FMPA Strategic Planning Session Ten-Year Plan

Transcription

1 FMPA Strategic Planning Session Ten-Year Plan Board of Directors and Executive Committee February 13, 2019

2 Session Outline What We ve Achieved and What s on Horizon 1. Review of Vision, Mission and Values 2. Review of February 2017 Strategic Priorities 3. Review Strategic Planning Material and Identify Potential Priorities A. Drivers of FMPA and Member Businesses Low Cost, Reliable and Clean B. FMPA Talent Management C. Ten-Year Resource Plan D. Environmental Responsibility E. Asset and Capital Plan and Rate Projections F. FMPA Risks and Opportunities G. Review Overall Electric and Natural Gas Market Outlook 4. Lunch 5. Review and Categorize Identified Potential Strategic Priorities 6. Develop Consensus on Top Strategic Priorities for Next 2 Years 2

3 Review of Vision, Mission and Values 3

4 Vision and Mission VISION Board: Being the preferred power and service provider for municipal electric utilities and the company of choice for employees. EC: To be the lowest cost, sustainable wholesale power provider in Florida. MISSION To provide competitively priced, reliable power and value-added services for FMPA s owner-customers through joint action. 4

5 Values Trust built through honesty, integrity, openness and respect Innovation and excellence Teamwork among employees and members-owner-customers A culture that values our employees and operating agents safety Cultural diversity Employee recognition, reward and empowerment Environmentally responsible operations Commitment to public power Transparent and effective communication The individual needs and desires of FMPA s owner-customers shall be given the strongest consideration consistent with the best interests of all owner-customers 5

6 Review of February 2017 Strategic Priorities 6

7 We ve Made Good Progress Since 2017 Good Success, and More Work to Do Rank Strategic Priority Steps Taken 1 Lower cost to ARP members 130 MW in excess sales to Bartow & Winter Park ~$50M in direct budget savings Implementing ongoing debt restructuring strategies 2 Enable member choice without negative impact to other members 3 Rate Making: Better align costs, develop load attraction rates 4 Work to tell the positive FMPA story and reduce negative perceptions 225 MW Solar Project and solar surcharge approach Vero Beach solution Var. O&M cost move approved by EC LAIR and EDR rates approved Narrow the rate spread program Dramatically improved FMPA s positive perception in traditional media and social media Enhanced public relations material and staff stakeholder engagement 7

8 We ve Made Good Progress Since 2017 Success, More Work to Do on Strategic Items Rank Strategic Priority Steps Taken 5 Enhance Member Services in technical, operational, compliance, and IT areas 6 Maintain/improve bond ratings 7 Develop strategic relationships for cost reduction 8 Employee development, retention and succession planning New Managers of Member Services with technical experience Expanded project management efforts Hurricane response support Several debt refundings completed St. Lucie Debt Strategy implemented which reduced debt by $161.5M Terminated BOA Forward Sales Agreement Solar PPA takes advantage of ITC Explored potential expansion of Pool Preliminary strategic transmission Training goals last two years included leadership/management training Revised policies/handbook 8

9 Drivers of FMPA and Member Businesses 9

10 Overview: Muni Challenges Increasing More to Achieve with Limited Resources Working to lower cost on retail front while Continuing to improve reliability of power system and managing staffing retention challenges (e.g. linemen) Increasing new workload (e.g., IT, compliance, new technology, communications) Responding to increased customer expectations (service options, rate structures, day-to-day communications, and engagement during emergencies) Addressing onset of distributed generation (rooftop PV) and associated rate design and equitable cost recovery issues Goal of increasing the member electric utilities value to each of their communities 10

11 Key Expectations at Wholesale & Retail Provide Low-Cost, Reliable and Clean Power LOW-COST POWER Customers Need It RELIABLE POWER Customers Expect It CLEAN POWER Customers Want It 11

12 Low-Cost Power: Customers Need It Income Below Average in Most FMPA Cities 2017 Real Personal Income per Capita Thousands Omitted $80 $70 $60 $50 $40 $30 $20 $10 $0 80 Key West Jax Beach Lake Worth Jacksonville U.S. $51,800 Florida $48,000 Homestead Alachua Gainesville Orlando Winter Park New Smyrna Tallahassee Leesburg Mount Dora Ft. Pierce Ocala Bartow Lakeland Williston Havana Kissimmee Chattahoochee Muni Weighted $43,700 Quincy Starke Clewiston Newberry Wauchula Blountstown Moore Haven Green Cove Bushnell Ft. Meade SOURCE: Woods and Poole Economics, Inc. and U.S. Census Bureau (adjusted to 2017 dollars) 12

13 FMPA Rates Down 32% Since Fiscal 2009 Electricity Prices Nationally Increased 11% All-Requirements Project Power Costs Average cost per 1,000 kwh billed by fiscal year $ $94.60 Lowest Billed Year Since 2004 $83.20 $79.40 $85.90 $81.80 $72.80 $71.90 $77.10 $

14 ARP Rates Competitive With Other JAAs More Work to Do to Get in Lower Third Annual Average Power Supply Costs by JAA (2017*) Average cost per 1,000 kwh billed. Source: PFM Financial $98 $81 $78 $77 $77 $77 ARP 17 $73 $73 $72 $70 $69 $69 $67 ARP 18 $64 *Santee data reflects 2016 operations. WPPI serves portions of MI, IA. 14

15 Florida Residential Cost Competitive Hydro-Rich Northwest Resource Advantaged Residential Average Cost, cents per kwh MA 21.6 CT 21.3 NH 19.6 RI 20.3 NJ 15.5 VT 18.0 MD 13.4 DE 12.6 DC 12.7 > 15 cents cents < 12 cents SOURCE: U.S. Energy Information Administration, 2018 average

16 Retail Rates Competitive, Could Improve There s More We Can Do We re Not Satisfied Residential Bill Comparison Cost per 1,200 kwh, Calendar Year 2013 vs 2018 Average Rate $160 $145 $130 $115 $ $ IOU Weighted Average Rate up 7% Muni Weighted Average Rate down 4.2% $ $ $ $ $ $ $ $ $100 ARP Weighted Average* Muni Weighted Average* FPL TECO Duke Florida 2017 and 2018 FMPA All-Requirements Project (ARP) and Muni rates weighted by 2017 annual load 16

17 Municipals Low-Cost Provider in Each Category No ARP Cities Lowest Cost Provider Rate Class Utility 1,000 KWH WAUCHULA 1,200 KWH CHATTAHOOCHEE 2,500 KWH CHATTAHOOCHEE Non-Demand 750 KWH TALLAHASSEE Non-Demand 1,500 KWH TALLAHASSEE 30 KW - 6,000 KWH LAKELAND 40 KW-10,000 KWH LAKELAND 75 KW - 15,000 KWH MT DORA 75 KW - 30,000 KWH LAKELAND 150 KW - 30,000 KWH MT DORA 150 KW - 60,000 KWH LAKELAND 300 KW - 60,000 KWH MT DORA 300 KW - 120,000 KWH LAKELAND 500 KW - 100,000 KWH MT DORA 500 KW - 200,000 KWH QUINCY Source: FMEA retail bill comparison data, Calendar Year 2018 Average Rate 17

18 Summary of the Low Cost Mission FMPA s costs have decreased significantly Some municipals have very competitive rates On average, municipals are lower than IOU average, but most municipals not as low as the lowest IOU There is more that could be done to have all municipals rate competitive, is this a focus area? Besides lowering wholesale power costs, what could FMPA do to help drive competitive costs? 18

19 Reliable Power: Customers Expect It Munis Good at Reliability; IOUs Making Strides After storms, municipals perform excellently Some municipals excellent in reliability indices Municipal performance on some reliability indices show widespread results Some municipals could benefit from implementing best practices (e.g., GIS mapping, tree trimming, pole inspection, etc.) 19

20 Reliability Benchmarks Coming Down Biggest Trend Is FPL s Notable Improvements FPL Since 2011 Duration. 32% Repair Time. 27% Frequency 7% Momentaries. 57% Key Drivers System hardening Best Practices Distribution automation 2017 Reliability Indices First place in green, second place in yellow Indices FL Muni FPL Duke Duration Repair Time Frequency Momentaries Length Gulf Power was first. 2 FPUC was first. 20

21 Distribution Hardening Pays Dividends Hardened Performed Significantly Better 3,000 2,500 2,000 1,500 1, FPL Pole Failures Hardened Non-Hardened Matthew Irma Feeder outages were 32% lower for Matthew, 16% lower for Irma Feeder restoration was 50% faster for Irma Wrong trees in the wrong place cited as primary cause of outages, along with storm surge for Irma Source: FPL PSC Presentation (May 2, 2018) 21

22 Best Practices Important for Reliability Advanced Technology Can Help, Too Other Best Practices Comprehensive maintenance program (e.g., GIS mapping, vegetation management, pole inspection, visual/infrared inspection) Targeted system hardening and undergrounding Wildlife mitigation Use of reclosers and TripSavers Smart Grid/AMI Benefits Automatic fault locating, isolation and service restoration (FLISR) Data from grid sensors used to predict failures Equipment monitoring optimizes equipment use/extends life Water meter leak detection 22

23 Customers Want Outage Information Proactive Communication Impacts Satisfaction Proactive communications, primarily delivered through digital channels are having a significant positive impact on customer satisfaction. The more proactive electric utilities are in clearly communicating [outage] information, the more satisfied their customers will be. J.D. Power Residential Electric Utility Customer Satisfaction Survey,

24 Craft, Technical Employees in Demand Some Cities Challenged to Attract, Retain Talent Reliability improvement programs require resources and expertise to implement successfully FMPA Salary Survey 2018 Journeyman Lineworker Salary for 16 Cities by Utility Size $90,000 $80,000 $70,000 $60,000 $50,000 Regional Comparisons Fla. Muni. Average $68,400 Southeast Average $72,400 National Average $81,200 $40,000 $30,000 $20,000 $10,000 $ Small Members Medium Members Large 24

25 NERC Regulatory Compliance if all they have is a hammer, everything looks like a nail Mandatory NERC Reliability Standards Over 1,400 requirements/sub-requirements Zero tolerance for non-compliance NERC s corporate goals in 2019 include: Integrating Internal Control reviews in all audits and spot checks Potentially adding new standard requirements for numerous priority risk areas FRCC transition to SERC July 2019 This Photo by Unknown Author is licensed under CC BY-NC-ND Compliance expertise and resource needs remain high 25

26 Cyber Security & Information Technology Threats evolving & Costs growing Security and Technology changing rapidly: Malware, ransomware, denial-ofservice attacks Phishing and social engineering Data identification and protection Penetration tests Cloud-based services Software and hardware upgrades Skills sets are changing and talented resources scarce 26

27 Summary of the Reliability Mission FMPA works to supply reliable wholesale power Many reliability initiatives are at the retail level Some systems challenged to address best practices Compliance, cyber, IT requirements escalating Is there an opportunity for member support on reliability initiatives? Is there a need for member support in compliance, cyber and IT areas? Typical Best Practices Tree trimming Pole inspection System map/gis Five-year plan Fuse coordination Hardening Automation AMI/Smart Grid Communications 27

28 Clean Power: Customers Want It But Most Don t Want to Pay More For It Florida has outstanding air quality and FMPA s fleet is very clean Interest in renewable energy continues to grow with solar focus in FL ~70% of customers interested in solar but only ~15% committed to paying more Utilities have an opportunity to provide cost-effective solar subscriptions to satisfy interested customers Current utility rate structure not suited for distributed generation 72% of residential customers believe there is a need to investigate solar SOURCE: 2017 FMPA Solar Energy Survey Market Assessment Study 28

29 FMPA Has a Clean Generation Fleet Emissions Below U.S. Averages by 59% & 82% NO x 59% Below U.S. Average Lbs./MWh, all generation, 2017 data SO 2 82% Below U.S. Average Lbs./MWh, all generation, 2017 data U.S. Florida FMPA Cane Island Treasure Coast U.S. Florida FMPA SOURCE: 2017 Annual Acid Rain Program 29

30 Utility-Scale Solar Low-Cost Solution Community Solar Is Much Lower Cost Utility-scale solar higher cost than running existing low-cost, naturalgas fueled units Utility-scale solar costs 1/3 the cost of rooftop solar Utility-scale solar subscription of interest to some customers Customers only pay a small adder to their electric rate Eliminates needs to add structures on roof-tops 4 Ideal for multi-family, low income 2 and homes not suited for rooftop Cents Per kwh Cost Natural Gas SOURCE: NREL, FMPA Utility Solar Rooftop Solar Rooftop Solar without ITC 30

31 Majority of Power Delivery Costs Fixed Traditional Cost of Service Not Aligned Transmission 7% Fuel Transport 7% Wholesale Power Cost Non-Fuel O&M 10% Other 3% Debt 40% Fuel 30% Variable O&M 3% Security 2% Cons. 3% Capacity 12% Fuel 32% Residential Enviro. 1% Customer 7% Energy 43% 60% or more of costs are fixed, and distribution is almost entirely fixed Over 90% of recovery is variable Source: Duke March 2018 rates for 1,000 kwh 31

32 Customer Charges at IOUs Moving Up Forward Looking Municipals Increasing $50 $45 $40 $35 $30 $25 $20 $15 $10 $5 $0 Beginning of Year Residential Customer Charge In January 2018, customer charges for Florida municipals and IOUs ranged from $3.50 to $ Co-Ops (Min) Duke Co-Ops (Max) Gulf FPL TECO 32

33 Summary of the Clean Mission Florida has very good air quality; FMPA fleet very clean Interest in solar generation growing in Florida with major IOU additions coming Opportunity for all utilities to offer low-cost solar subscription option to meet growing desire Is there a joint-action role to help municipals provide the clean power options customers want? As distributed generation grows, it is critical for utilities to price their service correctly. Interest in assisting members to alter rate structures to better match costs? 33

34 FMPA Talent Management 34

35 FMPA Age Demographics We Require More Expertise Age of FMPA Staff by Group Vertical Axis Reflects Count of Employees in Group <

36 Staff Changes for 2017 and Full time staff How they were filled 19 Left 7 Promotions or Repurposed 12 Filled Externally 36

37 FMPA Hires More Experienced Staff Enhance Ability to Serve Members 7 Years of Experience for New Hires Over Past 2 Years >20 37

38 Eligible Retirees 35% of Staff in 10 Yrs. Includes Executives and Directors 9 Eligible to retire now Including 1 Executive, 1 Manager 6 Eligible to retire in 5 years Including 1 Executive, 2 Directors, 1 SME 10 Eligible to retire in 10 years Including 3 Executives, 1 Director, 1 Manager 38

39 Four Critical Positions Identified Near Retirement Eligibility Areas of Expertise Qualified by Age Qualified by FMPA Successor Identified Communication >10 years Yes Yes Power Pool >5 years Yes Yes Compliance/IT >5 years Not Eligible Yes Human Resources >10 years >2 years No 39

40 Top Performers Identified Seventeen Staff Promotable One Level Five Promoted This Year Potential Leaders/Subject Matter Experts Continue Training & Development 40

41 Sharing Plant Skills Has Strategic Value Increase Reliability, Lower Costs, Develop Team Utilize all 70 plant staff among the three plant sites during regular operations and outages Multiple Benefits Quality work Lower costs Maximize plant operations Efficient utilization of staff skills Enhance staff development 3 sites, 1 unified team One Example: Staff from Cane Island helping at Treasure Coast in

42 Summary of Talent Management FMPA requires more expertise than before FMPA turnover created opportunities for repurposing positions and promotions Developing our top talent is still a priority Fleet sharing is making us more efficient Increased Member Services requires more expertise Significant changes in direction and pace require more active employee engagement 42

43 Ten-Year Resource Plan 43

44 Rates Competitive But Can Improve ARP Projected Ten-Year Rates Gas-Price Driven Overall rates are reasonably competitive, but still need improvement which will happen 2 3 years Rates are driven by gas prices and assumed to stay in $2.75 $3.50/MMBtu range ARP no need for significant new capacity until 2028 Several capacity decisions during next 5 years Capacity need involves comparison of market alternatives/prices to load management and solar Some opportunities for sale of extra energy 44

45 Future Load Growth 45

46 ARP Energy Grows at 0.9% Per Year Down From 1.2% Expected in 2016 Forecast Projected ARP Delivered Net Energy for Load (GWh) Source: 2018 FMPA Load Forecast (Fiscal Year) Excludes Wholesale Actual Forecast 7,000 6,500 6,000 Pre-Recession ( 98-06): 2.3% Post-Recession ( 12-17): 1.2% 2017 drop = Irma & Mild Winter 5,500 5,000 4,500 4, Note: Historical reflects Current Participants (excludes zero CROD). 46

47 Some Members Growing, Some Not 2017 Not Good Growth Basis (Irma/Winter) Member Weather-Adj. ( 12-16) CY Actual Growth ( 13-17) FY FY 2017 Actual NEL (GWh) Newberry 2.8% 2.8% 35.9 Kissimmee 2.0% 3.2% 1,580.6 Ft. Pierce 1.2% 1.7% Ocala 1.0% 1.1% 1,296.4 Keys 0.6% 0.9% Starke 0.4% 0.5% 70.0 Bushnell 0.2% 1.1% 24.3 Havana 0.0% -1.0% 23.6 Leesburg 0.0% 0.9% Clewiston -0.1% 1.5% Ft. Meade -0.3% 0.3% 41.1 Jacksonville Beach -0.5% 0.2% Green Cove Springs -1.2% -0.8%

48 Some Members Growing, Some Not More Members with Positive Change Utility Sales Growth CY Homestead 5.5% Lake Worth (thru 14) 3.4% Alachua ( 14-17) 2.9% New Smyrna Beach 2.2% Orlando 2.2% Moore Haven 2.2% Lakeland 1.6% Bartow 1.2% Gainesville 1.1% Utility Sales Growth CY Wauchula 0.9% Williston 0.7% Tallahassee 0.6% Chattahoochee 0.6% Jacksonville 0.5% Mount Dora 0.4% Winter Park 0.4% Quincy -1.3% Blountstown ( 14-17) -2.1% Seminole grew (w/o Lee) at 1.1%, Duke Energy Florida grew at 0.9% and FPL grew at 1.4%. 48

49 Forecast Customers Key Growth Driver Some Members Growing Much Faster Compound Average Growth in Residential Customers Projected ( ) (%) 10.0% 9.0% 8.0% 7.0% 6.0% 5.0% 4.0% 3.0% 2.0% 1.0% 0.0% Bushnell w SECO Impact ARP Avg. Electric Vehicles projected load impact limited (~1% to 2% through 2027). Bushnell w/o SECO Impact Bushnell w/seco Kissimmee Newberry Green Cove Sprgs Ocala Leesburg Ft. Pierce Keys Energy Ft. Meade Beaches Energy Bushnell w/o SECO Clewiston Havana Starke 49

50 Customers Grow More Steadily Per Meter Consumption Flat to Declining Change by Year in Residential Customers and Usage (%) 10.0% 8.0% 6.0% 4.0% 2.0% 0.0% -2.0% -4.0% -6.0% -8.0% Severe Winter Customers Under-occupied accounts (e.g. foreclosures) Usage Warm Summers 50

51 Economy is Turning the Corner Key Metrics Suggest Optimism for Future Economic Indicator Home Price Index ($2016) Gross State Product ($M) ($2009) Unemployment (%) Total Employment (000s) Construction Employment (000s) 2008 Value 2012 Value 2018 Value 213, , ,500* 764, , ,122* 6.3% 8.5% 3.7% 10,297 10,256 12, Tourists (millions) * * Reflects most recent data available (2017). Sources: FL Assoc. of Realtors, Bureau of Economic Analysis, Bureau of Labor Statistics, Woods and Poole Economics, Visit Florida 51

52 Supply and Demand Balance 52

53 ARP Has No Capacity Needs Until 2028 Capacity Needs of ~ MW Thereafter 2,000 FMPA 2019 Load and Resource Balance (15% Reserves) (MW) (87) (222) (237) (255) (275) (292) 1,800 1,600 1,400 1,200 1,000 Stanton A Oleander Peaking Small CC Coal Solar Stanton A Extension* Large CC Nuclear * FMPA does not expect to renew Stanton A PPA at current rates. 53

54 ARP Long Baseload Supply New Resources Will Be Peaking 1,800 1,600 1,400 1,200 1, Winter Cane Island 2 Stanton A FMPA ARP Resources Compared to Load (2018) (MW) Peaking Coal Summer Mild Day Large CC Nuclear

55 Solar Reduces Net Load in Key Hours Future Phases of Solar Will Have More Impact 1,800 1,600 Winter FMPA ARP Resources Compared to Load w/pv (2018) (MW) Summer 1,400 1,200 1, Mild Day

56 Increased Solar Impacts Load Shapes Will Require Fast Ramp if Solar Output Drops 4,000 3,500 Summer Peak Load Shape for FMPP (2020) (MW) As solar output grows, ramping risk increases. Could lose several hundred MWs in 15 minutes. 3,000 2,500 2,000 Load w/o Solar Load Net of Solar 2x More Solar 3x More Solar 1, More quick start resources or firm load management will be needed. 56

57 Muni Market Opportunities Continue Higher Margin Options vs. FMPP at Cost Municipal Power Supply Contract Termination Timeline 300 Contract Amount (MW) Williston Wauchula ALACHUA REEDY CREEK 0 Mt. Dora Chattahoochee HOMESTEAD Dec-2019 Dec-2020 May-2021 Mar-2022 Dec-2023 Dec-2024 Termination Month 57

58 Key Decisions Within Planning Horizon Market Alternatives Will be Explored Decision Implication Alternative(s) Cane 1 and 2 TARP Consider retirement relative to TARP obligations and loads Excess sales obligations serve as data point Stanton A PPA Oleander PPA 81 MW expires at end of 2023 unless it is renegotiated Notice given not to extend, ends after 2027 Seek market alternative on an as-needed basis Seek market alternative on an as-needed basis Advanced Gas Path for Workhorse CCs 15 MWs of increased capability per unit at low cost None AGP planned for at least 2 large fleet CCs DSM/Firm Interruptible Load Stanton 1 and 2 Potential Retirement Alternative to self-build or market capacity Pushes up capacity need with limited time for market discovery Market capacity if market capacity is cheaper Increase market capacity or explore addl. resources 58

59 Super-Peak Periods Generally Known ARP Almost Always Summer Peaking Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec , , , , , , , ,026 1,067 1,070 1, , ,091 1,144 1,146 1,125 1, ,024 1,149 1,182 1,202 1,175 1, ,044 1,182 1,202 1,243 1,211 1, ,047 1,191 1,212 1,266 1,235 1, ,059 1,192 1,209 1,262 1,234 1, ,036 1,168 1,181 1,228 1,212 1, ,118 1,140 1,192 1,158 1, , ,054 1,065 1,130 1,103 1, , ,003 1,013 1,075 1, , , Load Heat Map 2018 ARP Load Shape (MW) 59

60 Load Management Has Good Potential Could Shave ~2% from ARP Peak Someone Agrees To It Market Economic (It s Cost Effective) Technical (It s Possible) Recent study* suggests market potential savings range from 2% -3.5% on a cumulative basis Assuming half of that over ten years, ~1.75% of ARP Peak or ~25MW of market potential Various options have different levels of cost effectiveness * Source: DSM Potential Study (March 2017) (KU & LGE) (Cadmus) 60

61 Member Load Management Avoid Peak Looking for Low Cost Capacity Options Continue to Incent Most Hour Energy Sales Municipal activities to avoid FMPA peaks (e.g. pumping water, sewage processing, etc.) Retail customer generators avoiding (interruptible load contracts) Non-super peak energy pricing (TOU) to C/I to encourage energy sales other 20 hours a day Direct load control for residential and commercial avoiding FMPA peak Air Conditioners Water Heaters Member generators (load management) Probably not immediate value Compensation mechanism(s) may need to be derived 61

62 Summary of 10 Year Resource Plan Wholesale Market and Project Focused Likely, no need for major resource additions until 2027 Sell remaining excess capacity to non-arp Members Sell excess baseload energy at a margin FMPP currently not best option Pursue additional solar + storage? project opportunity for interested Members Track solar + storage cost reduction trends Need to resolve extensions on Stanton A, Oleander PPAs and TARP for Cane Island 1 & 2 in the next 2 years Do we want to focus on evaluating Load Management options (e.g. city load management, rate structure, C/I load management)? 62

63 Summary of Larger Need Beyond 2027 Sets Up Potential Need to Restructure ARP Potential need for larger resource if retirements occur with 4 5 years lead times potentially necessary Uncertainty regarding certain baseload resource retirements has increased Unplanned retirements may increase resource need to a level that partnerships may provide best options Options: Seek partnerships for power purchase agreements with highly efficient generation Continue expansion of solar/renewable program Explore peaking options at existing generation sites Ahead of large resource addition decision, reach consensus on proper ARP structure for next major resource process likely 2 years to execute Do we want to address the ARP future structure in the next 2 years? 63

64 Environmental Responsibility 64

65 FL Has Phenomenal Air Quality On Par with Best in the World for Particulates Comparison of PM 2.5 (ug/m3) Air Quality Levels in Florida (Weighted) vs. US Counties and Global Cities (Sources: ALA, WHO) 7 out of the 25 Cleanest Metro Areas are in Florida. EPA Standard/Safe Level:

66 FMPA Has a Clean Generation Fleet Emissions Below U.S. Averages by 59% & 82% NO x 59% Below U.S. Average Lbs./MWh, all generation, 2017 data SO 2 82% Below U.S. Average Lbs./MWh, all generation, 2017 data U.S. Florida FMPA Cane Island Treasure Coast U.S. Florida FMPA SOURCE: 2017 Annual Acid Rain Program 66

67 US Emissions Already Below 1990 Levels Market & Policy Forces + Recession Drivers 2,500 Historical Electric Power Sector Emissions (CO2, SO2, NOX) (Source: EIA) 2,000 Million Metric Tons 1,500 1,000 CO2 CO2 CO2 CO CO2 SO2 NOX 67

68 China, India Gains Offset US Declines Both Nations Projected Emissions to Increase 12,000 Historical CO 2 Emissions (MtCO 2 ) 10,000 8,000 6,000 4,000 2, EU28 China India United States of America Other Asia 68

69 FMPA Fleet has Low Carbon Footprint 34% Lower Rate than US Average 2017 CO2 Emissions (lbs./mwh) Source: 2017 Annual Acid Rain Program 1,552 1,191 1, US FL FMPA TCEC Cane Island 69

70 Carbon Tax Increases Energy Cost Impacts Those Who Can Least Afford It Estimated* ARP Energy and $25/ton Tax $/MWh, Derived from Historical ARP Energy Mix and Gas/Coal Emissions Rates $30.00 $25.00 $20.00 $15.00 $10.00 $ ARP rate impacts would range from ~$50M-$125M, or ~9%-19%. Excludes secondary impacts from higher gas prices and potential transportation tax effects $ *Note: some re-dispatch in favor of gas would likely occur assuming notice of carbon prices. Assumes blended emissions rates based on historical dispatch. 70

71 Summary of Environmental State We Have a Lot to Feel Good About FL has world class air quality FMPA s clean fleet outperforms the US average US Power NOX & SO2 emissions have declined ~80% since 1990 FMPA s CO2 footprint far lower than FL and US average A tax on carbon in the $15-$25/ton range would increase energy costs for FMPA by ~$8-$18/MWh (~9%-19% rate impact) Impacts felt by those least able to afford higher energy costs 71

72 Asset and Capital Plan and Rate Projections 72

73 ARP Fleet Age May Lead to Life Extension Considerations at End of 10 Year Plan Unit Start of Commercial Operation (Yr) Typical Planning Life of Unit (yrs) End of Expected Life (Yr)* Cane Island Stanton Cane Island Stanton A Stanton Treasure Coast Cane Island St Lucie Unit * Based on typical planning lifetimes. 73

74 Future ARP Capital Funding Needs Projected Between $12M - $15M / Year Small Amount of Debt Funding May be Necessary ($Millions) $35 $30 $25 $20 $15 $10 $5 $0 $13.7 Projected ARP Capital Expenditures and Funding Annual R&R Deposit Projected to Increase from $5.4M to $12.0M beginning FY 2020 $10.3 $15.8 $15.9 $3.1 $10.1 $32.4 Estimated $3.4M Annual Debt Service for Future Debt to Cover Capital Requirements $15.4 $7.2 $ Planned ARP Capital Expenditures Projected Annual R&R Funding Estimated Future Debt Service for Capital 74

75 ARP Debt Steady over Next Few Years Anticipated Refinancing of 2008C Bonds May Bring Savings in Mid-2020s $160 ARP Debt and Debt-Like Costs $120 Millions $80 $40 $ KUA TARP (Optional) KUA and KEYS TARP (Fixed) Assigned Small Project Debt & Capital R&R Funding Rate Protection Account Deposits Future Bonds (2008C Refi & Capital) Existing Bonds (w/o 2008C) 75

76 Total ARP Fixed Costs Projected to Remain Stable $50 Projected ARP Fixed Costs ($/MWh) $42 $40 $41 $42 $42 $40 $30 $/MWh $20 $10 $ Debt & Capital Lease Direct Charges & Other Gas Transport Purchased Capacity Fixed O&M 76

77 Overall ARP Costs Projected to Remain Stable if Gas Follows Forward Strip Projected ARP Average All-in Costs ($/MWh) $80 $74 $71 $71 $72 $73 $73 $73 $74 $75 $78 $60 $40 $20 $ Fiscal Year Demand Transmission Energy 77

78 ARP Costs Projected to Increase Steadily if Gas Follows EVA Reference Case Projected ARP Average All-in Costs ($/MWh) $80 $74 $70 $73 $76 $78 $80 $80 $81 $82 $84 $60 $40 $20 $ Fiscal Year Demand Transmission Energy 78

79 Summary of Target Cost Reductions to Lower Costs in Near-Term Focusing on FY Opportunities to decrease $/MWh energy costs and potential value Prepaid gas deals $3.3M/year (30,000 units) Incremental 3 rd party energy sales - $0.5M/year Optimizing value of Pool energy sales ~$0.9M/year Opportunities to decrease $/MWh fixed costs Sell PGP ownership interest - $5 - $20M Third-party capacity sales - $1M/year Incentivizing Participant native load growth Continued load attraction rates Lower non-super peak energy pricing to customers Renegotiate third-party contracts - $1.5M/year 79

80 Stanton and Tri-City Avg. Costs Decline after Debt Payoff New Rail Contract Also Improves Cost Competitiveness $120 $100 $115 Projected Stanton Project Costs Final debt year $/M $80 $60 $40 $63 $55 $56 $58 $59 $60 $62 $64 $65 $20 $0 Budget O&M Costs Other Costs Debt Service Fuel Costs Based on assumed capacity factor of 65% over period

81 Stanton II Costs Projected to Remain Above Market in Near Term Final Debt Payoff in 2027 $/MWh $100 $80 $60 $40 $94 $74 Projected Stanton II Project Costs $81 $81 $81 $87 $88 $90 Final debt year $70 $65 $20 $0 Budget O&M Costs Other Costs Debt Service Fuel Costs Based on assumed capacity factor of 65% over period

82 St. Lucie Costs Expected to Decline Steadily Costs Projected to Decrease Significantly After Debt Paid off In 2026 $80 $60 $74 Projected St. Lucie Project Costs $72 $70 $68 $66 $64 $62 $60 Final debt year $50 $/MWh $40 $40 $20 $0 Budget O&M Costs Other Costs Debt Service Other Costs include deposits to General Reserve Fund to pay bullet debt 82

83 Summary of Projects Stanton 1 & 2 are very clean coal units Stanton 1 debt paid off in 2019 Stanton 1 & 2 costs more competitive with reduced rail cost Explore Stanton 1 & 2 cost reductions in O&M and fuel areas to continue improvement St. Lucie costs decline over period similar to Stanton 1 & 2 Continue to emphasize need for cost improvements at St. Lucie 83

84 Risks and Opportunities 84

85 Risks and Opportunities for FMPA Key Risks Unchanged, Opportunities Realized Risks Carbon Tax and impact on coal and gas units and pricing to consumers Gas price swings affecting end customers rates SCR on Stanton 1 or other possible environmental upgrades or challenges Loss or lack of growth of member load through poor rate structures Steam generator replacement on St. Lucie or other life extension investment Low gas prices cause low capacity factor for coal (opportunity or risk?) Opportunities Sell excess capacity and energy at margin above FMPP option Use of customer demand to meet peak 85

86 Various Factors Could Influence Rates 1-Year Outlook on Ranges of Impact Potential Impact on ARP Rates CO2 Tax ($20/Ton) 15% -9% Natural Gas Prices +/- $1/MMBtu 9% Stanton 1 SCR 6% -1% Medium Term (Bilateral) Sales to Munis (100 MW) No Load Growth 1% < -1% Fixed O&M Costs +/- 5% < 1% < -1% Generating Fleet Availability +/- 1% < 1% 86

87 10 Year Planning Horizon Has Risks Distributed Generation Requires Strategy Risk Impacts Mitigation Options Natural Gas Price Volatility Penetration rate of Distributed Generation Load decline instead of growth Environmental Regulations or desire for reduced carbon footprint Volatile fuel prices may cause: high rates for ARP with high gas prices high coal Project rates with low gas prices Could result in load loss and solar PV integration issues Cost shift to low income customers Demand destruction could result in additional excess capacity increasing rates Capital investments such as Stanton 1 SCR for NOx? Early retirement of coal units possibly stranding debt Short term gas hedging Allow individual members to hedge energy costs Appropriately price service increasing fixed and reducing variable Solar subscription Reduce retail energy cost to encourage sales Sell excess in wholesale Increase NOx controls Add solar to offset 87

88 Active Fuel Management Possible Could be ARP Driven or at Member Level Within-year swings/volatility in gas prices relative to budget can cause: lumpy rates, mostly due to winter period cost spikes Larger budget variances within a given budget cycle Active fuel management within a pre-defined window, such as within a budget year, can help ensure budget alignment Shorter duration minimizes risk of market position should spot prices become more favorable 88

89 Transmission Costs and Opportunities 89

90 Rent for Transmission Going Up Tech + Regs. Mean IOU Rate Increases $7 Firm Transmission Rates (Excludes Ancillary Services) $6 $5 Currently, ARP pays ~$5/MWh for transmission. DEF's Forecasted Rates as of 11/2018 ($/kw-mo.) $4 $3 DEF $2 FPL $1 $- OUC Future FPL Rates Will Depend on Level of System Investment 90

91 Can Transmission Projects Reduce Costs? Example Projects Highlight Range of Cost Benefits Project 1: Direct Serve Select West Load Time Frame = Long, Uncertainty = High Project 2: Acquire Member Transmission, Become Transmission Service Provider (TSP) Time Frame = Short, Uncertainty = Moderate Project 3: Move Select West Load to new TSP Time Frame = Long, Uncertainty = High Project 4a: Major New Florida Transmission Corridor, FMPA Partial Ownership Time Frame = Very Long, Uncertainty = Very High Project 4b: Major New Florida Transmission Corridor, IOU Built, FMPA Rents Time Frame = Very Long, Uncertainty = Very High Construct new transmission to connect to select (not all) ARP west load from FMPA-owned generation. Calculated with one partner utility. FMPA acquires member transmission, constructs additional and charges a third party for transmission service. Cannot work for many members requires nearby third-party customer. FMPA constructs new transmission to connect select ARP west load to different transmission system (from one IOU to another). Calculated with two partner utilities. Major multi-utility, multi-year project which offers fractional ownership to participants, including FMPA. FMPA would not be the primary owner/operator. Requires many utility partners. Major multi-utility, multi-year project constructed by IOU. FMPA builds to connect member loads to corridor, pays NITS on new IOU. Requires many utility partners. 91

92 Options Exist, but Not Cost Competitive Negative ARP Benefit ~$3/MWh-$13/MWh Estimated 10-Year Net Benefits of Transmission Options $M, Estimates Have Uncertainty of +50%/-20% $150 $100 $50 $0 -$50 -$100 -$150 -$200 $(130) $131 $1 4a. New Corridor Own $(103) $56 $(47) 4b. New Corridor Rent $(88) $29 $(123) $63 $(59) $(59) 2. Become TSP 3. Partial TSP Change Cost Benefit Net Benefit $(166) $93 $(73) 1. Direct Serve 92

93 Summary of Transmission Investment Transmission costs are projected to go up significantly, nearly doubling over the next 10 years Current project ideas/examples show high capital outlay (~$90M to $170M), very long lead times (5 to 15 yrs.) and most require several willing partners. Few projects show potential to break-even. Significant uncertainty in cost estimates. Few project ideas that do not require new business models, contracts, or paradigm shifts in Florida market. Should searching for and investigating transmission projects be a priority? Are there other types of projects or concerns staff should investigate (besides those covered by the examples)? 93

94 Conclusions 94

95 Conclusion There is More Work to Do Build Off Progress Since 2017 w/new Targets Continued Member Services expansion for reliability improvement, solar subscription development, retail rate review, and technical support Rates are reasonably competitive but need to improve and are gas-price driven Need to continue with excess sales and cost management Support Member growth with load attraction rates and revised rate structure to increase non-super peak sales No major environmental upgrades anticipated New solar + storage opportunity for interested Members ARP will likely need capacity in 2028, and will monitor load growth and market opportunities versus load management Enhancing and evaluating further options to enable ARP Member resource choices with no impact to other Members (business model alternatives) Needs to be in place before major resource decision made in timeframe 95

96 Electric Demand, Supply and Generation Mix Changes 96

97 US Electric Sales Growth More Tepid Only 0.2% Per Year Recovery Since 2012 USA - Total and Industrial Electric Sales (TWh) Source: EIA State Profiles (2018 AEO) 4,000 3,500 3,000 2,500 Industry Growth -0.1% negative. 26% of US. Sales 2,000 1,500 1, Total Electric Sales (TWh) Industrial Sales (TWh) 97

98 FL Electric Sales 1.1% Growth Industrial Sales Only 7% in FL FL - Total and Industrial Electric Sales (TWh) Source: EIA State Profiles (2018 AEO) % Growth/Yr Decline due to Irma, soft Winter Total Electric Sales (TWh) 98

99 FRCC Expects Decent Future Growth 0.8% CAGR for FL thru 27 Projected FRCC Total Net Energy For Load (TWh) Source: FRCC 2018 Load and Resource Plan

100 FL Needs More Electricity Per Capita Cooling Load Drives Higher Residential Need 7,000 6,000 Annual per Capita Consumption (kwh) - Residential Sector Sources: EIA, Woods and Poole, Statista FL Great Recession 5,000 4,000 US 3,000 2,000 CA Northeast 1,

101 US Far More Balanced Overall Than FL Renewables Include Wind and Hydro 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Historical and Projected US Generation Mix (Source: EIA 2018 AEO) Other Other Other Other Hydro Gas 22% Wind Hydro Gas Coal Coal 40% 31% Solar Wind Hydro Hydro Gas Gas Coal 26% Solar Wind Coal Nuclear Nuclear Nuclear Nuclear 20% 11% 31% 20% 18% 33% 33% 18% 23% 27% 16% % 101

102 Gas Drives FL Generation Mix Solar Growing to ~6% by % 90% 80% Historical and Projected FRCC Generation Mix (Source: FL PSC) Other Interchange Oil Other Other Other Interchange Solar 5% Solar 6% 70% 60% 50% 40% Gas 40% Gas 63% Gas 64% Gas 66% 30% 20% 10% 0% Coal Coal Coal Coal 25% 10% Nuclear Nuclear Nuclear Nuclear

103 FMPA Mix Exposed to Gas Price Volatility Other 0% 2018 Actual Coal 15% $5 EVA Q and Gas Forward Strip Forecasts (Nominal $/MMBtu) $4 Gas 85% $3 $ Other 5% Coal 8% 2028 (Forward Strip Case) Other 5% EVA Ref. Case Gas Fwd Strip 2028 (EVA Case) Coal 18% Gas 87% Gas 77% 103

104 Solar Capacity Expected to Plateau ITC Phase Out Drives Slower Pace of Growth Historical and Projected Solar Capacity Additions Source: SNL Financial Power Market Forecast (December 2018) & FRCC Database GW National (GW) FL (GW) GW

105 FL Utility Solar Grows to ~7 GW by 28 Transmission Queue Far Exceeds Site Plans 15,000 12,500 10,000 7,500 5,000 2, Queue ('18) Nameplate (2018 TYSP) Firm to Grid (2018 TYSP) Source: FRCC Ten-Year Site Plan, Numbers in MWs 105

106 Storage Getting Cheaper, Not There Yet Capital Cost Needs to Decline ~50% Long Term Average Cost of Battery Storage* Vs. Benefit $160 $/MWh $120 $80 Fuel Cost Fixed Fuel Cost $40 $0 Costs Costs Energy Benefit Benefits *Reflects 1 MW Lithium Ion System with 4 Hour Daily Discharge. 106

107 Natural Gas Market Expectations 107

108 Shale Gas Rapidly Increased Production Drilling for Oil Ramped Up Production Further Annual Natural Gas Production Volumes Bcf/Day Source: EIA 85 Thru Oct

109 Changing Gas Production Zone Flows Shale and Tight Zones Grow with Fracking Bcf/Day Tight Coal Bed Tight Offshore Tight Tight Tight Tight Tight Tight Tight Conventional Shale Shale Shale Shale Shale Shale Shale Shale Shale

110 Power Demand, Mexico Export Way Up Native Industrial Demand Recovering Slightly Bcf/Day Gas Demand by Type Residential Commercial Industrial Power Pipeline Bcf/Day North American Gas Exchange Canada Import Mexico Export 110

111 LNG Exports Will Become Large Demand Upward Price Pressure Depends on Spreads* *Future volumes driven by spread between world and US prices. 111

112 Forward Market Expects Low Prices Prices Hovering Around $3/MMBtu Historical and Projected Short-Term Prices $/MMBtu, Sources: EIA, CME Group 112

113 EVA Projects Steady Gas Price Growth Power + LNG Demand Outpaces Supply Gains Projected Natural Gas Prices EVA (Henry Hub) and Forwards $/MMBtu, Sources: EVA Q Natural Gas Price Forecast, SNL Financial $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 EVA Forwards $

114 Strategic Planning Session 114