Financial / Managerial Considerations in the
Electric Power Industry
What’s Behind the Switch
Lecture 7
Gene Freeman
6/27/2016
ECEN 2060 Fall 2013
1
Agenda
1. Decision Environment for Utility Companies
2. The Profit Equation & the Nature of Costs
3. Comparison of Generation Technologies & Decision
Making Dilemmas
4. Predicting Future Costs for Facilities That Have Not
Been Built Yet
a) Fixed Costs
b) Variable Costs
c) LCOE
5. Tactical Planning - Load vs. Capacity
6. Politics
7. Appendix Methods
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ECEN 2060 Fall 2013
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Quiz
1. A business sells a device for $1.00 that costs
$0.50 in variable cost to make. It sells
1,000,000 of them per year. The company’s
fixed expenses are $250,000. What is the
break-even point
2. What is the annual Operating Income at
1,000,000 units
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Quiz Answers
1. QBE = FE / (ASP – uVC) = 250,000 / (1.00 - 0.50)
= 500,000 units
2. OI = Q x (ASP x - uVC) – FE
= 1,000,000 x (1.00 – 0.50) – 250,000
= $250,000
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Annual Fixed Cost Prediction for a New Facility
• Adding a new utility plant involves
– 20+ year estimates of future cost
– $B of borrowing
high interest loads
• Uncertainties in future fixed costs
– Interest rate fluctuations
– Fixed operations cost variations (e.g. salaries, materials)
– Insurance, Tax Rates, etc.
• What is known before a new plant it is built
– PR = Rated capacity (net output) in kW, MW or GW
– Estimated capital cost of the project
– Weighted Average Cost of Capital (WACC)
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Estimating Cost of Capital - WACC
Ownership
Equity %
Debt %
Equity
Cost %
Debt
Cost %
WACC
Cost %
Merchant Fossil Fuel
60
40
12.5
7.5
10.5
Merchant non Fossil Fuel
40
60
12.5
7.5
9.5
Investor Owned (IOU)
50
50
10.5
5
7.75
Publicly Owned (POU)
0
100
0
4.5
4.5
• WACC = Weighted Average Cost of Capital
• 2 kinds of borrowing for new plants
– Construction loans during the build phase
– Permanent financing once the plant is finished
• “Over Night” vs. “All-In” construction costs
– “Over Night” ignores construction loan charges
– Allows comparison of big projects to small ones (e.g. CCNG to Solar)
• Each company calculates its own WACC based on its particular
capital structure and costs
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Annualized Fixed Costs & FCR%
• Fixed costs on a new plant are estimated as follows
–
–
–
–
–
(PR x Capital cost / kW) x FCR%
FCR% = Fixed Charge Rate
FCR% = CRF% + Ops Fixed Cost% + Tax %
FCR% may also include target profit objective
CRF = Capital Recovery Factor = [ i * (1 + i )n ] / [(1 + i )n -1]
•
•
•
•
•
i = WACC
n = # years
Appendix A elaborates on the “finance” concepts
It is the largest part of the FCR%
For a $1B loan @ 10% over 20 years
– CRF = 11.75%
– Annual Payment = $117.5M
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Other Annualized Fixed Cost %
• It is impossible to predict accurately the future fixed
costs for a facility that has not been built yet
– Ops Fixed Cost% factors are based on history from
other plants of similar technology
– Tax Rates are normally stable so % factor
can be derived from prior history for the area
where the facility is being built
– Other fixed charge factors can be similarly estimated based on
history or other data
– These are added to CRF% to determine the multiplier that will be
applied to the projected cost of construction of a new asset
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Example 1.2 in book
• Investor Owned Utility has 52% equity @ 11.85% and
48% debt @ 5.4%
• 20 year payback period
• WACC = (0.52 x 0.1185) + (0.48 x 0.054) = 8.754%
• CRF = [0.08754 x (1 + 0.08754)20 ] / [(1+0.08754)20 – 1]
= 10.763%
• To build a new facility with estimated values
–
–
–
–
Construction cost = $1300/kW rated power
2% adder for Ops Cost
4% for Taxes
FCR = 16.763% (10.673% + 2% + 4%)
• For every kW of rated power,
– Fixed Costs = ($1300 / kW * 0.16763)
= $218 / year
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Agenda
1. Decision Environment for Utility Companies
2. The Profit Equation & the Nature of Costs
3. Comparison of Generation Technologies & Decision
Making Dilemmas
4. Predicting Future Costs for Facilities That Have Not
Been Built Yet
a) Fixed Costs
b) Variable Costs
c) LCOE
5. Tactical Planning - Load vs. Capacity
6. Politics
7. Appendix Methods
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Variable Cost Uncertainty
• Fuel is the biggest operating cost for a fossil fuel plant
• Future fuel costs are difficult to predict and compare
– Variability in pricing
– Differences in conversion rates of fuel into electric power
– Transportation costs
• Economic modeling is used to smooth out variability
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Computing Annualized Variable Costs
• Annual Energy Output kWhr/yr = PR x 8760 hrs/yr x CF
PR = Rated Output Power in kW
CF = % of a year that the plant operates
•
•
•
•
•
•
Preventative maintenance
Break-downs
Fuel shortages
Lack of demand
Planned Utilization
Margins
• Annualized Var. Cost $/yr
= (fuel cost + OM var) $/kWhr x Output kWhr/yr
– Fuel Cost $/kW = Fuel Cost $/MBTU x Heat Rate BTU/kW x LF
– LF (leveling Factor) is the accounting method for normalizing
future fuel cost fluctuations (see graph on next slide)
– Variable Operations and Maintenance cost are usually specified
in $/kWhr
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LF – Levelizing Curves for Cost of Energy
• See Appendix A in Text for derivation
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Annualized Variable Cost Estimate from Ex 1.3
• NGCC plant has the following statistics
–
–
–
–
–
–
NG costs - $6/MBtu with 5% / yr inflation rate
Interest (Discount) Rate = WACC = 10%
Thus LF =1.5 based Fig 1.28 @ 5% inflation & 10% discount rate
O&M variable Cost = 0.4¢ / kWhr
Heat Rate = 6900Btu / kWhr
CF = 0.7 (i.e. plant runs 70% of the time during a year)
• Annual Energy Delivered per kW of rated power =
8760 hrs x 0.7 = 6123 kWhr / yr
• Annual Fuel Cost / kWhr rated
6132 kWhr / yr x 6900 Btu / kWhr x $6 / MBtu x 1.5 = $381 / yr
• O&M cost /kW rated per year =
$0.004 x 6132 kWhr / yr = $25 / yr
• Total annual variable cost per kWhr =
$381 + $25 = $406 / kWhr
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Agenda
1. Decision Environment for Utility Companies
2. The Profit Equation & the Nature of Costs
3. Comparison of Generation Technologies & Decision
Making Dilemmas
4. Predicting Future Costs for Facilities That Have Not
Been Built Yet
a) Fixed Costs
b) Variable Costs
c) LCOE
5. Tactical Planning - Load vs. Capacity
6. Politics
7. Appendix Methods
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LCOE – Levelized Cost of Energy
• = (Annual Variable Cost + Annual Fixed Cost) / Annual Output
= $/kWhr
• This is an important figure when comparing various types of power
generation systems, especially conventional fossil fuel systems to
alternative energy sources
• It is an estimate of what future electric power output would cost from
any given technology based on
–
–
–
–
–
Rated Capacity of the facility
Planned Construction Costs
A bunch of assumptions
Prior experience
Accounting methodologies
• For Example 1.3
LOCE = ($218 + $406) /( 8760 x 0.7)
= 10.17¢ per kWhr
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Agenda
1. Decision Environment for Utility Companies
2. The Profit Equation & the Nature of Costs
3. Comparison of Generation Technologies & Decision
Making Dilemmas
4. Predicting Future Costs for Facilities That Have Not
Been Built Yet
a) Fixed Costs
b) Variable Costs
c) LCOE
5. Tactical Planning - Load vs. Capacity
6. Politics
7. Appendix Methods
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Tactical Decisions - Cost Optimization Issues
• Load vs. Capacity – hour by hour business problem
–
–
–
–
Peak Load Buying
Base Load Selling
Customer Demand Profiles
Proximity of Loads to Sources
• Fuel costs / kWhr are a different
– Different Conversion Efficiencies
– Different $ / MMBTU
$ / kWhr
– Different Emissions
• Location of plants affects both revenue and cost
–
–
–
–
Rate Governance is Local
Tax Rates are Local, State & Federal
Grid losses to the loads
Transportation Costs for Fuels
• Fixed costs are different from plant to plant
– Operations & Maintenance (age of systems)
– Depreciation & Amortization (initial cost of systems)
– Interest Rates on the Debt
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Demand Profile for a Mid-Western Utility
Type
Residential
Large Industrial
Small Commercial
Public Authorities
Wholesale
Other
Total
Number
2,940,024
1,147
419,618
68,510
75
3,429,374
Revenue
Total
Per Customer
$ / Yr
$ / Yr
2,713,575,000
922.98
1,534,728,000 1,338,036.62
2,956,077,000
7,044.69
130,538,000
1,905.39
687,912,000 9,172,160.00
427,389,000
8,450,219,000
Rate
$/kWhr
0.1084
0.0560
0.0829
0.1177
0.0436
KWhrs
Total
Per Customer
kWhrs / yr
kWhrs / yr
25,033,000,000
8,515
27,396,000,000
23,884,917
35,660,000,000
84,982
1,109,000,000
16,187
15,781,000,000 210,413,333
0.0805 104,979,000,000
• Mix of customers in 8 states in Mid-West
• Load peaking occurs during Summer Afternoons (cooling) and
Winter nights (heating)
• Buy power from suppliers to cover the peaks
• Sell excess power to the grid at wholesale rates
• Proximity of generation to large demand customers is important to
reduce line losses
• Proximity of plants to fuel sources reduces transportation costs
• Generation sources are spread out over the region
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Generation mix for Mid-Western Utility
Type of
Generation
Number of Units
Output (MW)
Avg Output / Unit
(MW)
Coal Fired Steam
23
7353
319.7
NG Fired Steam
13
1767
135.9
Co-Generation
5
288
57.6
Bio Mass Steam
6
52
8.7
71
5025
70.8
238
327
1.4
3
1594
531.3
74
371
5.0
433
16777
38.7
NG Turbine
Wind Turbine
Nuclear Steam
Hydroelectric
Total
Note the range of output capacity vs. the type of generation
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Transmission & Distribution
Transmission
Line Type
Area 1
(Miles)
500kV Grid Feeder
2917
345kV
6388
230kV
1801
161kV
281
Area 2
(Miles)
Area 3
(Miles)
Area 4
(Miles)
1152
1614
6805
12228
9684
1568
138kV
92
115kV
7129
1737
4923
11479
<115kV
82963
32090
73813
22067
349
204
230
426
Substations
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Capacity Utilization Logic – All Utilities
• The Mid-Western example company has 50% more capacity than it
was able to sell
– (17GW ~ 150GkWhrs)
– The company sold 105GkWhrs in 2012
• It also had to buy 34.9GkWhrs at wholesale rates on top of what it
could generate on its own
• Why is there so much excess capacity in their system?
– No plant can operate at a CF = 1
– Some plants are too expensive to operate at all (i.e. uVC > ASP) but
they are required to cover peak load periods
– Plant failures occur that cause unscheduled down time
– Preventative maintenance is required for all equipment, especially
plants that are at the end of their useable life
– Weather and accidents sometimes hit the grid causing localized
outages that must be “boot-strapped” by other sources
– Transmission & distribution losses reduce effective capacity (10% to
20%
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Capacity Utilization Logic – All Utilities
• Maximize utilization (CF) of existing high fixed cost / low
variable cost generation facilities first
– Coal Fired Steam
– Nuclear
– Hydro in some regions
• Use higher variable cost facilities next to supplement
base capacity
– Gas fired steam or Combined Cycle plants
• Cover peaks with purchased power or Gas Fired Central
Turbines (highest variable cost) only when needed
• How Solar and Wind fits depends upon the company
• Safety margins are set to protect grid during peak
loading and buffer down time
• Avoid rolling blackouts to compensate for capacity
shortages, but protect the grid
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Yearly Load Profile – Load Duration Curve
Hour to hour load
variability over a
whole year –
8760 hours
Load Variability
reordered from
highest to lowest
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Load Duration Curve
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Screening Curves
•
•
•
These curves plot the LCOE vs. capacity utilization for various types of
generation technology
The logic for developing these curves is explained in the text on pgs 42 &
43 for a NGCC plant . A similar logic is used for the other technologies
These curves are used to rank order which types of power will be used to
meet what parts of the load duration curve i.e which plants will be turned on
at what time of day
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Break Even – The Utility Industry Model
The text needs to
be corrected for
ex1.3. Total cost
of energy @ 0.7
CF is $624 not
$579
•
•
•
The x axis is the number of hours in a year and any point along it represents the CF
for a given asset (the number of hours in a year it is actually utilized)
The dark line is the total cost line.
This kind of graph is used to derive the screening curves that dictate which asset is to
be used for which load level. This is different for each type of generation asset in the
company
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Adding in Crossover Points from Screening Curves
This curve is unique for each operating company.
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Agenda
1. Decision Environment for Utility Companies
2. The Profit Equation & the Nature of Costs
3. Comparison of Generation Technologies & Decision
Making Dilemmas
4. Predicting Future Costs for Facilities That Have Not
Been Built Yet
a) Fixed Costs
b) Variable Costs
c) LCOE
5. Tactical Planning - Load vs. Capacity
6. Politics
7. Appendix Methods
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3 Sides of the Alternative Energy Argument
• Nothing needs to change
–
–
–
–
–
Large sums are being spent by critics debunking the data / science
Fostered by those with a big stake in the present economics
“Global warming is a farce driven by political agendas in Wash. D.C.”
“Use only PC or NG, we have plenty of it, it is the cheapest solution”
“Stop using tax $ to develop new technologies”
• We are running out of time
–
–
–
–
Intolerable climate change due to green house gases
“Eliminate fossil fuel consumption”
“Energy conservation a strategic imperative”
“Use alternative energy regardless of the cost”
• The system will continue to be governed by basic economics
– Core issues with alternative sources must be resolved before they can be
deployed. More engineering work is needed
– Investment in alternative sources will be paced by market forces
• New additions must demonstrate technical
$$$$$$
and economic competence
$$$$
$$
• Decisions will be based on costs & ROI
$
• Investment in Grid management reduces excess capacity
$$
$$$
• Convert PC to CCNG to reduce costs and emissions
$$$$$
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Economic Realities
• The installed base will not be scrapped in favor of alternative power
alternatives
– $ write off of existing generation capacity ~ $1T - $10T
– $ investment required for the alternatives ~ $20T
– Operating cost differentials favor
new technology - $3 - $10 /MWhr, but
– $12.6B - $42B / yr saving for 4.2M GWhrs
– 595 year payback (best case)
– 2381 year payback (worst case)
• Conversion to alternative technologies
will depend on
– Fixing deficiencies
– ROI
• Nuclear & hydroelectric have the lowest atmospheric impact
– Both require a lot more political / social support
– Large $$$$$$ investments required
– Nuclear waste disposal methods are not yet accepted by most people
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Scientific / Political Realities
• Global warming evidence is not fiction
– How much is caused by human activity
– How much is due to natural phenomenon
– The effects of both are additive!
• Regulations on pollution output will be stringent
– Adding to plant cost (initial investment and operating costs)
– Use of coal for generating electricity will continue to decline
• Converting obsolete capacity to cleaner alternatives is good politics
and good business
– Installing pollution free sources for new capacity is problematic
– The industry has to continue to develop alternatives
– Decisions on which ones fit best will be made on a regional / company
by company basis
• Spending more money on PR campaigns won’t change the facts
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Agenda
1. Decision Environment for Utility Companies
2. The Profit Equation & the Nature of Costs
3. Comparison of Generation Technologies & Decision
Making Dilemmas
4. Predicting Future Costs for Facilities That Have Not
Been Built Yet
a) Fixed Costs
b) Variable Costs
c) LCOE
5. Tactical Planning - Load vs. Capacity
6. Politics
7. Appendix A Methods
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Analysis Methods Text – Appendix A
• Payback Period: Time when ∑profits = Initial Investment (I)
– Text Example - 5 yr payback ($200 / yr savings) on an energy efficient air
conditioner that cost $1000 more to buy
– Most projects have non-linear payback rates
– I = $1000 & profit schedule below
• Payback Period ‘A’ = 2.33 Yrs
Year
Project A
Project B
1
500
100
2
400
200
3
300
300
4
100
400
• ‘A’ looks better but ‘B’ has better
overall return
5
500
• Method ignores total life cycle returns
6
600
• Suppose ‘A’ was in months
Total
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1300
2100
• Payback Period ‘B’ = 4.0 Yrs
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Analysis Methods Text - Appendix A
• Return on Investment ROI = (Returns – I) / I
– Text Example - 5 years of $200 on a $1000 investment
– For non-linear returns, add up annual returns and calculate a ROI
– Consider the following for the same $1000 investment
• ROI ‘A’ = 300 / 1000 = 30% - 4 yrs cum
Year
Project A
Project B
1
500
100
2
400
200
3
300
300
• ROI ‘B’ = 0 / 1000 = 0% - 4 yrs cum
4
100
400
• B looks better with 6 yr investment horizon
5
500
6
600
Total
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1300
• ROI ‘B’ = 1100 /1000 = 110% - 6 yrs cum
• Ignores time value of money and risk
2100
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Analysis Methods Text – Appendix A
•
Present Value = Future Returns / (1+discount rate) n
n = number of years returns are accumulated
•
Text Example – Constant annual returns for 2 different motors discounted
over 20 yrs
In our example I = $1000 & discount rate = 10%
NPV = PVx – Initial Investment
•
•
Year
Project A
PV A
Project B
PV B
• ‘B’ looks better
1
500
454.54
100
90.91
2
400
330.58
200
165.29
• NPV ‘A’ = 78.81 (7.9%)
3
300
225.39
300
225.39
• NPV ‘B’ = 403.94 (40.4%)
4
100
68.30
400
273.21
• Emphasis still on total return
5
500
310.46
6
600
338.68
2100
1403.94
Total
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• Could fund both – NPV >0
36
Analysis Methods Text – Appendix A
•
IRR – special case in NPV method
– Determines discount rate that causes PV = I
– Difficult to compute manually – requires iteration or spread sheet function
– Helps normalize return for projects with different life times and return profiles
– Allows comparison of projects to cost of capital (COC)
Project A
Project B
• IRR ‘A’ ~ 14%
PV @ 10%
1078.81
1403.94
PV @ 14%
1008.11
1214.02
• ‘B’ has better IRR
PV @18%
945.19
1058.08
• Both could be funded if COC <14%
PV @ 20%
916.25
990.63
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• IRR ‘B’ ~ 19%
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Analysis Methods Text – Appendix A
• Cash flow analysis is a way to look at the effect of variability of the
independent variables or results over time
–
–
–
–
–
Revenue
Costs
Interest rates
Tax rates
Etc.
• The engineer makes inputs to these types of analyses, they are
normally handled by bean counters
• This is nothing more than a “Model” for how cash flows into and out
of an enterprise as a result of a decision
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Which Analysis Method Is Best?
• Whatever one your company / boss requires
• Avoid over-analysis. Remember Pareto’s Law
• Most important is getting the assumptions right
– Future costs (labor rates, material costs, energy, interest rates)
– Pricing (what people will be willing to pay, competitors)
– Use high / low / median values to establish ranges for results
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