Utility Rates
Electric, Natural Gas, and Water
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 upon
meter size (like a capacity charge)
– Water (W) to your facility
– Wastewater (WW) 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
• 1CF water = 7.48 gallons water
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
Natural Gas
• Market
– Supplies & Demands
– Speculation
• LNG
• PGA
– Less of base rate
• Transporter, firm, interruptible, commercial, industrial
• Delivered in CF (measured in CF)
Natural Gas
• City gate
– Commodity + basis
– NYMEX + transportation and capacity
• Distribution charges
• Market differences – has storage
Natural Gas
• Customer service charge – billing, admin, metering, meter reading, other general business costs
• Therm factor – equalization factor for cf of delivered NG based upon the BTU content
Natural Gas Weekly Chart
Natural Gas Monthly
Increased Natural Gas Consumption
Worldwide Storage
US Storage 60 Days
EU Storage 15 Days
Asian Storage 8 Days
Natural Gas Storage
Balancing NG Seasonal Demand
US NG Transmission Pipelines
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
700,000
600,000
500,000
MW
400,000
300,000
200,000
100,000
1980
1983
1986
1989
Oil
Nuc
1992
Coal
1995
1998
Renew/Hydro/Oth
Gas
2001
2004
2007
5X16 Market Prices
$9
$70
$8
$60
$7
$50
$6
$40
$5
On-Peak Prices have
increased by 100%
since 2002
$30
$20
$3
$2
19
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$10
$4
On-Peak Electricity
Natural Gas
Price / MMBtu
$80
12
/3
1/
Price / MWh
12 Month Price of Wholesale Energy Commodities
Danville Energy Supply 1.1 % Load Growth
1,400,000
1,200,000
800,000
600,000
400,000
200,000
SEPA
Deutsche Bank 7x24
Danville Hydro
Prairie State 48 MW
Lehman 7x24
3 Year 5x16
2009 Monthly Purchases
AMP Hydro
9 Year 7x24
AEP 7x24
2008 Purchases
Net Shortfall
JP Morgan 7x24
2 Year 7x24
AMPGS 47.619 MW
Annual Energy
20
20
19
20
18
20
17
20
16
20
15
20
14
20
13
20
12
20
11
20
10
20
09
20
08
-
20
MWh
1,000,000
28
Aggregate Electricity Consumption
Source: Lawrence Berkeley National Laboratory
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
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.
Demand Intervals
1200
Power, kW
1000
800
600
400
200
0
12:00 AM
4:00 AM
8:00 AM
12:00 PM
hour of day
4:00 PM
8:00 PM
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
 Based on rates from Large General Service rate for a typical industrial plant energy and demand usage.
Charge Type
Usage
Rate
Service
Charge
$500.00
Energy
350,000 kWh
$0.036335
$12,722.50
Demand
1,000 kW
$11.25
$11,250.00
Taxes
Total
3% of bill
$734.18
$25,206.68
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
Service
Charge
$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
Total
3% of bill
$891.84
$30,619.84
Notes:
• TOU bill is more in this case. What is usage factor (is this a 1, 2, or 3 shift plant?)
Usage Factor
=
kWh / kW demand
=
350,000 kWh/ 1,000 kW
=
350 hrs/month
=
16 hrs/day
Plant probably operates two full shifts, maybe three shifts – with lower production at night.
Time of Use Rate Example
1200
Power, kW
1000
800
600
400
200
0
12:00 AM
4:00 AM
8:00 AM
12:00 PM
hour of day
4:00 PM
8:00 PM
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/kWh
Next 25,000 kWh ‐
$0.04/kWh
Above 35,000 kWh ‐
$0.03/kWh
Plant using 100,000 kWh would have an energy charge of $3,450 or $0.0345/kWh
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).