2019 Energy Update Bryan Municipal Utilities Kevin M. Maynard - - PowerPoint PPT Presentation

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2019 Energy Update

Bryan Municipal Utilities Kevin M. Maynard

Director of Utilities October 11, 2018

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Bryan Municipal Utilities overview

• Non-profit, community-owned utility services provider
• Established in 1892
• Three primary services
• Water
• Electricity
• Telecommunications
• 48 full-time and 18 part-time employees
• 2017 revenue of approximately $29 million

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Bryan Municipal Utilities overview

• Oversight provided by five-

member Board of Public Affairs

– Bryan residents elected by local citizens to four-year, staggered terms – Approve policies, staffing, budgets, rates – Authorize utility improvements and extensions – City Council approval of annual utilities budget and debt issues required

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
• Ortho/polyphosphate to stabilize water (avoid corrosion)
• 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)

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

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Residential 170,007,684 137,779,356

• 32,228,328
• 18.96

Commercial 307,241,748 174,217,428 -133,024,320

• 43.30

Total 477,249,432 311,996,784 -165,252,648

• 34.63

Water Sales by Rate Class (Gallons) Bryan Municipal Utilities

Rate Class 2017 Difference % Change 1997

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Water Utility rate plan

• In 2015, BPA adopted a five-year water rate plan
• Fourth year of rate plan effective with bills rendered
• n or after Dec. 20, 2018 (approximate 3% increase)
• Water rates generate sufficient revenue to meet

O&M expenses but are not sufficient to fully fund annual capital improvement costs of approximately $1 million

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Water Utility rate plan

• BPA directed staff to prepare new four-year rate

plan to replace current plan

– Approximate 7% annual adjustments from 2019-2022 – Increase fixed charges rather than volumetric charges

• Water rates remain competitive with others in area

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Water Utility primary issues

• Ensure adequate capital improvements funding

– Additional $600,000-$700,000 needed annually for water supply, treatment and distribution system improvements – Seeking water main replacement financing and grant

• ptions in 2019 and beyond

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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 solar field site west of town? – Do new treatment technologies make softening or other water quality enhancements feasible? – Water supply and treatment master plan being developed

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Telecommunications Utility

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Municipal Telecommunications Utility

• Current fiber optic system approximately 20 years old
• Estimated service life of fiber optic cable is 20-30 years
• Plan to rebuild fiber optic system over next 5-10 years
• Plan to increase Internet 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

• Emphasis on a diverse, more environmentally friendly

power supply portfolio

• Approximately 25% generated by renewable resources

including:

• Landfill gas to energy
• Hydroelectric
• Solar
• Wind
• Approximately 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, 3.6% AMP Hydro, 4.0% Meldahl Hydro, 3.2% Greenup Hydro, 1.5% AFEC (Natural Gas), 14.2% Prairie State (Coal), 28.2% EDI Landfill Gas (2021), 3.9% Blue Creek Wind (2022), 2.3% Bryan Solar, 1.1% Auglaize Hydro, 4.2% Morgan Stanley Purchase (2020), 8.9% BP Purchase (2024), 22.5%

Projected Bryan Municipal Utilities 2019 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 long-term changes in power supply costs

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Historic total power supply costs

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$34.93 $60.94 $67.66 $64.23 $68.64 $65.91 $72.17 $65.31 $68.67 $71.05 $69.10 $72.92 $82.84 $68.55 $0.00 $10.00 $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $80.00 $90.00 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

BMU Annual Power Supply Costs $/MWh

$ per MWh

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Electric Rate Plan

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2017 Electric COS study/rate plan

• In 2017, BPA adopted first year of proposed three-year

electric rate plan

• Rates last adjusted in 2006

– Power supply resources/costs changed significantly from 2006-2017 – New resources had greater demand and lesser energy charges – Power Supply Cost Adjustment (PSCA) had grown to $0.0279/kWh

• Help ensure adequate capital improvements funding
• Provide adequate funds (~$2.0 million annually) to maintain

reliable service and keep long term rates lower and more stable

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Three-year electric 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 (kW) charge
• Decrease energy (kWh) charge
• $2 million annual capital improvements allocation
• Power supply costs included in base rates rather than in PSCA
• BPA adopted Year 1 of three-year plan on August 15, 2017
• Year 2 modifications to be presented to BPA in November 2018

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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

City of Bryan

375 kWh 50.33 $ 47.42 $ 48.86 $ 1.44 $ 3.0% 750 kWh 91.16 86.59 87.46 0.87 $ 1.0% 1,500 kWh 169.58 164.93 164.68 (0.25) $

• 0.2%

1,000 kWh 146.43 $ 143.18 $ 147.68 $ 4.50 $ 3.1%

(1-Phase)

2,000 kWh 280.31 269.82 274.32 4.50 $ 1.7% 5,000 kWh 677.39 646.92 652.17 5.25 $ 0.8%

General Service:

10 kW/2,000 kWh 280.31 $ 269.82 $ 274.32 $ 4.50 $ 1.7%

(3-Phase)

25 kW/5,000 kWh 677.39 646.92 652.17 5.25 $ 0.8% 50 kW/10,000 kWh 1,259.37 1,226.42 1,244.92 18.50 $ 1.5% 100 kW/20,000 kWh 3,096.95 3,002.05 2,999.55 (2.50) $

• 0.1%

Large Power

500 kW/200,000 kWh 21,952.82 $ 20,555.32 $ 20,380.32 $ (175.00) $

• 0.9%

1,000 kW/400,000 kWh 43,708.82 40,881.32 40,526.32 (355.00) $

• 0.9%

2,500 kW/1,000,000 kWh 108,976.82 101,859.32 100,964.32 (895.00) $

• 0.9%

Percent Change

Existing 2018 Proposed Year 2 Residential General Service:

Rate Class Monthly Use

Increase/Decrease from Existing to Year 2 Plan w/$ 0.000 PSCA

Prior 2017

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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

• $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 increase in average energy production from 10.13 million kWh to 17.79 million kWh annually – Evaluating feasibility of installing new turbines/generators designed for site conditions

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Use local generation for peak shaving

• Approximately 38.5 MW of local

generation for emergency backup and peak shaving

• Three combustion turbines
• Nordberg diesel
• Bryan solar field
• Auglaize Hydroelectric Plant

– If water is available – Can store water for peak shaving

Westinghouse 191 Combustion Turbine 32

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Use local generation for peak shaving

• Projected capacity and transmission costs:
• 2019 - $4.23 million
• 2020 - $4.54 million
• 2021 - $5.32 million
• 2022 - $5.86 million
• 2023 - $5.89 million
• Operating Power Plant, Solar Field and Auglaize Hydroelectric Plant

during AEP and PJM peaks reduces BMU capacity/transmission costs

• Credits are approximately $12,500/MW-month or $150,000/MW-year
• Projected capacity and transmission credits of $4.72 million in 2019

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Peak shaving sensitivity analysis

• 2019-2023 costs based on 27.8 MW peak shaving; ~38.5 MW available

Year $ $/MWh $ $/MWh $ $/MWh 2019 10,452,526 52.33 2020 13,478,964 67.05 12,643,395 62.89 835,569 4.16 2021 13,503,289 67.01 12,361,848 61.35 1,141,441 5.66 2022 13,577,877 67.22 12,329,396 61.04 1,248,481 6.18 2023 13,626,753 67.31 12,371,755 61.11 1,254,998 6.20 Projected Purchased Power Expense Peaking Shaving Sensitivity Analysis 66% 100% Difference

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Peak shaving sensitivity analysis

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Peak shaving opportunities

• Soliciting bids to install emissions controls to

allow 2.5 MW Nordberg diesel to peak shave

• Utilizing Auglaize Hydroelectric Plant when

water is available

• Continue Water Plant peak reduction efforts
• Continue City departments peak reduction
• Continue voluntary customer peak reduction
• Expand local business and industry peak

reduction program

– Please let us know if you are willing to assist

Auglaize Hydro generators

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Electric utility sales trend

Residential 42,699,280 43,691,480 992,200 2.32 Commercial 21,321,287 25,805,790 4,484,503 21.03 Industrial 191,226,144 107,964,046

• 83,262,098
• 43.54

Total 255,246,711 177,461,316

• 77,785,395
• 30.47

Rate Class 2017 Difference % Change 1997

Energy Sales by Rate Class (kWh) Bryan Municipal Utilities

• Electric sales have decreased over the last 20 years
• Decreasing sales and inflation create rate pressure

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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 to market Bryan Industrial Park North and Bryan Industrial

and Commercial Park 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

expand or relocate to Bryan?

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Schedule EDR Economic Development Rate

• Adopted by Bryan BPA on November 21, 2017
• Additional energy purchased at less than current average cost
• Assumes BMU offsets capacity/transmission with local generation
• Incentive of $0.026/kWh off Large Power energy rate
• Reduces Large Power energy rate from $0.048/kWh to $0.022/kWh for

new/additional energy use only

• Less than 2006 Large Power rate

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Proposed Schedule EDR revisions

• BMU and customer determine 12-month Base Annual Energy Use

–New equipment added –Additional hours of operation

• BMU bills customer Large Power rate ($0.048/kWh) for next 12 months
• At end of next 12-month period, actual energy consumption is

compared to Base Annual Energy Use

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Proposed Schedule EDR revisions

• If actual energy consumption exceeds Base Annual Energy Use, BMU

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

• Performance based incentive—customer must grow/sustain increased

load to receive rebate over three successive 12-month periods

• No penalty for failure to increase load over Base Annual Energy Use

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Proposed Schedule EDR revisions

• Customer submits completed application to participate
• New/additional customer loads must be ≤1 MW
• Discount period is 36 months
• Annual load factor must be ≥55%
• Deviations from these parameters require BPA approval
• 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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How can you reduce your electric bill?

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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 = $2,080

(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

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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 by 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

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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 predictable savings

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

improvements?

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Electric system reliability

• American Public Power Association (APPA) is the service
• rganization 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 RP3 certified 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

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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

• Water rates projected to increase ~7% in 2019
• Large Power rates projected to decrease ~1.0% in 2019
• Power supply costs projected to decrease in 2019
• 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 welcome the opportunity to learn more about your

business

• We can all be more successful by working together

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Questions?

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Utilities and Energy Costs Ohio Gas Company

Bob Eyre

Vice President Gas Supply and Industrial Services October 11, 2018

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What can we expect to see regarding 2019 rates?

• Ohio Gas has taken the following actions to cushion the

impact of price fluctuations for our customers:

–Underground storage—Ohio Gas purchases a large portion of our natural gas requirements during the period of April-October and stores it underground for use throughout our winter season

• About 50% of the natural gas consumed during the winter comes

from storage and approximately 70% for peak day or coldest weather

• Helps ensure enough natural gas to meet customers' needs and

stabilize our gas rates

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What can we expect to see regarding 2019 rates?

• Ohio Gas has taken the following actions to cushion the impact of

price fluctuations for our customers:

–Hedging—Ohio Gas physically hedges approximately 50% of our winter supply production through the NYMEX, the world's largest physical exchange of natural gas commodities

• Reduces the volatility of our gas rates

–Billing plans—Ohio Gas offers balanced-billing plans that allow customers to spread their natural gas costs over 12 months, which makes it easier for our customers to budget cash flow

• We encourage customers to enroll during the fall months

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What can we expect to see regarding 2019 rates?

• Ohio Gas has taken the following actions to cushion the

impact of price fluctuations for our customers:

–What can you expect—Ohio Gas customers, based on the above taken actions, should experience a 15% rate decrease in the gas supply cost of your bill

• Rate decrease based on normal temperatures over a 30-year period
• If we experience a colder than normal winter, your gas bills will be

higher and vice versa; warm winter brings lower bills

• Last year we were 5% colder than normal

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Questions?