2015 LONG ISLAND

Transcription

1 PSEG Long Island Long Island Power Authority Rate Plan Technical Conference March 3,

2 Agenda Introductions Executive Summary Major Elements of the Three-Year Rate Plan Key Drivers of the Rate Adjustments (Slide 6) The Public Power Model, its structure, application and benefits (Slides 7-12, T. Falcone) Bond Coverage and the Phase In Benefits of Securitization and Financing Plan Treatment of Pension and Benefit Costs Development of the Rate Plan (Budgets, Revenue Requirements) (Slides 13-14, L. Figliozzi, G. Ahern) Rate Design Issues (COS/Rate Design/Tariffs) (Slides 15-24, J. Trainor) Revenue Decoupling Mechanism Rate Design Proposals (Including Delivery Service Adjustment, Gross Receipts Tax, Reliability of Data for Service and Demand Charges) 2 2

3 Agenda (cont d) Additional Rate Plan Elements and Issues on which Parties Request Further Explanation Power Supply (Slide 25, P. Napoli) Metrics (Slide 26, C. Gusick) Utility 2.0 (Slides 27-28, M. Weissman, M. Voltz) Long Island Choice Program (Slide 29, J. Trainor) Consumer Outreach, AMI (Slides 30-35, D. Eichhorn) Continuation of Underperforming Energy Efficiency Programs (Slide 36, D. Zaweski) Load Pocket Mitigation, including Alternatives to Generation and Other Infrastructure Improvements (Slides 37-41, N. Lizanich) Load Growth as a CapEx Driver (slides 42-43, N. Lizanich) PSEG LI FEMA Grant Implementation Plan (Slides 44-47, N. Lizanich) 3 3

4 Executive Summary The 3-Year Rate Plan was filed on January 30 th in accordance with the LIPA Reform Act (LRA) and the Amended and Restated Operations Services Agreement (OSA) The 3-Year Rate Plan Filing Achieves: Targeted investments in operations and infrastructure to support customer satisfaction, maintain reliability, improve storm response, enhance resiliency and move from a 4 th quartile to a 1 st quartile utility over five years Customer rates at the lowest level consistent with achieving customer satisfaction goals and sound fiscal practice. Transparent and comprehensive presentation of the operations of PSEG- Long Island (PSEG-LI) and the Long Island Power Authority (Authority) 4 4

5 Major Elements of the Three-Year Rate Plan Funds significant investments necessary to achieve the vision of LRA and OSA for first-quartile utility on Long Island over five years with modest rate adjustments All major rate classes receive 2% percent increases of the total bill each year or $3.25 per month for average residential customer Approximately % of delivery-only revenues Follows three years of no increases in delivery rates (three-year rate freeze) Low income customer discount will be increased to $10 per month for non-heating customers and $15 per month for heating customers, substantially mitigating the impact on eligible customers in 2016 Reforming the Energy Vision (REV) and Utility 2.0 are on a separate track Retail Choice and Power Supply Charge to be addressed in separate proceeding No major power plant anticipated to come online during rate plan period Substantial savings of estimated at $155 million during the rate period through proposed securitization legislation New finance policy will improve low bond ratings over five years, reduce debt relative to assets, and reduce customer cost during the rate plan 5

6 Key Drivers - Rate Adjustments Fund Investments in Creating a First Quartile Utility on Long Island Operational and front line service improvements to move from 4 th quartile to 1 st quartile over 5 years, including investments in customer experience, industry best practice tree trim and maintenance cycles, storm response, and reliability Infrastructure investment to support T&D reliability, IT investments that benefit the customer experience, and $730 million storm hardening and resiliency program (90% funded by FEMA) General increases in cost are targeted at inflation less 1% for productivity PSEG Long Island Fee pre-negotiated step up in 2016 Property tax increases on the delivery system are capped at 2% per year; no cap on National Grid PSA generation units; lower grant income due to collection of prior disaster recovery grants Investment in debt reduction improves the Authority s low credit ratings over five years and reduces debt relative to assets; public power model and securitization refinancing provides savings relative to what would have been collected through rates Cum. Change Operational Improvement $41.5 $7.0 -$3.5 $45.0 Infrastructure Investment $4.4 $18.8 $26.3 $49.5 General Increases -$2.1 $15.6 $17.9 $31.4 PSEG Long Island Fee $21.6 $1.3 $1.3 $24.2 Property Tax Increases $6.1 $6.2 $6.4 $18.7 Declining Grants $31.7 -$6.3 -$3.6 $21.7 Investment in Debt Reduction -$30.5 $31.7 $29.6 $30.8 $72.6 $74.3 $74.3 $

7 Benefits of New Business Model for Our Customers Experienced and Focused Utility Operator: realize 5-year vision of first class utility Savings from municipal financing: Continued access to tax-free debt, exemption from income taxes, and customer-owned utility saves customers approximately $400 million per year; Access to Federal and State Grants: $1.6 billion of grant agreements, including funding for 90% of $730 million storm hardening program and $35 million per year of State grants for efficiency; Savings from Securitization of Debt: $155 million savings during the rate plan through refinancing Authority bonds with lower cost UDSA bonds as proposed in the Governor s 2015 budget; Property Tax Savings: Pursuing litigation to reduce property tax assessments on legacy power plants and the inequitable property tax burden imposed on electric customers Non-Income Taxes as % of Total Revenue $ Million Long Island Power Authority 15.3% $549 Consolidated Edison 13.6% 1,403 Rochester Gas and Electric 9.3% 68 NYS Electric and Gas 7.4% 105 Orange and Rockland 7.2% 39 Central Hudson Gas & Electric 5.5% 40 National Grid 4.5% 105 New York State Average (excluding Authority) 10.4% 1,837 New York State Average (ex. Authority and ConEdison) 5.8% 433 7

8 Calculating Revenue Requirements for Public Power vs. Investor Owned Utilities P u b l i c P o w e r U t i l i t y R e v e n u e R e q u i r e m e n t s + Operating Expenses + Operating Taxes + Material Accruals (negative) + Debt Service principal + Debt Service interest + Debt Service coverage (funds capital projects in lieu of debt) I n v e s t o r O w n e d U t i l i t y R e v e n u e R e q u i r e m e n t s + Operating Expenses + Operating Taxes + Income Taxes + Amortization of reg. assets + Depreciation + Interest expense + Net income / Profit margin (paid to stockholders) For public power utilities, expenses are generally measured on a GAAP basis without the significant use of regulatory assets and liabilities; investor owned utilities make significant use of regulatory accounting Debt service coverage approach used for various types of public enterprises (e.g. public water utilities, toll roads, mass transportation agencies, etc.) 8

9 Public Power Model Results in Lower Rate Adjustments than Net Income Approach to Revenue Requirements Cumulative ($ millions) ($ millions) ($ millions) Impacts Requested Rate Adjustments 2.0% 2.0% 2.0% 6.0% Cumulative Delivery Revenue Adjustments Incremental Rate Request using Traditional Approach Net Income after Delivery Rate Adjustment $75 million Net Income Target (a) Additional Delivery Revenue Adjustments Annual Rate Adjustment with Traditional Model 5.7% 0.8% 1.0% 7.6% Lower Rates than net income (profit) based approach to utility ratemaking saving customers $281 million during 3-year rate plan Public power model does not seek to recover regulatory assets (prior cost deferrals) as required by a net income-based approach but instead targets coverage (as measured by rating agencies) Lower Debt and Higher Bond Ratings than historic approach; current bond ratings are the lowest of any major public power agency; rate plan reduces debt and cost to customers 9

10 Phased-In Coverage Targets During Rate Plan Result in Greater Rate Stability for Customers Coverage is calculated by the rating agencies as a margin on debt service and debt-like obligations such as capitalized leases; coverage instills confidence in rating agencies and investors that debt payments will be made (resulting in lower interest rates and customer bills) Coverage is then used each year by public power agencies to make a contribution to the capital program in lieu of borrowed funds (reducing future debt); all funds of public power utility retained or customer benefit (no funds paid out to third party owners) Coverage approach is consistent with the way rating agencies and investors view the Authority s financial performance the constituencies that determine the Authority cost of capital Phased-in minimum coverage requirements consistent with greater rate stability for customers and five year plan to maintain and improve the Authority s low bond ratings (lowest of any major public power agency) Authority Debt + Capitalized Leases 1.20x 1.30x 1.40x 1.45x Authority Debt + UDSA Debt + Capitalized Leases 1.15x 1.20x 1.25x 1.25x Coverage requirements are below those of other similar utilities but reflect Delivery Service Adjustments (DSA) for actual costs of debt service, power supply costs in delivery charges, and storm costs tradeoff between higher coverage and lower coverage plus DSA Financial policy consistent with sound fiscal operating practice and in the best interest of customers 10

11 Pending Legislation to Lower Cost of Authority Debt Through Securitization Reduces Rate Adjustments Up to $2.5 billion of existing triple-b debt could be financed at lower cost with triple-a securitization bonds during 2015 and 2016; savings (using forward yield curve) estimated at $155 million Debt service costs on existing debt during rate plan approx. $500 million per year after refinancing; any additional savings could reduce current or future revenue requirements Customers will realize actual savings achieved by refinancing via DSA 11

12 Pension and Retirement Benefit Costs Authority employees (40 staff) members of state retirement benefit plans PSEG Long Island employees (2,188 FTEs) receive benefits established by Collective Bargaining Agreements (unionized workforce) or substantially similar benefits as paid by National Grid (for transitioned employees). Non-union new hires receive 401(k)s Benefits are an obligation of PSEG Long Island; under OSA contract, Authority contractually responsible for cost Authority seeks to recover the cash contributions to the PSEG Long Island pension plans during the rate plan (vs. the GAAP cost) ERISA required substantial upfront cash funding to pension plan during 2014, significantly greater than the GAAP cost of the benefits in that year During , the cash contributions are less than the GAAP cost due to 2014 funding (i.e. the Authority s proposal results in lower electric rates) Authority has established an OPEB Account to pre-fund future contractual liability for retirement benefits other than pensions Contributions to OPEB Account in each year will be made from Coverage at actuarially determined rates rather than recovered in rates Authority has certain regulatory assets related to a 2013 National Grid settlement of retirement benefits for employees for period and deferrals of accruals. As with all regulatory assets, these costs are recovered in rates only to the extent that they were funded through borrowings 12

13 Development of the Rate Plan PSEG LI Operating Divisions (T&D, Customer Service, Shared Services, Power Supply, Energy Efficiency) Developed Operating and Capital Budgets Those Budgets Were turned Into Revenue Requirements and Rates by Incorporating: Input from HR Sales Forecast/Revenue at current rates Cost of Service/Rate Design/Tariff Issues Additional Elements of this Case not directly related to revenue requirements (future Power Supply planning, OSA Metrics, Utility 2.0/Energy Efficiency) 13

14 Development of the Rate Plan (cont d) Budgets, Revenue Requirements Development of PSEG LI Budget. Operating divisions provided the budget team with required headcount, activity levels, and other information supporting their budgets (e.g., expenses for contractors, M&S, any known changes). The budget team provided compensation and benefits loading information, O&M/capital allocation factors, general allocation factors and other relevant information to the development of the budgets for those functions on a FERC Account basis. Use of 2014 Data was neither practical nor appropriate was a transition year for PSEG LI and LIPA in which operations were still being transformed from operations under the MSA to the new operating model contained in the OSA. Operations in 2014 are therefore not representative of a full year of normal operations. Rather than using unrepresentative historical operating data, the rate plan is based on comprehensive, consolidated budgets supported by detailed testimony on behalf of the major operating divisions. Development of the Revenue Requirement: Remove non-cash expenses (e.g., pensions and OPEB accruals, depreciation, amortizations, and rate case deferrals) Add debt service (principal and interest) and fixed obligation coverage 14

15 Revenue Decoupling Revenue Decoupling will follow the Standard New York State Model Revenues Targets Set at Budgeted Revenues each year based on outcome of 3 year rate plan Future Year Revenue Targets subject to LIPA Board approval Revenue Decoupling includes Semi-Annual True-up with Out-of-Bound Testing during the 3 year rate plan No earnings cap required LIPA does not earn a profit; it only seeks to recover the level of revenues approved by the Trustees 15 15

16 RATE DESIGN PROPOSALS Residential Rate Changes Customer Charge set at $15, $17.50, and $20 in 2016, 2017, and 2018 respectively Low-income discount will be enhanced, introduce a larger heating discount Eliminate Inclining / Declining Block Rates -- LIPA currently has inclining block rates in the summer, declining in the winter. Will introduce a flat rate for Non-Heat Will introduce a flat summer rate for Heating Customers and declining in the Winter Will combine Rate Codes based on Non-Heat or Heat (180, 580 and TOU Rates Only) Seasonality removed for Rate 180 Rate Increase Allocated to Customer Charge and Winter Months 16 16

17 RATE DESIGN PROPOSALS (cont d) Commercial Rate Changes Removing Seasonality; Demand Rate, Energy Rate and Demand Ratchet the same all year. All Commercial Customer Charges will be reviewed and set by the Cost of Service Study based on typical costs for customer specific plant, meter reading, billing, call center and collections. Demand Rate Charges will increase to recover 50% of Revenue Requirement. Decrease in Energy Charge Positive impact on fixed cost recovery and Reduces intra-class cross subsidies No Change to design of TOU Rates including Rate

18 RATE DESIGN PROPOSALS (cont d) Delivery Service Adjustment Delivery Service Adjustment (DSA) would track the difference from budget to actual, not the total cost of the item. DSA would track the following costs: Delta Major Storms Reserve Funding (Bank / 3-Year Recovery) Delta Debt Service including fixed obligation coverage Delta Power Supply Costs in Delivery (PSA and NMP2) DSA would be an Annual Net Adjustment applied by Percent of Delivery First Tracking Period will only be nine months 18 18

19 RATE DESIGN PROPOSALS (cont d) Change to Gross Receipts Tax The current revenue tax calculation for Residential Customers transfers dollars between Commodity and Delivery charges before the respective tax rates are applied The Calculation for the transfers is based on the LI-Choice Delivery Rate Credit minus ($0.0392) Reason for transfer: To make a past rate adjustment revenue neutral. Reason to eliminate transfer: To cleanly apply the Commodity Tax Rate to commodity charges and Delivery Tax Rate to delivery charges 19 19

20 RATE DESIGN PROPOSALS (cont d) Reliability of Data Used for Customer and Demand Charges The Cost of Service Study uses 2016 Rate Plan Data PSEG detailed budgets done by FERC Account LIPA s budgets contain Power, Debt Service and A&G. All allocated using COS principles Plant data uses best available balances from depreciation study Cost of Service study uses standard COS doctrines for cost allocation Benchmarking Rates (next slides) 20 20

21 NY State Utility Rate Comparison 21

22 NY State Utility Rate Comparison 22

23 NY State Utility Rate Comparison 23

24 NY State Utility Rate Comparison 24

25 Power Supply Baseline Plan. Baseline power supply plan designed to ensure access to power supplies that meet NERC, NYSRC, NYISO planning and reliability standards, while also preserving all options to develop new electric generation or transmission projects currently under evaluation Base Delivery Rates. Base delivery rates in in the filing reflect (i)rates charged by Nat Grid under the PSA, (ii) LIPA s pro rata share of projected capital investments and O&M costs associated with Nine Mile 2, and (iii) costs for N-1-1 transmission projects on Long Island Integrated Resource Plan ( IRP ) -- In lieu of proposing additions at this time, PSEG LI is undertaking an IRP process that will enable us to make more definite assumptions about LIPA s future power supply requirements by December 2015 This will include evaluation of various options such as new on-island capacity, the potential repowering/replacement of existing capacity, possible transmission solutions, election of unforced delivery rights on existing transmission lines, and energy efficiency/renewables/storage/demand response activities 25 25

26 Metrics The OSA contains 21 performance metrics that measure PSEG Long Island s performance against specified operational and customer satisfaction goals Two Cost Management measures (cap, O&M budget); Eight Customer Satisfaction measures (e.g., JD Powers, customer surveys, abandonment rate) Five Technical and Regulatory Performance measures (e.g., SAIDI, CAIDI); Six Financial Performance measures (e.g., meter read rate, timely billing). Govern PSEG LI s incentive compensation, penalties against the fixed component of the Management Services Fee In 2014, PSEG Long Island met or exceeded all of the relevant measures except for one, the OHSA Recordable Incidence Rate metric 26 26

27 Utility 2.0/Energy Efficiency; Compliance with Reforming the Energy Vision (REV) Legal Requirement Utility 2.0 filed in 2014 per the LIPA Reform Act (Section f(ee)) and OSA, Section 4.2(A)(5), (A)(7) -- Requires LIPA/Service Provider to make annual filings related to implementing energy efficiency measures, distributed generation or advanced grid technology programs Rate Plan Submission The proposed Utility 2.0 Projects are described in the Rate Plan, as is LIPA Board s December 2014 approval of a 2015 operating budget including $2 million for Utility 2.0-related program development, and operating and capital budgets projections of $13.3 million and $3.9 million, respectively, for Utility 2.0 program implementation expenditures Support PSEG LI continues to strongly support Utility 2.0, and encourages the DPS to recommend the Utility 2.0 solutions in the currently pending Utility 2.0 Proceeding -- Conformance with REV The Commission-initiated REV initiative will lead to regulatory changes that promote energy efficiency, renewables like wind and solar, more DER (e.g., micro grids, onsite power supplies, and storage). The Utility 2.0 plan was developed to align to the extent possible with the REV initiative, PSEG LI is an active party to the REV Proceeding and intends to continue to be mindful of the policies and initiatives being developed in that proceeding and to incorporate them in future Utility 2.0 Plan annual filings that fit for PSEG Long Island 27 27

28 PSEG LI Utility 2.0 Program Timeline Program Title Targeted Load Pocket Initiative South Fork Glenwood/Rockaways Defer Key Capital Projects RFI/RFP market based solutions Advanced Metering Infrastructure 50,000 AMI to be installed. Program Description Summary Infrastructure deferment, IRP plan, DLC/ DER DR tariff. Leverage market based solutions AMI to be installed on largest customer segments and those described on slide 35 Program Timing Load Reduction (MW) 2015 South Fork 13 MW Glenwood 25 MW Rockaways 25 MW Throughout MW South Fork Microgrid Battery Storage Demand Response initiative Proposed demonstration project with DOE for battery storage on South Fork MW Expand DLC for MW residential AC and Pool Pump control/monitoring 28

29 LI Choice Program No Changes to LI Choice Programs at this time: pendency of the IRP, Capacity Market Study and separate Department review. Also, IT issues require careful consideration Some Fixed Power Costs (PSA and NMP2) will Remain in Delivery Rates ($537 Million) Will focus on being compliant with REV and other NY utilities Choice Programs, but may not be possible without releasing capacity DPS staff and ESCOs agree that a separate track for consideration is warranted 29 29

30 Consumer Outreach PSEG Long Island has a comprehensive program for consumer outreach that encompasses: Low Income Programs, Customer Education, State, Governmental and External Affairs, Corporate Communications and Media Outreach Mediums of Outreach Utilized: PSEG Long Island Website Blasts Social Media PSEG LI s Twitter and Facebook Pages Educational Videos Customer Information Materials Print, Radio and Online Customer Educational Materials Media Outlets Billing Inserts Legislative Outreach Community Partnership Program Billboards LIRR Platforms and Railcars Public Meetings Internet Pop Up Direct Mail Press Releases & Press Conferences Teleconferences (ie: pre/post storm calls with Government Officials) Outreach Storm Centers Automated Phone Messages IVR recorded messages 30

31 Consumer Outreach Scope of Outreach Low Income Programs PSEG Long Island Home Performance Program Customer Education and Information Customer Rights & Responsibilities Billing Services & Payment Alternatives Special Needs Customers Electric Safety Storm Outreach Plans Website, , Social Media & Mobile Applications Community Partnership Program Summer Demand Response/Load Reduction Energy Efficiency Programs State, Governmental and External Affairs Large project outreach and communication Storm Outreach and Plans Corporate Communications/Media Outreach 31

32 Consumer Outreach Additional Resources for Enhanced Outreach PSEG Long Island is requesting the following additional resources in the rate filing to enhance our current program: Enhanced Low Income Rate PSEG Long Island has proposed to increase the non-heat residential low income discount from $5.00 a month to $10.00 a month. 13,000 Non-Heat Residential Customers PSEG Long Island has proposed to increase the heat residential low income discount from $5.00 a month to $15.00 a month. 5,000 Heat Residential Customers Incremental Customer Education and Information Messaging PSEG Long Island has proposed to increase current spending levels in additional customer outreach spending each year. The increased funds are to cover: low income support, customer mailers, targeted outreach campaigns, educational videos/mailers/material, storm and emergency preparedness messaging. 32

33 AMI Strategy Objective and Current Capabilities Objective PSEG Long Island plans to leverage its current AMI program to enhance customer service, to improve operational efficiency and to provide a platform for the energy vision of the future without full-scale deployment Current AMI program capabilities 7,700 AMI meters deployed Highly successful AMI meter reading capability 99.7% daily register reads Automated meter read-to-bill process supports majority of LIPA tariff rates Successful remote connect and disconnect capability on Fire Island Web presentment solution allows customers to view daily consumption to manage energy Voltage, current and power factor monitoring supports tampering detection Current network coverage limits additional meter deployments 33

34 AMI Strategy Future Deployments Build network for system-wide connectivity Enables strategic deployment of AMI plan as proposed in rate case Deploy communications network for system-wide coverage 2015 implementation Rate Case (2016 to 2018) Policy Expansion All new meters installed as AMI (new customers, service changes and retirements) Approximately 40,000 residential meters per year Approximately 5,000 to 10,000 commercial meters per year Saturation Expansion Deploy AMI meters to address business needs Maximize customer benefits and control O&M costs Approximately 6,000 to 10,000 accounts per year (could vary depending on targeted accounts) 34

35 AMI Strategy Projections and Outcomes Through 2018 Over 30% commercial accounts completed O&M labor savings Addresses LTEs Reduces billing exceptions Approximately 15% of residential accounts completed Supports monthly meter reading Addresses unsafe accounts e.g. indoors, rear property, bad dogs, etc. Addresses LTEs Web presentment of energy data Upgrade PV net meters Supports system planning and operations Eliminate MV-90 legacy dial-up remote meter reading system. Complete function using AMI 1,500 C&I and load research reads 35

36 Status of Underperforming Renewable and Energy Efficiency Programs Underperforming Programs REAP Program Solar Hot Water Backyard Wind PA Cost Effectiven ess Ratio PA ratio 0.4 PA Ratio 0.1 PA Ratio 0.3 Current Status Income Qualified programs traditionally have had difficulty passting cost effectiveness test as they generally have higher labor costs and lower benefits Traditionally, measures focused on energy savings as opposed to capacity savings and measures offered typically had low coincidence factors Modified 2015 program design to make it more cost effective (2015 program has a 0.8 PA ratio) -- added RAC and Dehumidifiers for higher MW savings Low participation rates due to the requirement of customers having electric water heating -- small percent of customers with eletric water heating -- Discontinued program as of 2014 Not cost effective due to factors such as high incremental costs, system performance and maybe permit issues. Discontinued program starting only handling projects that were pre-approved and required Phase II rebates 36

37 Load Pocket Mitigation - Strategies for Mitigating Concerns Regarding Constrained Transmission Capability and/or Higher Load Growth Reviewing all projects for potential application of customer-side solutions Reliability requirements will determine type and feasibility of solution Competitive solicitations being developed to test market s ability to provide capacity relief for projects in a cost-effective manner with in-service dates necessary to support system reliability Three RFPs for major load area/nerc transmission projects RFI for five smaller regional transmission/distribution projects Information to be used to develop an experience base which increases with each successive round of solicitations. 37

38 Current Major Load Area RFPs: South Fork Need identified in Utility 2.0 filing ~$294 M Transmission investment identified starting in 2017 through 2022 Would allow for deferral date of need to install transmission lines to allow consideration of distributed generation and alternative REV type solutions REV Solutions under consideration 40 MW Solar FIT II--- only 21.3 MW contracted 13 MW of Guaranteed load relief South Fork RFP (technology agnostic) under development to further meet energy needs Microgrid concept 5 MW of battery 38

39 Current NERC Load Area RFPs Changes to NERC reliability standards require additional transmission reinforcement by 2020 PSEGLI is investigating use of distributed generation as alternative approach REV projects are being solicited based on load area characteristics to reduce size of incremental generation Rockaways: Identified in Utility 2.0 filing Targeting 27 MW of load relief: Market, distributed resources, energy efficiency Glenwood: New Region Supplement 2.0 filing - Per DPS recommendation Solicit programs to achieve target of 25 MW of load relief 39

40 Five Smaller Regional Transmission/Distribution RFIs Kings Highway Need to solve existing issues to allow for deferral of new substation Would require existing ~38 MW of load relief on five surrounding substations including seven distribution feeders As well as additional 25 MW of resources at Hauppauge Navy Road/Montauk Immediate need to solve existing issues REV solution would require 10 percent unloading at peak time of two 4kV distribution feeders Flooding and failing condition of equipment still needs to be addressed Hempstead Would allow for deferral of substation upgrade Would require 6 MW (~ 20 percent) capacity relief on three 4kV distribution feeders Riverhead to Eastport Would allow for deferral of reconductoring project Would require peak load relief of approximately 6-10 MW at two substations Plainview/Ruland Road Would allow for deferral of transmission project Would require approximately 20 MW capacity relief across two substations Lump load additions (e.g. Wang, Cannon, etc.) may require additional substation and new circuits 40

41 Transmission and Distribution System Modification or Distributed Resources as Economic Alternatives to Generation or Other Infrastructure Improvements Conventional modifications to minimize must run Holtsville GT generation Holbrook double bus tie Port Jefferson to Stony Brook reconductoring Elwood to Pulaski reconductoring State of the art sophisticated solutions in lieu of generation and/or transmission improvements to solve voltage collapse Dynamic devices at Holtsville and Wildwood installed in past. Distributed Resources/Utility 2.0 Programs Distributed resources combined with Utility 2.0 programs planned to avoid transmission needs in South Fork, Far Rockaway and Glenwood regions 41

42 Why is Load Growth Cited as a Capex Driver, but Growth Rate Only.1% Net DSM? Overall system growth is 2% LIPA programs, e.g., DSM, renewables, efficiency, drops system to 0.1% System growth rate masks how load is still growing in specific areas; Regional Growth, e.g. East End of LI growing 3% Lump load additions, e.g., Orchard - Garvies Point: 2 10 MW Flowerfield - SUNY R&D Park: 8 MW Barrett - Bay Park Sewage; 6-8 MW Sagitkos - Heartland (Wykoff) MW? Plainview/Old Bethpage- Country Point Development(Wang), Supreme Screw, Canon Expansion Nassau Coliseum: Phase I: 2MW. Police Academy: 2MW. Future Phases 42

43 Why is Load Growth Cited as a Capex Driver, but Growth Rate Only.1% Net DSM? (Cont d) Increased load growth due to change in building codes Allowed expansion in areas due to addition of sewage infrastructure, e.g., Hauppauge Projects that were originally identified and deferred Economy Resumption of development projects deferred due to 2009 depression Deferral due to lack of land to construct, Super Storm Sandy, and public outreach, e.g., Kings Highway Middle Island Berry Street Projects include those needed to address existing system constraints 69 kv reconductoring between Levittown to Plainedge Facilities at or near their existing capacity limits Riverhead to Eastport 69 kv reconductoring project 43

44 Areas Affected by Super Storm Sandy Related Power Outages 44

45 Flooding from Super Storm Sandy Severely Impacts Long Island s South Shore 45

46 Most Customer Outages in NYC Area Were the Result of Substation Flooding Substations in Flooded as a Result of Superstorm Sandy 46

47 PSEGLI FEMA Grant Implementation Plan LIPA has been awarded a $729M grant for mitigation on the T & D system 1. The elevating of substations damaged during Sandy ($9M) I. The mitigation work has already started at 6 of the stations (Arverne, Far Rockaway, Rockaway Beach, Long Beach, Park Place and Woodmere) II. The mitigation work on the remaining 6 damaged stations will be performed in 2015/ The hardening of transmission lines damaged by Sandy ($5M) I. Funding will rebuild portions of transmission lines damaged in Sandy 3. The installation of up to 1350 automatic sectionalizers ($75M) I. The installation of these devices will improve the resiliency of the system by reducing the number II. III. IV. of customers impacted by a single line outage. PSEGLI already has approximately 1350 automatic sectionalizers on the system The new devices will be intelligent devices that will be less reliant on operator interface to restore customer load. Some of the funding will be used for Auto Restoration scheme implementation and associated sophisticated controllers 4. The mitigation of mainline distribution circuits damaged during Sandy ($640M) I. Funding level is expected to address the rebuilding of 1025 miles of overhead construction II. Some combination of overhead and underground solutions is expected to maximize the benefit of this investment 47