Utility Rates

Electric, Natural Gas, and Water

Electric Utility

• Different Utility Business Models– “IOU” – Investor Owned Utility

• Ultimately responsible to investors for ROI• Publicly traded on stock market

– “Muni” – Municipally Owned Utility• Owned by a municipality or government entity

– “Coop” – Utility Cooperative• Private, independent electric utilities, owned by the

members they serve

Deregulation

• Over the past 15 years, some states have deregulated electrical power.

• This means that billing for the three basic components are separate and users may choose their own suppliers:– Generation– Transmission– Distribution

Electric Utility

• Generation– Power plant

• Base Load – Nuclear, Coal• Intermediate Load – Natural Gas, Oil• Peak Load – Natural Gas, Diesel• Renewable – Hydro, Wind, Solar

• Transmission– Delivery to distribution

• Distribution– Delivery to end user

Generation Loads• Standard Units for Electricity Commodities:

– 5 x 16 (Intermediate Power) = Power and energy for Monday thru Friday for the 16 hours of the day usually starting at 0700 and ending at 2300 (on-peak)

– 7 x 24 (Base load Power) = Power and energy for Monday thru Sunday for all 24 hours of the day

Electric Market Pressures

• Increasing fuel costs• Federal climate change (Congress and

EPA)• Decreasing supply margins

– Increasing electric demand – Decreasing supply - aging infrastructure– Stranded infrastructure costs

• Market prices set by gas fired generation costs more hours of the year

Deregulation

• Virginia has partially deregulated its markets

• NC has no plans to deregulate anytime soon

• Experience has shown that most people see an increase in costs with deregulation because – Companies must compete with high cost of electricity to places

like NY.– RTO/ISO cost increases

• PJM Installed Capacity – – Requirement began June 1, 2007– Adds $7.80 / MWh to 2009 total rate

Regional Transmission Organizations (RTO)Independent System Operators (ISO)

National Generation Capacity Trend

Capacity by Fuel Type

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

1980 1983 1986 1989 1992 1995 1998 2001 2004 2007

MW

Oil Nuc Coal Renew/Hydro/Oth Gas

5X16 Market Prices

12 Month Price of Wholesale Energy Commodities

$10

$20

$30

$40

$50

$60

$70

$80

Pri

ce /

MW

h

$2

$3

$4

$5

$6

$7

$8

$9

Pri

ce /

MM

Btu

On-Peak Electricity Natural Gas

On-Peak Prices haveincreased by 100%

since 2002

Aep / Dayton Hub 2010 7x24 Prices

$47.5

$50.0

$52.5

$55.0

$57.5

$60.0

9/7

/20

07

9/2

1/2

00

7

10

/5/2

00

7

10

/19

/20

07

11

/2/2

00

7

11

/16

/20

07

11

/30

/20

07

12

/14

/20

07

12

/28

/20

07

1/1

1/2

00

8

1/2

5/2

00

8

2/8

/20

08

2/2

2/2

00

8

3/7

/20

08

3/2

1/2

00

8

4/4

/20

08

4/1

8/2

00

8

5/2

/20

08

5/1

6/2

00

8

5/3

0/2

00

8

6/1

3/2

00

8

6/2

7/2

00

8

7/1

1/2

00

8

7/2

5/2

00

8

8/8

/20

08

8/2

2/2

00

8

A/D 7x24 2010 Trigger D (61.8%) = $54.6 Trigger E (50%) = $53.3Trigger F (38.2%) = $51.9 Trigger G (23.6%) = $50.2

DANVILLE

Price Strategy

Time Strategy

• Based on 18 Year natural gas movement.• Best middle to late winter and summer seasons.

Annual Natural Gas Future Prices

4.50

5.00

5.50

6.00

6.50

7.00

7.50

8.00

8.50

9.00

9.50

10.00

10.50

11.00

11.50

12.00

12.50

13.00

January February March April May June July August September October November December

Date

$/M

MB

TU

2002 2003 2004 2005 2006 2007 2008

January - February

August - September

Hurricane Katrina

13

Danville Energy Supply 1.1 % Load Growth

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

MW

h

SEPA Lehman 7x24 9 Year 7x24 JP Morgan 7x24Deutsche Bank 7x24 3 Year 5x16 AEP 7x24 2 Year 7x24Danville Hydro 2009 Monthly Purchases 2008 Purchases AMPGS 47.619 MWPrairie State 48 MW AMP Hydro Net Shortfall Annual Energy

14

Danville 2008 Power Resourses

-10 -10 -10.0 -10.0-10-15-10-15

-15

-50

0

50

100

150

200

250

300

JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

Month

MW

JPMorgan_2007-2012_7x24 Lehman_2007-2008_7x24 JPMorgan_2007-2008_5x16RHGS PSR RHGS Excess SEPADanville Hydro Danville Peaking Monthly 7x24 SaleMonthly Off-Peak Sale AMPO Peaking Expected Peak

15

Danville 2009 Power Recourses

6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.512.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.516 16 16 16 16 16 16 16 16 16 16 16

25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0 25.0

35.0 35.010.0 10.0 20.0 20.0 10.0 10.0

35.010.0

35.035.0 35.0

10.05.0

21 21

2121

21

2121 21

2121 21

21

0

50

100

150

200

250

300

JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

Month

MW

JP Morgan 7x24 Lehman 7x24 09-17 Detusche 7x24 09-12 AEP 7x24 09-109 year 7x24 2 year 7x24 Annual 7x24 Danville Hydro3 year 5x16 Monthly 7x24 Monthly 5x16 SEPADanville Peaking AMPO Peaking Expected PEAK

Electric Utility

• Typical Customer Classes– Residential– Commercial– Industrial

• Other typical classifications by Load– Small General Service– Medium General Service– Large General Service

Electric Utility

• Less Common Billing Components– Power Factor

• kW/kVA or kW/(kW + kVAR)

Commercial / Industrial Billing

• Industrial plants can use 1,000 kW or more of power.

• Power company must build capacity to meet the maximum load, even if it is used only a few hours per day air conditioners in the summer.

• Peak loads occur infrequently and must be met with expensive generation equipment (i.e., gas turbines), which increases cost to generate power.

Electric Utility• Typical Billing Components

– Kilowatts (kW) • Rate at which energy is supplied referred to as Demand, Load or Peak• Billed at peak (usually set at intervals of 15 or 30 minutes)• Infrastructure Capacity Charge

– Kilowatt-Hours (kWh) • Metered unit of Energy

– Customer Charge• Billing, meter reading, admin, and other general business costs

– Fuel Cost Adjustment• Transportation congestion, system peak charges or system costs, external purchases

and more costly generation assets used• Projected cost of power MINUS Power cost in base rates = Fuel Adjustment

Demand Intervals

0

200

400

600

800

1000

1200

12:00 AM 4:00 AM 8:00 AM 12:00 PM 4:00 PM 8:00 PM

hour of day

Po

we

r, k

W

Aggregate Electricity Consumption

Source: Lawrence Berkeley National Laboratory

Load Factor

LOAD FACTOR = Energy Usage (kWH)

Maximum Demand (kW) x hours/period

Electric Rates

• Demand Rate• TOU Rate• Ratchet Rate• Day-Ahead &

Real-Time Pricing• Tiered Rates• Interruptible• Other

Industrial Electric Bill

Charge Type Usage Rate Charge

Service $500.00

Energy 350,000 kWh $0.036335 $12,722.50

Demand 1,000 kW $11.25 $11,250.00

Taxes 3% of bill $734.18

Total $25,206.68

Based on rates from Large General Service rate for a typical industrial plant energy and demand usage.

Time of Use Rates

• It’s more expensive to make power during the day when everyone wants it rather than at night.

• Time of Use rate rewards customer using power at night with lower rates at night. However, rates during the day (on-peak) and the peak demand rate is usually higher.

Sample Bill – TOU Rate

Charge Type Usage Rate Charge

Service $500.00

On-peak Energy 150,000 kWh $0.03048 $4,572.00

Off-peak Energy 200,000 kWh $0.02548 $5,096.00

Demand (summer)

1,000 kW $19.56 $19,560.00

Taxes 3% of bill $891.84

Total $30,619.84

Time of Use Rate Example

0

200

400

600

800

1000

1200

12:00 AM 4:00 AM 8:00 AM 12:00 PM 4:00 PM 8:00 PM

hour of day

Po

we

r, k

W

TOU Example cont’d

• Energy used in the blue shading is charged at on-peak rates ($0.03048/kWh)

• Energy used in the red shading is charged at off-peak rates ($0.02548/kWh)

• On-peak times are for non-holiday weekdays. Weekends / holidays are off-peak

• Billing demand is determined to be maximum power used during any on-peak interval

Notes:

• Time of use benefits companies that work seven days per week and manufacture at night.

• Costs can be reduced by scheduling operations around peak periods – load shifting.

• Costs can be reduced by utilizing thermal storage for HVAC system and operating equipment during off-peak periods.

Demand Ratchet Clause

• Some older rate schedules specify that the billing demand is the maximum actual demand for the last 12 months.

• It can also be either the current month’s peak demand or 80% of the contract demand.

• This is so power companies can maximize investment of generation assets. Examples: – 40% of max clause to offset seasonality and mobility– Dominion A,B,C day rates

Tiered Rate:

Example: Energy Charge – First 10,000 kWh - $0.05/kWhNext 25,000 kWh - $0.04/kWhAbove 35,000 kWh - $0.03/kWh

Plant using 100,000 kWh would have an energy charge of $3,450 or $0.0345/kWh

Other

Duke Rate I• Double tiered schedule based on ratio of

kWh/kW demand, then sub-tiered based on energy usage within kWh/kW tier.

• These rates are difficult to compute, but generally reward companies that operate more hours and have flatter power profiles.

Link to NC Electric Utility Rates

• http://www.progress-energy.com/aboutenergy/rates/nctariffs.asp

• http://www.duke-energy.com/rates/north-carolina.asp

Is there competition in Utilities business?• http://www.duke-energy.com/north-carolina-l

arge-business/rates-bills/regional-rate-comparisons.asp

Conclusions

• Most power companies bill energy (kWh) and demand (kW).

• It is important to know your rates and where the penalty structures are within them.

• Track your energy trends both by units consumed and by dollar (helps find errors).

Water

• Compared to energy utilities, relatively inexpensive resource

• This will likely change in the future– As resource becomes more scarce– Pollution

• Better lab testing and detection

– Regulation– Aging infrastructure

• Treatment (W&WW)• Delivery (W) and transport (WW)

Water• Two sides to water

– Customer charge often based uponmeter size (like a capacity charge)

– Water to your facility– Wastewater from your facility

• More expensive…Why?

• Combined rates (W&WW)– Most common

• Singular rates (W or WW)– Irrigation rates (W only)– Sewer only rates (WW only)

Water

• Flat rates – flat price per unit metered• Tiered rates – prices change as use more

– May increase or decrease• Block rates – price changes depending upon block

• Typical metering units– Gallons, cubic feet, 100 cubic feet– Metering and billing units may differ

• Prime target for conversion errors

Facility Wastewater

• Most sewer systems are gravity fed (booster stations only where needed)

• Rarely metered– Usage based upon metered incoming water– Wide variations in flow present metering problems– Meters can be expensive

• Metered when company buys meter in agreement with utility– Only feasible for large users where lots of water used in

process