EXHIBIT 99.154
CIGMOD
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TRAINING MANUAL
January 1997
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SYSTEMATIC SOLUTIONS, INC. POLICY ASSESSMENT CORP.
534 E. DAYTON-YELLOW SPRINGS RD. 14604 WEST 62ND PLACE
FAIRBORN, OHIO 45324 ARVADA, COLORADO 80004
(937) 878-8603 (303) 467-3566
<Table>
WELCOME TO CIGMOD........................................................................................1
THE COMPETITIVE INDUSTRY GAMING MODEL....................................................................1
THE PHASES............................................................................................1
Transitional Market................................................................................1
Massive Restructuring..............................................................................1
System Divestiture.................................................................................1
Market Gaming......................................................................................2
Re-Regulation......................................................................................2
Industry Consolidation.............................................................................3
THE CIGMOD PLAYERS....................................................................................3
THE MARKET............................................................................................3
THE RETAIL COMPANIES..................................................................................3
THE GENERATION COMPANIES..............................................................................4
THE REGULATORY COMMISSION.............................................................................5
HOW TO PLAY CIGMOD.......................................................................................5
TIPS FOR NEW PLAYERS..................................................................................6
TIPS FOR THE RETAIL COMPANY...........................................................................6
CALCULATING WHAT YOU NEED TO BUY......................................................................6
NEGOTIATING YOUR CONTRACTS............................................................................6
ESTIMATING THE CAPACITY FACTOR OF A CONTRACT..........................................................7
ESTIMATING THE PER UNIT COST OF CONTRACT POWER........................................................8
PRICING RETAIL POWER..................................................................................9
CHECKING YOUR PROGRESS................................................................................9
TIPS FOR THE GENERATION COMPANY......................................................................10
HOW MUCH CAPACITY DO YOU HAVE?.......................................................................10
WHAT DO YOU WANT TO SELL IT FOR?.....................................................................10
SAMPLE CALCULATION FOR DETERMINING PROFIT OBJECTIVES.................................................11
DO YOU WANT TO BUILD MORE GENERATION?................................................................12
CHECKING YOUR PROGRESS...............................................................................13
RETAIL COMPANY ACTIONS - UNDERSTANDING AND USING FORMS..................................................14
FORM 1 - DIRECT ACCESS OR CFD CAPACITY CONTRACT......................................................14
FORM 2 - TRENDED DIRECT ACCESS OR CFD CAPACITY CONTRACT..............................................15
FORM R3 - RETAIL COMPANY SPOT MARKET PURCHASE STRATEGY...............................................16
FORM R4 - RETAIL COMPANY RETAIL PRICE STRATEGIES.....................................................17
FORM R5 - RETAIL COMPANY ADVERTISING BUDGET..........................................................18
FORM R6 - RETAIL COMPANY MERGER......................................................................19
FORM R7 - RETAIL COMPANY ACQUISITIONS................................................................19
FORM R8 - RETAIL COMPANY HOSTILE TAKE OVER...........................................................20
FORM R9 - RETAIL COMPANY FINANCIAL REORGANIZATION....................................................21
FORM R10 - RETAIL COMPANY MODIFY DIVIDEND RATE.......................................................21
FORM R11 - RETAIL COMPANY MODIFY DEBT/EQUITY RATIO...................................................22
FORM R12 - RETAIL COMPANY CASH TRANSFER..............................................................22
FORM R13 - RETAIL COMPANY DIRECT ACCESS BILLING STRATEGY.............................................24
FORM R14 - RETAIL COMPANY TAKE OVER STRATEGY.........................................................26
FORM R15 - RETAIL COMPANY CONTRACT CANCELLATION......................................................27
FORM R16 - RETAIL COMPANY PLAYER STATUS ADJUSTMENT...................................................28
</Table>
<Table>
RETAIL COMPANY REPORTS..................................................................................29
TABLE R1: RETAIL ENERGY COMPANY FORECAST............................................................29
TABLE R2: RETAIL ENERGY COMPANY STATEMENT OF INCOME AND FINANCE.....................................30
TABLE R3: RETAIL ENERGY COMPANY PURCHASES AND COSTS.................................................33
TABLE R4: RETAIL ENERGY COMPANY CONTRACT INFORMATION................................................35
TABLE R5: RETAIL ENERGY COMPANY PRICES..............................................................37
TABLE R6: RETAIL ENERGY COMPANY SALES...............................................................39
TABLE R7: RETAIL ENERGY COMPANY PERFORMANCE MEASURES................................................41
TABLE R8: SYSTEM ENERGY BALANCE.....................................................................43
TABLE R9: RETAIL ENERGY COMPANY COST PERFORMANCE DETAILS............................................45
Table R9: Retail Energy Company Cost Performance Details for 1999, DARW...........................45
TABLE R10: SYSTEM CAPACITY MARGIN...................................................................47
GENERATION COMPANY ACTIONS - UNDERSTANDING AND USING FORMS..............................................48
FORM 1 - DIRECT ACCESS OR CFD CAPACITY CONTRACT......................................................48
FORM 2 - TRENDED ELECTRIC CAPACITY CONTRACT..........................................................50
FORM G3 - GENERATION COMPANY CAPACITY EXPANSION STRATEGIES...........................................51
FORM G4 - GENERATION COMPANY SPOT MARKET BIDDING STRATEGIES..........................................52
FORM G5 - GENERATION COMPANY PLANT RETIREMENTS.......................................................54
FORM G6 - THE GENERATION COMPANY SPOT MARKET PURCHASE STRATEGIES.....................................55
FORM G7 - GENERATION COMPANY MERGERS.................................................................56
FORM G8 - GENERATION COMPANY ACQUISITION.............................................................56
FORM G9 - GENERATION COMPANY HOSTILE TAKE OVER.......................................................57
FORM G10 - GENERATION COMPANY FINANCIAL REORGANIZATION...............................................58
FORM G11 - GENERATION COMPANY MODIFY DIVIDEND RATE...................................................59
FORM G12 - GENERATION COMPANY MODIFY DEBT/EQUITY RATIO...............................................59
FORM G13 - GENERATION COMPANY CASH TRANSFER..........................................................60
FORM G14 - GENERATION COMPANY DIRECT ACCESS SELLING QUANTITY STRATEGIES..............................61
FORM G15 - THE GENERATION COMPANY DIRECT ACCESS BILLING STRATEGY.....................................62
FORM G16 - GENERATION COMPANY BUY/SELL CAPACITY......................................................64
FORM G17 - GENERATION COMPANY CANCEL CONSTRUCTION....................................................65
FORM G18 - GENERATION COMPANY TAKE OVER STRATEGY.....................................................66
FORM G19 - GENERATION COMPANY PLAYER STATUS ADJUSTMENT...............................................67
FORM G20 - TRANSMISSION CONSTRAINTS..................................................................68
GENERATING COMPANY REPORTS..............................................................................69
TABLE G1: GENERATION COMPANY CAPACITY REQUIREMENT STATEMENT (MW)....................................70
TABLE G2: GENERATION COMPANY STATEMENT OF INCOME AND FINANCE........................................71
TABLE G3: GENERATION COMPANY DIRECT ACCESS OR CFD SALES AND REVENUES................................72
TABLE G4: GENERATION COMPANY CONTRACT INFORMATION...................................................74
TABLE G5: GENERATION COMPANY CAPACITY COSTS.........................................................76
TABLE G6: GENERATING COMPANY CAPACITY UNDER CONSTRUCTION............................................78
TABLE G7: GENERATING COMPANY GENERATION COSTS.......................................................79
TABLE G8: GENERATING COMPANY GENERATION BALANCE.....................................................81
TABLE G9: SPOT MARKET SALES AND REVENUE.............................................................83
TABLE G10: GENERATING COMPANY PERFORMANCE MEASURES..................................................85
TABLE G11: REGION CAPACITY REQUIREMENT STATEMENT (MW)...............................................87
TABLE G12: REGIONAL GENERATION BALANCE..............................................................88
TABLE G13: REGIONAL CAPACITY MARGINS................................................................90
TABLE G14: UNIT COST SUMMARY........................................................................92
TABLE G15: TRANSMISSION CONSTRAINTS.................................................................95
</Table>
WELCOME TO CIGMOD
THE COMPETITIVE INDUSTRY GAMING MODEL
During the next few hours you will assume one or more of the new roles in the
electric industry marketplace - that of unregulated generator, a regulated or
unregulated retail company or an independent power producer. The challenge will
be to survive and even thrive in the new competitive market by understanding how
to make contracts, build plants, and merge with other companies.
The transition to a deregulated electric utility market is a messy one - with
many transitional steps occurring simultaneously. Your task will be to manage
these steps to put your company in a profitable position. We identify six phases
of the deregulation process and believe that CIGMOD can help you learn to "play
through" the phases successfully.
THE PHASES
The six phases identified are: Transitional Market, Massive Restructuring,
System Divestiture, Market Gaming, Re-regulation, and Industry Consolidation.
TRANSITIONAL MARKET
The transition phase of utility deregulation corresponds to an attempt at
"giving" up control while controlling the consequences. Ultimately the rules
increase to the point where compliance becomes an overwhelming task. At this
point, a collective solution that removes direct responsibility must come into
being. For the utilities, this is the Independent System Operator (ISO).
Learning to use an ISO is part of the CIGMOD experience.
MASSIVE RESTRUCTURING
Once any portion of the market place experiences the choices that competitive
economics offer, all other portions of the market place demand the same
treatment. Retail wheeling has little choice but to develop where economic
imbalances are perceived as unjustified and then quickly spread wherever
deregulation can gain a foothold. CIGMOD will give you experience working with
different retail wheeling scenarios.
SYSTEM DIVESTITURE
Once deregulation achieves retail wheeling, conflicts among generation,
marketing, transmission and distribution widen. Generation struggles in the
market place every moment of every day. It has high risks and high potential
gains. It has cash flow requirements to cover capacity financial burdens. It
needs to over-book capacity to make sure that capacity will be utilized as fully
as possible, knowing that it may be forced to go on the spot market itself to
meet contract obligations. It needs to inform the transmission system of its
intent without showing its hand to its competitors. It needs to build cash
reserves to cope with "price wars" and "gaming mishaps." Because transmission is
still
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regulated, it has "an obligation to serve" with minimal chance to earn
significant returns. If transmission expansion is required, the assets and
financial strength of the generation would be needed to secure investment funds
and support the project. The final results would be more competitive pressures
on the generator. This conflict of interest requires the two to severe all
financial and legal ties.
In addition, the distribution portion of the utility experiences regulatory
pressures to minimize cost. If marketing is part of distribution, it must find
low cost suppliers to maximize its retail and wholesale market share. The
associated generator would then need to negotiate contracts under competitive
bids with other generators. The inside information that an associated
distribution/marketing unit would have makes the negotiations problematic for
the associated generator. Further, the distribution company may find the
generation supply the transmission topology allows is more expensive than that
from a CCGT plant it could build nearby on its own.
Finally, the generator would have advantage marketing its own power without the
dependence on a "utility" marketing function serving its own interests,
especially when the generator must also sell power in other markets outside its
service area where it may be more competitive than "at home." Separating retail
marketing from the now passive distribution function and providing "generation"
its own independent marketing arm maximizes everyone's advantage. The pressures
to divest overpower any arguments to resist. CIGMOD simulates this divestiture.
MARKET GAMING
Once the companies have divested, each company can utilize its individual
capabilities to its best advantage. Because each entity has remnant features
suitable only in the regulated environment, an incongruity of new purpose and
old function occurs. Because each incongruity could pose a disadvantage, the
"battle" is necessarily fought more on wit than power. And as with any battle,
strategy and tactic guide progress and success. Whenever the choices of
alternative courses of action depend on the actions of others, the "theory of
games" applies. Hence there can be little doubt the transition will be a time of
gaming. CIGMOD helps you devise winning strategies under a variety of potential
assumptions about the future.
RE-REGULATION
Rules change only when economic or social pressure demand - whenever someone
feels "unfairness" is the source of his or her critical problem. Gaming produces
winners and losers. A slight tilt towards losing soon becomes a capsize as cash
and resources drain away. Some players abuse their market power, and the victims
demand safeguards. Some physical constraints or novel strategies may eventually
overwhelm specific market mechanisms and regulatory intervention then becomes
critical to avoid complete market failure. As the sides change and the strength
of competitors ebb and wane, new problems arise along with new rationalizations
to intervene. Eventually the system stabilizes when the effort to change the
rules exceeds the loss from coping with existing rules. CIGMOD can be
parameterized with different sets of rules.
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INDUSTRY CONSOLIDATION
Once the market recognizes the increase in certainty, participants would attempt
to lock-in advantageous situations. Many generators would find themselves
selling regularly to selected distribution companies, marketers, or customers.
The economies from reducing uncertainty further or locking in sales force
reintegration. The combined companies then have economies of scope. Because the
impetus for re-regulation implies that many participants have reached the "end"
of their gaming days, sweep-up acquisitions surge. A handful of national
vertically integrated utilities form but many small market niche utilities
continue in remote areas or in unique economic conditions. Transmission assets,
having been the pawns of the transition, lose market value and a single national
transmission company, probably with quasi-public ownership takes shape. The
storm of deregulation has finally subsided. CIGMOD can simulate the possible
surge in acquisitions and vertical integration.
THE CIGMOD PLAYERS
The CIGMOD players include retail companies and generation companies,
independent power producers, and the regulatory commission all interacting in a
single market. CIGMOD can be played with or without retail wheeling. If no
retail wheeling is allowed, then the retail companies remain regulated. If
retail wheeling is permitted then the industry is fully deregulated. Generally
the first few games use regulated retail companies; as players gather more
expertise, the additional complexities of retail wheeling are added.
THE MARKET
This version of CIGMOD simulates MAIN, MAPP and part of ECAR. The residential
customers live in everything from high rise apartments to mobile homes, there is
a wide variety of commercial establishments of all sizes and a large industrial
sector that includes mining, heavy industry and high technology is spread
throughout the service territories. The system as a whole is significantly
summer peaking, a result of high saturations in electric air conditioning (and
hot, humid summers). Winter heating requirements are met generally with natural
gas; the electric utilities face stiff competition from aggressive natural gas
companies in the area that actively compete for heating load.
THE RETAIL COMPANIES
In the absence of retail wheeling, the retail companies buy electricity from
generation companies and sell electricity to the residential, commercial, and
industrial customers within their service territory. The retail companies
negotiate contracts with generation companies to buy electricity and obtain any
remaining electricity on the spot market. The regulatory commission sets the
prices (with generation/transmission cost-pass-through provisions) charged by
the retail companies. Company performance is measured by reviewing negotiated
prices and comparing them with historical prices. The decisions the players make
include:
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1. Entering contracts to buy power;
2. Buying power from the spot market;
3. Setting retail prices;
4. Marketing and advertising to increase market share;
5. Initiating mergers, acquisitions or hostile takeovers;
6. Filing for financial reorganization;
7. Changing the dividend payout ratio;
8. Changing the debt/equity ratio;
9. Creating a generation company.
10. Participating in the power auction; and
11. Canceling contracts to buy power
When retail wheeling is added, retail prices have reduced regulatory
restrictions. CIGMOD provides additional information on sales to each service
area. The magnitude, timing and acceptance of retail wheeling is set at the
beginning of a CIGMOD game. Choosing to wheel is based on perceived price and
non-price factors, including advertising. Parameters can be adjusted to make
customers more or less susceptible to wheeling.
THE GENERATION COMPANIES
CIGMOD recognizes three types of generation companies: the generation companies
that result from splitting the current utility companies, independent power
producers (IPPs), and the "boundary" electric utility companies which may
service distribution companies in the region. The first two types are fully
modeled and are selected by players; the latter provides emergency power to the
region if available capacity in the region becomes scarce. Electricity is always
available - at a price. The default price for emergency power is set high,
penalizing those who do not procure sufficient power.
The independent power producer starts the game with no assets, liabilities or
capacity (unless IPPs exist at the beginning of the initial gaming period). The
IPP does have the ability to raise money for the construction of generating
capacity by issuing common stock and selling bonds. IPPs can build several types
of plants including gas combined cycle units.
The generation companies earn money by generating and selling electricity. They
enter into contracts with retail companies and construct new plants to fulfill
these contracts.
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They are required to meet their financial requirements by either selling bonds
or common stock. The decisions which the players make include:
1. Entering contracts to sell power;
2. Beginning construction of new plants;
3. Selling power to the spot market;
4. Retiring generating capacity;
5. Buying power from the spot market;
6. Initiating mergers, acquisitions or hostile takeovers;
7. Filing for financial reorganization;
8. Changing the dividend payout ratio;
9. Changing the debt/equity ratio;
10. Participating in the power auction;
11. Buying generating capacity from another generation company;
12. Selling generating capacity to another generation company;
13. Canceling a plant under construction;
14. Canceling contracts to sell power; and
15. Creating a retail energy company.
The plants generally constructed, natural gas plants, have a one year
construction time. If you initiate a natural gas plant in 1996, it is built in
1996 and can be used in 1997.
THE REGULATORY COMMISSION
In the absence of retail wheeling, the regulatory commission has the
responsibility of setting the pricing rules that the retail energy companies
will follow to charge the residential, commercial, and industrial customers. It
also determines the pricing and access rules for the distribution and
transmission companies and the operation rules of energy brokers and operating
companies. Regulated prices are based on the expenses, the rate base, and the
cost of capital of the regulated companies. A one year regulatory "lag" rewards
retail companies that lower costs in the regulated environment. Because prices
will not be adjusted until the second year, cost savings during the first year
of cost decreases accrue to the company and its stockholders.
HOW TO PLAY CIGMOD
To begin a game of CIGMOD players are divided into teams (generally 1-3 players
per team) and each team selects a name and its role as retail company,
generating company, independent power producer, or independent retail company.
After this information is entered into the computer, the initial years are
simulated and reports are produced for each team. After reviewing its reports,
each team implements contracts and other policy options by filling out action
forms and submitting the forms to the operator. The operator enters the data
from the forms into the computer, executes another year of the simulation,
5
and prints new reports for each team. This process is repeated until the end of
the simulation period (generally the year 2015).
TIPS FOR NEW PLAYERS
CIGMOD simulates a complex set of interactions. The reports are designed to
provide feedback on the results of your decisions. Therefore, you are encouraged
to make decisions by signing contracts, building plants, etc., and then review
the results of your actions. You will make mistakes, but from your mistakes you
will learn about CIGMOD and gaming strategies in the new competitive electric
industry.
TIPS FOR THE RETAIL COMPANY
Note that the demand forecasts include a 10% reserve margin. The retail
companies need to guard against unexpected demand growth and inaccurate
forecasts. You may wish to re-calculate your needs with a different reserve
margin when you contract for power. Remember, any power you fail to contract for
that you later need, will be satisfied with power from the spot market.
CALCULATING WHAT YOU NEED TO BUY
Table R1 contains an estimate of the amount of power in MW you need to purchase
to satisfy you peak demand using a 10% reserve margin. You will generally want
contracts with low capacity costs for your peaking demands and contracts with
low energy costs for your baseload demands and R4 (Retail Company Contract
Information).
After you determine how much and what kind of power you need, you need to know
what you have under contract and how long these contracts last. To see a summary
of your current contracts, look at retail report R1 (Retail Energy Company
Forecast) under Capacity Under Contract.
NEGOTIATING YOUR CONTRACTS
In CIGMOD contracts are reservations for capacity and are given in MW. The
energy taken in GWh will depend on the actual needs of the retail company.
Therefore, the cost to the retail company for capacity payments is fixed by the
contract; the energy costs are variable and will depend on the amount of energy
taken.
Now you have to determine what you would be willing to pay for the new capacity.
The best way to do this is to get some idea of what you paid for it in the past
- - a benchmark for future negotiations with generators. Again, look at Table R4
(Retail Company Contract Information). Two sets of component costs are given -
one is in mills (0.10 cents) per kWh and the other in $/kW. The average cost
calculated in Table R4 is a per kWh measure and includes a portion of any
capacity charges negotiated in the contract (and apportioned to all kWh) as well
as the variable cost. Therefore, while the fixed and
6
variable cost components of the generation remain the same through the life of
the contract, the average cost may change as more or fewer kWh are purchased.
As you look over your previous contracts you will begin to get some idea of what
you will be willing to pay for power in the future. You probably should try to
use these numbers as ceiling prices - competition theoretically should make your
prices fall. How far under these prices you can go is up to you and your
negotiating skills.
Once you understand your needs and current contract costs you should talk to
several generating companies to obtain price quotes for the power you need. The
generating companies are generally anxious to sell power. The price quotes will
contain capacity charges and energy charges; you will need to balance the
capacity and energy charges to compare the generating company offers. The
capacity charge reserves actual MW of generating capacity for your customers;
the energy charge is a per kWh charge that covers variable costs (including fuel
costs). The specific variable and capacity costs for each contract are listed in
Table R4 (Retail Company Contract Information).
One way to compare the offers is to convert both prices to an average cost. To
convert capacity and energy charges into a cost per kWh, you will need to
estimate the expected capacity factor of the contract. The capacity factor of a
contract is the amount of energy purchased divided by the maximum amount of
energy which could be purchased. The capacity factors of your existing contracts
are given on Table R4. You can estimate the expected capacity from each contract
(see below) or use a "rule of thumb" of a capacity factor of 65%.
Another way to compare and negotiate prices is to force one of the numbers on
the generating companies and make them compete on the other. For example, tell
the generating companies you are willing to pay $100/kW, but would like to see
alternative offers on the energy charges.
Given capacity costs are fixed and energy costs are variable, your decision on
the best method to trade-off the two charges will become part of your strategy
and part of what you will learn from CIGMOD. You are encourage to make several
small to medium sized contracts, then review your reports and see the impact of
each contract.
ESTIMATING THE CAPACITY FACTOR OF A CONTRACT
The amount of energy purchased from a contract depends on when it is
"dispatched" by the retail company which in turn depends on the energy
(variable) cost of the contract. The contracts with the lowest energy cost are
dispatched first. If you negotiate a contract with an energy cost lower than any
of your existing contracts, then its capacity factor will be high (possibly 100%
indicating that you purchased power every hour of the year from this contract).
If you negotiate a contract with energy costs higher than your existing
contracts, then its capacity will be low (possibly zero indicating that you
purchased no
7
energy from this contract). If the energy cost is somewhere in the middle, then
you would expect the capacity factor to be in the middle as well.
ESTIMATING THE PER UNIT COST OF CONTRACT POWER
Suppose you are offered a contract with a $300/kW capacity charge and 25
mills/kWh energy charge which you expect to have a 65% capacity factor. What
would be the estimated average cost of power for this contract if you need 100
MW of capacity?
Set up the known quantities:
$300/kW CAPACITY CHARGE
25 mills/kWh ENERGY CHARGE
100 MW or 100,000 kW of CAPACITY NEEDED
65% expected CAPACITY FACTOR
8760 HOURS PER YEAR
Determine the potential kWh of production from 100 MW (100,000 kW)
contract if the capacity factor is 65%:
100,000*8760*.65=569,400,000 kWh
569,400,000 kWh could be expected to be purchased from a 100 MW
contract if the capacity factor is 65%.
The capacity cost (cost of reserving this capacity) is $300 (per kW)
times 100,000 kW or $30 million:
$300*100,000 = $30,000,000.
The energy cost is 25 mills ($0.025) per kWh times 569,400,000 kWh
purchased or $14.235 million:
$0.025*569,400,000=$14,235,000
The total cost of the contract is the capacity cost ($30,000,000) plus
the energy cost ($14,235,000) or $44,235,000:
$30,000,000+$14,235,000 = $44,235,000
The average cost per kWh is the total cost ($44,235,000) divided by the
number of kWh purchased (569,400,000) or 78 mills ($0.078):
$30,000,000/569,400,000 = $0.078 or 78 mills or 7.8 cents per
kWh
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The capacity cost per kWh is the capacity cost $30,000,000 divided by
the number of kWh purchased (569,400,000) or 53 mills/kWh ($0.053/kWh):
$30,000,000/569,400,000=$0.053/kWh or 5.3 cents or 53
mills/kWh.
The average cost of power is equal to the energy cost of 25 mills/kWh
plus the capacity cost of 53 mills/kWh or 78 mills/kWh:
53 mills (capacity cost)+25 mills (energy costs)=78 mills/kWh or 7.8
cents/kWh.
PRICING RETAIL POWER
If no retail wheeling is taking place, then prices are determined in the
regulatory arena and the retail company has no flexibility in its pricing.
However, if retail wheeling is operating, the retail company must price its
power competitively. The unit of power calculations performed above should give
the retail company the minimum prices it can charge to generate sufficient
revenue to cover all its costs. However, this is only a beginning; the minimum
revenue figure may be accomplished in many different ways. Fixed costs may be
added to or subtracted from different loads to compete in different sub-markets.
Prices can be raised above cost when the retailer believes it is advantageous to
do so. A trial and error approach will help the retail company determine the
shape of the demand curve(s) it is facing.
CHECKING YOUR PROGRESS
There is a set of indicators that allows you to track your performance and
measure it against the performance of others. Variables listed include sales,
average price, profits and return on equity.
o In games with no retail wheeling:
To find out how you're doing, check the average class prices (Table of Retail
Performance Measures) to see if your prices are lower than prices during the
historical period. Since you are technically still "regulated", you are allowed
to recover your costs from your service territory. So your prices are your best
indicator of how well you are doing. If your prices are much higher than
expected, check to see if you contracted for enough power. If you didn't, you
had to buy on the spot market at a high price. Remember that you will experience
natural demand growth in the future. Also, if your prices are falling, you will
capture additional market share so demand will increase over and above the
economically driven demand increase.
o In games with retail wheeling:
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A good place to start is to look at your return on equity. If it has started to
fall, your prices may be too high and you may losing your market share. Check
your sales. If they are falling, try to bargain harder with generators the next
time and try to more closely match you base and peaking loads. There is a
mechanism to release parties from their contracts by mutual agreement, try to
use this if your contracts are really overpriced (both parties must agree to the
release). Reduce your prices where ever possible, starting where you are losing
the most load.
TIPS FOR THE GENERATION COMPANY
As an unregulated generator, you can no longer rely on rate case rates and
stable retail markets. You can use your past history as a guide to future
pricing, but it perhaps is better to think of past prices as ceiling prices. In
order to sell your power, you need to know what you have, how much you have and
what it costs to use it.
HOW MUCH CAPACITY DO YOU HAVE?
Look at Table G1: Generation Components and Capacity Requirements. Your capacity
is divided into capacity currently committed by contract and that which is
available for sale. The capacity currently committed by contract can exceed the
actual capacity. If the actual demand (up to the contract level) exceeds your
supply, you will buy emergency power to fill the excess demand. Also shown on
this table is capacity under construction. Natural gas plants take two years to
build. After looking at the total capacity available and the capacity under
contract, you should make a decision about how much capacity you will offer for
sale.
WHAT DO YOU WANT TO SELL IT FOR?
Look at the Table G5 of Generation Company Capacity Costs to understand your
companies cost structure. The plants are divided into fuel types with each plant
having its own set of costs. The embedded annual fixed cost represents the cost
per kW you need to recover on your existing plant to stay financially healthy.
The variable cost of plants (mills/kWh) is the marginal cost of energy from a
particular plant type. It includes both variable O&M costs and fuel costs. The
plant capacity factor is used to help allocate your fixed costs on a per kWh
basis. It is simply the percentage of potential GWh that are actually generated.
There are 8760 hours in a year. If a plant is available 90% of the time then
(8760-*.90) 7884 hours are available for the plant to generate. If the capacity
factor is 65%, then the plant is generating for (8760*0.65) 5125 hours per year.
If the plant is 100 MW, then it produced 512,500 MWh or 512.5 GWh of power
during the year.
When you prorate your fixed costs over the kWh generated from the plant, and add
the variable costs (including fuel costs), you have determined your average
embedded cost of power from that unit. In order to recover all your fixed costs,
you need to sell at least the estimated kWh of generation from that plant at a
price equal to the average embedded
10
cost of power. If price is set equal to the average minimum cost of power but
you sell fewer kWh, then you will be short revenue. If you sell the estimated
kWh but charge a price that does not cover your average embedded costs, you will
also come up revenue short. To provide a "cushion" against this happening, you
can set your prices slightly higher or calculate your average embedded cost of
power with a more conservative kWh value.
If you want to, you can offer the capacity cost and variable cost indicated by
your embedded costs. However, you can certainly offer more or less or you can
alter the ratio of fixed to variable costs. Suppose, for example, your capacity
cost for a particular plant is $75 and the variable cost is 25 mills/kWh. If a
retail company is shopping around for 100 MW of baseload capacity, setting your
capacity costs at $100/kW rather than $75/kW and your variable costs at 19
mills/kWh rather than 25 mills/kWh, might enable you to recover your costs and
present a more appealing package to a the baseload power buyer who tends to look
at variable cost. (The reverse is true for those shopping for peaking capacity.)
To determine whether your new mix of fixed and variable costs will meet your
profit objectives, perform the following calculations:
SAMPLE CALCULATION FOR DETERMINING PROFIT OBJECTIVES
CAPACITY COST: $150/kW
VARIABLE COST: 19 mills/kWh
EXPECTED LOAD FACTOR: 80%
MW DESIRED: 100 MW or 100,000 kW
NUMBER OF HOURS IN A YEAR: 8760
Calculate the total capacity revenue:
$150*100,000=$15,000,000 in total capacity costs
Calculate the potential kWh sales from 100,000 kW capacity (kW*number
of hours in the year* expected load factor:
100*1000*8760*.8=700,800,000 kWh sales
Calculate revenue from variable costs. Divide total capacity costs by
total kWh sales to yield fixed cost per kWh:
$15,000,000/700,800,000=$0.021/kWh or 2.1 cents/kWh or 21
mills/kWh.
These 21 mills of fixed cost are then added to the 19 mills of variable
for a total average cost of 40 mills/kWh. Total revenue is calculated
by multiplying average cost per kWh by total kWh:
11
0.040*700,800,000=$28,032,000
If the original values had been used,
CAPACITY COST: $75/kW
VARIABLE COST: 25 mills/kWh
LOAD FACTOR: 80%
MW DESIRED: 100 MW or 100,000 kW
NUMBER OF HOURS IN A YEAR: 8760
Calculate the total capacity costs:
$75*100,000=$7,500,000 in total capacity costs
Calculate the potential kWh sales from 100 MW capacity (kW*number of
hours in the year*load factor:
100*1000*8760*.8=700,800,000 kWh sales
Divide total capacity costs by total kWh sales to yield fixed cost per
kWh:
$7,500,000/700,800,000=$0.011/kWh or 1.1 cents/kWh or 11
mills/kWh.
These 11 mills of fixed cost are then added to the 25 mills of variable
for a total average cost of 36 mills/kWh. Total revenue is calculated
by multiplying average cost per kWh by total kWh:
0.036*700,800,000=$25,228,800
In this case, your new numbers would yield about $3M more in profits and, since
more of the costs are "fixed", less risk as well.
DO YOU WANT TO BUILD MORE GENERATION?
New generation can be constructed for demand or financial reasons. Building in
response to demand increases has been the traditional response of generators.
But you no longer must build to meet new demand - that demand can seek
generation elsewhere. A new option is to build to increase market share and
revenue. New construction may have lower variable costs than existing plant and
may be worth investing in even if the generation company or the region is not
"capacity short."
12
CHECKING YOUR PROGRESS
The Table of Generation Performance Indicators lists a set of indicators that
allows you to track your performance and measure it against the performance of
others. Variables listed include sales, average price, profits (net revenue) and
return on equity.
13
RETAIL COMPANY ACTIONS - UNDERSTANDING AND USING FORMS
All player actions are implemented by submitting a completed form to the
operator. These forms are entered into the computer by the operator who then
runs the model and prints reports. In each form you should provide all the
information, but only the information requested; complex contracts must be
submitted on multiple forms. When submitting a form which affects two players,
both players must agree to the terms therein, but only one form is submitted.
There are two basic kinds of forms - forms for individual actions that exist for
a specific length of time such as a contract between two parties and forms that
initiate strategies that remain in effect until a new strategy form is
submitted. An example of a strategy form would be retail pricing strategies or
generation spot market bidding strategies.
FORM 1 - DIRECT ACCESS OR CFD CAPACITY CONTRACT
Form 1 is the Direct Access or CfD Capacity Contract form and is used to submit
contracts for the sale or purchase of capacity. Although a Contract for
Differences (CfD) is essentially a money transfer, it is completed in the same
fashion as a Direct Access contract. Each bi-lateral agreement between a
generator and a retail energy company must be represented on a Form 1: "Direct
Access or CfD Capacity Contract". Help determining energy and capacity costs can
be found in the section "What do You Want to Sell it For" in the generator's
section of the CIGMOD explanations, tips and procedures handout. It is not
essential that each contract have both a capacity charge and an energy charge;
many contracts are made with energy charges alone. Since this form represents an
agreement between a retail company and a generator, it is used by both parties;
HOWEVER ONLY ONE FORM PER TRANSACTION IS SUBMITTED TO THE OPERATOR.
14
DIRECT ACCESS or CfD CAPACITY CONTRACT - Form 1
A Contract Between Retail Energy Company:
------------------
and Generation Company:
------------------
Contract Beginning Year:
----------
Contract Ending Year:
----------
Capacity (MW):
----------
Energy Cost (Mills/kWh):
----------
Capacity Cost ($/kW):
----------
Simulation Year:
---------- ------------
Operators Use Only
FORM 2 - TRENDED DIRECT ACCESS OR CFD CAPACITY CONTRACT
Form 2 is the Trended Electric Capacity Contract form and is used to submit
contracts for capacity sales and purchases when terms change over time. In all
other respects, the procedure is the same as the procedure for filling out Form
1.
TRENDED DIRECT ACCESS OR CfD CAPACITY CONTRACT - Form 2
A Contract Between Retail Energy Company:
------------------
and Generation Company:
------------------
<Table>
<Caption>
Beginning Ending
--------- ------
Contract Year:
---------- ----------
Capacity (MW):
---------- ----------
Energy Cost (Mills/kWh):
---------- ----------
Capacity Cost ($/kW):
---------- ----------
</Table>
Simulation Year:
---------- ------------------
Operators Use Only
15
FORM R3 - RETAIL COMPANY SPOT MARKET PURCHASE STRATEGY
The Retail Company Spot Market Purchase Strategy Form R3 allows the retail
company to set a policy for spot market purchases. Either an exogenously
specified number of MW or a percentage of each type of demand which is used to
determine the amount of spot power purchased. The loading order which determines
when the purchases will be made. If no values are specified, then zero is the
default specification. Either an exogenous mills/kWh can be used or a fraction
of previous spot market prices can be used to trigger the purchases.
RETAIL COMPANY SPOT MARKET PURCHASE STRATEGY - Form R 3
Retail Company:
----------------------------
I would like to buy the following capacity from the spot market:
<Table>
<Caption>
MW OR % of Demands
Baseload
--------- -----------
Intermediate
--------- -----------
Peaking
--------- -----------
AND
</Table>
Use the following prices to determine the loading order of my spot purchases:
(IF LEFT BLANK A PRICE OF ZERO (0) WILL BE USED FOR THE LOADING ORDER)
<Table>
<Caption>
% of Spot Market Price
Mills/kWh OR in Previous Period
--------- -- ----------------------
Baseload
--------- -----------
Intermediate
--------- -----------
Peaking
--------- -----------
</Table>
Simulation Year:
----------- -------------------
Operators Use Only
16
FORM R4 - RETAIL COMPANY RETAIL PRICE STRATEGIES
Form R4 is the Retail Company Energy Price Strategies form and is used by the
retail companies to set prices when retail wheeling is permitted. With retail
wheeling the model allocates customer purchases based on prices.
RETAIL COMPANY RETAIL PRICE STRATEGIES - Form R 4
Retail Company:
---------------------------
<Table>
<Caption>
Percentage of Percentage of OR Price
Fixed Cost + Variable Cost (Mills/kWh)
------------- ------------- -----------
Residential
---------- ---------- ----------
Commercial
---------- ---------- ----------
Industrial
---------- ---------- ----------
</Table>
Simulation Year:
---------- ------------------
Operators Use Only
17
FORM R5 - RETAIL COMPANY ADVERTISING BUDGET
Retail companies need to advertise to retain market share. Form R5 allows them
to set their advertising budgets either as a percent of revenues or completely
exogenously. Target areas (as many as desired) are then selected by putting a 1
or 0 for each area and the advertising budget is split among the selected areas.
Advertising loses effectiveness if everyone does it. It is the relative level of
advertising that is important for increasing sales.
RETAIL COMPANY ADVERTISING BUDGET - Form R 5
Retail Company:
-----------------------------------------
Advertising Budget: OR
----------------- -----------------
M$/year % of Revenues
Target Areas (Put a one (1) in the areas you wish to target):
<Table>
<Caption>
Residential Commercial Industrial
----------- ---------- ----------
Minnesota
----------- ---------- ----------
Iowa, Dakotas
----------- ---------- ----------
Illinois, Wisconsin
----------- ---------- ----------
Ohio, Indiana
----------- ---------- ----------
Canada
----------- ---------- ----------
</Table>
Simulation Year:
--------- -----------------
Operators Use Only
18
FORM R6 - RETAIL COMPANY MERGER
Form R6 is the Retail Company Merger form and is used when two generating
companies decide to merge. It requires the approval of both parties. During a
merger all assets and liabilities of two companies are combined to form one
company. The purchase price is not an issue in a merger. Both sets of players
now work together.
RETAIL COMPANY MERGERS - Form R 6
Retail Company: is merging
----------------------
Retail Company: into it.
---------------------------
Simulation Year:
----------- ------------------
Operators Use Only
FORM R7- RETAIL COMPANY ACQUISITIONS
Form R7 is the Retail Company Acquisitions form and is used when a retail
company acquires another retail company. It requires the approval of both
parties. During an acquisition the acquiring company receives all the assets and
liabilities of the acquired company except the common stock and retained
earnings. The change in net assets of the acquiring company is based on the
purchase price. The acquired company is left with cash, equal to the purchase
price of the company, the common stock, and retained earnings, computed from the
purchase price.
RETAIL COMPANY ACQUISITION - Form R 7
Retail Company: is acquiring
----------------------
Retail Company: .
---------------------------
Purchase Price (M$):
-----------------
Simulation Year:
---------- ------------------
Operators Use Only
19
FORM R8 - RETAIL COMPANY HOSTILE TAKE OVER
Form R8 is the Hostile Take Over form and is used when a retail company attempts
a hostile take over of another retail company. Companies must be paid for in
cash - no leveraged buy-outs. The purchasing utility would need to provide the
common stock equity plus 20 percent in cash (accumulated in short term
investments and tracked on the income statement) to complete a hostile takeover.
The company initiating the take-over is allowed to use the cash of the take-over
target to meet the cash requirement. The purchasing utility assumes the debt
responsibility of the take over target. Except for the cash requirement the
hostile takeover is the same as an acquisition.
RETAIL COMPANY HOSTILE TAKE OVER - Form R 8
Retail Company: is buying out
----------------------
Retail Company: .
---------------------------
Simulation Year:
---------- ------------------
Operators Use Only
20
FORM R9 - RETAIL COMPANY FINANCIAL REORGANIZATION
Form R9 is the Retail Financial Reorganization form and is used to modify the
exogenously specified financial parameters outside the normal boundary of the
game. This form provides additional financial flexibility for company
management.
RETAIL COMPANY FINANCIAL REORGANIZATION - Form R 9
Retail Energy Company:
------------------------------------------
Net Assets (M$):
-------------------------
Long Term Debt (M$):
-------------------------
Debt Interest (M$/yr):
-------------------------
Common Stock (M$):
-------------------------
Retained Earnings (M$):
-------------------------
Preferred Stock (M$):
-------------------------
Cash (M$):
-------------------------
Simulation Year:
---------- ------------------
Operators Use Only
FORM R10 - RETAIL COMPANY MODIFY DIVIDEND RATE
Form R10 is the Retail Company Modify Dividend Rate form and is used to adjust
the amount of dividends paid each year. The dividend payout rate may be adjusted
as desired. Sometimes it is desirable to alter the dividend payout rate to allow
the company to accumulate cash for takeover opportunities.
This form is used to input the results of a financial reorganization of the
company. The values entered on the form are the company values after the
reorganization. All lines must be filled in. Do not put the change in the
values, put the actual value.
21
RETAIL COMPANY MODIFY DIVIDEND RATE - Form R 10
Retail Energy Company:
------------------------------------------
Common Stock Dividend Payout Ratio (%):
-------------
Simulation Year:
---------- ------------------
Operators Use Only
FORM R11- RETAIL COMPANY MODIFY DEBT/EQUITY RATIO
Form R11 is the Retail Company Modify Debt/Equity Ratio form. Prudent
adjustments can be made to this ratio to give the retail player added financial
flexibility.
RETAIL COMPANY MODIFY DEBT/EQUITY RATIO - Form R 11
Retail Energy Company:
------------------------------------------
Marginal Debt/Equity Ratio (%):
----------
Simulation Year:
---------- ------------------
Operators Use Only
FORM R12 - RETAIL COMPANY CASH TRANSFER
Retail form R12 allows the retail company to transfer cash from a retail company
to a generating company. It requires the approval of both parties.
22
RETAIL COMPANY CASH TRANSFER - Form R 12
FROM
Retail Company:
--------------------------------
TO
Generation Company:
---------------------------
Transfer M$
--------
Simulation Year:
---------- ------------------
Operators Use Only
(use negative values to transfer cash from the generation company to the
retail company.)
23
FORM R 13 - RETAIL COMPANY DIRECT ACCESS BILLING STRATEGY
The Retail Company Direct Access Billing Strategy Form allows the player to
enter into the computer auction to buy power from the computer generators. The
retail company specifies a minimum offer price one of four ways. Either it is
specified by type as a percent of the minimum priced contract in the previous
period OR as a fraction of the first contract signed in the previous period OR
as a percent of spot market price OR completely exogenously. Only one method
should be selected and this strategy will remain in effect until the retail
player changes it by submitting another form.
24
RETAIL COMPANY DIRECT ACCESS BIDDING STRATEGIES - Form R 13
Retail Company:
----------------------------------------------------
1. Minimum. Initial Bid Prices are a percent of the minimum priced
contract in the previous period
<Table>
<Caption>
Initial Price as a Percent Stop Price as a Percent Capacity as %
Power Type of Minimum Price of Spot Market Price Of Needs
---------- -------------------------- ----------------------- -------------
Baseload
------------- ------------ -----------
Intermediate
------------- ------------ -----------
Peaking
------------- ------------ -----------
</Table>
2. First. Initial Bid Prices are a percent of the first contract signed
in the previous period.
<Table>
<Caption>
Initial Price as a Percent Stop Price as a Percent Capacity as %
Power Type of First Contract Price of Spot Market Price Of Needs
---------- -------------------------- ----------------------- -------------
Baseload
------------- ------------ -----------
Intermediate
------------- ------------ -----------
Peaking
------------- ------------ -----------
</Table>
3. Spot Market. Initial Bid Prices are a percent of the spot market
prices.
<Table>
<Caption>
Initial Price as a Percent Stop Price as a Percent Capacity as %
Power Type of Spot Market Price of Spot Market Price Of Needs
---------- -------------------------- ----------------------- -------------
Baseload
------------- ------------ -----------
Intermediate
------------- ------------ -----------
Peaking
------------- ------------ -----------
</Table>
4. User. Initial Bid Prices are user specified.
<Table>
<Caption>
Capacity Bid Energy Bid Stop Price Capacity as %
Power Type ($/kW) (Mills/kWh) (Mills/kWh) Of Needs
---------- -------------- ----------- ----------- -------------
Baseload
------------- ------------ ----------- -------------
Intermediate
------------- ------------ ----------- -------------
Peaking
------------- ------------ ----------- -------------
Simulation Year:
---------- -----------------
Operator Use Only
</Table>
25
FORM R14 - RETAIL COMPANY TAKE OVER STRATEGY
Form R14 is the Retail Company Take Over Strategy form. This allows the retail
company to set its strategy once, and the computer will make the financial
transactions as they become available. Take over policies can be based on an
aggressive "increase market share" philosophy or a purely defensive "eat or be
eaten" philosophy or cost based (neutral). The strategy chosen remains in effect
until a new form is submitted. This option is currently under construction and
is not operational.
RETAIL COMPANY TAKE OVER STRATEGY - Form R 14
Retail Company:
----------------------
Neutral
---------------
Aggressive
---------------
Defensive
---------------
Simulation Year:
--------------- ------------------
Operators Use Only
26
FORM R15 - RETAIL COMPANY CONTRACT CANCELLATION
Form R15 is the Retail Contract Cancellation form and is used to cancel
previously signed contracts. Both parties must agree to cancel a contract and no
initial contracts (the contracts in force at the beginning of the game) may be
canceled. The information about your existing contracts is given in the reports
R3 and R4. The "Money Paid from ..." lines have been included on this sheet to
permit contract buyouts by either party.
RETAIL COMPANY CONTRACT CANCELLATION - Form R 15
Retail Energy Company:
--------------
Generation Company:
----------------
Beginning Year of Contract to be Canceled:
------------
Ending Year of Contract to be Canceled:
--------------
Capacity to be Canceled (MW):
----------------
Fuel Type:
-----------------
Money Paid from Retail Energy Co. to Generation Co. ($M):
-------------
Money Paid from Generation Co. to Retail Energy Co. ($M):
-------------
Simulation Year:
--------------- -----------------
Operator Use Only
27
FORM R16 - RETAIL COMPANY PLAYER STATUS ADJUSTMENT
Retail Form R16 is a housekeeping form that allows human players to become
computer players and vice versa or exit the game all together. This form is used
when a generation company wants to also operate a retail operating company. The
generation company selects a retail energy company currently being run by the
computer or out of the game and changes the status to human and gives the
company a new name.
RETAIL COMPANY PLAYER STATUS ADJUSTMENT - Form R 16
Retail Company: is changing
----------------------
its status to: HUMAN
----------
COMPUTER
----------
N/A
----------
and its name to .
------------------------------------
28
RETAIL COMPANY REPORTS
TABLE R1: RETAIL ENERGY COMPANY FORECAST
PURPOSE: Table R1 shows your forecasted sales and peak demand by type (baseload,
intermediate and peaking). Also on the table is the total capacity that you
already have under contract by year, an estimate of your current reserve margin
and your desired reserve margin for comparison.
USE: the retail company uses the information in Table R1 to determine how much
and what type of capacity to purchase. The level of reserves is up to you;
remember that emergency power is expensive and will be used if you do not
purchase sufficient capacity.
DEFINITIONS:
o ELECTRICITY SALES: forecasted sales, measured in GWh per year. These
forecasts can be inaccurate and will change from year to year.
o PEAK DEMAND: in MW. Again, remember that this is a forecast - and forecasts
can be wrong.
o ESTIMATED RESERVES: a 10% reserve margin is the default specification for
unexpected changes in demand, however this is a variable that you may
change.
o PEAK W/ RESERVES: Peak demand in MW including a 10% (or your selected
value) reserve margin.
o PEAKING: MW of capacity required to serve low load factor peak demand.
Peaking needs usually occur only a few times in a year.
o INTERMEDIATE: MW of capacity required to serve shoulder load between
baseload and peak demand.
o BASELOAD: MW of capacity required to serve high load factor peak demand.
This power is needed most of the time.
o TOTAL CAPACITY UNDER CONTRACT: MW of capacity already contracted for to
meet demand
o HISTORICAL PURCHASED CONTRACTS: These historical contracts are needed to
simulate the historical period. They are set to zero in the future.
o SURPLUS OR DEFICIT: If contracted capacity (capacity under contract plus
historical contracts) is less than peak demand (the sum of base,
intermediate and peaking requirements plus your selected reserve margin),
the difference in MW is shown here as a deficit; if more, as a surplus. In
other words, a negative sign indicates that you might consider additional
capacity; a positive sign indicates that you may have over contracted for
power. Deficits will result in spot market purchase.
o RESERVE MARGIN: Actual ratio of surplus MW to peak demand MW.
29
Table R1: Retail Energy Company Forecast for 1999
American Electric Power, DARW
<Table>
<Caption>
1999 2000 2001 2002 2003
------- ------- ------- ------- -------
Electricity Sales (GWh/YR) .................. 146,507 150,247 152,695 155,183 157,711
Peak Demand (MW) ............................ 29,175 31,269 32,271 33,306 34,373
Estimated Reserves (MW) ..................... 2,918 3,127 3,227 3,331 3,437
Peak w/ Reserves (MW) ....................... 32,093 34,396 35,498 36,636 37,811
Peaking (MW) ................................ 3,738 4,529 4,870 5,231 5,614
Intermediate (MW) ........................... 10,444 11,912 12,532 13,169 13,822
Baseload (MW) ............................... 17,911 17,955 18,096 18,236 18,375
Capacity under Contract (MW) ................ 10,586 10,586 10,586 10,586 10,586
Historical Purchase Contracts (MW) .......... 0 0 0 0 0
Surplus (Deficit) (MW) ...................... (21,507) (23,810) (24,913) (26,051) (27,225)
Reserve Margin (MW/MW) ...................... (0.64) (0.66) (0.67) (0.68) (0.69)
</Table>
TABLE R2: RETAIL ENERGY COMPANY STATEMENT OF INCOME AND FINANCE
PURPOSE: Table R2 shows the company income statement (all values in $M)
including common measures of performance such as the debt/equity ratio and
return on equity as well as an important new element in a competitive
environment - cash on hand.. It divides power purchases into general source
categories - bilateral contracts, contracts for differences, spot purchases,
historical purchases and emergency power.
USE: the income statement shows how well you are doing financially and where
your problems might be if you are not doing well. If you were required to make
emergency purchases, the cost will show up here. The effects of dividend changes
and other financial variable changes will also be easy to see on in this table.
IMPORTANT DEFINITIONS:
OPERATING EXPENSES FROM:
o DIRECT ACCESS CONTRACTS: Bilateral contract costs from contracts made with
other players.
o CONTRACTS FOR DIFFERENCES: A type of futures contract with other players
designed to hedge against spot market purchase price swings. Electricity is
purchased from the spot market with these contracts.
o SPOT MARKET PURCHASES: Power purchased from the spot market at the market
price.
o PURCHASES: Historical purchases negotiated before the game began. These
will gradually expire as the game progresses..
o EMERGENCY POWER: A forced, computer generated purchase. Emergency power is
purchased because contractual power was inadequate to cover your load.
o OPERATING INCOME: Calculated as Operating Revenues minus Operating
Expenses.
o NET INCOME: Operating Income plus Other Income minus Interest Payments.
30
In the Sources and Uses of Funds section of this report, the following variables
are of particular interest:
CONSTRUCTION EXPENDITURES: Money spent on new plant
o COMMON STOCK DIVIDENDS: Money paid out to stockholders; this variable can
be modified by the player.
o COMPANY PURCHASE PRICE: If you have engaged in a takeover or buyout during
the previous year, the cost of the purchase is recorded here.
o CASH (ON HAND): Yearly additions to retained earnings. Cash and retained
earnings need to be watched and adjusted (by increasing expenditures, if
necessary) to avoid becoming a take-over target.
o RETAINED EARNINGS: Retained earnings.
o RETURN ON EQUITY: Classic measure of company health; with the retail
company, big deviations in year to year income can cause this variable to
fluctuate widely because retail companies have little equity compared to
other companies.
31
Table R2: Retail Energy Company Statement of Income and Finance (in millions)
for 1999 American Electric Power, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998
---------- ---------- ---------- ---------- ----------
Operating Revenues ..................... 4,153 4,328 2,977 2,585 2,447
Operating Expenses:
Direct Access Contract .............. 3,425 2,023 2,076 2,052 2,194
Contract for Differences ............ 0 0 0 0 0
Spot Market Purchases ............... 0 0 0 0 0
Purchases ........................... 740 0 0 0 0
Emergency Power ..................... 0 0 0 0 0
General and Admin. O&M .............. 3 3 3 3 3
Advertising Budget .................. 0 21 22 15 13
Depreciation ........................ 5 5 5 6 6
Income Taxes ........................ 2 788 309 181 84
Other Taxes ......................... 5 5 5 6 6
Misc. Expenses ...................... (36) (30) (24) (18) (12)
TOTAL ............................ 4,144 2,794 2,374 2,229 2,281
Operating Income ....................... 9 1,534 603 355 166
Other Income ........................... (0) 0 52 73 86
Interest Payments ...................... 4 3 3 3 3
Net Income ............................. 5 1,531 651 425 248
Sources
Net Income .......................... 5 1,531 651 425 248
Depreciation ........................ 5 5 5 6 6
Funds From Debt ..................... 15 0 0 0 0
Funds From Common Stock ............. 5 0 0 0 0
Funds from Preferred Stock .......... 0 0 0 0 0
Funds from Cash ..................... 0 0 0 0 0
TOTAL ............................ 30 1,536 656 430 254
Uses
Construction Expenditures ........... 0 5 14 19 19
Common Stock Dividends .............. 3 1,010 429 280 163
Preferred Stock Dividends ........... 0 1 1 1 1
Debt Repayment ...................... 8 2 2 1 1
Company Purchase Price .............. 0 0 0 0 0
Pref. Stock Sinking Fund ............ 0 0 0 0 0
Cash ................................ 0 518 211 129 70
Miscellaneous Projects .............. 20 0 0 0 0
TOTAL ............................ 32 1,536 656 430 254
Assets
Current Assets ...................... 0 0 0 0 0
Net Assets .......................... 105 105 114 127 140
Cash ................................ 0 518 729 858 928
TOTAL ............................ 105 623 843 985 1,068
Liabilities
Current Liabilities ................. 8 8 8 8 8
Long Term Debt ...................... 47 45 44 42 41
Preferred Stock ..................... 8 8 8 8 7
TOTAL Liabilities ................. 63 61 60 58 56
Equity
Common Stock ........................ 31 31 31 31 31
Retained Earnings ................... 11 531 752 896
Common Stockholders Equity ........ 42 562 783 927 1,011
TOTAL Liabilities and Equity ........... 105 623 843 985 1,068
Debt Fraction of Capitalization ........ 0.53 0.07 0.05 0.04 0.04
Return on Equity ....................... 0.13 2.72 0.83 0.46 0.25
</Table>
32
TABLE R3: RETAIL ENERGY COMPANY PURCHASES AND COSTS
PURPOSE: Table R3 shows purchases from, unit costs and total costs by generating
company. Also shown are line losses, spot market purchases and emergency
purchases
USE: This table tracks the amount and cost of power purchased from each
generation company and the spot market. The average cost of power for your
company. This table should help you discover whether or not you are making
advantageous contracts and should help you decide whether or not to purchase
more spot market power.
IMPORTANT DEFINITIONS:
IN THE PURCHASES SECTION:
o TOTAL PURCHASES: The sum of all your purchases by company.
o LOSSES: Retail companies are responsible for the energy lost during
transmission and distribution. The energy that is lost is recorded here.
o NET SALES: Total Purchases minus Losses.
IN THE UNIT COST SECTION:
o SPOT MARKET BASELOAD POWER: Your average cost of spot market baseload
power.
o SPOT MARKET INTERMEDIATE POWER: Your average cost of spot market
intermediate power.
o SPOT MARKET PEAKING POWER: Your average cost of spot market peaking power
o EMERGENCY POWER: Your average cost of emergency power.
SYSTEM SPOT MARKET PRICES SECTION:
o SPOT MARKET BASELOAD POWER: System average cost of spot market baseload
power.
o SPOT MARKET INTERMEDIATE POWER: System average cost of spot market
intermediate power.
o SPOT MARKET PEAKING POWER: System average cost of spot market peaking
power.
o EMERGENCY POWER: System average cost of emergency power.
33
Table R3: Retail Energy Company Purchases & Costs for 1999
American Electric Power, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998
---------- ---------- ---------- ---------- ----------
PURCHASES (GWh)
Minnesota Power ............................ 0 6,333 6,333 16,074 11,455
Primergy ................................... 0 31,078 25,355 25,355 18,208
Otter Tail Power ........................... 0 0 0 0 0
Wisconsin Power and Light .................. 0 0 0 1,378 5
Interstate/IES Utilities ................... 0 4,185 1,378 0 0
North/South Dakota ......................... 0 474 526 445 586
Central Illinois Light Co. ................. 0 25 109 88 169
Union Electric ............................. 0 1,317 1,878 0 0
Commonwealth Edison ........................ 0 3,109 6,727 6,037 12,310
Illinois Power ............................. 0 14,426 15,491 13,979 14,728
American Electric Power .................... 139,119 77,196 82,550 81,513 88,992
Cinergy .................................... 0 0 0 0 0
Iowa Illinois Gas & Electric ............... 0 1,785 2,045 1,654 2,375
Canada ..................................... 0 352 411 0 0
Independent Power Producer ................. 0 0 0 0 0
Baseload Spot Market Power ................. 0 0 0 0 0
Intermediate Spot Market Power ............. 0 0 409 623 2,299
Peak Spot Market Power ..................... 0 0 0 0 0
Emergency Power ............................ 0 0 0 0 0
TOTAL PURCHASES ............................ 139,119 140,280 143,213 147,147 151,126
LOSSES ..................................... 7,544 7,607 7,766 7,979 8,195
NET SALES .................................. 131,574 132,673 135,446 139,167 142,931
UNIT COSTS (MILLS/kWh)
Minnesota Power ............................ 0.00 10.80 10.80 10.91 11.72
Primergy ................................... 0.00 12.43 12.02 12.02 11.59
Otter Tail Power ........................... 0.00 0.00 0.00 0.00 0.00
Wisconsin Power and Light .................. 0.00 0.00 0.00 8.38 3.73
Interstate/IES Utilities ................... 0.00 18.89 8.38 0.00 0.00
North/South Dakota ......................... 0.00 19.79 19.70 19.14 18.99
Central Illinois Light Co. ................. 0.00 34.58 30.76 31.04 30.36
Union Electric ............................. 0.00 21.62 22.63 0.00 0.00
Commonwealth Edison ........................ 0.00 37.20 28.31 28.67 26.79
Illinois Power ............................. 0.00 13.71 15.08 13.43 14.73
American Electric Power .................... 35.26 14.09 14.01 14.10 13.85
Cinergy .................................... 0.00 0.00 0.00 0.00 0.00
Iowa Illinois Gas & Electric ............... 0.00 23.17 22.71 23.45 22.28
Canada ..................................... 0.00 21.37 21.15 0.00 0.00
Independent Power Producer ................. 0.00 0.00 0.00 0.00 0.00
Spot Market Baseload Power ................. 0.00 0.00 0.00 0.00 0.00
Spot Market Intermediate Power ............. 0.00 0.00 0.00 0.00 0.00
Spot Market Peak Power ..................... 0.00 0.00 0.00 0.00 0.00
Emergency Power ............................ 0.00 0.00 0.00 0.00 0.00
AVERAGE .................................... 35.26 14.42 14.50 13.94 14.52
COSTS (M$/YEAR)
Minnesota Power ............................ 0 68 68 175 134
Primergy ................................... 0 386 305 305 211
Otter Tail Power ........................... 0 0 0 0 0
Wisconsin Power and Light .................. 0 0 0 12 0
Interstate/IES Utilities ................... 0 79 12 0 0
North/South Dakota ......................... 0 9 10 9 11
Central Illinois Light Co. ................. 0 1 3 3 5
Union Electric ............................. 0 28 42 0 0
Commonwealth Edison ........................ 0 116 190 173 330
Illinois Power ............................. 0 198 234 188 217
American Electric Power .................... 4,905 1,088 1,156 1,149 1,232
Cinergy .................................... 0 0 0 0 0
Iowa Illinois Gas & Electric ............... 0 41 46 39 53
Canada ..................................... 0 8 9 0 0
Independent Power Producer ................. 0 0 0 0 0
Baseload Spot Market Power ................. 0 0 0 0 0
Intermediate Spot Market Power ............. 0 0 0 0 0
Peak Spot Market Power ..................... 0 0 0 0 0
Emergency Spot Market Power ................ 0 0 0 0 0
TOTAL .................................... 4,905 2,023 2,076 2,052 2,194
SYSTEM SPOT MARKET PRICES (MILLS/KWH)
Baseload Spot Market ....................... 25.00 23.59 22.56 22.68 24.29
Intermediate Spot Market ................... 50.00 27.81 23.60 28.09 32.31
Peaking Spot Market ........................ 75.00 37.27 37.76 39.70 49.79
Emergency Purchases ........................ 120.00 37.30 40.60 41.88 85.74
</Table>
34
TABLE R4: RETAIL ENERGY COMPANY CONTRACT INFORMATION
PURPOSE: Table R4 shows the particulars of your existing capacity contracts with
generators by year and generation company. MW of capacity reserved, GWh
purchased, energy and capacity costs are included. A calculation of average cost
is also shown.
USE: Looking at these contracts will help you get a feel for what you should be
paying for your power. Notice that there are two costs in each contract: an
energy cost (expressed on a kWh basis) and a capacity cost for reserving
generation capacity (expressed on a kW basis changes to the retail energy
company is also included. Engaging this switch passes all the fuel cost risk
from the generator to the retail company.
DEFINITIONS:
o YEARS OF THE CONTRACT: The years when the contract is active.
o CONTRACT CAPACITY: Amount of capacity (in MW) under contract.
o ENERGY COST: The variable cost of contract/mills/ (Kwh). Normally this is
the cost of power production including current fuel costs. It is possible
and sometimes desirable to "roll in" part of the capacity cost into the
energy cost.
o CAPACITY COST: Cost of reserving firm power service. Notice that this cost
is given in dollars per kW while the contract capacity is listed in MW.
Multiply the dollars per kW by 1000 to get dollars per MW.
o GENERATION COMPANY: The company with whom you have the contract.
o PURCHASES: This is the amount of energy (in GWh) purchased from this
contract in the previous period.
o POWER COST: This is the total cost (M$) of the energy and capacity
purchased from this contract in the previous period.
o AVE. COST: This is the average cost of energy (mills/kWh) purchased from
this contract in the previous period.
o CAPACITY FACTOR: This is the energy purchased in the previous period
divided by the maximum energy which could be purchased from this contract.
o FUEL TYPE: The fuel type is only used to identify the contract if you need
to cancel it.
At the end of Table R4 are the spot market purchases for the current year by
type.
35
Table R4: Retail Energy Company Contract Information for 1999
American Electric Power
<Table>
<Caption>
CONTRACT ENERGY CAPACITY POWER AVE
CAPACITY COST COST GENERATION PURCHASES COSTS COSTS FUEL CAPACITY
(MW) (Mills/kWh) ($/kW) COMPANY (GWh) (M$) (Mills/kWh) TYPE FACTOR
-------- ----------- -------- ---------- --------- ------ ----------- ---- --------
1999-2002 215 29.24 5 Wisconsin Power and Ligh 1,104 33 30.24 Gas/Oil Turbi 0.59
2003-2021 215 0.00 5 Wisconsin Power and Ligh 0 0 0.00 Gas/Oil Turbi 0.00
1999-1999 88 18.52 3 North/South Dakota 661 13 18.94 Gas/Oil Turbi 0.86
2000-2021 88 0.00 3 North/South Dakota 0 0 0.00 Gas/Oil Turbi 0.00
1999-2000 86 38.88 2 Illinois Power 749 29 39.12 Gas/Oil Turbi 1.00
2001-2021 86 0.00 2 Illinois Power 0 0 0.00 Gas/Oil Turbi 0.00
1999-2000 155 12.63 2 Minnesota Power 1,144 15 12.88 Gas/Oil Steam 0.84
2001-2021 155 0.00 2 Minnesota Power 0 0 0.00 Gas/Oil Steam 0.00
1999-2000 370 29.27 8 Commonwealth Edison 1,674 52 30.94 Gas/Oil Steam 0.52
2001-2021 370 0.00 8 Commonwealth Edison 0 0 0.00 Gas/Oil Steam 0.00
1999-2001 171 21.37 2 Illinois Power 1,179 26 21.65 Gas/Oil Steam 0.79
2002-2021 171 0.00 2 Illinois Power 0 0 0.00 Gas/Oil Steam 0.00
1999-1999 1,082 9.06 10 Minnesota Power 9,476 97 10.21 Coal Steam 1.00
2000-2000 1,082 9.03 10 Minnesota Power 0 0 0.00 Coal Steam 0.00
2001-2021 1,082 0.00 10 Minnesota Power 0 0 0.00 Coal Steam 0.00
1999-1999 2,725 10.31 11 Primergy 23,868 276 11.57 Coal Steam 1.00
2000-2000 2,725 10.33 11 Primergy 0 0 0.00 Coal Steam 0.00
2001-2021 2,725 0.00 11 Primergy 0 0 0.00 Coal Steam 0.00
1999-2001 2,363 21.73 10 Commonwealth Edison 10,760 257 23.88 Coal Steam 0.52
2002-2021 2,363 0.00 10 Commonwealth Edison 0 0 0.00 Coal Steam 0.00
1999-2001 1,597 12.13 16 Illinois Power 13,987 195 13.92 Coal Steam 1.00
2002-2021 1,597 0.00 16 Illinois Power 0 0 0.00 Coal Steam 0.00
1999-2001 427 19.58 12 Iowa Illinois Gas & Elec 2,824 61 21.46 Coal Steam 0.75
2002-2021 427 0.00 12 Iowa Illinois Gas & Elec 0 0 0.00 Coal Steam 0.00
1999-1999 155 4.46 12 Iowa Illinois Gas & Elec 1,360 8 5.89 Nuclear 1.00
2000-2021 155 0.00 12 Iowa Illinois Gas & Elec 0 0 0.00 Nuclear 0.00
1999-2001 1,152 7.58 11 Canada 10,089 90 8.89 Hydro 1.00
2002-2021 1,152 0.00 11 Canada 0 0 0.00 Hydro 0.00
1999 10,007 43.72 0 Baseload Spot 0 0 43.72 Baseload Spot
1999 0 0.00 0 Intermediate Spot 10,821 0 0.00 Interm. Spot
1999 0 0.00 0 Peaking Spot 0 0 0.00 Peaking Spot
1999 0 0.00 0 Other Purchases 0 0 0.00 Oth. Purchase
1999 0 0.00 0 Emergency 0 0 0.00 Emergency
1999 Total 154,907 1,150 7.42
</Table>
36
TABLE R5: RETAIL ENERGY COMPANY PRICES
PURPOSE: Prices, without T&D by class and year are listed along with average
class prices from other regions for comparison. Revenue is also broken out by
class.
USE: Table R5 can help develop pricing strategies that will keep your company
competitive. You can adjust your prices to remain competitive in certain markets
based on the information in this table.
IMPORTANT DEFINITIONS:
o PRICES, EXCLUDING T&D: Your prices by class and an average price.
o CONSUMER PRICES, EXCLUDING T&D: Average region prices by class for
comparison.
o PRICES, EXCLUDING T&D: Your prices by class and an average price.
o CONSUMER PRICES: Average regional prices including charges from the
distribution and transmission companies.
o CONSUMER PRICES, EXCLUDING T&D: Average regional prices charge by the
retail energy companies for comparison with your prices.
37
Table R5: Retail Energy Company Prices
American Electric Power, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
---------- ---------- ---------- ---------- ---------- ----------
SALES (GWh)
Residential 27,824 27,946 28,482 29,137 29,818 30,551
Commercial 20,530 20,787 21,443 22,193 22,916 23,603
Industrial 41,977 42,480 44,258 46,530 48,990 51,541
Street/Misc 1,150 1,168 1,203 1,223 1,245 1,273
Resale 40,093 40,292 40,062 40,085 39,963 39,538
TOTAL PURCHASES 131,574 132,673 135,446 139,167 142,931 146,507
PRICES - EXCLUDING T&D (MILLS/kWh)
Residential 35.75 36.76 25.52 21.13 19.19 18.71
Commercial 41.08 42.11 31.18 27.12 25.27 24.87
Industrial 29.15 30.23 19.95 16.52 14.84 14.63
Street/Misc 48.63 49.69 39.08 35.34 33.57 33.26
Resale 25.82 26.88 16.27 13.85 13.17 14.05
AVERAGE 31.56 32.62 21.98 18.57 17.12 17.13
REVENUE (M$/YR)
Residential 995 1,027 727 616 572 572
Commercial 843 875 669 602 579 587
Industrial 1,224 1,284 883 769 727 754
Street/Misc 56 58 47 43 42 42
Resale 1,035 1,083 652 555 526 555
TOTAL 4,153 4,328 2,977 2,585 2,447 2,510
CONSUMER PRICES (MILLS/kWh)
Minnesota Residential 70.73 72.10 65.66 65.00 62.14 61.61
Iowa,North/South Res 82.05 86.16 78.86 77.36 73.06 69.98
Illinois/Wisconsin Res 90.49 91.69 75.49 70.94 69.20 69.99
Ohio/Indiana Residential 64.84 67.05 57.19 53.95 52.82 51.73
Canada Residential 60.43 60.83 69.39 68.76 70.35 73.52
Minnesota Commercial 61.44 62.29 55.02 54.12 50.75 49.45
Iowa,North/South Commercial 67.63 70.36 63.55 63.04 59.49 57.22
Illinois/Wisconsin Comm 71.62 72.10 56.80 51.89 49.99 50.67
Ohio/Indiana Commercial 57.07 58.79 49.31 46.05 44.64 43.07
Canada Commercial 57.26 57.70 56.11 57.90 59.34 62.04
Minnesota Industrial 41.41 41.66 36.74 35.28 31.74 30.16
Iowa,North/South Industrial 38.61 41.87 37.55 34.71 29.14 26.86
Illinois/Wisconsin Indust 49.33 49.37 37.73 33.61 30.76 31.14
Ohio/Indiana Industrial 36.87 38.18 29.29 26.11 24.44 22.98
Canada Industrial 38.96 39.38 40.95 42.00 42.89 44.85
Other 63.44 63.57 50.02 45.90 44.87 45.55
Resale 26.37 27.10 26.68 24.02 22.10 21.73
CONSUMER PRICES - EXCLUDING T&D (MILLS/kWh)
Minnesota Residential 31.70 32.07 24.83 22.81 18.35 16.14
Iowa,North/South Res 46.77 49.21 41.32 40.05 36.29 33.81
Illinois/Wisconsin Res 58.26 57.70 40.75 35.41 32.67 32.33
Ohio/Indiana Residential 36.05 36.94 26.57 22.81 21.11 19.48
Canada Residential 18.71 19.31 27.29 25.81 26.35 28.27
Minnesota Commercial 39.74 40.10 32.32 30.80 26.65 24.56
Iowa,North/South Commercial 46.63 48.67 41.48 41.15 37.89 35.96
Illinois/Wisconsin Comm 53.43 53.13 37.40 32.18 29.92 30.19
Ohio/Indiana Commercial 40.40 41.43 31.58 28.08 26.40 24.60
Canada Commercial 34.37 34.94 32.99 34.31 35.14 37.11
Minnesota Industrial 33.74 33.78 28.70 27.14 23.46 21.73
Iowa,North/South Industrial 29.65 32.69 28.17 25.49 20.15 18.12
Illinois/Wisconsin Indust 42.30 42.13 30.32 26.18 23.30 23.60
Ohio/Indiana Industrial 29.87 30.90 21.88 18.74 17.10 15.71
Canada Industrial 31.13 31.62 32.99 33.78 34.24 35.69
Other 58.76 58.94 45.32 41.29 40.28 40.99
Resale 22.07 22.40 22.15 19.86 18.16 17.99
</Table>
38
TABLE R6: RETAIL ENERGY COMPANY SALES
PURPOSE: Table R6 shows the regions where you are making your sales both in
terms of GWh and market share.
USE: This table can help you maintain and gain market share by showing you where
your pricing and advertising policies are increasing market share and where they
are causing market share to fall.
IMPORTANT DEFINITION:
o MARKET SHARE: the percent of the total existing electric market that is
served by your company. Market share is a "size of the slice" measure, the
pie being the existing demand for electricity.
39
Table R6: Retail Energy Company Sales
American Electric Power, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
---------- ---------- ---------- ---------- ---------- ----------
SALES (GWh/yr)
Minnesota Residential 0 0 1 7 19 36
Iowa,North/South Residential 0 0 2 8 22 48
Illinois/Wisconsin Residential 0 0 26 93 227 451
Ohio/Indiana Residential 27,824 27,946 28,452 29,022 29,531 29,970
Canada Residential 0 0 2 7 20 45
Minnesota Commercial 0 0 2 5 12 24
Iowa,North/South Commercial 0 0 1 5 12 23
Illinois/Wisconsin Commercial 0 3 14 44 104 205
Ohio/Indiana Commercial 20,530 20,783 21,423 22,130 22,767 23,309
Canada Commercial 0 0 3 9 21 42
Minnesota Industrial 0 1 11 41 104 201
Iowa,North/South Industrial 0 0 4 14 35 68
Illinois/Wisconsin Industrial 0 5 31 108 262 512
Ohio/Indiana Industrial 41,977 42,473 44,206 46,338 48,515 50,621
Canada Industrial 0 1 6 29 74 139
Other 1,150 1,168 1,203 1,223 1,245 1,273
Resale 40,093 40,292 40,062 40,085 39,963 39,538
MARKET SHARE (%)
Minnesota Residential 0.000 0.000 0.015 0.070 0.178 0.340
Iowa,North/South Residential 0.000 0.000 0.027 0.128 0.339 0.724
Illinois/Wisconsin Residential 0.000 0.000 0.052 0.185 0.441 0.856
Ohio/Indiana Residential 68.990 68.438 67.616 66.677 65.669 64.572
Canada Residential 0.000 0.000 0.020 0.092 0.252 0.580
Minnesota Commercial 0.000 0.004 0.024 0.078 0.181 0.339
Iowa,North/South Commercial 0.000 0.004 0.024 0.080 0.191 0.372
Illinois/Wisconsin Commercial 0.000 0.005 0.026 0.077 0.174 0.331
Ohio/Indiana Commercial 66.493 66.461 66.345 66.083 65.601 64.825
Canada Commercial 0.000 0.004 0.029 0.097 0.234 0.455
Minnesota Industrial 0.000 0.006 0.043 0.163 0.391 0.728
Iowa,North/South Industrial 0.000 0.005 0.037 0.138 0.327 0.606
Illinois/Wisconsin Industrial 0.000 0.008 0.050 0.163 0.375 0.702
Ohio/Indiana Industrial 74.082 74.044 73.985 73.902 73.725 73.327
Canada Industrial 0.000 0.007 0.063 0.315 0.795 1.480
Other 8.030 8.029 8.034 8.051 8.135 8.297
Resale 36.965 36.670 36.233 35.715 35.142 34.550
</Table>
40
TABLE R7: RETAIL ENERGY COMPANY PERFORMANCE MEASURES
PURPOSE: Table R7 provides a comparison of company performance among all the
retail companies. Information includes sales, average prices, revenues, net
income, and return on equity.
USE: The retail companies are evaluated based on their ability to optimize these
variables. In games without retail wheeling successful retail companies are
those with the lowest prices.
Table R7: Retail Energy Company Performance Measures for 1999
American Electric Power, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
--------- --------- --------- --------- --------- ---------
SALES (GWh/Year)
Minnesota Power 10,203 10,780 11,706 12,825 14,108 15,453
Primergy 61,434 61,832 63,187 64,781 66,639 68,620
Otter Tail Power 4,317 4,546 4,902 5,335 5,827 6,255
Wisconsin Power and Light 10,840 10,849 11,112 11,536 12,076 12,564
Interstate/IES Utilities 15,804 15,918 16,179 16,556 17,206 18,069
North/South Dakota 3,600 4,524 5,954 7,585 9,183 10,557
Central Illinois Light Co. 5,835 5,846 6,086 6,501 7,135 8,032
Union Electric 53,603 53,589 54,469 55,614 56,608 57,050
Commonwealth Edison 85,171 85,266 87,288 89,820 92,236 93,681
Illinois Power 22,112 22,139 22,603 23,234 24,027 24,809
American Electric Power 131,574 132,673 135,446 139,167 142,931 146,507
Cinergy 50,569 51,018 52,150 53,503 54,731 55,964
Iowa Illinois Gas & Electric 6,147 6,202 6,308 6,481 6,787 7,238
Canada 36,066 36,760 37,450 38,125 38,523 38,420
Independent Power Producer 0 0 0 0 0 0
AVERAGE PRICE (MILLS/kWh)
Minnesota Power 28.7 26.8 27.3 25.3 25.4 26.3
Primergy 33.8 34.6 27.4 25.6 19.8 16.6
Otter Tail Power 28.0 27.9 35.6 33.9 33.2 34.5
Wisconsin Power and Light 31.2 31.6 28.7 26.9 26.9 28.7
Interstate/IES Utilities 33.8 38.2 34.5 30.9 24.6 21.8
North/South Dakota 33.8 24.9 20.8 29.1 28.6 28.1
Central Illinois Light Co. 34.9 35.2 28.7 26.5 23.5 22.3
Union Electric 38.0 36.9 34.4 29.5 26.9 25.9
Commonwealth Edison 57.2 56.8 37.3 30.8 30.3 32.5
Illinois Power 47.3 46.8 35.5 32.5 25.4 25.3
American Electric Power 31.6 32.6 22.0 18.6 17.1 17.1
Cinergy 33.8 34.8 29.1 26.8 25.3 20.2
Iowa Illinois Gas & Electric 40.1 41.9 38.4 36.1 30.8 28.8
Canada 26.4 26.9 32.0 31.9 32.6 34.7
Independent Power Producer 0.0 0.0 0.0 0.0 0.0 0.0
Average Price 37.6 37.9 29.6 26.4 24.2 23.6
</Table>
41
<Table>
TOTAL REVENUE (M$)
Minnesota Power 293.24 288.56 319.32 324.72 358.51 406.65
Primergy 2,076.40 2,137.00 1,729.57 1,656.68 1,321.50 1,141.50
Otter Tail Power 121.04 126.69 174.33 180.82 193.44 215.55
Wisconsin Power and Light 338.09 343.07 319.21 309.82 325.17 360.09
Interstate/IES Utilities 534.74 607.37 558.33 510.87 422.76 393.73
North/South Dakota 121.66 112.67 123.97 220.72 262.36 296.51
Central Illinois Light Co. 203.80 205.71 174.69 172.34 167.97 179.46
Union Electric 2,036.54 1,976.42 1,874.56 1,641.13 1,520.06 1,475.89
Commonwealth Edison 4,872.31 4,843.14 3,251.85 2,768.49 2,794.55 3,041.10
Illinois Power 1,046.03 1,036.49 803.36 755.99 609.42 627.99
American Electric Power 4,153.14 4,327.82 2,977.13 2,584.59 2,446.61 2,510.10
Cinergy 1,708.81 1,775.16 1,517.67 1,433.83 1,383.93 1,130.67
Iowa Illinois Gas & Electric 246.47 260.15 241.97 234.00 209.27 208.17
Canada 951.32 988.84 1,197.05 1,215.21 1,254.08 1,331.31
Independent Power Producer 0.00 0.00 0.00 0.00 0.00 0.00
NET INCOME (M$)
Minnesota Power 1.88 6.76 37.46 25.09 23.03 (11.11)
Primergy 11.27 511.92 255.50 453.33 327.03 117.09
Otter Tail Power 0.65 0.53 31.36 29.34 23.04 44.74
Wisconsin Power and Light 3.77 40.22 31.97 13.53 (2.89) (51.96)
Interstate/IES Utilities 3.50 133.43 125.86 158.49 102.38 72.20
North/South Dakota 3.65 33.10 (5.97) 45.41 55.35 90.16
Central Illinois Light Co. 2.68 37.57 20.22 23.43 15.07 32.62
Union Electric 8.44 390.92 503.15 422.73 365.08 520.81
Commonwealth Edison 5.34 1,949.12 976.38 539.28 339.49 (65.32)
Illinois Power 6.62 354.40 219.31 296.10 171.42 124.45
American Electric Power 5.46 1,530.70 651.21 424.75 248.22 401.07
Cinergy 8.68 308.35 178.06 133.69 286.98 51.88
Iowa Illinois Gas & Electric 3.14 76.56 68.16 82.98 64.98 62.26
Canada 1.54 58.47 210.56 201.86 170.91 35.31
Independent Power Producer (0.00) (0.00) (0.00) (0.00) (0.00) (0.00)
RETURN ON EQUITY
Minnesota Power 0.126 0.393 1.253 0.653 0.498 (0.317)
Primergy 0.125 1.941 0.729 0.899 0.531 0.179
Otter Tail Power 0.134 0.105 2.001 1.145 0.689 0.920
Wisconsin Power and Light 0.127 0.930 0.591 0.231 (0.052) (7.827)
Interstate/IES Utilities 0.129 1.844 1.094 0.938 0.503 0.317
North/South Dakota 0.122 0.803 (0.170) 0.897 0.797 0.901
Central Illinois Light Co. 0.133 1.145 0.511 0.493 0.287 0.513
Union Electric 0.125 1.950 1.355 0.821 0.571 0.638
Commonwealth Edison 0.133 2.773 0.944 0.443 0.255 (0.052)
Illinois Power 0.151 2.164 0.922 0.876 0.433 0.284
American Electric Power 0.131 2.725 0.832 0.458 0.245 0.349
Cinergy 0.134 1.823 0.776 0.487 0.772 0.133
Iowa Illinois Gas & Electric 0.127 1.509 0.923 0.813 0.524 0.429
Canada 0.119 0.819 0.747 0.417 0.261 0.051
Independent Power Producer (99.000) (99.000) (99.000) (99.000) (99.000) (99.000)
</Table>
42
TABLE R8: SYSTEM ENERGY BALANCE
PURPOSE: This table provides a "snapshot" of the complete electric market you
are competing in. Each company's sales and where the energy came from by company
is provided as well as a record of emergency purchases.
USE: You can use Table R8 to evaluate your purchasing strategies by comparing
them with your competitors. You can see whether you rely more or less on the
spot market, what your reserve margin is relative to your competitors (subtract
sales from purchases) and whether your emergency purchases seem excessive when
compared to other utilities.
Table R8: System Energy Balance (gWh) for 1999, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
------- ------- ------- ------- ------- -------
TOTAL SALES
Minnesota Power 10,203 10,780 11,706 12,825 14,108 15,453
Primergy 61,434 61,832 63,187 64,781 66,639 68,620
Otter Tail Power 4,317 4,546 4,902 5,335 5,827 6,255
Wisconsin Power and Light 10,840 10,849 11,112 11,536 12,076 12,564
Interstate/IES Utilities 15,804 15,918 16,179 16,556 17,206 18,069
North/South Dakota 3,600 4,524 5,954 7,585 9,183 10,557
Central Illinois Light Co. 5,835 5,846 6,086 6,501 7,135 8,032
Union Electric 53,603 53,589 54,469 55,614 56,608 57,050
Commonwealth Edison 85,171 85,266 87,288 89,820 92,236 93,681
Illinois Power 22,112 22,139 22,603 23,234 24,027 24,809
American Electric Power 131,574 132,673 135,446 139,167 142,931 146,507
Cinergy 50,569 51,018 52,150 53,503 54,731 55,964
Iowa Illinois Gas & Electric 6,147 6,202 6,308 6,481 6,787 7,238
Canada 36,066 36,760 37,450 38,125 38,523 38,420
Independent Power Producer 0 0 0 0 0 0
TOTAL 497,275 501,942 514,839 531,065 548,016 563,218
TOTAL LOSSES 39,868 29,099 30,236 31,544 32,907 34,132
TOTAL PURCHASES
Minnesota Power 10,723 11,330 12,302 13,478 14,826 16,241
Primergy 71,063 60,308 61,917 63,733 65,876 68,205
Otter Tail Power 4,924 5,185 5,592 6,086 6,646 7,135
Wisconsin Power and Light 11,586 11,595 11,876 12,329 12,906 13,428
Interstate/IES Utilities 16,714 16,836 17,111 17,510 18,197 19,111
North/South Dakota 4,058 5,101 6,713 8,552 10,353 11,902
Central Illinois Light Co. 6,030 6,041 6,289 6,718 7,373 8,301
Union Electric 56,676 56,661 57,591 58,802 59,853 60,320
Commonwealth Edison 92,338 92,440 94,633 97,378 99,996 101,563
Illinois Power 22,798 22,826 23,305 23,956 24,773 25,579
American Electric Power 139,119 140,280 143,213 147,147 151,126 154,907
Cinergy 53,680 54,157 55,358 56,794 58,099 59,407
Iowa Illinois Gas & Electric 6,433 6,491 6,602 6,783 7,103 7,575
Canada 41,001 41,790 42,575 43,342 43,795 43,678
Independent Power Producer 0 0 0 0 0 0
TOTAL 537,143 531,041 545,076 562,609 580,923 597,350
</Table>
43
<Table>
DIRECT ACCESS OR CfD PURCHASES
Minnesota Power 6,251 3,423 1,856 2,014 3,184 2,977
Primergy 59,264 5,444 6,504 43,852 60,252 58,690
Otter Tail Power 2,832 41 1,283 1,264 1,361 4,966
Wisconsin Power and Light 9,802 0 0 0 0 0
Interstate/IES Utilities 11,819 1,866 5,829 13,232 16,716 17,338
North/South Dakota 3,137 5,101 1,786 2,444 4,477 11,902
Central Illinois Light Co. 5,675 1,037 1,821 3,786 5,680 7,532
Union Electric 44,958 16,995 34,569 44,996 50,705 54,150
Commonwealth Edison 88,570 0 0 0 0 0
Illinois Power 19,654 1,790 5,281 15,547 18,809 19,004
American Electric Power 111,295 140,280 142,803 146,524 148,827 144,085
Cinergy 50,330 7,225 14,080 25,938 48,018 56,534
Iowa Illinois Gas & Electric 5,632 701 2,360 3,579 5,491 5,694
Canada 40,420 0 0 0 0 0
Independent Power Producer 0 0 0 0 0 0
TOTAL 459,640 183,904 218,172 303,177 363,521 382,872
SPOT PURCHASES
Minnesota Power 0 7,906 10,446 11,464 11,643 13,263
Primergy 0 54,863 55,413 19,881 5,624 9,516
Otter Tail Power 0 5,144 4,309 4,821 5,285 2,169
Wisconsin Power and Light 0 11,595 11,876 12,329 12,906 13,428
Interstate/IES Utilities 0 14,970 11,282 4,278 1,481 1,773
North/South Dakota 0 0 4,928 6,108 5,876 0
Central Illinois Light Co. 0 5,004 4,468 2,932 1,693 768
Union Electric 0 39,666 23,022 13,806 9,148 6,170
Commonwealth Edison 0 92,440 94,633 97,378 99,996 101,563
Illinois Power 0 21,036 18,023 8,409 5,964 6,575
American Electric Power 0 0 409 623 2,299 10,821
Cinergy 0 46,932 41,279 30,857 10,081 2,873
Iowa Illinois Gas & Electric 0 5,790 4,242 3,203 1,612 1,881
Canada 0 41,790 42,575 43,342 43,795 43,678
Independent Power Producer 0 0 0 0 0 0
TOTAL 0 347,137 326,904 259,432 217,402 214,478
TOTAL OTHER PURCHASES 77,503 0 0 0 0 0
TOTAL EMERGENCY PURCHASES 0 0 0 0 0 0
TOTAL PURCHASES 537,143 531,041 545,076 562,609 580,923 597,350
</Table>
44
TABLE R9: RETAIL ENERGY COMPANY COST PERFORMANCE DETAILS
PURPOSE: This table lists average cost of power, average unit cost of contracts,
average unit costs of spot market purchases and common stockholders equity for
each company.
USE: You can use this table to compare your buying strategies with those of
other companies. You can determine whether your average power costs were too
high relative to other companies' contract prices.
DEFINITION:
o AVERAGE COST OF POWER: This is the weighted average cost of contract power,
spot market purchases and emergency power.
TABLE R9: RETAIL ENERGY COMPANY COST PERFORMANCE DETAILS FOR 1999, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
----- ----- ----- ----- ----- -----
AVERAGE COST OF POWER (MILLS/KWH)
Minnesota Power 28.56 26.06 24.00 23.36 23.81 27.08
Primergy 33.58 26.20 23.54 18.92 15.49 15.64
Otter Tail Power 27.84 27.68 29.09 28.50 29.49 27.63
Wisconsin Power and Light 30.70 27.76 25.86 25.80 27.33 32.93
Interstate/IES Utilities 33.48 29.64 26.90 21.72 19.37 18.70
North/South Dakota 32.95 17.17 21.64 22.82 22.40 19.55
Central Illinois Light Co. 34.17 28.53 25.41 23.05 21.67 18.54
Union Electric 37.76 29.51 25.36 22.40 21.14 17.69
Commonwealth Edison 57.08 33.88 26.78 25.87 27.83 34.47
Illinois Power 46.82 30.61 26.19 20.46 19.29 21.56
American Electric Power 31.50 21.06 17.53 16.02 15.96 15.01
Cinergy 33.51 28.64 25.79 24.51 20.33 19.73
Iowa Illinois Gas & Electric 39.47 29.40 27.80 23.92 22.27 21.42
Canada 26.16 25.13 26.32 27.11 29.16 35.23
Independent Power Producer 0.00 0.00 0.00 0.00 0.00 0.00
Average Cost of Power 37.41 27.00 23.52 21.52 20.91 21.94
UNIT COST OF CONTRACTS (MILLS/KWH)
Minnesota Power 32.36 28.39 17.37 16.81 15.62 12.82
Primergy 32.58 36.71 33.80 17.00 15.35 15.43
Otter Tail Power 31.19 89.00 22.12 22.48 22.67 16.89
Wisconsin Power and Light 30.10 0.00 0.00 0.00 0.00 0.00
Interstate/IES Utilities 35.75 35.57 20.69 16.71 17.34 17.69
North/South Dakota 34.09 13.59 20.58 10.47 10.97 13.09
Central Illinois Light Co. 34.85 35.06 24.71 18.98 18.74 17.28
Union Electric 39.35 24.46 20.52 18.03 17.63 13.18
Commonwealth Edison 58.19 0.00 0.00 0.00 0.00 0.00
Illinois Power 54.04 37.13 24.76 14.11 16.15 16.90
American Electric Power 30.78 14.42 14.54 14.00 14.74 14.08
Cinergy 33.85 35.61 24.60 21.10 18.87 19.29
Iowa Illinois Gas & Electric 44.48 35.54 23.94 19.09 18.58 15.94
Canada 26.37 0.00 0.00 0.00 0.00 0.00
Independent Power Producer 0.00 0.00 0.00 0.00 0.00 0.00
Average Unit Cost 38.45 17.73 17.43 15.91 16.09 15.32
</Table>
45
<Table>
UNIT COST OF SPOT MARKET PURCHASES (MILLS/KWH)
Minnesota Power 19.97 22.79 21.87 21.91 23.32 28.81
Primergy 25.15 23.59 22.56 16.73 0.00 14.86
Otter Tail Power 14.95 23.59 22.56 22.36 24.29 30.04
Wisconsin Power and Light 21.33 24.21 22.78 23.48 25.48 32.47
Interstate/IES Utilities 26.03 23.59 23.39 16.01 0.00 0.00
North/South Dakota 24.70 0.00 20.49 20.61 21.57 0.00
Central Illinois Light Co. 26.60 23.59 23.38 23.51 24.29 0.00
Union Electric 18.69 23.59 17.08 15.07 12.64 5.91
Commonwealth Edison 42.07 24.45 22.88 23.78 25.92 33.37
Illinois Power 16.74 23.59 22.56 17.86 18.06 26.32
American Electric Power 26.60 0.00 0.00 0.00 0.00 0.00
Cinergy 19.24 23.59 23.21 23.77 8.20 0.00
Iowa Illinois Gas & Electric 16.75 23.59 23.39 17.53 15.40 20.12
Canada 16.94 24.01 22.70 23.22 25.11 31.71
Independent Power Producer 0.00 0.00 0.00 0.00 0.00 0.00
Average Unit Cost 24.17 23.87 22.35 22.02 22.63 28.19
COMMON STOCKHOLDERS EQUITY (M$/YR)
Minnesota Power 14.93 17.19 29.90 38.40 46.21 35.02
Primergy 89.81 263.68 350.38 504.34 615.37 655.02
Otter Tail Power 4.88 5.03 15.67 25.62 33.43 48.62
Wisconsin Power and Light 29.66 43.26 54.06 58.58 55.49 6.64
Interstate/IES Utilities 27.08 72.36 115.07 168.88 203.61 228.09
North/South Dakota 29.98 41.21 35.18 50.61 69.41 100.04
Central Illinois Light Co. 20.12 32.81 39.60 47.49 52.54 63.55
Union Electric 67.63 200.43 371.39 515.01 639.04 816.01
Commonwealth Edison 40.18 702.77 1,034.63 1,217.88 1,333.21 1,267.61
Illinois Power 43.79 163.79 237.88 338.09 395.94 437.82
American Electric Power 41.50 561.74 782.95 927.18 1,011.38 1,147.57
Cinergy 64.54 169.10 229.38 274.59 371.91 389.32
Iowa Illinois Gas & Electric 24.74 50.73 73.86 102.04 124.09 145.23
Canada 12.91 71.39 281.94 483.80 654.71 690.02
Independent Power Producer (0.00) (0.00) (0.00) (0.00) (0.00) (0.00)
</Table>
46
TABLE R10: SYSTEM CAPACITY MARGIN
PURPOSE: This table shows generation capacity by generation company; retail peak
demand by retail company, and a capacity margin calculation by company. It also
contains a region reserve margin and an effective region reserve margin.
USE: Table R10 is used for planning purposes to indicate how "tight" the
capacity is getting in a region.
IMPORTANT DEFINITIONS:
o CAPACITY MARGIN: Generation Capacity minus Retail Company Peak
o REGION RESERVE MARGIN: Capacity Margin divided by Generation Capacity
o EFFECTIVE REGION RESERVE MARGIN: includes outages
47
GENERATION COMPANY ACTIONS - UNDERSTANDING AND USING FORMS
All player actions are implemented by submitting a completed form to the
operator. These forms are entered into the computer by the operator who then
runs the model and prints reports. In each form you should provide all the
information, but only the information requested; complex contracts must be
submitted on multiple forms. When submitting a form which affects two players,
both players must agree to the terms therein, but only one form is submitted.
There are two basic kinds of forms - forms for individual actions that exist for
a specific length of time such as a contract between two parties and forms that
initiate strategies that remain in effect until a new strategy form is
submitted. An example of a strategy form would be retail pricing strategies or
generation spot market bidding strategies.
FORM 1 - DIRECT ACCESS OR CFD CAPACITY CONTRACT
Form 1 is the Direct Access or CfD Capacity Contract form and is used to submit
contracts for the sale or purchase of capacity. Although a Contract for
Differences (CfD) is essentially a money transfer, it is completed in the same
fashion as a Direct Access contract. Each bi-lateral agreement between a
generator and a retail energy company must be represented on a "Direct Access or
CfD Capacity Contract". Help determining energy and capacity costs can be found
in the section "What do You Want to Sell it For" in the generator's section of
the CIGMOD explanations, tips and procedures handout. It is not essential that
each contract have both a capacity charge and an energy charge; many contracts
are made with energy charges alone. Since this form represents an agreement
between a retail company and a generator, it is used by both parties; HOWEVER
ONLY ONE FORM PER TRANSACTION IS SUBMITTED TO THE OPERATOR.
48
DIRECT ACCESS or CfD CAPACITY CONTRACT - Form 1
A Contract Between Retail Energy Company:
------------------
and Generation Company:
------------------
Contract Beginning Year:
----------
Contract Ending Year:
----------
Capacity (MW):
----------
Energy Cost (Mills/kWh):
----------
Capacity Cost ($/kW):
----------
Simulation Year:
------------- -----------------
Operator Use Only
49
FORM 2 - TRENDED ELECTRIC CAPACITY CONTRACT
Form 2 is the Trended Electric Capacity Contract form and is used to submit
contracts for capacity sales and purchases when terms change over time. In all
other respects, the procedure is the same as the procedure for filling out Form
1.
TRENDED DIRECT ACCESS OR CfD CAPACITY CONTRACT - Form 2
A Contract Between Retail Energy Company:
------------------
and Generation Company:
------------------
<Table>
<Caption>
Beginning Ending
---------- ----------
Contract Year:
---------- ----------
Capacity (MW):
---------- ----------
Energy Cost (Mills/kWh):
---------- ----------
Capacity Cost ($/kW):
---------- ----------
</Table>
Simulation Year:
------------ -----------------
Operator Use Only
50
FORM G3 - GENERATION COMPANY CAPACITY EXPANSION STRATEGIES
Form G3 is a strategy form allowing the generator to select one of four capacity
expansion strategies. Once a strategy is selected, it remains in place until
another form is submitted. If no form is submitted, then no building occurs; the
default specification is "no building throughout the game". The first three
options in Form G3 are actual strategies based on your own sales, your region's
sales or spot market prices. The last option is for a single plant. Once the
plant is constructed, no further construction will occur unless a new form is
submitted.
GENERATION COMPANY CAPACITY EXPANSION STRATEGIES - Form G 3
Generation Company:
---------------------------
1. Sales. When you are selling more than __________ percent of your power
through direct access contracts, then build __________ percent of your
current capacity.
OR
2. System Needs. When the system needs power, build ___________ percent of
the system deficiency.
OR
3. Spot Market. When the spot market price is greater than the cost of new
capacity, then build __________ percent of the system capacity.
OR
4. User. Specify new capacity to be constructed:
Region:
---------------
Fuel Type:
----------------------------------
Year to Begin Construction:
-------------------
Capacity (MW):
-----------------------------
Simulation Year:
---------- -----------------
Operator Use Only
51
FORM G4 - GENERATION COMPANY SPOT MARKET BIDDING STRATEGIES
is used to select a generation company spot market bidding strategy - how the
generator will construct his offer price to the pool. One of two methods may be
used. The generator may select a fraction of fixed and fraction of variable cost
(either fraction can be greater than 1) of each plant type that will become the
offer price. Or the pricing can be done exogenously by pricing homogeneous
blocks of power from a specified region. The generator can select only one
method for bidding all his power. If the block method is selected, then the
region where the plants are located must be specified. If the generating company
has plants in different regions, a separate form must be filled out for each
region when using the block pricing method.
52
GENERATION COMPANY SPOT MARKET BIDDING STRATEGIES - Form G 4
Generation Company:
----------------------------
1. Percent Method
<Table>
<Caption>
Percent of Percent of Percent of
Fixed Cost Variable Cost Unused Capacity
---------- ------------- ---------------
Gas/Oil Turbine
---------- ---------- ----------
Gas/Oil CC
---------- ---------- ----------
Gas/Oil Steam
---------- ---------- ----------
Coal
---------- ---------- ----------
Advanced Coal
---------- ---------- ----------
Nuclear
---------- ---------- ----------
Hydro
---------- ---------- ----------
Renewables
---------- ---------- ----------
</Table>
OR
2. User Specified
Region:
------------------------
<Table>
<Caption>
Capacity Price
(MW) (Mills/kWh)
------------ ------------
Block 1
------------ ------------
Block 2
------------ ------------
Block 3
------------ ------------
Block 4
------------ ------------
Block 5
------------ ------------
Block 6
------------ ------------
Block 7
------------ ------------
Block 8
------------ ------------
Block 9
------------ ------------
Block 10
------------ ------------
Simulation Year:
---------- -----------------
Operator Use Only
</Table>
53
FORM G5 - GENERATION COMPANY PLANT RETIREMENTS
Form G5 is used to retire plants. Only a few plants retire during the game
unless this form is submitted. The region in which the plant is located can be
determined from Table G5.
GENERATION COMPANY PLANT RETIREMENTS - Form G 5
Generation Company:
-------------------
Region:
------------------------------
Plant Type:
--------------------------
Year of Retirement:
----------
Capacity to Retire (MW):
----------
Simulation Year:
---------- -----------------
Operator Use Only
54
FORM G6 - GENERATION COMPANY SPOT MARKET PURCHASE STRATEGIES
The Generation Company Spot Market Purchase Strategy Form G6 allows the
generation company to set a policy for spot market purchases. One of two
strategies may be selected - either based on an exogenously specified number of
MW or a percentage of total demand by capacity type. This is spot market
purchases only, emergency power is not included. The loading order determines
when your purchases will be made . If no minimum is set, then zero is the
default specification. Prices may be specified in either Mills/Kwh or as a
fraction of previous spot market prices.
GENERATION COMPANY SPOT MARKET PURCHASE STRATEGIES - Form G6
Generation Company:
----------------------------
I would like to buy the following capacity from the spot market:
<Table>
<Caption>
MW OR % of Demands
Baseload
--------- ----------
Intermediate
--------- ----------
Peaking
--------- ----------
</Table>
Use the following prices to determine the loading order of my spot
purchases:
<Table>
<Caption>
% of Spot Market Price
Mills/kWh OR in Previous Period
--------- -- ----------------------
Baseload
--------- ---------
Intermediate
--------- ---------
Peaking
--------- ---------
</Table>
Simulation Year:
---------- -----------------
Operator Use Only
55
FORM G7 - GENERATION COMPANY MERGERS
Form G7 is the Generation Company Merger form and is used when two generating
companies decide to merge. It requires the approval of both parties. During a
merger all assets and liabilities of two companies are combined to form one
company. The purchase price is not an issue in a merger. Both sets of players
now work together as a single company.
GENERATION COMPANY MERGERS - Form G 7
Generation Company: is merging
----------------------
Generation Company: into it.
---------------------------
Simulation Year
---------- -----------------
Operator Use Only
FORM G8 - GENERATION COMPANY ACQUISITION
Form G8 is the Generation Company Acquisitions form and is used when a
generation company acquires another generation company. It requires the approval
of both parties. During an acquisition the acquiring company receives all the
assets and liabilities of the acquired company except the common stock and
retained earnings. The change in net assets of the acquiring company is based on
the purchase price. The acquired company is left with cash, equal to the
purchase price of the company, the common stock, and retained earnings, computed
from the purchase price.
GENERATION COMPANY ACQUISITION - Form G 8
Generation Company: is acquiring
----------------------
Generation Company: .
---------------------------
Purchase Price (M$):
-----------------
Simulation Year:
---------- -----------------
Operator Use Only
56
FORM G9 - GENERATION COMPANY HOSTILE TAKE OVER
Form G9 is the Hostile Take Over form and is used when a generation company
attempts a hostile take over of another generation company. Companies must be
paid for in cash - no leveraged buy-outs. The purchasing utility would need to
provide the common stock equity plus 20 percent in cash (accumulated in short
term investments and tracked on the income statement) to complete a hostile
takeover. The company initiating the take-over is allowed to use the cash of the
take-over target to meet the cash requirement. The purchasing utility assumes
the debt responsibility of the take over target. Except for the cash requirement
the hostile takeover is the same as an acquisition.
GENERATION COMPANY HOSTILE TAKE OVER - Form G 9
Generation Company: is buying out
----------------------
Generation Company: .
---------------------------
Simulation Year:
---------- -----------------
Operator Use Only
57
FORM G10 - GENERATION COMPANY FINANCIAL REORGANIZATION
Form G10 is the Generation Financial Reorganization form and is used to modify
the exogenously specified financial parameters outside the normal boundary of
the game. This form provides additional financial flexibility for company
management.
This form is used to input the results of a financial reorganization of the
company. The values entered on the form are the company values after the
reorganization. All lines must be filled in. Do not put the change in the
values, put the actual value.
GENERATION COMPANY FINANCIAL REORGANIZATION - Form G 10
Generation Company:
----------------------------------------------
Net Assets (M$):
-------------------------
Long Term Debt (M$):
----------------------------
Debt Interest (M$/yr):
----------------------------
Common Stock (M$):
----------------------------
Retained Earnings (M$):
----------------------------
Preferred Stock (M$):
----------------------------
Cash (M$):
----------------------------
Simulation Year:
---------- -----------------
Operator Use Only
58
FORM G11 - GENERATION COMPANY MODIFY DIVIDEND RATE
Form G11 is the Generation Company Modify Dividend Rate form and is used to
adjust the amount of dividends paid each year. The dividend payout rate may be
adjusted as desired. Sometimes it is desirable to alter the dividend payout rate
to allow the company to accumulate cash for takeover opportunities.
GENERATION COMPANY MODIFY DIVIDEND RATE - Form G 11
Generation Company:
--------------------------------------------
Common Stock Dividend Payout Ratio (%):
------------
Simulation Year:
---------- -----------------
Operator Use Only
FORM G12 - GENERATION COMPANY MODIFY DEBT/EQUITY RATIO
Form G12 is the Generation Company Modify Debt/Equity Ratio form. Prudent
adjustments can be made to this ratio to give the retail player added financial
flexibility.
GENERATION COMPANY MODIFY DEBT/EQUITY RATIO - Form G 12
Generation Company:
--------------------------------------------
Marginal Debt/Equity Ratio (%):
---------
Simulation Year:
---------- -----------------
Operator Use Only
59
FORM G13 - GENERATION COMPANY CASH TRANSFER
Generation form G13 allows the generating company to transfer cash from a
generating company to a retail company. It requires the approval of both
parties.
GENERATION COMPANY CASH TRANSFER - Form G 13
FROM
Generation Company:
--------------------------------
TO
Retail Company:
-----------------------------------
Transfer M$
------------
Simulation Year:
---------- -----------------
Operator Use Only
(use negative values to transfer cash from the retail company to the
generation company.)
60
FORM G14 - GENERATION COMPANY DIRECT ACCESS SELLING QUANTITY STRATEGIES
Form G14 is used to set the strategy for selling power in the computer auction.
This strategy will determine whether the computer players are allowed to buy
your power. The amount of generation assigned to the power auction can be
determined by fuel type by either specifying the MW available or a percent of
total capacity using each fuel. If no form is submitted, then no power is
offered to the auction.
GENERATION COMPANY DIRECT ACCESS SELLING QUANTITY STRATEGIES
- Form G 14
Generation Company:
-------------------------
<Table>
<Caption>
Capacity Percent of
Plant Type (MW) OR Capacity
---------- -------- --------
Gas/Oil Turbine
---------- ----------
Gas/Oil CC
---------- ----------
Gas/Oil Steam
---------- ----------
Coal
---------- ----------
Advanced Coal
---------- ----------
Nuclear
---------- ----------
Hydro
---------- ----------
Renewables
---------- ----------
Simulation Year:
---------- -----------------
Operator Use Only
</Table>
61
FORM G15 - THE GENERATION COMPANY DIRECT ACCESS BIDDING STRATEGY
The Generation Company Direct Access Bidding Strategy Form (G15) allows the
player to enter into the computer auction to sell power to the computer retail
energy companies. The generating company specifies a minimum offer price one of
two ways. Either it is specified by type as a percent of fixed and variable
costs OR as an exogenously specified number. If the percentage is used, a second
choice of whether to use embedded or new plant costs is also required. Only one
method should be selected and this strategy will remain in effect until the
retail player changes it by submitting another Form G 15.
62
GENERATION COMPANY DIRECT ACCESS BIDDING STRATEGIES-Form G 15
Generation Company: ______________________________________________
Bid Prices to direct access power auction are a fraction of
OR costs fixed and variable costs.
-------------- --------------
1. embedded 2. new plant
<Table>
<Caption>
Initial Price Initial Price Stop Price
Percent of Percent of Percent of
Plant Type Fixed Cost Variable Cost Variable Costs
---------- ------------- ------------- --------------
Gas/Oil Turbine
---------- ---------- -----------
Gas/Oil CC
---------- ---------- -----------
Gas/Oil Steam
---------- ---------- -----------
Coal
---------- ---------- -----------
Advanced Coal
---------- ---------- -----------
Nuclear
---------- ---------- -----------
Hydro
---------- ---------- -----------
Renewables
---------- ---------- -----------
</Table>
OR
3. User. Bid Prices are specified directly:
<Table>
<Caption>
Initial Initial
Fixed Cost Variable Cost Stop Price
Plant Type ($/KW) (Mills/kWh) (Mills/kWh)
---------- ---------- ------------- -----------
Gas/Oil Turbine
---------- ---------- -----------
Gas/Oil CC
---------- ---------- -----------
Gas/Oil Steam
---------- ---------- -----------
Coal
---------- ---------- -----------
Advanced Coal
---------- ---------- -----------
Nuclear
---------- ---------- -----------
Hydro
---------- ---------- -----------
Renewables
---------- ---------- -----------
</Table>
Simulation Year:
---------- -----------------
Operator Use Only
63
FORM G16 - GENERATION COMPANY BUY/SELL CAPACITY
Form G16 is the Buy/Sell Capacity form and is used by a generator who wants to
sell a generating unit to another generating company. The book value of the
plant can be estimated by multiplying the capacity cost times the number of
kilowatts being sold.
GENERATION COMPANY BUY/SELL CAPACITY - Form G 16
Generation Company:
-------------------------------------------------
Generation Company Buying Capacity:
--------------------------------
Region:
------------------------------------
Plant:
-------------------------------------
Year:
-------------------------------------
Capacity (MW):
-----------------------------
Purchase Price (M$):
-------------------------
Book Value of Capacity (M$):
------------------
Simulation Year:
---------- -----------------
Operator Use Only
64
FORM G17- GENERATION COMPANY CANCEL CONSTRUCTION
Form G17 is the Cancel Construction form and is used to cancel the construction
of plants initiated during the game. This form can only be used for plant types
that require more than one year to construct.
GENERATION COMPANY CANCEL CONSTRUCTION - Form G 17
Generation Company:
-----------------------------------------------
Plant Type:
-------------------
Region:
----------------------------------
Capacity Under Construction to be Canceled (MW):
----------------
Simulation Year:
---------- -----------------
Operator Use Only
65
FORM G18 - GENERATION COMPANY TAKE OVER STRATEGY
Form G18 is the Generation Company Take Over Strategy form. This allows the
generation company to set its strategy once, and the computer will make the
financial transactions as they become available. Take over policies can be based
on an aggressive "increase market share" philosophy or a purely defensive "eat
or be eaten" philosophy or cost based (neutral). The strategy chosen remains in
effect until a new form is submitted. This option is currently being developed
and is not available.
GENERATION COMPANY TAKE OVER STRATEGY - Form G 18
Generation Company:
----------------------
Neutral
-------
Aggressive
-------
Defensive
-------
Simulation Year:
---------- -----------------
Operator Use Only
66
FORM G19 - GENERATION COMPANY PLAYER STATUS ADJUSTMENT
Generation Form G19 is a housekeeping form that allows human players to become
computer players and vice versa or exit the game all together. This form is used
when a generation company wants to also operate a retail operating company. The
generation company selects a retail energy company currently being run by the
computer or out of the game and changes the status to human and gives the
company a new name.
GENERATION COMPANY PLAYER STATUS ADJUSTMENT - Form G 19
Generation Company: is changing
----------------------
its status to: HUMAN
---------
COMPUTER
---------
N/A
---------
and its name to .
------------------------------------
Simulation Year:
---------- -----------------
Operator Use Only
67
FORM G20 - TRANSMISSION CONSTRAINTS
Form G20 initiates transmission constraints. This is decided upon and set at the
beginning of the game and is not changed by individual players.
TRANSMISSION CONSTRAINTS - Form G 20
Capacity
Transmission Line (MW)
MAPP Canada to MAPP US
-------------
MAPP US to MAIN
-------------
MAIN to ECAR
-------------
Simulation Year:
---------- -----------------
Operator Use Only
68
GENERATING COMPANY REPORTS
TABLE G1: GENERATION COMPANY CAPACITY REQUIREMENT STATEMENT (MW)
PURPOSE: This table shows existing levels of generation capacity, additions
under construction and retirements. An estimated reserve margin is offered.
Capacity under contract is provided to calculate capacity available for sale.
USE: the generator uses the information in Table G1 to determine how much
capacity can be offered for sale. The table also provides an indication of when
capacity under construction will be available, when new capacity might be needed
due to retirements or contractual obligations and what reserve margin would be
appropriate.
DEFINITIONS:
o CAPACITY ON-LINE: total MW generation capacity available for generation at
the beginning of the year
o CAPACITY UNDER CONSTRUCTION: MW of new capacity under construction. The
length of the construction time depends on the plant being built.
o ESTIMATED RESERVES: A twenty percent reserve margin is estimated. You may
choose to ignore this level and calculate your own.
o HISTORICAL PURCHASE CONTRACTS: contracts made historically that are set to
zero in the future.
o EFFECTIVE CAPACITY: Total capacity less the reserve margin.
o CAPACITY UNDER CONTRACT: MW of capacity under a wholesale contract
o CAPACITY AVAILABLE FOR SALE: If contracted capacity is less than effective
capacity the difference in MW is shown here.
o CAPACITY DEFICIT: If the contracted capacity is greater than the effective
capacity, the difference in MW is shown here.
Table G1: Generation Company Capacity Requirement Statement (MW) for 1999
Wisconsin Power and Light, DARW
<Table>
<Caption>
1999 2000 2001 2002 2003 2004 2005
-------- -------- -------- -------- -------- -------- --------
Capacity On-line 9,081 9,281 9,281 9,281 9,281 9,281 9,281
Capacity under Construction 200 0 0 0 0 0 0
Capacity Retirements 0 0 0 0 0 0 0
Total Capacity 9,281 9,281 9,281 9,281 9,281 9,281 9,281
Estimated Reserves 2,320 2,320 2,320 2,320 2,320 2,320 2,320
Historical Purchase Contracts 0 0 0 0 0 0 0
Effective Capacity 6,961 6,961 6,961 6,961 6,961 6,961 6,961
Capacity Under Contract 1,562 1,562 1,562 1,562 1,562 1,562 1,562
Capacity Available for Sale 5,399 5,399 5,399 5,399 5,399 5,399 5,399
Capacity Deficit 0 0 0 0 0 0 0
</Table>
69
TABLE G2: GENERATION COMPANY STATEMENT OF INCOME AND FINANCE
PURPOSE: Table G2 shows the company income statement (all values in $M)
including common measures of performance such as the debt/equity ratio and
return on equity. Notice that operating revenues are divided into contract
revenues and central dispatch revenues.
USE: the income statements shows how well you are doing financially and where
your problems might be if you are not.
DEFINITIONS:
OPERATING REVENUES:
o DIRECT ACCESS CONTRACT REVENUE: revenue from dispatching contracts.
o CENTRAL DISPATCH REVENUE: additional revenue from being dispatched by the
pool as the lowest cost producer.
o CONTRACT FOR DIFFERENCES REVENUE: revenue from contracts hedging on
generation price volatility.
o SPOT MARKET REVENUE: revenue from sales to the spot market
o OTHER REVENUE: Includes revenue from transmission constraints
OPERATING EXPENSES FROM:
o SPOT MARKET PURCHASES: Power purchased from the spot market at the market
price.
o PURCHASED POWER:: Historical purchases which are set to 0 in the future.
o EMERGENCY POWER: A forced, computer generated purchase. Emergency power is
purchased because contractual power was inadequate to cover your load.
o OPERATING INCOME: Calculated as Operating Revenues minus Operating
Expenses.
o NET INCOME: Operating Income plus Other Income minus Interest Payments.
SOURCES AND USES OF FUNDS
o CONSTRUCTION EXPENDITURES: money spent on new plant
o COMMON STOCK DIVIDENDS: money paid out to stockholders; this variable can
be modified by the player.
o COMPANY PURCHASE PRICE: if you have engaged in a takeover or buyout during
the previous year, the cost of the purchase is recorded here.
BALANCE SHEET
o CASH (ON HAND): yearly additions to retained earnings. Cash and retained
earnings need to be watched and adjusted (by increasing expenditures, if
necessary) to avoid becoming a take-over target.
o RETAINED EARNINGS: cumulative cash on hand
o RETURN ON EQUITY: classic measure of company health.
70
Table G2: Generation Company Statement of Income and Finance (in millions) for
1999 Wisconsin Power and Light, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
-------- -------- -------- -------- -------- --------
Operating Revenues:
Direct Access Contracts ............. 333 2 6 192 199 196
Contract for Differences ............ 0 0 0 0 0 0
Central Dispatch .................... 0 0 0 0 0 0
Spot Market ......................... 0 291 301 687 689 913
Other ............................... 123 102 82 146 97 49
Total ............................. 456 394 388 1,025 985 1,158
Operating Expenses:
Fuel Cost ........................... 122 145 151 419 394 392
Operation and Maintenance ........... 54 73 74 195 191 188
Purchased Power ..................... 38 0 0 0 0 0
Spot Market Purchases ............... 0 0 0 0 0 0
Central Dispatch .................... 0 0 0 0 0 0
Emergency Purchased Power ........... 0 0 0 0 0 0
Total Production Expenses ......... 214 218 225 614 585 580
Depreciation ........................ 26 32 30 128 121 114
Income Taxes ........................ 13 -6 -9 -49 -60 5
Other Taxes ......................... 10 11 11 45 42 41
General and Admin. Costs ............ 21 0 0 9 10 9
Miscellaneous Expenses .............. 132 110 88 157 105 52
TOTAL ............................ 417 366 345 904 803 801
Operating Income ....................... 39 28 43 121 182 357
Other Income ........................... 5 4 6 9 2 12
Interest Payments ...................... 13 17 16 64 94 91
Net Income ............................. 31 16 33 66 90 279
Sources
Net Income .......................... 31 16 33 66 90 279
Depreciation ........................ 26 32 30 128 121 114
Funds From Debt ..................... 78 0 0 380 0 0
Funds From Common Stock ............. 0 0 0 780 0 0
Funds from Preferred Stock .......... 0 0 0 0 0 0
Funds from Cash ..................... 0 0 0 64 0 0
TOTAL ............................ 134 48 64 1,417 211 393
Uses
Expenditures for New Capacity ....... 9 0 0 0 0 51
Common Stock Dividends .............. 29 9 21 42 57 182
Preferred Stock Dividends ........... 2 1 2 2 4 4
Preferred Stock Sinking Fund ........ 1 1 1 2 2 2
Debt Repayment ...................... 85 6 6 21 33 31
Company Purchase Price .............. 0 0 0 1,350 0 0
New Liquid Investments .............. 0 30 34 0 116 124
Common Stock Repurchased ............ 2 0 0 0 0 0
Misc. Projects ...................... 7 0 0 0 0 0
TOTAL ............................ 134 48 64 1,417 211 393
Assets
Current Assets ...................... 0 0 0 67 67 250
Net Assets .......................... 483 549 519 2,183 2,062 1,999
Liquid Investments .................. 0 30 64 0 116 55
TOTAL ............................. 483 579 583 2,250 2,245 2,304
Liabilities
Current Liabilities ................. 98 98 98 0 0 0
Long Term Debt ...................... 138 182 176 977 945 913
Preferred Stock ..................... 25 32 31 66 64 62
TOTAL Liabilities ................. 260 312 304 1,043 1,008 975
Equity
Common Stock ........................ 109 148 148 928 928 928
Retained Earnings ................... 114 119 130 279 308 402
Common Stockholders Equity ........ 223 267 278 1,207 1,236 1,330
TOTAL Liab. and Equity ................. 483 579 583 2,250 2,245 2,304
Debt Fraction of Capitalization ........ 0.38 0.40 0.39 0.45 0.43 0.41
Return on Equity ....................... 0.14 0.06 0.12 0.05 0.07 0.21
</Table>
71
TABLE G3: GENERATION COMPANY DIRECT ACCESS OR CFD SALES AND REVENUES
PURPOSE: Table G3 shows sales to, unit prices and total revenues by retail
company. Also shown are line losses, spot market purchases and emergency
purchases
USE: This table tracks your sales on a company by company basis and also
calculates an average price of power for your company and compares it to an
average spot market price. This table should help you discover whether or not
you are making advantageous contracts with retail companies and should help you
decide whether or not to sell more power in the spot market.
IMPORTANT DEFINITIONS:
IN THE SALES SECTION:
TOTAL PURCHASES: the sum of all your sales by retail company. This is gross
sales to the retail company - the retail company nets out line losses.
IN THE UNIT PRICE AND REVENUES SECTIONS:
AVERAGE PRICE: Your average price for all your contract sales
TOTAL REVENUE: Total revenues from your contract sales
72
Table G3: Generation Company Direct Access or CfD Sales & Revenues for 1999
Wisconsin Power and Light, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
------ ---- ---- ------ ------ ------
DIRECT ACCESS or CfD SALES (GWh)
Minnesota Power 0 0 0 0 0 0
Primergy 0 0 0 0 128 128
Otter Tail Power 0 0 53 0 0 100
Wisconsin Power and Light 11,586 0 0 0 0 0
Interstate/IES Utilities 0 0 0 0 0 0
North/South Dakota 0 0 0 0 0 0
Central Illinois Light Co. 0 0 0 1,664 1,664 888
Union Electric 0 0 0 0 81 81
Commonwealth Edison 0 0 0 0 0 0
Illinois Power 0 0 0 0 0 835
American Electric Power 0 0 0 1,378 5 1,104
Cinergy 0 0 81 6,525 8,715 6,516
Iowa Illinois Gas & Electric 0 0 0 0 0 0
Canada 0 0 0 0 0 0
Independent Power Producer 0 0 0 0 0 0
Total 11,586 0 134 9,567 10,594 9,653
DIRECT ACCESS or CfD PRICES (Mills/kWh)
Minnesota Power 0.00 0.00 0.00 0.00 0.00 0.00
Primergy 0.00 0.00 0.00********** 5.54 5.54
Otter Tail Power 0.00 0.00 26.44******************** 25.69
Wisconsin Power and Light 28.75 0.00 0.00 0.00 0.00 0.00
Interstate/IES Utilities 0.00 0.00 0.00 0.00 0.00 0.00
North/South Dakota 0.00 0.00 0.00 0.00 0.00 0.00
Central Illinois Light Co. 0.00 0.00 0.00 21.69 21.69 22.51
Union Electric 0.00 0.00 0.00 0.00 39.28 25.15
Commonwealth Edison 0.00 0.00 0.00 0.00 0.00 0.00
Illinois Power 0.00 0.00 0.00 0.00 0.00 30.61
American Electric Power 0.00 0.00 0.00 8.38 3.73 30.24
Cinergy 0.00 0.00 38.91 21.77 18.13 17.21
Iowa Illinois Gas & Electric 0.00 0.00 0.00 0.00 0.00 0.00
Canada 0.00 0.00 0.00 0.00 0.00 0.00
Independent Power Producer 0.00 0.00 0.00 0.00 0.00 0.00
Average 28.75 0.00 33.93 19.84 18.70 20.35
DIRECT ACCESS or CfD REVENUES (M$/year)
Minnesota Power 0 0 0 0 0 0
Primergy 0 0 0 0 1 1
Otter Tail Power 0 0 1 0 0 3
Wisconsin Power and Light 333 0 0 0 0 0
Interstate/IES Utilities 0 0 0 0 0 0
North/South Dakota 0 0 0 0 0 0
Central Illinois Light Co. 0 0 0 36 36 20
Union Electric 0 1 1 1 3 2
Commonwealth Edison 0 0 0 0 0 0
Illinois Power 0 0 0 1 1 26
American Electric Power 0 0 0 12 0 33
Cinergy 0 0 3 142 158 112
Iowa Illinois Gas & Electric 0 0 0 0 0 0
Canada 0 0 0 0 0 0
Independent Power Producer 0 0 0 0 0 0
Total 333 2 6 192 199 196
</Table>
73
TABLE G4: GENERATION COMPANY CONTRACT INFORMATION
PURPOSE: Table G4 shows the particulars of your existing generation capacity
contracts by year, fuel type and distribution company. Sales from each contract,
revenue and average prices are also detailed.
USE: Looking at these contracts will help you get a feel for what you should be
charging for your power. Notice that there are two costs in each contract: an
energy cost (expressed on a kWh basis) and a capacity cost for reserving
generation capacity.
DEFINITIONS:
o CONTRACT CAPACITY: amount of capacity (in MW) under contract to the
distributor.
o ENERGY COST: this is generally the variable cost of power production
including current fuel costs. It is possible and sometimes desirable to
"roll in" part of the capacity cost into the energy cost.
o CAPACITY COST: Cost of reserving firm power service. Notice that this cost
is given in dollars per kW while the contract capacity is listed in MW.
Multiply the dollars per kW by 1000 to get dollars per MW.
o AVERAGE PRICE: The average price is sales divided by revenue. Normally, the
average price will change with sales because fixed costs decline per unit
as more kWh of energy are sold.
o CAPACITY FACTOR: This is the energy purchased in the previous period
divided by the maximum energy which could be purchased from this contract.
o AVERAGE PRICE: The fuel type is only used to identify the contract if you
need to cancel it.
74
Table G4: Generation Company Contract Information for 1999
Wisconsin Power and Light
<Table>
<Caption>
CONTRACT ENERGY CAPACITY
CAPACITY COST COST RETAIL SALES REVENUE AVE. PRICE FUEL CAPACITY
(MW) Mills/kWh) ($/kW) COMPANY (GWh) (M$) (Mills/kWh) TYPE FACTOR
-------- ---------- -------- ------- ----- ------- ----------- ---- --------
1999-2000 95 29.82 7 Illinois Power 835 26 30.61 Gas/Oil Turbi 1.00
2001-2021 95 0.00 7 Illinois Power 0 0 0.00 Gas/Oil Turbi 0.00
1999-2002 215 29.24 5 American Electric Power 1,104 33 30.24 Gas/Oil Turbi 0.59
2003-2021 215 0.00 5 American Electric Power 0 0 0.00 Gas/Oil Turbi 0.00
1999-1999 190 20.75 8 Central Illinois Light C 888 20 22.51 Coal Steam 0.53
2000-2021 190 0.00 8 Central Illinois Light C 0 0 0.00 Coal Steam 0.00
1999-1999 724 20.75 8 Cinergy 4,138 92 22.19 Coal Steam 0.65
2000-2021 724 0.00 8 Cinergy 0 0 0.00 Coal Steam 0.00
1999-1999 271 6.84 15 Cinergy 2,372 20 8.56 Nuclear 1.00
2000-2021 271 0.00 15 Cinergy 0 0 0.00 Nuclear 0.00
1999-2000 15 5.09 4 Primergy 128 1 5.54 Hydro 1.00
2001-2021 15 0.00 4 Primergy 0 0 0.00 Hydro 0.00
1999-2001 1 2.72 4 Cinergy 7 0 3.16 Hydro 1.00
2002-2021 1 0.00 4 Cinergy 0 0 0.00 Hydro 0.00
1999-1999 42 24.83 2 Otter Tail Power 100 3 25.69 Waste 0.27
2000-2021 42 0.00 2 Otter Tail Power 0 0 0.00 Waste 0.00
1999-1999 9 24.90 2 Union Electric 81 2 25.15 Waste 1.00
2000-2021 9 0.00 2 Union Electric 0 0 0.00 Waste 0.00
1999 Total 9,653 196 20.35
</Table>
75
TABLE G5: GENERATION COMPANY CAPACITY COSTS
PURPOSE: Table G5 shows the features of your existing generation capacity by
fuel type and region including capacity factors and a breakdown of embedded
costs.
USE: This table helps you make cost-based decisions about what to sell your
power for by providing you with the information you need to determine the
minimum price necessary to cover your costs. To allocate fixed costs over sales
an estimate of sales must be made. This estimate is done using plant capacity
factors and is described elsewhere in this document.
Pricing power is done on the basis of fixed and variable costs. Fixed costs must
be annualized and prorated by a capacity factor to convert them into mills/kWh.
This task is performed for you in the following table for capacity factors of
25, 50, and 75%. These fixed costs are then added to the variable costs to get
a total mills/kWh cost of generation. These total costs are also listed in the
table for 25, 50 and 75% capacity factors.
DEFINITIONS:
o PLANT AVAILABILITY FACTOR: Percent of the year plant is available.
o ACTUAL CAPACITY FACTOR: Capacity factor of the plant for the previous year.
o CAPACITY COSTS: Construction cost of the plant ($/Kw).
o LEVELIZED CAPACITY COST: Capacity costs "spread out" on an annual basis.
o FIXED O&M COSTS: O&M costs that do not vary with GWh generated.
o ANNUAL FIXED COST: Sum of the levelized Capacity Cost and the fixed O&M
costs. Values for fixed costs in mills/kWh are given for different capacity
factors.
o VARIABLE O&M COSTS: O&M costs that vary with the GWh sold.
o VARIABLE COST OF PLANTS: Sum of fuel and variable O&M costs.
o AVERAGE COST OF POWER: this calculation is performed given several plant
capacity factors.
76
Table G5: Generation Company Capacity Costs for 1999
Wisconsin Power and Light, DARW
<Table>
<Caption>
Oil/Gas CT Oil/Gas CC Oil Steam Coal Adv. Coal Nuclear Hydro Waste
---------- ---------- --------- --------- --------- --------- --------- ---------
Generation Capacity (MW)
MAPP Canada 0 0 0 0 0 0 0 0
MAPP US 654 0 0 4,794 0 637 41 172
MAIN 0 0 0 0 0 0 0 0
ECAR 1 700 0 1,857 0 166 60 0
Total 655 700 0 6,651 0 803 101 172
Electricity Generated (GWh) 502 2,724 0 25,676 0 4,725 269 312
Plant Availability Factor (%) 95.00 90.00 0.00 75.00 0.00 85.00 75.00 60.00
Actual Capacity Factor (%) 8.75 44.42 0.00 61.14 0.00 84.68 75.00 20.73
Existing Plants
Fixed Cost ($/KW)
Capacity Costs 162 747 0 182 0 410 121 0
Levelized Capacity Cost 28.10 129.30 0.00 31.54 0.00 70.97 21.03 0.00
Fixed O&M Costs 4.86 12.06 0.00 16.82 0.00 17.38 2.01 16.11
Annual Fixed Cost 32.96 141.36 0.00 48.36 0.00 88.34 23.04 16.11
Fixed Cost (MILLS/kWh)
Actual Capacity Factor 42.98 36.33 0.00 9.03 0.00 11.91 3.51 8.87
25% Capacity Factor 15.05 64.55 0.00 22.08 0.00 40.34 10.52 7.35
50% Capacity Factor 7.52 32.27 0.00 11.04 0.00 20.17 5.26 3.68
75% Capacity Factor 5.02 21.52 0.00 7.36 0.00 13.45 3.51 2.45
Variable Cost (MILLS/KWH)
Fuel Cost 35.84 15.53 0.00 12.35 0.00 1.57 0.00 21.43
Variable O&M Costs 0.44 0.69 0.00 3.07 0.00 0.00 0.00 4.51
Pollution Tax Rate 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Variable Cost 36.28 16.22 0.00 15.42 0.00 1.57 0.00 25.94
Average Cost (MILLS/kWh)
Actual Capacity Factor 79.26 52.55 0.00 24.45 0.00 13.48 3.51 34.81
25% Capacity Factor 51.33 80.76 0.00 37.50 0.00 41.91 10.52 33.30
50% Capacity Factor 43.80 48.49 0.00 26.46 0.00 21.74 5.26 29.62
75% Capacity Factor 41.29 37.73 0.00 22.78 0.00 15.01 3.51 28.39
New Plants
Fixed Cost ($/KW)
Capacity Costs 472 617 1,000 1,400 1,469 2,500 1,804 1,800
Levelized Capacity Cost 81.70 106.80 173.10 242.34 254.29 432.75 312.27 311.58
Fixed O&M Costs 4.86 12.06 0.52 16.82 16.82 17.38 2.01 16.11
Annual Fixed Costs 82.54 108.89 173.19 245.25 257.20 435.76 312.62 314.37
Fixed Cost (MILLS/kWh)
Actual Capacity Factor 15.70 20.72 32.95 46.66 48.93 82.91 59.48 59.81
25% Capacity Factor 37.69 49.72 79.08 111.99 117.44 198.98 142.75 143.55
50% Capacity Factor 18.85 24.86 39.54 55.99 58.72 99.49 71.38 71.77
75% Capacity Factor 12.56 16.57 26.36 37.33 39.15 66.33 47.58 47.85
Variable Cost (MILLS/KWH)
Fuel Cost 35.84 15.53 17.47 12.35 12.35 1.57 0.00 21.43
Variable O&M Costs 0.44 0.69 4.52 3.07 3.07 0.00 0.00 4.51
Pollution Tax Rate 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Variable Cost of Plants 36.28 16.22 21.99 15.42 15.42 1.57 0.00 25.94
Average Cost (MILLS/kWh)
25% Capacity Factor 73.97 65.94 101.07 127.41 132.86 200.54 142.75 169.49
50% Capacity Factor 55.12 41.08 61.53 71.41 74.14 101.06 71.38 97.72
75% Capacity Factor 48.84 32.79 48.35 52.75 54.56 67.89 47.58 73.79
</Table>
77
TABLE G6: GENERATION COMPANY CAPACITY UNDER CONSTRUCTION
PURPOSE: Table G6 provides a listing of the generation plant under construction.
USE: For tracking purposes.
Table G6: Generation Company Capacity under Construction for 1999
Wisconsin Power and Light
Completion
MW Plant Type Date
no plants under construction at this time
78
TABLE G7: GENERATION COMPANY GENERATION COSTS
PURPOSE: Table G7 provides a detailed breakdown of generation plant use and
costs and a comparison with system wide costs.
USE: You can use this table to evaluate your costs against your competitors.
DEFINITIONS:
o CAPACITY FACTOR: fraction of the year the plant is generating.
PRICE OF SPOT MARKET PURCHASES:
o SPOT MARKET BASELOAD POWER: Your average cost of spot market baseload
power.
o SPOT MARKET INTERMEDIATE POWER: Your average cost of spot market
intermediate power.
o SPOT MARKET PEAKING POWER: Your average cost of spot market peaking power
o EMERGENCY POWER: Your average cost of emergency power.
SYSTEM SPOT MARKET PRICES :
o SPOT MARKET BASELOAD POWER: System average cost of spot market baseload
power.
o SPOT MARKET INTERMEDIATE POWER: System average cost of spot market
intermediate power.
o SPOT MARKET PEAKING POWER: System average cost of spot market peaking
power.
o EMERGENCY POWER: System average cost of emergency power.
Note: If a number is too large to fit in the space allocated in a report, then
the number is replaced by a string of *********. This normally occurs on a unit
price or cost when a fixed cost is divided by a very small number of kWhs.
79
Table G7: Generation Company Generation Costs for 1999
Wisconsin Power and Light, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
----- ------ ------ ------ ------ ------
CAPACITY (MW)
Gas/Oil Turbines 255 255 255 654 654 655
Gas/Oil Combined Cycle 0 0 0 700 700 700
Gas/Oil Steam 0 0 0 0 0 0
Coal Steam 1,420 1,759 1,759 4,794 4,794 6,651
Advanced Coal 0 0 0 0 0 0
Nuclear 219 219 219 637 637 803
Hydro 39 39 39 41 41 101
Waste 172 172 172 172 172 172
GENERATION (GWh)
Gas/Oil Turbines 874 0 79 510 408 502
Gas/Oil Combined Cycle 0 0 0 2,743 2,352 2,724
Gas/Oil Steam 0 0 0 0 0 0
Coal Steam 6,971 11,559 11,559 27,846 26,686 25,676
Advanced Coal 0 0 0 0 0 0
Nuclear 1,625 1,631 1,631 4,743 4,743 4,725
Hydro 223 256 256 269 269 269
Waste 110 0 143 317 261 312
CAPACITY FACTOR
Gas/Oil Turbines 39.12 0.00 3.56 8.90 7.12 8.74
Gas/Oil Combined Cycle 0.00 0.00 0.00 44.73 38.35 44.42
Gas/Oil Steam 0.00 0.00 0.00 0.00 0.00 0.00
Coal Steam 56.04 75.00 75.00 66.31 63.55 44.07
Advanced Coal 0.00 0.00 0.00 0.00 0.00 0.00
Nuclear 84.71 85.00 85.00 85.00 85.00 67.18
Hydro 65.28 75.00 75.00 75.00 75.00 30.55
Waste 7.28 0.00 9.50 21.02 17.35 20.73
FUEL AND O&M COSTS (M$)
Gas/Oil Turbines 33 1 4 22 18 21
Gas/Oil Combined Cycle 0 0 0 53 47 53
Gas/Oil Steam 0 0 0 0 0 0
Coal Steam 131 208 208 510 492 508
Advanced Coal 0 0 0 0 0 0
Nuclear 6 6 6 19 19 21
Hydro 0 0 0 0 0 0
Waste 6 3 6 11 10 11
FUEL AND O&M COSTS (Mills/kWh)
Gas/Oil Turbines 37.69********** 51.86 42.51 44.06 42.62
Gas/Oil Combined Cycle 0.00 0.00 0.00 19.29 19.81 19.32
Gas/Oil Steam 0.00 0.00 0.00 0.00 0.00 0.00
Coal Steam 18.85 17.98 17.98 18.32 18.44 19.78
Advanced Coal 0.00 0.00 0.00 0.00 0.00 0.00
Nuclear 3.91 3.90 3.90 3.90 3.90 4.52
Hydro 0.35 0.31 0.31 0.31 0.31 0.75
Waste 51.21********** 45.30 34.69 36.54 34.81
PRICE OF SPOT MARKET PURCHASES (MILLS/KWH)
Baseload Spot Market 0.00 0.00 0.00 0.00 0.00 75.89
Intermediate Spot Market 0.00 0.00 0.00 0.00 0.00 75.89
Peaking Spot Market 0.00 0.00 0.00 0.00 0.00 0.00
Emergency Purchases 0.00 0.00 0.00 0.00 0.00 0.00
SYSTEM-WIDE PRICE OF SPOT MARKET PURCHASE (MILLS/KWH)
Baseload Spot Market 25.00 23.59 22.56 22.68 24.29 30.04
Intermediate Spot Market 50.00 27.81 23.60 28.09 32.31 46.02
Peaking Spot Market 75.00 37.27 37.76 39.70 49.79 92.30
Emergency Purchases 120.00 37.30 40.60 41.88 85.74 120.00
</Table>
80
TABLE G8: GENERATION COMPANY GENERATION BALANCE
PURPOSE: Table G8 provides a summary of the generation company sales to retail
companies and the actual generation and power purchases.
USE: The table shows where the generation company sales are originating and how
the plants are being dispatched.
81
Table G8: Generation Balance (GWh/Yr) for 1999
Wisconsin Power and Light, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
--------- --------- --------- --------- --------- ---------
DIRECT ACCESS SALES
Minnesota Power 0 0 0 0 0 0
Primergy 0 0 0 0 128 128
Otter Tail Power 0 0 53 0 0 100
Wisconsin Power and Light 11,586 0 0 0 0 0
Interstate/IES Utilities 0 0 0 0 0 0
North/South Dakota 0 0 0 0 0 0
Central Illinois Light Co. 0 0 0 1,664 1,664 888
Union Electric 0 0 0 0 81 81
Commonwealth Edison 0 0 0 0 0 0
Illinois Power 0 0 0 0 0 835
American Electric Power 0 0 0 1,378 5 1,104
Cinergy 0 0 81 6,525 8,715 6,516
Iowa Illinois Gas & Electric 0 0 0 0 0 0
Canada 0 0 0 0 0 0
Independent Power Producer 0 0 0 0 0 0
Total 11,586 0 134 9,567 10,594 9,653
SALES TO SPOT MARKET
Block 1 0 0 106 363 527 856
Block 2 0 0 0 3,862 3,300 3,616
Block 3 0 0 0 0 0 0
Block 4 0 11,559 11,559 22,450 20,079 19,786
Block 5 0 0 0 0 0 0
Block 6 0 1,631 1,631 16 16 16
Block 7 0 256 122 35 35 35
Block 8 0 0 116 133 170 247
Block 9 0 0 0 0 0 0
Block 10 0 0 0 0 0 0
Total 0 13,446 13,534 26,860 24,127 24,556
CENTRAL DISPATCH SALES 0 0 0 0 0 0
TOTAL SALES 11,586 13,446 13,668 36,427 34,720 34,209
GENERATION
Gas/Oil Turbines 874 0 79 510 408 502
Gas/Oil Combined Cycle 0 0 0 2,743 2,352 2,724
Gas/Oil Steam 0 0 0 0 0 0
Coal Steam 6,971 11,559 11,559 27,846 26,686 25,676
Advanced Coal 0 0 0 0 0 0
Nuclear 1,625 1,631 1,631 4,743 4,743 4,725
Hydro 223 256 256 269 269 269
Waste 110 0 143 317 261 312
Total 9,802 13,446 13,668 36,427 34,720 34,209
SPOT MARKET PURCHASES
Baseload 0 0 0 0 0 0
Intermediate 0 0 0 0 0 0
Peak 0 0 0 0 0 0
Total 0 0 0 0 0 0
PURCHASES 1,784 0 0 0 0 0
CENTRAL DISPATCH PURCHASES 0 0 0 0 0 0
EMERGENCY 0 0 0 0 0 0
TOTAL GENERATION & PURCHASES 11,586 13,446 13,668 36,427 34,720 34,209
</Table>
82
TABLE G9: SPOT MARKET SALES AND REVENUE
PURPOSE: Table G9 provides information on spot market sales and revenue. The bid
price and the actual price received are recorded as are the sales and capacity
factor.
USE: This table is useful for checking your bidding strategy and determining how
many of your bids were accepted.
DEFINITIONS:
o CAPACITY BID: This is the amount of capacity bid into the spot market. If
capacity is bid into the spot market from more than one region, then the
values are summed before being shown on this table.
o BID PRICE: This is the price at which your capacity is offered to the spot
market. This bid price determines which blocks the spot market will
purchase from.
o SPOT MARKET SALES: The amount of power the spot market purchased from each
block.
o PRICES RECEIVED: The amount paid by the spot market depends on the cost of
the last block dispatched during each hour. This price will generally be
higher than the bid price for each block.
o SPOT MARKET REVENUES: Revenues are equal to spot market sales times the
prices received.
o CAPACITY FACTOR: This is the fraction of the year which the spot market
purchased power from each block.
83
Table G9: Spot Market Sales and Revenue for 1999
Wisconsin Power and Light, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
-------- -------- -------- -------- -------- --------
CAPACITY BID (MW)
Block 1 0 242 242 621 621 621
Block 2 0 0 0 630 630 627
Block 3 0 0 0 0 0 0
Block 4 0 1,320 1,320 3,070 2,952 2,804
Block 5 0 0 0 0 0 0
Block 6 0 186 186 2 2 2
Block 7 0 29 14 4 4 4
Block 8 0 103 103 103 103 103
Block 9 0 0 0 0 0 0
Block 10 0 0 0 0 0 0
Total 0 1,880 1,865 4,430 4,313 4,161
BID PRICE (MILLS/KWH)
Block 1 0.00 36.29 36.29 36.29 36.29 36.29
Block 2 0.00 0.00 0.00 16.22 16.25 16.25
Block 3 0.00 0.00 0.00 0.00 0.00 0.00
Block 4 0.00 15.44 15.43 15.43 15.43 15.43
Block 5 0.00 0.00 0.00 0.00 0.00 0.00
Block 6 0.00 1.57 1.57 1.57 1.59 1.59
Block 7 0.00 0.01 0.00 0.00 0.01 0.01
Block 8 0.00 25.95 25.95 25.95 25.95 25.95
Block 9 0.00 0.00 0.00 0.00 0.00 0.00
Block 10 0.00 0.00 0.00 0.00 0.00 0.00
SPOT MARKET SALES (GWH)
Block 1 0 0 106 363 527 856
Block 2 0 0 0 3,862 3,300 3,616
Block 3 0 0 0 0 0 0
Block 4 0 11,559 11,559 22,450 20,079 19,786
Block 5 0 0 0 0 0 0
Block 6 0 1,631 1,631 16 16 16
Block 7 0 256 122 35 35 35
Block 8 0 0 116 133 170 247
Block 9 0 0 0 0 0 0
Block 10 0 0 0 0 0 0
Total 0 13,446 13,534 26,860 24,127 24,556
PRICES RECEIVED (MILLS/KWH)
Block 1 0.00 0.00 37.49 38.23 42.28 56.32
Block 2 0.00 0.00 0.00 26.43 30.96 40.01
Block 3 0.00 0.00 0.00 0.00 0.00 0.00
Block 4 0.00 21.62 21.96 25.18 27.71 35.65
Block 5 0.00 0.00 0.00 0.00 0.00 0.00
Block 6 0.00 21.62 21.96 22.13 23.59 29.56
Block 7 0.00 21.62 21.96 22.13 23.59 29.56
Block 8 0.00 0.00 36.61 37.51 41.28 54.33
Block 9 0.00 0.00 0.00 0.00 0.00 0.00
Block 10 0.00 0.00 0.00 0.00 0.00 0.00
SPOT MARKET REVENUES (M$)
Block 1 0 0 4 14 22 48
Block 2 0 0 0 102 102 145
Block 3 0 0 0 0 0 0
Block 4 0 250 254 565 556 705
Block 5 0 0 0 0 0 0
Block 6 0 35 36 0 0 0
Block 7 0 6 3 1 1 1
Block 8 0 0 4 5 7 13
Block 9 0 0 0 0 0 0
Block 10 0 0 0 0 0 0
Total 0 291 301 687 689 913
CAPACITY FACTOR (%)
Block 1 0.00 0.00 5.00 6.67 9.68 15.72
Block 2 0.00 0.00 0.00 69.98 59.80 65.80
Block 3 0.00 0.00 0.00 0.00 0.00 0.00
Block 4 0.00 100.00 100.00 83.49 77.64 80.56
Block 5 0.00 0.00 0.00 0.00 0.00 0.00
Block 6 0.00 100.00 100.00 100.00 100.00 100.00
Block 7 0.00 100.00 100.00 100.00 100.00 100.00
Block 8 0.00 0.00 12.87 14.72 18.75 27.33
Block 9 0.00 0.00 0.00 0.00 0.00 0.00
Block 10 0.00 0.00 0.00 0.00 0.00 0.00
</Table>
84
TABLE G10: GENERATION COMPANY PERFORMANCE MEASURES
PURPOSE: Table G10 provides a comparison of company performance among all the
generating companies. Information includes sales, average prices, revenues, net
income, and return on equity.
USE: The generating companies are evaluated based on their ability to optimize
these variables.
DEFINITIONS:
o AVERAGE PRICE: This is the average price received from selling power to
retail energy companies or the spot market.
Table G10: Performance Measures for 1999
Wisconsin Power and Light, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
--------- --------- --------- --------- --------- ---------
SALES (GWh/Year)
Minnesota Power 10,723 13,454 18,703 97,627 95,384 97,567
Primergy 71,063 79,644 66,300 51,170 55,933 59,490
Otter Tail Power 4,924 5,921 8,183 8,207 8,266 8,242
Wisconsin Power and Light 11,586 13,446 13,668 36,427 34,720 34,209
Interstate/IES Utilities 16,714 6,344 13,960 0 0 0
North/South Dakota 4,058 4,434 4,566 4,564 4,726 4,904
Central Illinois Light Co. 6,030 2,850 2,014 1,692 1,977 2,782
Union Electric 56,676 48,775 40,993 0 0 0
Commonwealth Edison 92,338 84,765 86,331 86,788 85,973 85,708
Illinois Power 22,798 17,771 20,804 20,935 21,805 23,144
American Electric Power 139,119 131,827 145,239 160,600 197,135 222,169
Cinergy 53,680 71,484 69,911 45,745 41,312 44,560
Iowa Illinois Gas & Electric 6,433 6,845 9,861 8,810 9,716 10,818
Canada 41,001 45,785 47,805 42,977 42,197 43,165
Independent Power Producer 0 0 0 0 0 0
AVERAGE PRICE (Mills/kWh)
Minnesota Power 26.2 15.9 18.2 20.8 20.7 21.6
Primergy 35.3 22.8 22.7 22.1 21.6 24.8
Otter Tail Power 24.3 27.5 19.4 19.4 19.6 20.6
Wisconsin Power and Light 39.3 29.3 28.4 28.1 28.4 33.9
Interstate/IES Utilities 43.0 45.4 30.9 0.0 0.0 0.0
North/South Dakota 82.5 60.0 52.0 44.8 38.3 36.8
Central Illinois Light Co. 56.2 68.2 76.4 73.3 59.9 55.6
Union Electric 39.7 28.8 29.2 0.0 0.0 0.0
Commonwealth Edison 52.7 18.1 19.2 19.8 21.6 28.7
Illinois Power 58.0 27.5 24.4 22.5 22.1 23.9
American Electric Power 30.1 19.1 19.1 16.5 16.7 16.5
Cinergy 38.0 24.9 24.1 27.5 29.0 35.3
Iowa Illinois Gas & Electric 69.2 46.3 36.3 33.5 30.8 32.0
Canada 25.4 21.2 21.2 19.3 19.2 23.7
Independent Power Producer 0.0 0.0 0.0 0.0 0.0 0.0
</Table>
85
<Table>
TOTAL REVENUE (M$)
Minnesota Power 281.3 214.2 340.4 2,029.6 1,974.6 2,110.8
Primergy 2,509.2 1,819.4 1,504.2 1,132.9 1,208.1 1,477.2
Otter Tail Power 119.5 162.7 158.5 159.6 162.4 170.0
Wisconsin Power and Light 455.7 394.4 388.1 1,025.2 985.0 1,158.2
Interstate/IES Utilities 719.3 288.0 430.9 0.0 0.0 0.0
North/South Dakota 334.9 266.0 237.4 204.7 181.0 180.6
Central Illinois Light Co. 339.2 194.5 153.8 124.1 118.4 154.8
Union Electric 2,249.3 1,403.2 1,197.1 0.0 0.0 0.0
Commonwealth Edison 4,863.1 1,534.7 1,657.6 1,715.1 1,853.9 2,462.7
Illinois Power 1,323.1 488.9 507.1 470.3 482.3 554.1
American Electric Power 4,183.5 2,523.1 2,779.2 2,643.5 3,288.2 3,661.6
Cinergy 2,037.3 1,783.1 1,685.9 1,258.4 1,198.8 1,571.4
Iowa Illinois Gas & Electric 445.5 317.1 358.0 294.8 299.0 346.1
Canada 1,041.8 970.9 1,015.7 827.5 810.3 1,022.4
Independent Power Producer 0.0 0.0 0.0 0.0 0.0 0.0
NET INCOME (M$)
Minnesota Power 27.77 (61.84) (62.20) (112.21) (109.75) 1.58
Primergy 206.38 (265.81) (249.98) (267.85) (241.30) (59.02)
Otter Tail Power 14.31 15.83 (16.02) (17.19) (19.31) (26.36)
Wisconsin Power and Light 30.53 15.73 33.21 65.83 90.21 278.85
Interstate/IES Utilities 34.85 (107.68) (89.00) 136.93 140.83 144.98
North/South Dakota 23.98 12.25 24.95 37.16 53.94 85.42
Central Illinois Light Co. 9.19 (14.37) (7.88) (0.37) 17.11 56.36
Union Electric 263.40 (108.36) (125.32) 202.62 207.69 211.78
Commonwealth Edison 238.35 (1,027.21 (925.38) (881.39) (831.06) (410.87)
Illinois Power 127.48 (288.21 (274.20) (245.88) (197.83) (115.60)
American Electric Power 288.46 (480.92) (478.24) (812.62) (970.08) (1,299.42)
Cinergy 105.82 (102.51) (104.44) (63.23) 16.10 301.67
Iowa Illinois Gas & Electric 31.71 (17.72) (6.88) (18.17) 7.35 60.15
Canada 54.16 40.42 90.84 51.60 70.61 220.80
Independent Power Producer 0.00 0.00 0.00 0.00 0.00 (0.85)
RETURN ON EQUITY
Minnesota Power 0.094 (0.138) (0.114) (0.063) (0.066) 0.001
Primergy 0.119 (0.158) (0.175) (0.233) (0.268) (0.071)
Otter Tail Power 0.197 0.129 (0.154) (0.202) (0.302) (0.433)
Wisconsin Power and Light 0.137 0.059 0.119 0.055 0.073 0.210
Interstate/IES Utilities 0.105 (0.204) (0.125) 0.104 0.103 0.102
North/South Dakota 0.131 0.057 0.111 0.157 0.212 0.301
Central Illinois Light Co. 0.069 (0.116) (0.069) (0.003) 0.146 0.414
Union Electric 0.152 (0.062) (0.077) 0.101 0.100 0.099
Commonwealth Edison 0.060 (0.299) (0.315) (0.397) (0.534) (0.374)
Illinois Power 0.114 (0.312) (0.383) (0.472) (0.584) (0.577)
American Electric Power 0.139 (0.247) (0.332) (0.929) (2.878) (99.000)
Cinergy 0.075 (0.076) (0.085) (0.055) 0.014 0.244
Iowa Illinois Gas & Electric 0.108 (0.047) (0.014) (0.040) 0.016 0.126
Canada 0.082 0.060 0.129 0.072 0.095 0.270
Independent Power Producer 0.000 0.000 0.000 0.000 0.000 (0.038)
</Table>
86
TABLE G11: REGION CAPACITY REQUIREMENT STATEMENT (MW)
PURPOSE: This table shows generation capacity by fuel type including additions
and retirements and regional peak demand with and without reserves. It also
contains a system reserve margin.
USE: Table G11 is used for planning purposes to indicate how "tight" the
capacity is getting in a region.
IMPORTANT DEFINITIONS:
ESTIMATED RESERVES: calculated at 20% default specification
SYSTEM RESERVE MARGIN: Capacity Margin divided by Generation Capacity
Table G11: Region Capacity Requirement Statement (MW) for 1999, DARW
<Table>
<Caption>
1999 2000 2001 2002 2005
-------- -------- -------- -------- --------
Region Peak Demand 102,190 107,741 110,712 113,808 123,935
Estimated Reserves 25,548 26,935 27,678 28,452 30,984
Peak w/ Reserves 127,738 134,676 138,390 142,260 154,918
Region Capacity:
Gas/Oil Turbines 6,984 6,984 6,984 6,984 6,984
Gas/Oil Combined Cycle 2,800 4,100 4,100 4,100 4,100
Gas/Oil Steam 3,789 3,789 3,781 3,745 3,650
Coal Steam 82,893 82,893 82,746 82,746 82,746
Advanced Coal 0 0 0 0 0
Nuclear 20,565 20,565 20,565 20,565 20,565
Hydro 7,487 7,487 7,487 7,487 7,487
Waste 472 472 472 472 472
Retirements:
Gas/Oil Turbines 0 0 0 0 0
Gas/Oil Combined Cycle 0 0 0 0 0
Gas/Oil Steam 0 8 36 0 0
Coal Steam 0 147 0 0 0
Advanced Coal 0 0 0 0 0
Nuclear 0 0 0 0 0
Hydro 0 0 0 0 0
Waste 0 0 0 0 0
Capacity under Construction:
Gas/Oil Turbines 0 0 0 0 0
Gas/Oil Combined Cycle 1,300 0 0 0 0
Gas/Oil Steam 0 0 0 0 0
Coal Steam 0 0 0 0 0
Advanced Coal 0 0 0 0 0
Nuclear 0 0 0 0 0
Hydro 0 0 0 0 0
Waste 0 0 0 0 0
Total Region Capacity 126,290 126,135 126,099 126,099 126,004
Capacity Surplus 0 0 0 0 0
Capacity Deficit 1,448 8,541 12,291 16,161 28,914
SYSTEM RESERVE MARGIN (%) 22.31 17.22 13.93 10.80 1.67
</Table>
87
TABLE G12: REGIONAL GENERATION BALANCE
PURPOSE: Table G12 is a sales and generation balance sheet. Sales are divided
into direct access by company, spot market by company and central dispatch
sales, if any. Generation is by fuel type. Outside spot market purchases are
also included.
USE: A summary sheet comparing sales and generation.
88
Table G12: Regional Generation Balance (GWh/Yr) for 1999, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
------- ------- ------- ------- ------- -------
DIRECT ACCESS SALES
Minnesota Power 10,723 3,423 1,856 2,014 3,184 2,977
Primergy 71,063 5,444 6,504 43,852 60,252 58,690
Otter Tail Power 4,924 41 1,283 1,264 1,361 4,966
Wisconsin Power and Light 11,586 0 0 0 0 0
Interstate/IES Utilities 16,714 1,866 5,829 13,232 16,716 17,338
North/South Dakota 4,058 5,101 1,786 2,444 4,477 11,902
Central Illinois Light Co. 6,030 1,037 1,821 3,786 5,680 7,532
Union Electric 56,676 16,995 34,569 44,996 50,705 54,150
Commonwealth Edison 92,338 0 0 0 0 0
Illinois Power 22,798 1,790 5,281 15,547 18,809 19,004
American Electric Power 139,119 140,280 142,803 146,524 148,827 144,085
Cinergy 53,680 7,225 14,080 25,938 48,018 56,534
Iowa Illinois Gas & Electric 6,433 701 2,360 3,579 5,491 5,694
Canada 41,001 0 0 0 0 0
Independent Power Producer 0 0 0 0 0 0
Total 537,143 183,904 218,172 303,177 363,521 382,872
SALES TO SPOT MARKET
Minnesota Power 0 7,121 11,716 48,427 45,785 46,717
Primergy 0 44,611 33,945 18,815 17,331 20,888
Otter Tail Power 0 807 848 873 898 949
Wisconsin Power and Light 0 13,446 13,534 26,860 24,127 24,556
Interstate/IES Utilities 0 2,159 2,614 0 0 0
North/South Dakota 0 3,960 4,041 4,119 4,140 4,243
Central Illinois Light Co. 0 2,825 1,904 1,604 1,808 2,407
Union Electric 0 47,458 22,886 0 0 0
Commonwealth Edison 0 81,656 76,717 70,108 57,038 63,927
Illinois Power 0 3,044 1,829 2,108 2,611 3,789
American Electric Power 0 31,915 53,890 14,451 11,867 12,233
Cinergy 0 71,484 69,911 45,745 41,312 44,389
Iowa Illinois Gas & Electric 0 3,700 6,456 4,485 4,671 4,725
Canada 0 35,255 29,875 24,771 24,035 25,063
Independent Power Producer 0 0 0 0 0 0
Total 0 349,440 330,166 262,365 235,623 253,886
CENTRAL DISPATCH SALES 0 0 0 0 0 0
TOTAL SALES 537,143 533,344 548,338 565,542 599,144 636,759
GENERATION
Gas/Oil Turbines 2,835 1,026 2,523 2,692 2,742 3,152
Gas/Oil Combined Cycle 0 0 20,692 15,603 15,758 15,788
Gas/Oil Steam 2,270 2,333 2,441 3,031 3,411 4,569
Coal Steam 303,505 345,769 334,127 354,951 375,455 391,089
Advanced Coal 0 0 0 0 0 0
Nuclear 115,354 139,144 138,735 138,131 135,514 134,755
Hydro 33,742 42,285 46,270 47,523 47,478 47,418
Waste 447 484 252 679 563 552
Total 458,154 531,041 545,039 562,609 580,923 597,324
SPOT MARKET PURCHASES
Baseload 0 2,303 3,262 2,933 18,221 39,434
Intermediate 0 0 0 0 0 0
Peak 0 0 0 0 0 0
Total 0 2,303 3,262 2,933 18,221 39,435
PURCHASES 77,500 0 0 0 0 0
CENTRAL DISPATCH PURCHASES 0 0 0 0 0 0
EMERGENCY 1,488 0 37 0 0 0
TOTAL GENERATION & PURCHASES 537,143 533,344 548,338 565,542 599,144 636,759
</Table>
89
TABLE G13: REGIONAL CAPACITY MARGINS
PURPOSE: Table G13 contains regional and system wide capacity margins.
USE: This table is useful when determining where to build new plants
DEFINITIONS:
o CAPACITY MARGIN: Generation Capacity minus Retail Company Peak
o SYSTEM RESERVE MARGIN AND REGIONAL RESERVE MARGIN: Capacity Margin divided
by Peak Load.
o EFFECTIVE SYSTEM AND REGION RESERVE MARGINS: The effective capacity margin
is the total generating capacity derated based on forced and unforced
outages less the peak load then divided by the peak load. This includes
plant outages
90
Table G13: Regional Capacity Margins (mW/Yr) for 1999, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
-------- -------- -------- -------- -------- --------
RETAIL COMPANY PEAK
Minnesota Power 1,338 1,424 1,561 1,727 1,915 2,113
Primergy 10,880 9,254 9,493 9,766 10,091 10,453
Otter Tail Power 580 614 666 730 803 866
Wisconsin Power and Light 2,002 2,000 2,047 2,124 2,223 2,313
Interstate/IES Utilities 2,705 2,724 2,768 2,831 2,939 3,081
North/South Dakota 600 745 970 1,226 1,478 1,695
Central Illinois Light Co. 1,137 1,137 1,182 1,262 1,385 1,561
Union Electric 8,875 8,862 9,001 9,186 9,345 9,413
Commonwealth Edison 17,928 17,923 18,326 18,833 19,312 19,589
Illinois Power 3,395 3,394 3,460 3,549 3,661 3,768
American Electric Power 26,268 26,483 27,025 27,750 28,481 29,175
Cinergy 9,195 9,275 9,477 9,719 9,938 10,160
Iowa Illinois Gas & Electric 1,034 1,043 1,060 1,088 1,136 1,208
Canada 6,334 6,461 6,590 6,719 6,801 6,795
Independent Power Producer 0 0 0 0 0 0
TOTAL 92,271 91,340 93,627 96,510 99,508 102,190
GENERATION CAPACITY
Minnesota Power 1,197 2,048 2,748 16,692 16,692 21,662
Primergy 13,271 15,516 15,516 15,516 15,516 20,136
Otter Tail Power 573 971 971 971 971 1,260
Wisconsin Power and Light 2,105 2,444 2,444 6,998 6,998 9,081
Interstate/IES Utilities 2,922 3,853 4,553 0 0 0
North/South Dakota 721 896 896 896 896 1,163
Central Illinois Light Co. 1,257 1,324 1,324 1,324 1,324 1,719
Union Electric 11,715 13,944 13,944 0 0 0
Commonwealth Edison 24,396 25,113 25,813 25,813 25,813 33,498
Illinois Power 5,164 5,762 5,762 5,762 5,762 7,478
American Electric Power 23,383 28,677 28,677 28,677 28,677 0
Cinergy 11,611 12,248 12,248 12,248 12,248 15,895
Iowa Illinois Gas & Electric 1,549 1,701 2,401 2,401 2,401 3,116
Canada 7,581 7,691 7,691 7,691 7,691 9,981
Independent Power Producer 0 0 0 0 0 0
TOTAL 107,445 122,190 124,990 124,990 124,990 124,990
CAPACITY MARGIN 15,174 30,850 31,363 28,480 25,482 22,800
SYSTEM RESERVE MARGIN (%) 16.45 33.78 33.50 29.51 25.61 22.31
EFFECTIVE SYSTEM RESERVE MARGIN (%) (10.38) 2.64 2.82 (0.22) (3.22) (5.66)
SYSTEM PEAK
MAPP Canada 6,334 6,414 6,473 6,539 6,580 6,578
MAPP US 12,830 11,958 12,407 12,922 13,531 14,142
MAIN 37,644 37,153 38,106 39,359 40,683 41,797
ECAR 35,463 35,815 36,641 37,690 38,715 39,673
TOTAL 92,271 91,340 93,627 96,510 99,508 102,190
REGIONAL CAPACITY
MAPP Canada 7,581 7,691 7,691 7,691 7,691 7,691
MAPP US 16,689 20,680 20,680 20,680 20,680 20,680
MAIN 48,181 52,894 52,894 52,894 52,894 52,894
ECAR 34,994 40,925 43,725 43,725 43,725 43,725
TOTAL 107,445 122,190 124,990 124,990 124,990 124,990
REGIONAL RESERVE MARGIN (%)
MAPP Canada 19.69 19.91 18.81 17.63 16.89 16.93
MAPP US 30.08 72.94 66.68 60.03 52.83 46.23
MAIN 27.99 42.37 38.81 34.39 30.01 26.55
ECAR (1.32) 14.27 19.33 16.01 12.94 10.21
EFFECTIVE REGIONAL RESERVE MARGIN (%)
MAPP Canada (9.69) (9.53) (10.36) (11.25 (11.81) (11.78)
MAPP US 2.07 34.54 29.67 24.83 19.21 14.06
MAIN (0.41) 10.42 7.66 4.20 0.81 (1.88)
ECAR (25.59) (13.90) (8.97) (11.50) (13.84) (15.65)
</Table>
91
TABLE G14: UNIT COST SUMMARY
PURPOSE: Table G14 provides a break down of unit costs: operating expenses, fuel
costs, O&M costs, purchase costs and other costs by company.
USE: This table is useful for evaluating your competitor's costs as well as
determining the competitiveness of your own costs.
92
Table G14: Unit Cost Summary (Mills/kWh) for 1999, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
------- ------- ------- ------- ------- -------
OPERATING EXPENSES
Minnesota Power 40.65 19.35 20.03 20.30 19.74 19.56
Primergy 38.23 25.30 25.21 25.50 23.94 23.74
Otter Tail Power 36.25 23.53 20.54 20.61 20.93 22.64
Wisconsin Power and Light 42.49 27.23 25.25 24.81 23.12 23.42
Interstate/IES Utilities 56.00 55.26 33.96 0.00 0.00 0.00
North/South Dakota 100.29 56.44 45.55 35.61 25.79 18.41
Central Illinois Light Co. 56.22 70.10 75.87 68.56 47.50 33.39
Union Electric 42.09 28.56 29.44 0.00 0.00 0.00
Commonwealth Edison 46.76 24.95 24.66 24.61 25.80 28.01
Illinois Power 55.56 38.63 32.99 29.47 26.46 24.31
American Electric Power 33.55 21.47 21.14 20.27 20.50 21.28
Cinergy 36.35 24.45 23.59 25.71 25.16 25.51
Iowa Illinois Gas & Electric 72.01 47.30 35.17 32.51 27.34 24.27
Canada 16.46 13.13 12.73 11.03 10.68 12.17
Independent Power Producer 0.00 0.00 0.00 0.00 0.00 0.00
FUEL COSTS
Minnesota Power 11.18 11.84 12.88 11.15 11.10 11.14
Primergy 10.08 10.73 9.94 8.93 9.45 9.69
Otter Tail Power 11.60 11.63 11.79 11.88 11.98 12.16
Wisconsin Power and Light 12.48 10.81 11.07 11.50 11.34 11.45
Interstate/IES Utilities 13.11 12.42 14.03 0.00 0.00 0.00
North/South Dakota 11.48 10.81 11.24 11.49 11.71 12.16
Central Illinois Light Co. 17.32 18.34 19.43 20.61 19.74 18.46
Union Electric 11.90 12.00 11.06 0.00 0.00 0.00
Commonwealth Edison 11.07 4.89 4.76 4.85 5.53 6.12
Illinois Power 13.32 12.89 13.68 13.70 13.93 14.13
American Electric Power 14.16 13.32 13.54 13.71 13.90 13.93
Cinergy 14.21 13.83 14.31 14.33 14.27 14.31
Iowa Illinois Gas & Electric 10.04 8.57 10.98 10.78 11.18 11.41
Canada 2.95 3.39 2.94 1.96 1.83 2.02
Independent Power Producer 0.00 0.00 0.00 0.00 0.00 0.00
O&M COSTS
Minnesota Power 4.36 4.09 3.59 3.97 4.01 3.97
Primergy 7.62 7.36 7.93 8.95 8.55 8.30
Otter Tail Power 4.79 4.70 4.42 4.40 4.38 4.35
Wisconsin Power and Light 5.51 5.43 5.39 5.36 5.50 5.51
Interstate/IES Utilities 6.68 12.50 6.93 0.00 0.00 0.00
North/South Dakota 5.59 5.43 5.30 5.28 5.16 5.02
Central Illinois Light Co. 4.56 7.24 9.37 10.73 9.48 7.36
Union Electric 6.42 6.96 7.63 0.00 0.00 0.00
Commonwealth Edison 12.95 11.86 11.51 11.48 11.78 11.98
Illinois Power 7.24 8.38 7.69 7.67 7.50 7.27
American Electric Power 5.89 5.85 5.56 5.30 5.02 4.97
Cinergy 4.13 3.59 3.60 4.49 4.77 4.56
Iowa Illinois Gas & Electric 13.56 11.84 8.45 8.94 8.27 7.82
Canada 4.88 4.92 4.56 4.19 4.13 4.23
Independent Power Producer 0.00 0.00 0.00 0.00 0.00 0.00
</Table>
93
<Table>
PURCHASE COSTS
Minnesota Power 19.97 0.00 0.00 0.00 41.14 0.00
Primergy 25.15 0.00 0.00 0.00 0.00 0.00
Otter Tail Power 14.95 26.92 21.96 22.13 23.59 31.21
Wisconsin Power and Light 21.33 0.00 0.00 0.00 0.00 3.92
Interstate/IES Utilities 26.03 37.13 0.00 0.00 0.00 0.00
North/South Dakota 24.70 0.00 0.00 41.22 48.51 79.16
Central Illinois Light Co. 26.60 37.13 39.65 40.92 48.07 0.00
Union Electric 18.69 30.34 28.88 0.00 0.00 0.00
Commonwealth Edison 42.07 0.00 0.00 0.00 0.00 0.00
Illinois Power 16.74 37.28 0.00 0.00 0.00 0.00
American Electric Power 31.34 35.63 33.13 34.82 27.68 31.75
Cinergy 19.24 0.00 0.00 0.00 0.00 0.00
Iowa Illinois Gas & Electric 16.75 26.86 29.62 0.00 0.00 0.00
Canada 16.94 0.00 0.00 0.00 0.00 0.00
Independent Power Producer 0.00 0.00 0.00 0.00 0.00 0.00
OTHER COSTS
Minnesota Power 10.82 3.41 3.56 5.18 4.63 4.45
Primergy 15.52 7.20 7.34 7.62 5.94 5.75
Otter Tail Power 8.82 5.97 2.75 2.73 2.58 2.20
Wisconsin Power and Light 20.62 11.00 8.79 7.95 6.27 6.46
Interstate/IES Utilities 25.43 30.35 13.00 0.00 0.00 0.00
North/South Dakota 75.97 40.20 29.01 18.84 8.92 1.23
Central Illinois Light Co. 32.67 44.52 47.05 37.19 18.25 7.56
Union Electric 18.90 9.59 10.68 0.00 0.00 0.00
Commonwealth Edison 20.95 8.20 8.39 8.28 8.49 9.91
Illinois Power 32.33 17.35 11.61 8.11 5.03 2.91
American Electric Power 5.52 2.10 1.96 1.19 0.87 0.23
Cinergy 16.73 7.03 5.69 6.89 6.12 6.64
Iowa Illinois Gas & Electric 46.03 26.90 15.75 12.79 7.90 5.04
Canada 8.39 4.82 5.23 4.88 4.72 5.93
Independent Power Producer 0.00 0.00 0.00 0.00 0.00 0.00
</Table>
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TABLE G15: TRANSMISSION CONSTRAINTS
PURPOSE: Table G15 charts the flow of electricity across critical transmission
lines. Calculated are transmission flows and generation constrained off or on.
USE: This is the summary for transmission constraints and it is used to check
for unexplained sales changes.
IMPORTANT DEFINITIONS:
GENERATION CONSTRAINED OFF: Generation forced off-line due to transmission
constraints
GENERATION CONSTRAINED ON: Generation forced on-line because transmission
constraints prohibited transmission of power from outside the region.
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Table G15: Transmission Constraints (MW) for 1999, DARW
<Table>
<Caption>
1994 1995 1996 1997 1998 1999
-------- -------- -------- -------- -------- --------
Demand at Peak Hour
MAPP Canada 6,334 6,414 6,473 6,539 6,580 6,578
MAPP US 12,830 11,958 12,407 12,922 13,531 14,142
MAIN 37,644 37,153 38,106 39,359 40,683 41,797
ECAR 35,463 35,815 36,641 37,690 38,715 39,673
Generation at Peak Hour
MAPP Canada 6,142 5,803 5,803 5,803 5,803 6,214
MAPP US 12,568 14,019 14,527 15,108 15,758 15,955
MAIN 35,681 38,551 39,345 41,100 43,676 42,868
ECAR 33,834 33,151 34,160 34,670 34,364 37,236
Flows Out of the Region
MAPP Canada 0 0 0 0 0 0
MAPP US 0 2,061 2,121 2,186 2,227 1,813
MAIN 0 1,398 1,239 1,741 2,993 1,071
ECAR 0 0 0 0 0 0
Flows Into the Region
MAPP Canada 192 611 671 736 777 363
MAPP US 262 0 0 0 0 0
MAIN 1,964 0 0 0 0 0
ECAR 1,629 2,664 2,481 3,021 4,351 2,438
Unconstrained Generation
MAPP Canada 6,142 5,803 5,803 5,803 5,803 6,145
MAPP US 12,568 15,544 14,640 15,649 16,435 16,489
MAIN 35,681 37,027 39,345 40,574 42,999 42,868
ECAR 33,834 33,151 34,047 34,655 34,364 36,771
Generation Constrained Off
MAPP Canada 0 0 0 0 0 0
MAPP US 0 1,525 113 541 677 534
MAIN 0 0 0 0 0 0
ECAR 0 0 0 0 0 0
Generation Constrained On
MAPP Canada 0 0 0 0 0 69
MAPP US 0 0 0 0 0 0
MAIN 0 1,525 0 526 677 0
ECAR 0 0 113 14 0 465
Nameplate Generating Capacity
MAPP Canada 7,581 7,691 7,691 7,691 7,691 7,691
MAPP US 16,689 20,680 20,680 20,680 20,680 20,680
MAIN 48,181 52,894 52,894 52,894 52,894 52,894
ECAR 34,994 40,925 43,725 43,725 43,725 43,725
Nameplate Transmission Line Capacity
MAPP Canada to US 1,520 1,520 1,520 1,520 1,520 1,520
MAPP to MAIN 1,450 1,450 1,450 1,450 1,450 1,450
MAIN to ECAR 5,200 5,200 5,200 5,200 5,200 5,200
Transmission Flows (Eastbound)
MAPP Canada to US 0 0 0 0 0 0
MAPP to MAIN 0 1,450 1,450 1,450 1,450 1,450
MAIN to ECAR 1,629 2,664 2,481 3,021 4,351 2,438
Transmission Flows (Westbound)
MAPP Canada to US 192 611 671 736 777 363
MAPP to MAIN 454 0 0 0 0 0
MAIN to ECAR 0 0 0 0 0 0
Transmission Capacity Available (Eastbound)
MAPP Canada to US 1,712 2,131 2,191 2,256 2,297 1,883
MAPP to MAIN 1,904 0 0 0 0 0
MAIN to ECAR 3,571 2,536 2,719 2,179 849 2,763
Transmission Capacity Available (Westbound)
MAPP Canada to US 1,328 909 849 784 743 1,157
MAPP to MAIN 996 2,900 2,900 2,900 2,900 2,900
MAIN to ECAR 6,829 7,864 7,681 8,221 9,551 7,638
</Table>
96