Board Finance & Budget Planning Workshop. April 18, 2016

Transcription

1 Board Finance & Budget Planning Workshop April 18,

2 Management Introduction (Glenn Steiger) 2

3 Overview Management Introduction Strategic Plan Cost of Doing Business FY2017 Financial Highlights Division Highlights Customer Resource Energy Resource Planning Engineering & Operations Administration Next Steps 3

4 Dominant Market Trends COST OF DOING BUSINESS Higher cost of transmission charges More aging of distribution infrastructure Increased power supply costs ECONOMY Regional growth continues to exceed national More business consolidation LOAD Less traditional energy load More companies offering DG and storage More electric transportation More available energy sources/solar More energy efficiency TECHNOLOGY More complexity of technology and systems More data management at user level Internet of things SOCIAL Greater demands of millennials Higher expectations for a customer relationship REGULATIONS More environmental regulation More regulatory control over power supply 4

5 Select Pro Forma Data Fiscal Year Rate Adjustment < 5% Debt Coverage > 1.75 Cash Reserves ~ 145 Days % 3.24* 230* % % % % % % % % % * Budget revised from Proforma 5

6 What is Driving the Budget Strategic plan imperatives No more than 5% increase in rates Recognition of competitive labor force Customer service goals and expectations Most important A Balanced Budget! 6

7 Financial Highlights (Robert Orbeta) 7

8 FY 2017: Highlights Revenue Projections are based on January 25, 2016 Board approved load forecast and an assumption of 5.0% rate increase. Operating Expenses Increases in labor are based on bargaining unit contracts. Benefits for all employees are included in administration s budget. Purchased power is the largest expense and is approximately the same as prior year. Non-operating Expenses Debt repayment, Pilot/ROI and City transfer are in line with prior year. 8

9 FY 2017: Capital Projects Special Funds (UUD, REC and C&T) Projects: FY 2017 includes $5.4M for the following capital projects: $2.5M for AMI implementation $750k for Substation SF6 breakers (Cartwright & Jenney) $250k for Microgrid $300k for LED lighting upgrades (Phase II) $1.6M Underground Utility Districts 9

10 FY 2017: Capital Projects (cont.) Future infrastructure New development residential, commercial & industrial Alameda Point Site A ~ $1.2M Pole test and treatment (10-year cycle) ~ $370k Pole Replacement ~ $500k Coast Guard Island tie in ~ $350k Technology upgrades GIS, software, core switches, system memory, mobile devices and workstations ~ $820 Warehouse Migration ~ $200k Other miscellaneous projects ~ $1.4M 10

11 Cap &Trade / REC Sales Expenditure Budgeted Cap & Trade Expenditures = $40,000 Opower & Miscellaneous Programs (program ends in 2016) Budgeted REC Sales Expenditures = $955,000 Online Rebate System and Payments Energy Efficiency programs (low income/multi-family) Upstream lighting, energy audits Non-residential retrofit programs (lighting, motors, HVAC) 11

12 Budget Policy Highlights Policy was approved by the Board last year General Manager submits proposed operating budget including proposed expenditures and financing means Ratepayer comments solicited during regular meetings Budget legally enacted through passage of a resolution Formal budget integration is a management control device during the year Budgets are on a basis consistent with generally accepted accounting principles 12

13 Compliance Test Discussion Charter Compliance Test & Retention Calculation: Based on the ordinance calculation, a General Fund transfer is required General Fund Transfer: $2,800,000 included in the Budget Debt Coverage Ratio Calculation: 3.24 coverage ratio exceeds bond requirement s policy of 1.75 Operating Reserve Compliance Test: 230 days of operating cash projected at year-end exceeds financial requirement of 145 days. 13

14 FY 2017 Financial Summary REVENUE FY 2016 Budget FY 2017 Budget FY17 - FY16 % Change Revenue from Operations $54,768,665 $56,818,388 $2,049,723 4% C&T / REC Net Income $6,844,274 $3,743,478 ($3,100,796) -45% Non-Operating Revenue $713,380 $741,000 $27,620 4% Total Revenue $62,326,319 $61,302,866 ($1,023,453) -2% Reserve Funding ($7,939,274) ($3,743,478) $4,195,796-53% Reserve Spending $3,146,599 $6,395,000 $3,248, % Total Revenue & Reserves $57,533,644 $63,954,388 $6,420,744 11% EXPENSES Purchased Power ($30,030,250) ($30,192,758) ($162,508) 1% Operating Expense ($21,609,703) ($21,905,846) ($296,142) 1% Non-operating Expense ($5,443,354) ($5,249,764) $193,590-4% Add Back Non-Cash Items $3,062,000 $3,230,000 $168,000 5% Debt Principal Payments ($1,170,000) ($1,220,000) ($50,000) 4% Capital Projects & Eqpt ($5,469,924) ($7,517,782) ($2,047,858) 37% Total Expenses ($60,661,231) ($62,856,151) ($2,194,919) 4% Net Adjustment ($3,127,587) $1,098,237 $4,225, % 14

15 Budget Comparison to Last Year (in Thousands) 70,000 60,000 FY ,303 FY ,326 50,000 FY ,869 FY ,578 40,000 30,000 FY 2017 FY ,000 10,000 - (10,000) FY ,988 FY ,083 Revenue Operating Expense Non-Operating & Other Expense FY 2017 (2,652) FY ,793 Net Reserves (fund less spend) 15

16 FY 2017 Revenue Electricity Sales budget is $56,818,388, or $2,049,723 higher than last year s budget Underground Utility District program is funded in the Electric budget through rates C&T Net Income budget is $729,852 or $55,291 more than last year s budget REC Sales Net Income budget is $3,013,626 or ($3,156,087) lower than last year s budget (REC sales contract matures December 2016) 16

17 FY 2017 Revenue (cont.) UUD, C&T Net Income and REC Sales Net Income shall be placed into designated reserve accounts Other Operating Revenues are expected to be consistent with historical trends and market conditions AMP estimates that it will use approximately $37,763 from cash reserves if revenue and expenses occur as budgeted 17

18 Operating Expenses by FERC (in Thousands) 35,000 30,000 FY ,193 FY ,030 25,000 20,000 15,000 FY2017 FY ,000 5,000 FY2017 4,796 FY2016 4,560 FY2017 5,084 FY2016 6,121 FY2017 8,795 FY2016 7,929 - Purchased Power Distribution & Maintenance Customer Accounts & Sales Administrative & General 18

19 FY 2017 Operating Expenses by FERC Purchased Power budget is $30,192,758*, or $162,508 more than last year s budget Operations & Maintenance budget is $4,796,360, or $236,360 more than last year s budget Customer Accounts & Sales budget is $5,084,126 or $1,036,794 less than last year s budget; Cap & Trade & REC expenses included are $995,000 or ($1,120,000) less than last year s budget Administrative & General budget is $8,795,360 or $866,577 more than last year s budget Total Expense from Operations, excluding depreciation, is $18,675,846, or $66,143 more than last year s budget 19

20 Direct and Indirect Debt Service (Interest & Principal) $7,000,000 $6,000,000 $5,000,000 $4,000,000 $3,000,000 $2,000,000 $1,000,000 $0 Fiscal year 2010 A/B Interest & Principal NCPA & TANC (combined) Interest & Principal 20

21 2010 A/B Debt Service Payments $3,000,000 $2,500,000 $2,000,000 $1,500,000 $1,000,000 $500,000 $ A Principal 2010 A Interest 2010 B Principal 2010 B Interest 21

22 Non-Operating Expenses 3,000,000 FY ,800,000 FY ,800,000 2,500,000 2,000,000 1,500,000 FY ,461,393 FY ,510,674 FY ,417,257 FY ,389,500 FY 2017 FY ,000, ,000 FY ,886 FY ,820 - Debt Related Charges PILOT / ROI City Transfer Other (Net) 22

23 FY 2017 Non-Operating Expenses Debt related charges (interest) decreases as the 2010 A/B principal is being paid Other revenues and expenses (net), include Interest Income and outside billing are budgeted higher than last year 23

24 24 FY 2017 Expenditure Make-up

25 Budgeted Staffing

26 City Related Expenses FY 2017 FY 2016 % Change General Fund Transfer $2,800,000 $2,800, % PILOT / ROI $1,417,257 $1,510, % City cost allocation $754,500 $776, % City direct cost $210,528 $136, % Rent warehouse, etc. $0 $189, % Garage fees & sewer $84,600 $96, % Total $5,266,885 $5,509, % AMP PERS cost $1,673,836 $1,370, % AMP benefit cost $2,504,865 $1,871, % Repay Loan to City (FY16-cash item) $0 $2,200, % OPEB cost $60,000 $56, % Other Payments $4,238,701 $5,947, % 26

27 Balancing Account The Balancing Account (BA) is a rate stabilization mechanism The BA adjustment is recorded at year-end The BA will change from ~$14,873,054 at the beginning of FY 2017 to ~$16,055,291 at the end of FY

28 Sources of Funds for Investment Solar PV Rebate Reserve $28,025 $28,025 Insurance Reserve $1,200,000 $1,200,000 C&T / REC Sales Reserves $17,360,261 $15,922,993 Underground District Reserve Operating Funds Balancing Account & Misc. $7,669,126 $7,205,126 $10,591,207 $10,554,207 $13,155,267 $16,055,291 Beginning FY 2017 Ending FY

29 Budget to Actual and Forecast Comparison (in Thousands) $58,000 $56,000 $54,000 $52,000 $50,000 $48,000 $46,000 Electricity Sales FY 2013 FY 2014 FY 2015 FY2016 FY2017 Budget Actual Forecast $31,000 $30,000 $29,000 $28,000 $27,000 $26,000 Purchased Power FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 Budget Actual Forecast 20,000 Operating Expenses $10,000 Capital Projects 15,000 10,000 5,000 $8,000 $6,000 $4,000 $2,000 - FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 Budget Actual Forecast $0 FY 2013 FY 2014 FY 2015 FY 2016 FY 2017 Budget Actual Forecast 29

30 Customer Resource Division (CRD) Customer Service Customer Programs Communications Energy Efficiency 30

31 Customer Resource Division (CRD) Customer Resources Customer Services Customer Programs Communication Energy Efficiency Customer Assistance Energy Assistance Project Ease Medical Discounts 3rd Party Notification Balanced Payments Online Bill Pay Customer Surveying Employee Surveying EV Discount Program Solar Interconnections Solar True Ups Key Accounts Commercial Roundtable Residential Roundtable Home Energy Management Pilot Community Solar Flash Newsletter Bill Inserts External & Internal Comm. Programs Marketing Advertising Community Contests Website AMI communication PUB minutes Alameda Green My Energy Home Energy Residential Online Rebate In Store LED Rebates Multi-Family Rebates Commercial Retrofits Commercial HVAC Customized Rebates Energy Audits 31

32 CRD GOALS FOR Ensure that customers have a positive experience Increase customer energy efficiency Provide programs that support green Alameda Provide programs that increase revenues Increase community engagement and goodwill Achieve high employee satisfaction 32

33 CRD INITIATIVES FOR 2017 Online payment system upgrade Mobile website implementation AMI deployment communications plan Lobby renovation Continued implementation of REC expenditures for energy efficiency AMP service center energy efficiency plan Community contest Residential customer advisory panel Employee community volunteer program Internal communications plan 33

34 OTHER CRD PROJECTS FOR 2017 Community solar customer program Multi-family energy efficiency program Commercial turnkey energy efficiency program Residential online rebate program Residential customer satisfaction survey Employee satisfaction survey Employee orientation program AMP sustainability team Cool the Earth 34

35 Energy Resource Planning (ERP) Forecasting & Planning Resource Management Rate Design & Analysis Compliance 35

36 Energy Resource Planning (ERP) Energy Resource Planning Forecasting & Planning Resource Management Rate Design & Analysis Compliance Annual Load Forecast Annual 10-year Pro-forma Forecast Budget Planning Program Planning Resource Planning Procure / Sales Power Cost Management REC Sales C&T Program Market Programs Alternatives Annual Cost-of- Service Review Rate Schedules Rate Design Restructuring Usage Profiling NEM Successor New Tariffs Legislative & Regulatory Transmission (ISO, TANC, PG&E) Power Content Renewable Portfolio Standards Greenhouse Gas 36

37 ERP Goals / Initiatives Improve forecasting models Update 10-year plan and incorporate into forecast models Complete phase 1 community solar program development (ready for construction) Analyze resource portfolio, identify changes and update Integrated Resource Plan 37

38 ERP Goals / Initiatives (cont.) Solicit 2017, 2018, 2019 REC Sales Continue Cap & Trade program participation Continue to monitor market programs Continue to participate in local generation opportunities 38

39 ERP Goals / Initiatives (cont.) Complete transition to new Cost-of Service model and Rate Forecast model Implement Phase 1 of Time-of-Use and complete planning for other phases Continue analysis of usage profiles Implement NEM Successor program as NEM program completes Develop new tariffs as needed 39

40 ERP Goals / Initiatives (cont.) Coordinate transmission reliability and cost reduction options with vendor organizations Maintain RPS compliance documentation Maintain Air Resources Board emissions filings and documentation 40

41 Engineering & Operations (E&O) Line Operations Electrical Maintenance/Substations Engineering System Operations Compliance & Safety 41

42 Engineering & Operations (E&O) Engineering & Operations Line Electric Equipment Engineering System Operations Compliance & Safety Maintenance Construction Inspection Streetlight Maintenance Substation Maintenance & Construction Metering SCADA Initiate Design Engineer Document Dispatch First Response AMP Safety NERC Compliance Emergency Management 42

43 Engineering & Operations (E&O) Future Engineering & Operations Transmission & Distribution (T&D) Field Services Engineering System Operations Compliance & Safety Maintenance Construction Inspection First Response Metering Streetlight Maintenance Initiate Design Engineer Document Dispatch SCADA Substation Maintenance & Construction Work Planning AMP Safety NERC Compliance Emergency Management 43

44 E&O Goals Maintain low customer outage frequency and duration, ensuring AMP remains in top quartile for SAIDI/SAIFI annually Replace 15% of AMP s infrastructure by 2020 Improve infrastructure project management workflow so that by 2020 all projects are within budget and on schedule Complete infrastructure for Alameda Point by

45 E&O Division: FY17 Initiatives Low Customer Outage Frequency & Duration 5-year cycle of distribution detailed and visual inspection Annual cycle of transmission inspection & maintenance Tree trimming Compliance with NERC Standards Replace AMP infrastructure Distribution poles Streetlights (Historic and LED) Improve project management workflow Future infrastructure 45

46 Administration Finance, Utility Billing & Accounting Information Systems Support Services 46

47 Administration Organization Administration Finance, Billing & Accounting Utility Information Systems Support Services Finance Billing Meter Reading Accounts payable Accounts Receivable Fixed Assets IT Security Software Maintenance Hardware Maintenance MAN Internet/Intranet Purchasing Warehousing Facilities Contract management 47

48 Administration Goals Meet all bond covenants Ensure AMP s average rates are competitive Ensure mutually agreeable transfer to city Ensure balanced budget Ensure effective organizational management Establish system interoperability Maintain sufficient level of cyber security 48

49 Administration FY2017 Initiatives Long-range financial forecasts for Meeting bond covenants Mutually agreeable transfer to City Balanced Budget Develop business model reflecting 2020 needs Virtual desktop Online form submission and database Voice over internet protocol (VOIP) phones 49

50 50 NEXT STEPS

51 FY 2017 Board Policy Issues Alameda Point AMI (implementation and funding) Community solar Technology upgrades Online payment systems Financial systems Customer billing 51

52 Budget Schedule Annual Planning Workshop (completed January 25, 2016) 10-year Pro Forma and update on rate projections planned for regular meeting of the Public Utilities Board (completed March 21, 2016) Staff will present recommendations for rate allocation among rate classes for the Board to consider at the regular meeting of the Public Utilities Board on April 18 Board provides final comments on draft budget by May 6 Staff will present the budget and the Board will consider adoption at the regular meeting of the Public Utilities Board on June 20 at 7:00 p.m. Staff will implement the approved rate schedules and FY 2017 budget beginning July 1 52

53 Contact Information For additional information, please contact: Robert Orbeta