Transcript Utility Rates - Nc State University

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
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
$10
$4
$3
$2
On-Peak Electricity
Natural Gas
Price / MMBtu
$80
12
/3
1/
19
9
Ju 7
lA 98
pr
A 99
pr
D 00
ec
-0
Ju 0
l-0
Ja 1
n0
Ju 2
l-0
Fe 2
b0
O 3
ct
-0
Ja 3
n0
Ju 4
lFe 04
b05
Ju
l-0
Ja 5
n0
Ju 6
l-0
Ja 6
nA 07
ug
A 07
ug
A 09
ug
-1
1
Price / MWh
12 Month Price of Wholesale Energy Commodities
A/D 7x24 2010
Trigger F (38.2%) = $51.9
Trigger D (61.8%) = $54.6
Trigger G (23.6%) = $50.2
Trigger E (50%) = $53.3
8/22/2008
8/8/2008
7/25/2008
$5 3
$5 6
$5 5
$5 5
$5 5
$5 7
$5 8
$5 7
$5 7
$5 7
$5 6
$5 6
$5 6
$5 5
$5 5
$5 5
$5 5
$5 4
$5 4
$5 8
$5 9
Aep / Dayton Hub 2010 7x24 Prices
7/11/2008
6/27/2008
6/13/2008
5/30/2008
5/16/2008
$5 3
$5 9
$5 8
$5 8
$5 7
$5 7
$5 8
$60.0
5/2/2008
4/18/2008
4/4/2008
3/21/2008
3/7/2008
2/22/2008
$5 5
$5 5
$5 5
$5 5
$5 5
$5 5
$5 4
$5 4
$5 3
$5 3
$5 2
$5
$5 2 3
$5 3
$5 2
$57.5
2/8/2008
1/25/2008
1/11/2008
12/28/2007
12/14/2007
$5 1
$55.0
11/30/2007
11/16/2007
$4 9
$4 9
$5 0
$5 0
$5 0
$52.5
11/2/2007
10/19/2007
10/5/2007
9/21/2007
$4 8
$50.0
9/7/2007
Price Strategy
DANVILLE
$47.5
Time Strategy
•
•
Based on 18 Year natural gas movement.
Best middle to late winter and summer seasons.
Annual Natural Gas Future Prices
13.00
January - February
Hurricane Katrina
12.50
12.00
11.50
August - September
11.00
10.50
$/MMBTU
10.00
9.50
9.00
8.50
8.00
7.50
7.00
6.50
6.00
5.50
5.00
4.50
January
February
2002
March
2003
April
May
2004
June
2005
July
Date
2006
August
September
2007
October
2008
November
December
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
13
Danville 2008 Power Resourses
300
250
200
MW
150
100
50
0
-10
-15
-10
-15
MAR
APR
MAY
-10
-10
-10.0
-10.0
OCT
NOV
-15
-50
JAN
FEB
JPMorgan_2007-2012_7x24
RHGS PSR
Danville Hydro
Monthly Off-Peak Sale
JUN
JUL
AUG
Month
Lehman_2007-2008_7x24
RHGS Excess
Danville Peaking
AMPO Peaking
SEP
DEC
JPMorgan_2007-2008_5x16
SEPA
14
Monthly 7x24 Sale
Expected Peak
Danville 2009 Power Recourses
300
250
200
MW
21
150
100
50
21
21
35.0
35.0
25.0
21
21
21
21
21
35.0
35.0
21
20.0
25.0
20.0
25.0
21
25.0
10.0
25.0
35.0
10.0
25.0
16
12.5
6.5
16
12.5
6.5
16
12.5
6.5
16
12.5
6.5
16
12.5
6.5
16
12.5
6.5
16
12.5
6.5
16
12.5
6.5
16
12.5
6.5
16
12.5
6.5
MAR
APR
MAY
JUN
JUL
AUG
SEP
OCT
NOV
DEC
25.0
10.0
25.0
16
12.5
6.5
16
12.5
6.5
JAN
FEB
21
10.0
10.0
25.0
21
5.0
25.0
10.0
25.0
35.0
25.0
0
Month
JP Morgan 7x24
9 year 7x24
3 year 5x16
Danville Peaking
Lehman 7x24 09-17
2 year 7x24
Monthly 7x24
AMPO Peaking
Detusche 7x24 09-12
Annual 7x24
Monthly 5x16
Expected PEAK
AEP 7x24 09-10
Danville Hydro
SEPA
15
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
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
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
 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
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
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.progressenergy.com/aboutenergy/rates/nctariffs.asp
• http://www.duke-energy.com/rates/northcarolina.asp
Is there competition in Utilities business?
• http://www.duke-energy.com/north-carolinalarge-business/rates-bills/regional-ratecomparisons.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 upon
meter 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