Exhibit 99.243
Introduction to the New California Power Market
[POWER MARKET LOGO]
INTRODUCTION TO THE NEW CALIFORNIA POWER MARKET
BY
ISSAC MOORE, PACIFIC GAS AND ELECTRIC AND JOHN H. ANDERSON, NORDPOOL ASA
PLEASE SEND ANY COMMENTS TO: ISSAC MOORE, PACIFIC GAS AND ELECTRIC
EMAIL: IWM2@PGE.COM
As of January 1, 1998, a new competitive Power Market will be in operation in California. The present California Power Market consists of primarily utility owned generation, transmission and distribution which is used to meet each utility’s demand. In addition, these utilities participate in short-and long-term bilateral contracts to meet short-term changes in demand, and demand growth, respectively. In California there are three (3) major control areas operated by the three (3) investor-owned utilities. Each utility is responsible for matching load and resources within its control area to maintain frequency, and match scheduled and actual flows at the tie points. This paper provides an overview of participants, structure and functions of the New Market. Unlike other commodity markets electricity cannot be stored. At any time there must be a balance between generation and consumption. The dynamics of a competitive power market are influenced by technical matters such as real time operation of the transmission grid and the power system. The primary objectives of the new market are to promote vigorous competition in generation supply, to implement direct access for customers, to create an Independent System Operator, to create a new spot market called the Power Exchange and provide customer choice through tariff rates, spot market rates, bilateral contracts, and contracts for differences. Given the new market structure all users will pay for grid support services and share in the benefits of competition. Because the Power Exchange will premier market based pricing of power in California, special emphasis will be given herein to this new spot market.
[CHART]
Figure 1 — The New California Market Structure
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There are a number of participants that make up the new market structure: Generators, Power Exchange (Spot Market) , Scheduling Coordinators (Bilateral Transactions), Independent System Operator (Grid Dispatch and transmission access), Utility Distribution Companies (UDC’s), Retail Marketers (Energy Service Provider), and Customers (load). All of these entities will have specific roles in the New Power Market.
INDEPENDENT SYSTEM OPERATOR
The ISO controls the dispatch of generation, manages the reliability of the transmission grid, provides open access to the transmission, buys and provides ancillary services as required, coordinates day-ahead, hour-ahead schedules and performs real time balancing of load and generation, settles real time imbalances and ancillary services sales and purchases. The ISO, also, administers congestion management protocols for the transmission grid.
The ISO will serve as the control area operator for most of California. As the control area operator, the ISO must match the power output of the Generating Units within the electric power system, plus the energy purchased from entities outside the electric power system minus energy sold to entities outside the electric power system, with the demand within the electric power system under its control; maintain scheduled interchange with other Control Areas; maintain the frequency of the electric power system and provide sufficient generation.
UTILITY DISTRIBUTION COMPANIES (UDC’S)
UDC’s provide distribution service to all customers within their service territory, meter energy delivered and bills for energy and use of transmission, distribution, Competitive Transition Charges, offer bundled energy tariffs to their customers, buy bulk power from the PX for their customers, and offer optional meter reading and usage measurement services to other market participants.
SCHEDULING COORDINATORS
SC’s submit balanced schedules and provide settlement ready meter data to the ISO. SC’s settle with generators and retailers, the PX and the ISO; maintain year round twenty-four hour scheduling center and provides some operating instructions to generators and retailers, transfer schedules in and out of the PX.
RETAILERS (ENERGY SERVICE PROVIDER)
Retailers buy power for, and market power to retail customers and serve as demand aggregators for retail loads; retailers, also, bill retail customers for energy and contracted services, schedules load and generation through a Scheduling Coordinator or PX, and pays SC and/or generators for energy and ancillary services.
GENERATORS
Generators may bid power into the PX or schedule power through a Scheduling Coordinator; generators may also bid ancillary services into the ISO or self-provide through a Scheduling Coordinator; they may have contracts with retailers and will respond to ISO and Scheduling Coordinator instructions. The generators provide transmission losses to transmission and distribution boundaries and submit bills to retailers and/or scheduling coordinator for energy and ancillary services provided.
CUSTOMERS
All customers may choose direct access via a local utility retailer, power marketers, or generators. Customers may choose to remain a single customer or become part of an aggregated load under utility tariff rates, spot market rates, bilateral contract or contract for differences from the local utility retailer, power marketers or generators.
POWER EXCHANGE
California Power Exchange is a non profit corporation for the primary purpose of providing an efficient, competitive energy auction open on a non-discriminatory basis to all suppliers and spot market purchases, that meets the loads of exchange customers at market prices. The competitive trading of power in the forward (Day Ahead, Hour Ahead) markets will be managed by the California Power Exchange (PX). “Bilateral and Contract for Differences” markets will be independent of the Forward Markets. The PX is a Scheduling Coordinator and
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submits balanced schedules to the ISO for all its participants. All other services used to maintain a secure and aggregated reliable power supply are traded in markets managed by the Independent System Operator (ISO).
The PX will accept demand and generation bids from its participants and determine the Market Clearing Price (MCP) at which energy is bought and sold.
Balanced demand and supply schedules for the successful bidders are then submitted to the ISO. Along with these schedules, are adjustment bids submitted to the ISO which selects decremental/incremental bids to relieve or eliminate congestion on the transmission grid. In addition to managing the forward markets, the PX performs settlement functions with the ISO, PX participants (including UDC’s), and other Scheduling Coordinators; it reports usage to the ISO for settlements and provides some operating instruction to generators and retailers.
DAY AHEAD MARKET
To participate in the PX market, a prospective participant must meet a number of eligibility requirements including credit worthiness, identifying metered entities it serves, etc. Once certified a participant may trade in the 24 hourly power markets for next day delivery. For each trade there is a mutual obligation for payment between the PX and its market participants. Day Ahead Market Settlements are based on schedules and are made subsequent to the close of the Day Ahead Market.
Trading procedures in the Day Ahead Market are as follows: From all supply/demand bids submitted to the PX from participants, an MCP is determined for each hour of the 24 hour scheduling day. The PX validates bids and constructs aggregate supply/demand curves to determine the MCP and publishes the resulting schedules. The PX must, also, determine if bids submitted result in a potential overgeneration condition. If a potential overgeneration condition occurs, the PX must inform the ISO. If the overgeneration condition is not eliminated during subsequent bidding iterations, then the ISO will implement its overgeneration protocol to eliminate the overgeneration condition. The process of participants submitting different bids based on bidding activity rules and the PX determining a new MCP for each round of bidding is called bid iteration. Bid iterations are conducted to establish the optimum MCP and demand/supply schedules. Bids submitted into the Day Ahead Market auction need not be attributed to any particular unit or physical scheduling plant. Such a bid is referred to as a portfolio bid. To make it possible to validate portfolio bids that are accepted into the Day Ahead Market, participants must submit physical schedules of individual generating units.
HOUR AHEAD MARKET
In the Hour Ahead Market bids are submitted to the PX at least 2 hours before the hour of operation. There are no iterations or portfolio bids accepted in the Hour Ahead Market.
The main objectives of this market are to give participants final opportunities to optimize their schedules and reduce the real time imbalance. MCP is determined the same as the Day Ahead Market. The PX communicates price and traded quantities to PX participants immediately after the Hour Ahead Market is closed.
The participants who have traded in the Hour Ahead Market provide adjusted schedules to the PX and ISO.
DETERMINATION OF MARKET CLEARING PRICE (MCP)
The participants supply bids are added into one supply curve and all demand bids into one demand curve.
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| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Aggregated Demand Bid |
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| $/MWh | | | | | | | 0 | | | | 10 | | | | 11 | | | | 20 | | | | 30 | |
| MW | | | | | | | 1200 | | | | 1200 | | | | 800 | | | | 800 | | | | 400 | |
[GRAPH]
Figure 2 — Aggregated Bid Demand Curve
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Aggregated Supply Bid |
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| $/MWh | | | | | | | 40 | | | | 35 | | | | 22 | | | | 20 | | | | 15 | |
| MW | | | | | | | 1100 | | | | 1000 | | | | 800 | | | | 500 | | | | 250 | |
[GRAPH]
Figure 3 — Aggregated Bid Supply Curve
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[GRAPH]
Figure 4 — Market Clearing Price
The MCP is set at the intersection point between demand and supply curves. After the first price determination, participants are able to take part in submitting additional bids (i.e. bid iterations) to ensure a convergence towards optimal schedules and price for the participants. The iterations process terminates and the market is closed when no revised bids are received or when the PX’s convergence criteria is met.
INITIAL PREFERRED SCHEDULES
Once the MCP is determined the participants submit the following to the PX:
| 1. | | Individual schedules by generating unit, take out point for demand. |
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| 2. | | Adjustment bids for congestion management. |
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| 3. | | Ancillary service bids. |
The location of the participants’ individual generating units connection to the grid is known to the PX and the ISO. All information must be attributed to individual generating units or Physical Scheduling Plant. This applies to unit schedules, adjustment bids for congestion management and ancillary service bids.
A Physical Scheduling Plant is by definition a group of related generating units which by physical operational design must be operated as if they were a single generating unit.
A schedule may comprise imports, exports, transfers or generation. A participant’s schedule is balanced when trades on the PX markets are concluded. See Figure 5. Generator’s schedules are adjusted to compensate for transmission losses. The real losses are not known before all metered data are processed. Losses are equal to (1-GMM) *G where G is generated power in MW and can be positive, zero or negative. The Generator Meter Multipliers (GMM) are published for each generator location and scheduling point by the ISO prior to the bidding in the Day Ahead Market.
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Figure 5 — Balancing Resources and Commitments
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RESOURCES VERSUS COMMITMENTS
MANAGEMENT OF INTER-ZONAL CONGESTION
If the ISO determines from submitted schedules that the power flow across a transmission path connecting adjacent zones exceeds maximum transmission capacity, then inter-zonal congestion exists. Under the condition of inter-zonal congestion submitted schedules have to be changed to reduce the power flow across the congested path using adjustment (incremental, decremental) bids submitted to the ISO for the zone on each side of the congestion.
In a situation where congestion between two zones occurs, supply is greater than demand in the “surplus” zone and demand greater than supply in the “deficit” zone.
[BAR CHART]
Figure 6 — Zonal Pricing
INTERZONAL CONGESTION
There are adjustment bids both for supply and demand and each bid comprises price and power quantities. In the surplus zone, supply has to be reduced or demand increased; and in the deficit zone supply has be increased or demand decreased. (See Figure 5.)
CONGESTION
If the scheduled power flow across zones does not exceed the transmission capacity as determined by the ISO, the MCP is only priced in the Day Ahead Market for the total ISO area. If the scheduled power flow across zonal boundaries (a zone is an area where congestion is expected to be small) exceeds the transmission capability between zones, then different zonal prices are determined to allow market prices (i.e. trades) to relieve congestion.
The procedure to eliminate congestion is determined by the ISO and can be explained, in the simplest case, as follows:
| 1. | | A price merit order is set up based on the adjustment bids. |
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| 2. | | The bids representing the lowest price for adjustment to increase supply or reduce demand in the “deficit” zone will be called upon to change their schedules. |
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| 3. | | The bids representing the highest price for adjustment to reduce supply or increase demand in the “surplus” zone will be called upon to change their schedules. |
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| 4. | | The last generating unit called upon defines the zonal prices in the two zones. |
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The zonal prices replace MCP and applies to all energy traded in the Day Ahead market. The participants who are called upon to relieve congestion provide adjusted guidelines to the PX, and ISO. After inter-zonal congestion is alleviated, inter-zonal congestion is then evaluated.
INTRA-ZONAL CONGESTION
When intra-zonal congestion (i.e. congestion within a zone) occurs, it is managed by the ISO utilizing adjustment bids. The procedure for relieving intra-zonal congestion in the ISO is as follows:
| 1. | | Within each zone adjustment bids will be arranged in merit order with less expensive resources first to be incremented when generator must be increased and more expensive resources will be the first to be decremented when generators must be decreased. |
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| 2. | | Changes in schedules to eliminate intra-zonal congestion will not create or increase inter-zonal congestion. |
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| 3. | | Net amounts paid by the ISO to the Scheduling Coordinator for use of adjustment bids and amounts charged to Schedule Coordinate are calculated on a zone-by-zone basis through a Grid Operations Charge. |
THE ANCILLARY SERVICES MARKET
The purpose of the Ancillary Services Market is to maintain the reliability to the transmission grid controlled by the ISO.
[GRAPH]
Figure 7 — Ancillary Services
There are several types of ancillary services (A/S). There are four A/S that are used to match load and resources:
| • | | Regulation provides automatic generation control (AGC). |
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| • | | Spinning reserve is unloaded, synchronized generating capacity. |
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| • | | Non-spinning reserve is generating capacity with less than 10 minutes response. |
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| • | | Replacement reserve is generating capacity with less than 60 minutes. |
Additional types of A/S are Reactive Power which helps to maintain system voltage and Generation Black Start reserve which aids in system recovery during major outages.
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[BAR CHART]
Figure 8 — Reserve Market Prices
Based on reserve requirements determined by the ISO for each of the above reserve types, and bids submitted by the participants, the price of the required reserve quantity is determined. Payment is determined by the ISO and managed through the PX.
IMBALANCES
Real times imbalances are the result of the difference in schedules and metered values for demand and supply. The supply side may include metered generation, imports, purchases in the Day Ahead and Hour Ahead Markets, and bilateral contracts.
The demand side may include metered or calculated delivery to end-users, sales in the Day Ahead, and Hour Ahead Markets and bilateral sale contracts. The imbalances are settled in the final settlement based on the marginal price in the real time market.
[BAR CHART]
Figure 9 — Real Time Imbalances
When the metered data are processed the imbalance for each hour and zone is calculated as the difference between the participant’s use of power resources (generation and purchase contacts) and power commitments (sale contracts and consumption).
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In the two examples in Figure 10, HAH means Hour Ahead Market and DAH means Day Ahead Market. In example (a) there is no congestion and the Market Clearing Price (MCP) replaces all zonal prices. The participant’s actual commitments exceed scheduled resources. Participants are charged for the difference between actual and scheduled load based on the price in the real time market. In example (b) the participant has been called upon to increase generation by an amount equal to the congestion (CON) to relieve inter-zonal congestion. CON is a part of the participant’s commitment.
[GRAPH]
Figure 10 — MCP Versus Zonal Pricing
DAY AHEAD AND HOUR AHEAD SETTLEMENTS
A preliminary billing statement is sent to market participants 3 days after each trade day, and a final billing statement is issued 7 days after each trade day. For disputes, market participants have 5 days after each trade day to dispute billing statements. Invoices are issued 7 days after the end of each trading period or calendar month. Payments from participants required 15 days after the end of the trade period and payments to participants will be made 17 days after end of trade period.
The PX is exposed to a settlement risk which corresponds to the participants net purchase throughout the total settlement period. A PX participant is required to provide a security deposit in the form of a letter of credit, irrevocable guarantee, or escrow agreement which at least corresponds in value to a participant’s 15-day trading volume.
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[CHART]
Figure 11 — Day/Hour Ahead Settlement, Invoicing and Payment Process
REAL TIME MARKET
The Real time market is a tool for the ISO to adjust power generation to match load and is based on adjustment bids from the supply side only. ISO sorts the bids in price merit order and calls upon the bids when it is necessary to adjust the balance between generation and load. The last unit called upon in each hour defines the marginal price in the real time market. See Figure 12.
For the Real Time market the trading period is a calendar month. (See Figure 13.) The meter reading data is collected within 38 days of each trading day. Preliminary statements are issued within 48 days following the trading period and the Final Statement within 62 days. Settlement disputes are terminated 60 days after each trade day. PX invoices are issued 62 days, participants payments should be received 68 days, payments to participants 70 days after the end of each trade period.
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Figure 12 — Real Time Market Price
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[BAR CHART]
Figure 13 — Real Time Settlement, Monthly PX, and ISO Charges
MARKET ACTIVITY SEQUENCE
Day prior to day of operation
| 1. | | Trade in the Day Ahead Market and determination of Market Clearing Price (MCP) |
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| 2. | | Over-generation management |
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| 3. | | Participants submit unit schedules to the PX |
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| 4. | | Inter-zonal congestion management and determination of zonal market clearing price based on day ahead market adjustment bids. |
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| 5. | | Participants called upon to relieve inter-zonal congestion submit revised schedules to the PX. |
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| 6. | | Intra-zonal congestion management. |
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| 7. | | Participants called upon to relieve intra-zonal congestion submit revised schedules to the PX. |
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| 8. | | The PX submit final day ahead schedule to the ISO. |
Day of operation
| 1. | | Trade in Hour Ahead Market and determination of hour ahead market clearing price |
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| 2. | | Inter-zonal congestion management based on hour ahead adjustments bids |
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| 3. | | Participants called upon to relieve inter-zonal congestion submit revised schedules to the PX |
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| 4. | | Intra-zonal congestion management. |
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| 5. | | Participants called upon to relieve intra-zonal congestion submit revised schedules to the PX |
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| 6. | | The PX submit final hour ahead schedules to the ISO. |
Hour of operation
Real time operations managed by the ISO and determination of real time market price (Ex-Post Price)
7-62 days after end of trade period
Billing Day Ahead Market and Hour Ahead Market
Settlement and billing Real Time Market
HEDGING RISKS
In a competitive power market the participants are exposed to financial risk due to the volatility of the market price. It is expected that bilateral financial hedging contracts will be widely used by the participants for the purpose of risk management. Hedging contracts may take many forms and provide a flexible mechanism both on short- and long-term transactions.
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[CHART]
Figure 14 — Contract for Differences
A simple hedging contract may take the form of the seller paying the buyer the price difference between the Day Ahead Clearing Price and the contractual hedging price whenever the Day Ahead Clearing Price is the highest. Whenever the Day Ahead Clearing Price is the lowest the buyer pays the seller.
These contracts do not impose an obligation for the physical delivery of energy. The buyer may buy the contractual volume on the Day Ahead Market and the total cost will be equal to the contractual price regardless of the volatility in market. In the same manner the seller has hedged a sale on the Day Ahead Market equal to the contractual price.
On the demand and the supply side there is a mutual interest to enter into contracts of this kind and share the risk of trading.
BILATERAL CONTRACTS
These contracts impose an obligation for the physical delivery of energy. These contracts are formulated outside of the PX markets but they can be bid into the spot market.
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