2018 Energy Update Bryan Municipal Utilities Kevin M. Maynard - - PowerPoint PPT Presentation

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2018 Energy Update

Bryan Municipal Utilities Kevin M. Maynard

Director of Utilities November 9, 2017

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Bryan Municipal Utilities overview

• Not-for-profit, community-owned utility services

provider

• Established in 1892
• Three primary services
• Water
• Telecommunications
• Electricity
• 44 full-time employees
• More than $26 million annual revenue

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Bryan Municipal Utilities overview

• Operations oversight provided by five-member Board of

Public Affairs

– Bryan residents elected by local citizens – Approve policies, staffing, budgets, rates – Authorize utility improvements and extensions

Bryan Board of Public Affairs

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Water Utility

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Municipal Water Utility

• Water supply provided by seven deep wells (127 to 147

feet) in four locations

• 8.0 MGD raw water production capacity
• 5.0 MGD treatment capacity
• 1.41 average daily output
• 1.91 MGD peak daily output

Bryan Water Treatment Plant

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Municipal Water Utility

Treatment process consists of:

• Aeration to oxidize iron and manganese, release undesirable gases
• Chlorination for additional oxidation and disinfection
• Filtration to remove oxidized iron and manganese
• Bryan’s source water contains naturally occurring fluoride; no

additional fluoridation required

• Water considered very hard; total hardness of approximately 327

mg/l (19 grains/gallon)

• Bryan’s treatment process does not include softening

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Municipal Water Utility

• 1.4 million gallons of elevated

storage (two water towers)

• One average day of finished

water storage

• 1.0 million gallons of ground

level raw water storage at Water Treatment Plant

• No environmental compliance

issues

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Water Utility sales trend

• Water sales have declined over the last 20 years
• Decreasing sales and inflation create rate pressure

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Residential 170,007,684 140,258,228

• 29,749,456
• 17.50

Commercial 307,241,748 184,980,400 -122,261,348

• 39.79

Total 477,249,432 325,238,628 -152,010,804

• 31.85

% Change Rate Class 1997 2016 Difference

Water Sales by Rate Class (Gallons) Bryan Municipal Utilities

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Water Utility rate plan

• In 2015, BPA adopted a five-year water rate plan
• Third year of plan effective with bills rendered on or

after December 20, 2017

• Water rates remain very competitive with others in area

even after implementation of five-year rate plan

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Water Utility rate plan

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Water Utility primary issues

• Ensuring adequate capital improvements funding

– Additional $500,000-$600,000 annually needed for water supply, treatment and distribution system improvements – Will evaluate 2018 water main replacement financing

• ptions

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Water Utility primary issues

• Planning for future

– If additional water supply and treatment capacity is needed in the future, what is the best location? – Current location or site west of town (solar field site) – Do new treatment technologies make softening or other water quality enhancements feasible? – Water supply and treatment alternatives study planned in 2018

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Telecommunications Utility

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Municipal Telecommunications Utility

• Developing plan to rebuild fiber optic network over next 5

to 10 years

• Plan to increase speeds by year-end 2018

– Residential speeds of up to 30 Mbps – Business speeds of up to 100 Mbps

• Future focus:

– Reliability – Increased bandwidth/speed – Local customer service – Cost competitiveness

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Electric Utility

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Power Supply

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Power Supply arrangements

• In its early years, BMU generated all of the energy used

locally at its power plant

• In 1954, BMU established an interconnection with Toledo

Edison

• Purchasing power from TE was less expensive than

installing another generator at the time

• TE interconnection provided a backup source of power to

improve reliability

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Power Supply arrangements

• Natural gas for generating electricity curtailed during

early 1970s Energy Crisis and fuel oil prices increased

• BMU began purchasing most of its electric energy from

TE instead of generating it locally

• BMU power plant used to reduce peak demands and for

emergency backup

• Due in part to its nuclear power plant construction

program, TE’s power prices increased significantly during late 1970s

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Power Supply arrangements

• In response, BMU purchased 10.5 miles of abandoned

railroad right-of-way and constructed a high voltage transmission line to connect to Ohio Power (now AEP)

• In 1982, BMU switched to AEP and reduced electric rates

by an average of 23%

• BMU was able to purchase power from AEP at cost-based

rates of approximately $0.03/kWh until 2006

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Power Supply arrangements

• By the mid-2000s the electric industry had moved from

cost-based to market-based power supply costs

• When the AEP contract was renewed in 2006, power

supply costs increased from 3.5 cents/kWh to 6.1 cents/kWh

• BMU’s power supply costs have averaged 6.5 cents/kWh

to 7.2 cents/kWh since 2007

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Power Supply arrangements

• BMU is a member of American Municipal Power, Inc.

(AMP), a not-for-profit wholesale power supply and services agency for 135 municipal electric systems in nine states

• Joint action through AMP allows BMU to achieve

economies of scale and manage risks

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Power Supply arrangements

• BMU began receiving an allocation of New York Power

Authority (NYPA) hydropower through AMP in mid-1980s

• BMU participated in construction of the Belleville

Hydroelectric Plant through AMP in 1990s

• In 2007, to reduce power cost volatility, BMU began

purchasing blocks of power through AMP that had varying contract lengths

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Power Supply arrangements

• As market prices continued to increase through 2008,

BMU evaluated participation in a number of power supply projects through AMP

• BMU agreed to participate in construction of the Prairie

State Energy Campus and the Cannelton, Smithland and Willow Island hydroelectric projects in 2007

• BMU agreed to participate in the Meldahl and Greenup

hydroelectric projects in 2010

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Power Supply arrangements

• Emphasis on a diverse, more environmentally friendly

power supply portfolio

• Approximately 30% of power supply is generated by

renewable resources including:

• Landfill gas to energy
• Hydroelectric
• Solar
• Wind
• Approximately 25%-30% of

power supply is market purchases

Auglaize Hydroelectric Plant

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American Municipal Power 88.7% Belleville Hydro 3.6% NYPA Hydro 2.6% Bryan Power Plant 0.2% Auglaize Hydro 4.9%

Bryan 2011 Power Supply Resources

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NYPA Hydro, 2.6% Belleville Hydro, 3.7% AMP Hydro, 4.2% Meldahl Hydro, 3.4% Greenup Hydro, 1.7% AFEC (Natural Gas), 13.2% Prairie State (Coal), 28.4% EDI Landfill Gas (2021), 4.0% Blue Creek Wind (2022), 2.4% Bryan Solar, 1.2% Auglaize Hydro, 4.3% Morgan Stanley Purchase (2020), 9.2% BP Purchase (2024), 22.0%

Bryan 2018 Power Supply Resources

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Power Supply arrangements

• Diverse resources reduce power supply cost volatility
• More environmentally friendly resources reduce risk of

carbon tax, cap and trade or other environmental compliance costs

• New assets help stabilize power costs for foreseeable future
• Transition to more diverse, asset-based, environmentally-

friendly power supply portfolio was accomplished without significant changes in power supply costs

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Historic Power Supply costs

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Electric Rate Plan

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2017 Electric COS Study/Rate Plan drivers

• Rates were last adjusted in 2006
• Power supply resources have changed since 2006
• Prairie State Energy Campus
• AMP Fremont Energy Center (AFEC)
• Cannelton/Smithland/Willow Island Hydroelectric Projects
• Greenup/Meldahl Hydroelectric Projects
• Bryan Solar Field
• New resources have greater demand and lesser energy costs
• Power Supply Cost Adjustment (PSCA) had grown to $0.0279/kWh
• Provide adequate capital improvements funding
• Determine funding level required to maintain reliable service and help keep rates lower

and more stable over long term

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Rate Plan goals

• Maintain electric system financial integrity
• Allocate costs of providing service in a fair and equitable manner

using industry practices

• Rates designed to be overall revenue neutral
• Move rates toward cost of service
• Include projected power supply costs in rates

– Minimize Power Supply Cost Adjustment (PSCA)

• Minimize customer financial impacts
• Develop rates that send appropriate price signals

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Cost of Service results

Table 7 Cost of Service summary*

* January 2017 UFS Electric Cost of Service Study and Financial Projection, page 10

Customer Class Cost of Service Projected Revenues % Change Residential 5,531,785 $ 5,556,366 $

• 0.4%

General Service 3,256,967 3,252,398 0.1% Security Lighting 48,829 46,327 5.4% Street Lighting 352,238

• Large Power

10,606,376 11,294,154

• 6.1%

Total 19,796,195 $ 20,149,245 $

• 1.8%

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Proposed three-year rate plan

• Overall revenue neutral
• Moves rate classes toward cost of providing service while minimizing

customer financial impacts

• Increase monthly customer charge
• No change in General Service/Large Power demand charge
• Decrease combined energy/PSCA charge
• Increase security lighting rate
• $2 million annual capital improvements allocation
• Incorporates projected power supply costs in base rates rather than

in PSCA

• BPA adopted Year 1 of three-year plan on August 15, 2017

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Large Power rates

Current Year 1 Year 2 Year 3 Customer Charge 187.50 $ 220.00 $ 225.00 $ 230.00 $ Energy Charge (1st 300 kWh per kW Demand) 0.02900 $ 0.04800 $ 0.04710 $ 0.04625 $

(All other energy)

0.02200 $ 0.04800 $ 0.04710 $ 0.04625 $ All Demand Charge 20.00 $ 20.00 $ 20.00 $ 20.00 $ PSCA 0.02790 $

• $
• $
• $

Current Year 1 Year 2 Year 3 Customer Charge 187.50 $ 220.00 $ 225.00 $ 230.00 $ Energy Charge (1st 300 kWh per kW Demand) 0.05690 $ 0.04800 $ 0.04710 $ 0.04625 $

(All other energy)

0.04990 $ 0.04800 $ 0.04710 $ 0.04625 $ All Demand Charge 20.00 $ 20.00 $ 20.00 $ 20.00 $ PSCA

• $
• $
• $
• $

Current and Proposed Rates

Three-Year Three-Year

Rates with PSCA Included in Energy Cost

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Typical Customer Bill Comparisons

Existing to First Year of Plan w $0.000 PSCA

375 kWh 50.33 $ 47.42 $ (2.91) $

• 5.8%

750 kWh 91.16 86.59 (4.57) $

• 5.0%

1500 kWh 169.58 164.93 (4.65) $

• 2.7%

1000 kWh 146.43 $ 143.18 $ (3.25) $

• 2.2%

(1-Phase)

2000 kWh 280.31 269.82 (10.49) $

• 3.7%

5000 kWh 677.39 646.92 (30.47) $

• 4.5%

General Service:

10KW/2,000 kWh 280.31 $ 269.82 $ (10.49) $

• 3.7%

(3-Phase)

25KW/5,000 kWh 677.39 646.92 (30.47) $

• 4.5%

50KW/10,000 kWh 1,259.37 1,226.42 (32.95) $

• 2.6%

100KW/20,000 kWh 3,096.95 3,002.05 (94.90) $

• 3.1%

Large Power

500KW/200,000 kWh 21,952.82 $ 20,555.32 $ (1,397.50) $

• 6.4%

1,000KW/400,000 kWh 43,708.82 40,881.32 (2,827.50) $

• 6.5%

2,500KW/1,000,000 kWh 108,976.82 101,859.32 (7,117.50) $

• 6.5%

Increase/Decrease from Existing to Year-1 Plan w/$ 0.000 PSCA

Percent of Change

Existing 2017 Residential General Service:

City of Bryan

Proposed Year 1

Rate Class Usage

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Factors impacting electric bills

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Projected Power Supply costs

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• How can these costs be reduced?

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Power Supply changes

• $42.40 Citi Energy contract expires in 2017

– Approximately 3.5% of annual energy requirements – Replace with $36.75 BP Remaining Requirements contract – Approximately $38,951 annual savings

• $39.79 AEP Remaining Requirements contract expires in 2017

– Approximately 6.7% of annual energy requirements – Replace with $36.75 BP Remaining Requirements contract – Approximately $33,037 annual savings

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Power Supply changes

• $62.95 Morgan Stanley contract expires in 2020

– Approximately 10% of annual energy requirements – Replace with $36.75 BP Remaining Requirements contract – Approximately $524,000 annual savings

• $69.69 EDI Landfill Gas contract expires in 2021

– Approximately 4.3% of annual energy requirements – Replace with $36.75 BP Remaining Requirements contract – Approximately $288,554 annual savings

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Power Supply changes

• $49.50 Blue Creek Wind contract expires in 2021

– Approximately 2.6% of annual energy requirements – Replace with $36.75 BP Remaining Requirements contract – Approximately $67,027 annual savings

• Auglaize Hydroelectric Plant water resources evaluation

– Study indicates water resources can support capacity increase from 4,200 kW to 10,280 kW and increase in average energy production from 10.13 million kWh to 17.79 million kWh annually – Evaluate feasibility of installing new turbines and generators designed for site conditions

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Use local generation for peak shaving

• Approximately 39 MW of local

generation for emergency backup and peak shaving

• 26 MW two (2) Westinghouse

191 combustion turbines

• 4 MW G.E. Frame 3

combustion turbine

Westinghouse 191 Combustion Turbine 43

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Use local generation for peak shaving

• 2.5 MW Nordberg diesel
• 2 MW solar field
• 4.2 MW Auglaize Hydroelectric

Plant

• Located on Auglaize River

southwest of Defiance

• Six generating units
• Can peak shave when water is

available

• Ability to store two feet of water

Nordberg Diesel Generator

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Use local generation for peak shaving

• PJM capacity costs projected to increase from $1.756 million in 2017

to $2.564 million in 2018

• AEP transmission costs projected to increase from $2.055 million in

2017 to $3.276 million in 2018

• Operating Bryan Power Plant, Solar Field and Auglaize Hydroelectric

Plant during AEP and PJM peaks reduces BMU capacity/transmission costs

• Credits are approximately $10,000/MW-month or $120,000/MW-year
• Projected credits of $4.48 million in 2018

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Year $ $/MWh $ $/MWh $ $/MWh 2018 12,165,216 62.01 2019 14,050,324 71.27 13,098,915 66.45 951,409 4.82 2020 14,583,368 73.61 13,464,929 67.96 1,118,439 5.65 2021 14,184,776 71.24 13,031,118 65.46 1,153,658 5.78 2022 14,105,512 70.49 12,903,195 64.48 1,202,317 6.01 Projected Purchased Power Expense Based On Peaking Shaving Success Rate 66% 100% Difference

Projected power expense with peak shaving credits

• 2019-2022 costs based on 27.8 MW peak shaving; 32+ MW available

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Additional peak shaving opportunities

• Evaluating emissions controls to allow 2.5 MW

Nordberg diesel to be permitted for peak shaving

• Utilize Auglaize Hydroelectric Plant when water

is available

• Continue Water Plant peak reduction efforts
• Work with City departments on peak reduction
• Continue voluntary customer peak reduction
• Investigate local business and industry peak

reduction program

Auglaize Hydro generators

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Total electric sales have decreased

Residential 42,699,280 46,665,280 3,966,000 9.29 Commercial 21,321,287 27,037,855 5,716,568 26.81 Industrial 191,226,144 108,107,254

• 83,118,890
• 43.47

Total 255,246,711 181,810,389

• 73,436,322
• 28.77

Rate Class 2016 Difference % Change 1997

Energy Sales by Rate Class (kWh) Bryan Municipal Utilities

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Power Supply costs have increased

• 1997: $9.14 million, $0.0336/kWh
• 2016: $15.268 million, $0.0729/kWh
• $6.128 million difference, 67% increase
• Power supply costs were 83.4% of 2016 Electric Utility O&M expenses
• Decreasing sales and increasing costs (including inflation) create rate

pressures

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Increased electric sales benefits

• Additional energy purchased at less than current average cost
• Lower-cost additional energy reduces everyone’s power supply cost
• Allows fixed costs to be spread over a greater number of units
• Continue development and marketing of Bryan Industrial Parks

North and South and other available local industrial sites

• Market available local business buildings
• Help existing local businesses expand operations
• Do existing industries have customers or suppliers that we can help

relocate to Bryan?

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Electric Economic Development Rate

• Schedule Economic Development Rate (EDR) adopted by BPA on March

15, 2011

• New and existing Large Power (>50 kW) electric customers eligible
• Businesses selling or providing goods directly to general public

ineligible

• New load must be ≥200 kW at 55% monthly load factor (79,200 kWh)

at least three months per year

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Electric Economic Development Rate

• $0.01/kWh discount for monthly energy use that exceeds customer’s

historic energy use

• Term of Schedule EDR discount—36 months
• Customer must purchase all electric energy requirements from BMU

for five years

• Four customers participated in Schedule EDR program since 2011
• One participant currently

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Proposed Schedule EDR revisions

• Additional loads of 1 MW or less can be served under the BP

Remaining Requirements agreement ($0.03675/kWh) through 2024

• Assumes BMU continues to offset capacity and transmission costs with

local generation

• BMU can offer an economic development incentive of $0.026/kWh off

the Large Power rate

• Reduces Large Power energy rate from $0.048/kWh to $0.022/kWh for

new load only

• Less than 2006 Large Power rate

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Proposed Schedule EDR revisions

• BMU and customer determine 12-month historic energy consumption

baseline

–New equipment added –Additional hours of operation

• BMU continues to bill customer at Large Power rate ($0.048/kWh) for

next 12 months

• At end of next 12-month period, actual energy consumption is

compared to historic baseline energy consumption

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Proposed Schedule EDR revisions

• If actual energy consumption exceeds historic baseline kWh use, BMU

issues rebate check/billing credit to customer for difference (increase) in kWh x $0.026/kWh

• Performance based incentive—customer must grow and sustain

increased load to receive rebate over three years

• No penalty for failure to increase load over baseline kWh use

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Proposed Schedule EDR revisions

• Customer submits completed application to participate
• New customer loads must be ≤1 MW
• Discount period remains three years
• Annual load factor must be ≥55%
• Deviations from these parameters handled on a case by case basis and

require BPA approval

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Assumptions

• PSCA and kWh tax still apply to all kWh used
• Assumes no BMU capital investment to serve additional load
• Available to existing and new Large Power customers

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Schedule EDR revision advantages

• Rate covers out of pocket expense and contributes to fixed costs
• Load growth reduces average power supply cost for all customers
• Load growth within city limits increases kWh tax to General Fund
• Load growth often results in more local jobs
• Based on customer feedback, present revised Schedule EDR for BPA

consideration at November 21 regular meeting

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Ways customers can impact their electric bills

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Load Factor improvement

• Three primary components to Large Power bill:

–Customer charge: $220 per month –Demand charge: $20/kW (Maximum rate of energy use per month— kWh/hour) –Energy charge: $0.048/kWh

• Load factor is the ratio of actual energy use over a given period of

time versus energy use at peak demand rate over same period

• The greater the load factor, the lesser the average cost per kWh

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Load Factor improvement

• Example:
• Local Company A has monthly demand of 1,404 kW and 525,600 kWh

energy consumption

• 100% monthly Load Factor calculation

–1,404 kW x 24 hours/day x 30 days/month = 1,010,880 kWh

• Actual monthly Load Factor calculation

–525,600 kWh/1,010,880 = 51.99% Load Factor

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Load Factor improvement

• Average cost/kWh at 100% Load Factor

–$20/kW x 1,404 kW = $28,080 –1,010,880 kWh x $0.048/kWh = $48,522 –$28,080 + 48,522 = $76,602 or $0.0758/kWh

• Average cost/kWh at 51.99% Load Factor

–$20/kW x 1,404 kW = $28,080 –525,600 kWh x $0.048/kWh = $25,229 –$28,080 + 25,229 = $53,309 or $0.1014/kWh

• All additional hours operating same equipment each month costs

$0.048/kWh, not $0.1014/kWh

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Managing peak demands

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Load Factor improvement

• Peak monthly demand of 1,404 kW
• Large Power Demand rate = $20/kW
• Total monthly demand cost = $28,080
• 0.25 hours during month exceeded 1,400 kW
• 4.5 hours during month exceeded 1,300 kW
• 4.75 hours of managing electric use to stay below 1,300 kW = $2,000

(7.1%) savings on monthly demand costs

• Required 33.75 hours of load management to reduce peak by another

100 kW and save additional $2,000 (14.2%) on monthly demand costs

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How to improve monthly Load Factor

• Keep peak demand the same, increase kWh use
• Reduce peak demand, keep kWh use the same
• Reduce peak demand, increase kWh use
• Review hourly electric demand data to identify opportunities to

manage peak demands

• Increased operating hours (additional shifts, additional days, longer

daily hours of operation) using same equipment increases Load Factor

• Greater monthly Load Factor = Lesser cost/kWh

• Reliable. Local. Yours.

Power factor improvement

• Ratio of real power to apparent power due to inductive loads such as

motors and transformers

• Reduces usable capacity of plant electric systems and increases

resistance losses

• Power factor billed as Reactive kW at the rate of $0.56/RkW
• Typically corrected using capacitors installed by electrical contractor
• For power factors of <85%, payback periods may be relatively short

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Off-Peak Electric Rate

• Requires time-differentiated demand meter
• Billed demand is greater of maximum kW demand during on-peak

hours or 50% of the maximum kW demand during off-peak hours

• On-peak hours are 7 a.m. to 7 p.m. on all non-holiday weekdays
• All other time is off-peak
• Holidays are New Years Day, Memorial Day, Independence Day, Labor

Day, Thanksgiving Day and Christmas Day

• Reliable. Local. Yours.

Energy efficiency

• The cheapest kilowatt-hour is the one you don’t use
• Lighting retrofits, power factor correction and energy efficient motor

replacements are relatively easy to implement and offer more predictable savings

• Interest in energy efficiency programs?
• Interest in revolving loan fund to help finance energy efficiency

improvements?

• Reliable. Local. Yours.

Electric system reliability

• American Public Power Association (APPA) is the service organization

for more than 2,000 U.S. community-owned electric utilities

• APPA’s Reliable Public Power Provider (RP3) program recognizes

utilities that demonstrate high proficiency in four key areas:

– Reliability – Safety – Workforce development – System improvement

• BMU first received RP3 certification in 2006
• BMU is RP3certified through 2018

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Electric system reliability

Toledo Edison AEP Ohio Regional Average BMU 0.5500 1.0800 0.6907 0.3909 System Average Interruption Frequency Index (SAIFI) Average number of electric service interruptions/customer/year

Utility 2016

70

Toledo Edison AEP Ohio Regional Average BMU 111.20 minutes 58.16 minutes Average duration of electric service interruptions

Utility 2016

96.57 minutes 143.45 minutes Customer Average Interruption Duration Index (CAIDI)

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Takeaways

• Large Power rates decreased approximately 6.5% in October
• Continue to seek ways to further reduce electric costs while

maintaining reliable service

• We are here to help you—our customers and owners are the

same people

• We would welcome the opportunity to learn more about your

business

• We can all be more successful by working together

• Reliable. Local. Yours.

Questions?

Bob Eyre and Kevin Maynard Oct. 30, 1995