Resource Planning Update. May 12, 2016 Board Meeting Presentation

Transcription

1 Resource Planning Update May 12, 2016 Board Meeting Presentation

2 Strategic Directive 9: Resource Planning The Board of Directors recognizes that the District will have to adapt to the rapidly changing electric utility business environment. The OPPD resource planning process will provide the resources and analytical capability to adequately assess OPPD s Integrated Resource Portfolio (or Supply and Demand Portfolio) to ensure reliable, competitive, cost-effective and environmentally sensitive service for our customers. To attain this goal, OPPD shall: Periodically assess, for strategic and integrated resource plans, OPPD s mix of generation assets, demand-side management programs, purchased power agreements and renewable energy resources. Utilize multiple scenarios to properly evaluate the range of risks posed by varying future assumptions such as, but not limited to fuel costs, economic growth, regulations and emerging technologies. Ensure all integrated resource strategic plans support and align with OPPD s Strategic Directives. 2

3 Strategic Directive 2: Competitive Rates The Board of Directors shall establish a rate target of 20% below the West North Central Regional average published rates on a system average basis. In implementing this rate target, OPPD shall adhere to these principles: Maintain fair, reasonable and non-discriminatory rates; Equitably assign costs across and within all customer classes; Pursue rate process and structure changes to reflect the cost of energy when it is used; Offer flexibility and options; Be simple and easy to understand; and, Encourage demand reduction and energy efficiency. 3

4 Strategic Trends Increased Regulations Sub 1% or Negative Growth Renewable Energy Investments Grid Modernization Distributed Generation Technology Customer Expectations Increased Cyber Security Employee Benefits Cost Pressures Revenue Growth Low Market Prices (gas and wind) Increased Energy Efficiencies Economic Pressures Continued Load Reduction 4

5 Overall Schedule 1/4/16 6/16/16 Resource Plan Schedule 4/30/16 9/1/16 CPP* Schedule 5/30/16 2/17 IRP** Schedule *Clean Power Plan **Integrated Resource Plan 5

6 Study Framework Questions What is OPPD s optimal rebalanced portfolio considering many market, regulatory, and technological futures? What current assets remain part of any optimal future OPPD portfolio? What is the cost of keeping the current assets in OPPD s future portfolio? What is the cost or benefit of delaying potential asset retirements? 6

7 Modeling Scope Rebalance the supply side assets Assess the economic viability of Fort Calhoun Station (FCS) Include an assessment of CPP impact 7

8 Technologies Considered by Optimization Gas Turbines (GE7FA, GE LMS100) Combined Cycles (2x1 GE7FA, 2x1 Advanced) Cogen Combined Cycles (Siemens 2000E, 5000FEE) NG Reciprocating Engines (Wartsila 1, 6, and 12 Unit 18V50SG) New Solar New Wind Long Duration Batteries (Zinc and Lithium Based) Energy Efficiency Programs (RIM Score over 1.0 by AEG study) Capacity and Energy Contracts (Thermal, Wind, and Solar) Extended Power Uprate (EPU) Excluded by Preliminary Analysis: Pulverized Coal, IGCC, Nuclear 8

9 Scenarios Investigated Scenario No CPP CPP Purpose Baseline FCS is not retired and NO4 and NO5 converted to natural gas in (FCS uprate is model option) X X Answers: What is the cost of business as usual? Rebalanced All capacity and energy options are considered. Keep existing contracts (PPAs, WAPA, NC2). Must meet renewable target of 30 50%. A wide range of resource alternatives are considered including FCS uprate. X X Answers: What is OPPD's optimum portfolio? 9

10 Optimized Portfolio Capacity Options 10

11 Key Findings FCS drops out of every case when given an option Additions are economically driven not compliance driven EPU is not economic other carbon free options are more economic OPPD is in a good economic position to comply with the current CPP regulation Constrained energy sales moderate market variability Stochastics confirm lower cost and risk associated with the rebalanced portfolio 11

12 System Accredited Capacity: No CPP Baseline 3,000 System Requirements DSM New DSM Renewable Energy 2,500 Fort Calhoun Wind New Wind NG Reciprocating Engines Gas CTs % Accredited System Capacity, MW 2,000 1,500 1,000 North Omaha North Omaha Conversion Nebraska City % % 500 Existing Gas & Oil Units Existing Contracts % Existing Contracts Existing Oil & Gas Nebraska City North Omaha North Omaha Gas Conversion Nuclear New Gas Turbines NG Reciprocating Engines New Contracts Battery Existing Wind New Wind DSM New DSM System Requirements 12

13 System Accredited Capacity: No CPP Rebalanced 3,000 2,500 System Requirements Capacity Contracts DSM DSM Batteries Wind NG Reciprocating Engines New DSM New Wind Renewable Energy % Accredited System Capacity, MW 2,000 1,500 1,000 North Omaha Nebraska City Gas CTs % % 500 Existing Gas & Oil Units Existing Contracts % Existing Contracts Existing Oil & Gas Nebraska City North Omaha Nuclear New Gas Turbines North Omaha Gas Conversion New Contracts NG Reciprocating Engines Battery Existing Wind New Wind DSM New DSM System Requirements 13

14 System Accredited Capacity: CPP Baseline 3,000 2,500 System Requirements Fort Calhoun Wind DSM New DSM New Wind NG Reciprocating Engines Gas CTs Renewable Energy % Accredited System Capacity, MW 2,000 1,500 1,000 North Omaha North Omaha Conversion Nebraska City % % 500 Existing Gas & Oil Units Existing Contracts % Existing Contracts Existing Oil & Gas Nebraska City North Omaha North Omaha Gas Conversion Nuclear New Gas Turbines NG Reciprocating Engines New Contracts Battery Existing Wind New Wind DSM New DSM System Requirements 14

15 System Accredited Capacity: CPP Rebalanced 3,000 2,500 System Requirements Capacity Contracts Gas CTs New DSM DSM New Wind Wind NG Reciprocating Engines Renewable Energy % Accredited System Capacity, MW 2,000 1,500 1,000 North Omaha Nebraska City North Omaha Conversion % % 500 Existing Gas & Oil Units Existing Contracts % Existing Contracts Existing Oil & Gas Nebraska City North Omaha North Omaha Gas Conversion Nuclear New Contracts New Gas Turbines NG Reciprocating Engines Battery Existing Wind New Wind DSM New DSM System Requirements 15

16 System Replacement Energy Fort Calhoun Generation 18,000,000 17,000,000 System Generation vs. Energy Requirements Baseline Nuclear, 100% New Addition Generation Wind, 42% Gas, 2% Not Required, 56% 16,000,000 15,000,000 14,000,000 13,000,000 12,000,000 11,000,000 10,000,000 9,000,000 8,000, Generation, GWh Rebalanced System Requirements Baseline No CPP Rebalanced No CPP Net System Requirements 16

17 Optimized Portfolio Model Results 17

18 Portfolio System Cost, NPV Differential Scenario No CPP CPP Baseline Reference $262M Rebalanced $994M $735M NPV cost calculations from

19 Risk vs Cost Tradeoff Lower Cost and Lower Financial Risk 19

20 Financial Impacts 20

21 Energy Sales Financial Assumptions Retail consistent with 2016 Corporate Operating Plan (COP) Off-system based on SPP energy prices Revenues Retail revenues are based on COP energy sales Off-system reflects updated SPP energy prices 21

22 Expenditures Financial Assumptions Operations & Maintenance and Capital COP Case updated to reflect market conditions Rebalanced Cases FCS discontinues operations in 2016 Decommissioning Options Decon beginning in 2016 with completion in 2025 Safstor beginning in 2016 with completion in

23 Financing Financial Assumptions COP Case Includes future debt issuances Rebalanced Cases No future debt issuances expected Rate Stabilization Reserve Rebalanced Cases Fund increased $34M 23

24 Financial Summary Discontinuing FCS operations results: Improved competitive position No projected general rate increases through forecast period Fuel and Purchased Power Adjustment (FPPA) will apply to future years and have not been modeled Potential need to reset energy rate within general rates Large write off of FCS Large net income loss in 2016 Increased debt ratio Stable debt service coverage and liquidity position Reduced financial risks 24

25 Net Income* $150 $100 $50 $0 $ Millions $(500) $(1000) COP Rebal COP Rebal COP Rebal COP Rebal COP Rebal Rebalanced COP Debt Retirement Account Use Rate Stabilization Account Use *Includes $977M write off for FCS plant investment less depreciation 25

26 Debt Retirement & Rate Stabilization Account Balances* $60 $50 $ Millions $40 $30 $20 $10 $ COP Rebal COP Rebal COP Rebal COP Rebal COP Rebal Rate Stabilization Debt Retirement *At year end 26

27 Debt Ratio 70% 60% Total Debt to Total Capital Ratio Target = 50% 50% 40% 30% 20% 10% 0% COP Rebal COP Rebal COP Rebal COP Rebal COP Rebal

28 Coverage Ratios 2.75 Total Debt Coverage Target >=2.00x COP Decon Safst COP Decon Safst COP Decon Safst COP Decon Safst COP Decon Safst Supports Board Strategic Directive Policy SD 3: Access to Credit Markets 28

29 Days Cash on Hand* 250 Total Days Cash on Hand Target >=100 Days 200 Days COPDecon Saf COPDecon Saf COP Decon Saf COP Decon Saf COP Decon Saf * At year end, excluding liquidity facilities Supports Board Strategic Directive Policy SD 3: Access to Credit Markets 29

30 Rate Target History* 0.0% OPPD Average Retail Rate Compared to Regional Average (2012 Present) 2.0% 4.0% 6.0% 8.0% 7.0% 6.1% 7.7% 6.7% 7.1% 10.0% 12.0% 12.9% 14.0% 15.3% ~$120 million gap 16.0% 18.0% 20.0% 17.4% 20% Target '12 '13 '14 '15 '16 '17 '18 '19 ' % OPPD % Below Regional Average Target *FPPA Adjustments Not Modeled Regional Average Source for EIA, IHS Global Insights 30

31 Keys to Success Effective implementation of Decommissioning Plan and staff reductions Continued implementation of OPPD Way cost reductions Maintain $250M Line of Credit and Commercial Paper program 31

32 Conclusion 32

33 Recommendations/Next Steps Continued pursuit of Rebalanced Portfolio Options Long Term Capacity Replacement Utilize Integrated Resource Plan and Stakeholder process to finalize replacement options Short Term Capacity Replacement Utilize North Omaha 1-3 on natural gas during peak load periods Purchase available low cost excess capacity from other SPP participants Cease operations at FCS by December 31, 2016 Decommissioning methodology recommendation is to be presented at the June 16, 2016 Board Meeting No projected general rate increase through 2021; creating the path to achieve rates that are 20% below the regional average 33

34 Closing This was a difficult decision to recommend, but the right decision for the customer-owners The recommendation is not reflective of employee or Exelon performance This recommendation is reflective of the changing energy market landscape, the economies of scale of a small nuclear plant, and existing nuclear was not considered in the CPP 34

35 These decisions will allow OPPD to pursue our vision of leading the way we power the future 35