FERC Filings
AFFIDAVIT OF RICHARD TABORS ON THE ORDER ESTABLISHING REFUND EFFECTIVE DATE AND PROPOSING TO REVISE MARKET-BASED TARIFFS AND AUTHORIZATIONS ISSUED ON NOVEMBER 20, 2001
AFFIDAVIT
1. THE COMMISSION’S PROPOSALS WILL NOT ENSURE JUST AND REASONABLE RATES IN BULK POWER MARKETS
In FERC EL01-118-000 the Commission is proposing to condition, and subject to refund, all market based rate transactions based on a standard for anti-competitive behavior that is unprecedented, vague and flawed. This draconian level of direct regulatory intervention in all commercial transactions of all parties represents a dramatic change from the Commission’s past approach to regulatory oversight of prices in competitive bulk power markets. In effect, the Commission is sending a message that it may henceforth presume high and/or volatile prices to be the outcome of anti-competitive behavior unless proven otherwise. This message implies, incorrectly, that low and/or stable prices are the expected signs of a workably competitive commodity market while high and/or volatile prices are automatically questionable, and likely the result of ant-competitive behavior. Variability in prices are critical in commodity markets where they provide the signal for consumer short-run and long-run response as well as the signal for supplier investment.
The goal of these proposals is to ensure just and reasonable rates in market-based transactions. While that goal is both legitimate and laudable, it will not be achieved by these proposals. Instead these proposals will have the exact opposite affect, they will lead to unjust and unreasonable prices. In summary, the proposals represent an extreme level of regulatory intervention that is not justified by market performance to date and will lead to less efficient markets.
2. ACTUAL EXPERIENCE IN WHOLESALE MARKETS TO DATE DOES NOT JUSTIFY SUCH SIGNIFICANT REGULATORY INTERVENTION.
The Commission’s proposal represents a dramatic and unprecedented shift in its approach to enforcing market rules. This new approach has the potential to completely stymie and reverse the progress made to date in fostering competition in bulk power markets. This dramatic change in approach is inexplicable based on actual experience with market-based rates in bulk power markets over the last several years.
One could understand the Commission proposing to take dramatic action if there was evidence of jurisdictional sellers engaging in anticompetitive behavior or exercising market power on a widespread and regular basis.
However, the Commission has presented no such evidence to justify its proposals. In fact it states explicitly that “...we do not find here that particular sellers have, for example, exercised market power.” This finding is consistent with the Commission’s findings in New York on non-spinning reserves and in both the California and the Pacific Northwest cases.
Instead, the only justification presented by the Commission is a concern that a particular seller with market-based rate authorization might, under certain circumstances, engage in behavior that could result in unjust rates. This proposal represents a case of the tail wagging the dog. The Commission’s desire to prevent the possibility of an instance of unjust and unreasonable prices in a limited number of transactions due to anti-competitive behavior by an unspecified market participant should not override its broader responsibility to ensure just and reasonable prices in the vast majority of transactions of all market participants through the operation of competitive markets. The Order provides no justification for the conditioning of all commercial transactions of all sellers with market-based rate authorization based on such a vague and ill-defined standard.
The Commission’s concern about the potential for the exercise of market power to lead to unjust rates in the future may be influenced by its recent experience with wholesale markets in California and the WSCC. Even that experience does not justify the conditioning of all transactions of all sellers with market-based rate authorization. First, the Commission has specifically found that problems in California are largely attributable to the rules that governed the operation of its market but has yet to find that any specific seller in that market exercised market power. Second, the claims of unjust and unreasonable prices in those markets, when subjected to scrutiny in litigated proceedings, may prove to be wildly overstated or even nonexistent, as has been the case in the Pacific Northwest refund case. In her recommended decision in that case, ALJ Cintron did not find the market-based prices during the refund period to be unjust or unreasonable.
3. APPLYING THIS CONDITION TO BILATERAL CONTRACTS WILL REDUCE THE LEVEL AND EFFICIENCY OF COMPETITION IN BULK POWER MARKETS
The Commission is proposing to subject the prices in all market based rate transactions to refund. The imposition of this condition on all commercial transactions of all parties will reduce the level and efficiency of competition in bulk power markets. In fact, this initiative may have the unintended effect of driving sellers, and hence buyers, away from primary reliance on forward contracts to primary reliance on spot contracts resulting in a host of adverse impacts. In order to appreciate why this conditioning will have such an adverse impact on the operation of these markets one must begin with an understanding of the range of markets and transactions involved.
Bulk Power Markets
Within any given geographic market there is not a single bulk power market but instead a myriad of distinct markets. The two most common categories are “real-time” or “spot” electricity markets and forward markets. A spot market bilateral contract for electricity differs from a forward market bilateral contract for electricity in many respects, and therefore represents a different “product” from the perspective of both a buyer and a seller. These differences include:
- Timing of the contractual commitment. Spot market transactions are entered the day-of or day-prior to delivery, forward market transactions may be entered days to years prior to delivery.
- Duration of the commitment. Spot market transactions are, by the Commission’s definition, day ahead or 24 hours or less, forward market transactions may be for multiple years.
- The hours in which electricity will be delivered. Spot market transactions provide for deliveries in a specific hour or hours up to 24 hours in advance. Forward market transactions provide for deliveries in blocks of heavy load hours (HLH), light load hours (LLH) or all hours (flat) for durations of balance of month, month, quarter, annual or multiple years.
- Spot market contracts almost always go to delivery whereas forward contracts can be, and frequently are, traded several times prior to delivery. This ability to trade forward contracts gives their buyers the ability through continuous trading to “fine tune” their portfolio. For Load Serving Entities (LSE) this allows them to match expectations of changing demand conditions as these unfold toward the time of delivery. Through these trades suppliers are able to balance their fuel purchase commitments and marketers are able to supply increasingly useful hedges for both supply and demand.
As a result of these key differences, the value of the electricity purchased and sold under each type of transaction will be different and hence the price will be different.
The existence of a wide range of markets is one of the key reasons why a competitive market can achieve a higher level of economic efficiency than a regulated market. A buyer in a competitive market can choose the portfolio of spot and forward contracts that best meets its particular mix of operational, budget and risk requirements. Similarly a seller in a competitive market can meet the requirements of a particular customer using a portfolio of its own generation and resources acquired through spot and bilateral contracts.
Impact of Conditioning All Transactions
The primary impact of this conditioning would be to reduce, if not eliminate, the faith of market participants in the finality and integrity of negotiated, bilateral transactions thereby raising the level of uncertainty associated with those financial instruments substantially. The increase in uncertainty will lead to higher average prices, as sellers would have to increase the risk premiums in each transaction. The imposition of this condition will also lead to less efficient markets, since participants will be reluctant to continue using complex, multi-party contracts.
One of the basic tenets of public policy and the operation of competitive markets has always been that individuals and economic entities that operate within the law or the rules / regulations established by relevant and accepted organizations such as the New York Stock Exchange or the Chicago Board of Trade are not subject to ex post review. The Commission’s proposal to subject the prices in all market based rate transactions to refund would eliminate confidence in the integrity of all transactions.
Participants have always been aware of, and accepted the risk of, prices in a specific transaction being subject to refund in the event that they were found to be unjust and unreasonable. However, the magnitude of that financial exposure was limited to a specific transaction, generally accompanied by an extensive review process that demanded burden of proof on the part of the complainant and covered a well-defined and limited refund period. In contrast, by conditioning all transactions to an already past refund effective date, the Commission will increase the financial exposure of sellers dramatically. Moreover, the proposal will penalize sellers and benefit buyers, without any basis for such discrimination between market participants.
One of the major sources of uncertainty will be the standard that the Commission will use to determine if the price in a specific transaction is unjust and unreasonable. It is unclear why, or how, the Commission would seek to find a price in a bilateral contract to be unjust and unreasonable when the buyer was under no obligation to enter the contract. As has been demonstrated in the PNW refund case, buyers participating in wholesale markets do have alternatives, both in terms of physical supply and financial hedges. Physical supply alternatives include investing in generation (supply) and in load control and efficiency (demand) while financial hedging alternatives include entering into long-term supply contracts with either marketers or between suppliers and consumers. Therefore, buyers who voluntarily enter specific bilateral contracts in wholesale markets do so based upon their physical supply strategies, purchasing strategies, the product options available to them, the market information available to them and the contract terms they agree to. Buyers and sellers mutually agree to specific contract terms based on known costs, benefits and risks. This breadth of contract alternatives makes the exercise of market power in such a multi-product competitive market very difficult.
While it is not the intent of the Commission to eliminate bulk power markets through this order, this could be the unintended result. If a marketer cannot sell above its purchase prices (if this is the definition of a marketer’s incremental cost) it cannot participate in the market.
The increases in uncertainty described above will lead in turn to an increase in the cost of energy. It is likely that prices would measurably and systematically increase in both spot and forward markets. Sellers will increase their prices to adjust for the increase in financial risk associated with their increased exposure to the possibility of ex post resetting of the commercially negotiated prices. This uncertainty will be seen in several other dimensions as well. Developers of power plants will be reticent to invest when there is a possibility or probability that the prices upon which they are basing their investment will not be realized due to regulatory intervention. This is particularly important in terms of investor expectations regarding periods of high prices – periods that provide revenues that all generators require to recover their capital investments. Marketers who provide liquidity to the market will leave because they are unable to benefit from the higher price days to offset their losses on lower priced days. This lack of liquidity will affect who is in the market, how the market behaves and whether the goals of open access are ever realized.
The proposed conditioning of transactions will lead to a decline in economic efficiency and higher prices by discouraging the use of complex, multi-party contracts because of the difficulty of “unwinding” such contracts in the event of a refund. Both buyers and sellers will be hesitant to enter into transactions that involve multiple market participants with complex supply portfolios. Fear of needing to “unwind,” i.e. to pay and be paid in a refund process, will prevent many transactions outright, will increase the cost of those that are consummated and will discourage the precise creative portfolio contracting that is the heart of any commodity trading process.
4. THE PROPOSED APPROACH FOR IDENTIFYING UNJUST AND UNREASONABLE PRICES IS VAGUE AND INCONSISTENT WITH ECONOMIC PRINCIPLES
The effect of the Commission’s proposal is not simply to increase the magnitude of potential refunds it can authorize as a remedy when it finds a specific instance of anti-competitive behavior by a specific market participant. Instead, the effect of this proposal is to add uncertainty to all commercial transactions of all market participants. This effect is dramatic and has far-reaching and harmful consequences in and of itself, as discussed elsewhere in this affidavit. However, what significantly magnifies this harm and opens a Pandora’s box of uncertainty are the vague references to the standard that the Commission would apply to assess the exercise of market power. The Commission provides very little explanation of the definition or the intended application of this standard. For example, the proposal omits the determination of the relevant markets and products to which this standard would be applied. Instead, the proposal only provides examples of economic and physical withholding as evidence of anti-competitive behavior. The Commission may have intended to provide only conceptual illustration of the definition of anti-competitive behavior, without intending to introduce a specific standard. However, these examples do not define anti-competitive behavior correctly. Further, the implications of the terminology used in describing economic withholding appear to violate economic principles that govern competitive market operation.
4.1 NO RECOGNITION OF VARIOUS MARKETS FOR VARIOUS PRODUCTS
There is a wide range of markets operating within the bulk power market in any given region as noted in the preceding section. The Commission recognized the differences in value between spot market transactions and forward market transactions in its December 15, 2000 order. While the Commission has consistently declined to find market power in long-term sales it has explicitly not indicated that these will not be in the set to be evaluated under this order. Further, the Commission has not indicated whether or how the standard should or could be applied in any of individual market.
4.2 AN INCREMENTAL-COST BASED STANDARD VIOLATES FUNDAMENTAL PRINCIPLES OF COMPETITIVE MARKETS
The Commission’s example of economic withholding indicates that offering supply above full incremental cost and the market price, thereby presumably not selling into the market, constitutes economic withholding. This example presents a serious ambiguity regarding the definition of incremental cost, and major flaws in the expectation of behavior in competitive electricity markets.
INCREMENTAL COST SHOULD INCLUDE OPPORTUNITY COST
The ambiguity concerns the absence of clarity on the constituents of “full incremental cost,” and specifically the omission of “opportunity cost.” “Full incremental cost” associated with the supply of a unit of energy may be assumed to include all costs that would be avoided were that unit of energy not supplied. However, this should also include any incremental revenues that would not be earned if that unit of energy were not supplied, since incremental revenues that are lost to a market participant are financially equivalent to an incremental cost.
Opportunity cost bidding is an economically rational, commonplace characteristic behavior of competitive commodity markets. Specifically, in electricity markets, opportunity cost is a recognized and vital element of efficient economic decision-making, the absence of which would lead to flawed operating and investment decisions, and higher societal costs. The importance of opportunity cost can be illustrated using two specific examples, electric generators participating in emissions markets and hydroelectric resources. While these two are examples are discussed in below and presented in greater detail in Attachments A and B to this affidavit, it is critical to note that there is a range of other examples that could have been used. One such is the need of natural gas fired generators to consider the opportunity cost of the gas when making the decision to operate. The gas has a current value when it is transformed into electricity. It has another value (opportunity value) if it is sold into the market for another use and still another if it is stored for future use.
Electric Generators Participating in Emissions Markets
A well-established policy tool implemented by the Environmental Protection Agency (EPA) for reducing nitrogen-based emission (NOx) from electric generation is the cap-and-trade program. Examples include the Ozone Transport Region (OTR) in the Northeast US, and the Regional Clean Air Incentives Market (RECLAIM) program in California. The concept involves the establishment of a cap on the total allowable emissions in the market, which is usually well below actual emissions, and an allocation of those total emission allowances among existing generators. Market participants then may trade these allowances in an emissions market. The intent of this program is to allow market forces to determine which units are better off investing in emission-control technologies, and which are better off purchasing allowances. In order for these market forces to work market participants must be able to incorporate the economic cost of their emission-control decisions in the electricity market.
For example, in order to generate electricity, a market participant must either purchase an allowance or “use” an existing allowance. If the participant decides not to generate, he or she either avoids the cost of purchasing the allowance in the emissions market, or sells an existing allowance in that market. Thus, the value of these emission allowances constitute an opportunity cost associated the decision to generate or not to generate. This cost must be represented in electricity supply bids in order to allow generators to make rationale economic decisions regarding the operation of their facilities. In fact, the cap-and-trade programs rely on these rationale operational decisions to encourage generators to make economically efficient investment decisions related to emission control technologies. If these opportunity costs are not included in electricity supply bids, cleaner units will not get the feedback that they need in order to determine if they are better off selling their NOx allowances to dirtier generators rather than generating themselves. From the total market perspective, if these opportunity costs are not included in electricity supply bids, the supply of credits will be artificially reduced, leading to higher prices in NOx emissions markets, higher overall costs of compliance and higher electricity prices. A complete example of the economic analysis of emission credit use decisions in electric generation is included as Attachment A to this affidavit.
Hydro-electric resources
Another critical example of the necessity of including opportunity cost in electricity bidding is that of hydro units. Hydro resources account for a significant portion of the supply to electricity markets in the Northeast and Western US. These units differ fundamentally from thermal units in that they (i) have a limited and unpredictable fuel source (water); (ii) have vast storage capabilities; and (iii) can be ramped from zero to full output within a few minutes.
Due to their limited and cyclical (annual) water supply, operators of hydro systems have to constantly trade off the value of generating electricity now against the value of generating electricity at a future point in time, i.e. opportunity cost. Thus, a unit of hydroelectric energy sold at current market prices, has an opportunity cost tied to its replacement value in a future time period. For example, a unit of hydro-electricity sold in summer represents the loss of a unit of supply for the upcoming winter. Hydro system owners with load serving obligations face an even more difficult trade-off, since the unit generated in summer would have to be replaced by a market purchase to meet load in winter. Thus, opportunity cost is the only basis upon which hydro operators can make economically efficient trade-offs between generating now and generating in the future. Hydro operators have to estimate future market prices, and generate only if the current price exceeds future anticipated market prices. Thus, hydro generators have to relate their bids for the sale of generation now to their expectations regarding the price of electricity in the future in order to have any degree of certainty that what they sell today will not cost them more to replace tomorrow. A complete example of the economic analysis of hydroelectric generation opportunity cost based decisions is included as Attachment B to this affidavit.
INCREMENTAL COST-BASED BIDDING UNDERMINES CAPITAL RECOVERY
The Commission’s example of economic withholding contains a major flaw in the expectation and understanding of bidding behavior in competitive electricity markets. Specifically, the example indicates that supply offers that exceed incremental cost and market price are de facto examples of economic withholding. This implies that if market participants’ bids exceed their “full incremental cost,” they are potential candidates for accusations of market power abuse.
The major flaw in this reasoning is that even if one assumes that “full incremental cost” includes opportunity cost, market participants who are limited to bidding their full incremental costs will not have any ability to recover their fixed capital costs. To deny market participants the opportunity to set their supply bids to recover some portion of their fixed costs in addition to full incremental costs will completely eliminate the financial incentive for any future investments in new capacity and will jeopardize the viability of existing investments driving the system to quantity rationing (rolling black-outs).
It may be argued that there at least some markets in which most sellers receive prices above their full incremental costs without having sought those prices, i.e., those markets with bid-based auctions and single market clearing prices (such as California, New York, PJM). In those markets most units receive prices above their incremental costs even if they bid only these incremental costs, and therefore do recover some contribution towards recovery of fixed costs in every hour dispatched. However, even in those markets the units that set the market clearing price do not have that opportunity. Again, in the absence of a separate capacity market, if market participants were limited to bidding their full incremental costs then units that set the market clearing price would not earn any revenues toward recovery of their fixed costs including a fair return on their investments, since they would receive revenues only equivalent to their incremental costs.
This can be illustrated in the simple case of a peaking unit. Peakers typically only run a few hundred hours each year. Due to their high incremental costs, they have no guarantee that their bids will be less than the market clearing price, i.e., infra-marginal and thus dispatched in most hours of the year with recovery of a contribution towards their fixed costs in those hours. Instead, these units have to submit bids that cover their full incremental cost plus a contribution to recovery of their fixed costs in the hope that they will be dispatched in a sufficient number of high market price hours each year. Consider, for example, a peaker with an annual carrying cost of $45,000/MW-year and full incremental costs of $50/MWh . If the owner of that unit expects that it may be dispatched 300 hours a year, it would set its bids at $ 200/MWh to recover its full incremental cost of $50/MWh plus a contribution towards recovery of its capital cost in each hour dispatched of $150/MWh ($45,000 recovered over 300 hours).
The second flaw concerns the reasoning that supply offers in periods of high demand that are above both incremental costs and market prices are automatically attributable to anti-competitive behavior. As illustrated in the above peaker example, market participants in perfectly competitive markets would set their bids at levels that would ensure recovery of their full incremental cost in every hour and would give them a realistic probability of recovering their fixed costs, including a reasonable return on investment, over the hours dispatched each year. Moreover, in setting those bids market participants bear the risk of not generating as many hours per year as they expect if they find no willing buyers in a bilateral market or are not selected for dispatch in a power pool. There is every likelihood that some units, such as the peakers described above, will not be dispatched even in periods of high demand due to the availability of other, cheaper, peakers whose bids set the market clearing price. Yet, according to the example of economic withholding in the Commission’s Order, the peakers whose bids were not accepted could be accused of anti-competitive behavior.
In the extreme circumstance of scarcity where every available generator on the system is required to meet demand, and is able to do so (subject to transmission constraints), a generator supply offer in a competitive market would never exceed market price, because the market price would rise to the level of, and be set by, the last generator in order to ensure that demand is met. If transmission constraints did, in fact, prohibit selection of the last supply offer the market price would rise to whatever level is permitted under the market rules (infinite, in theory). In that situation, the unit whose supply offer was rejected could be accused of economic withholding according to the Commission's proposal, despite a legitimate explanation for its situation. This example illustrates the lack of critical details in the Commission's standard of economic withholding.
In order to apply such a standard one must consider a host of factors, such as transmission constraints, presence/absence of price caps, and market rules governing the determination of market price. The Commission does not address any of these factors in discussing this standard.
If such a rule were implemented as described, market participants would have no way to protect themselves from the risk of being accused of anti-competitive behavior except to bid their “full incremental cost,” since they would have no ex-ante knowledge of the market price, and therefore could not ensure that their supply offers were “below market price.” The Commission apparently intends to achieve its objective of preventing the free increase of market price in times of scarcity by requiring all bids from all generators at all times that may set the market price to be based on incremental cost. This proposition is flawed, and will achieve exactly the opposite effect of the Commission’s intent, namely to discourage new investments and market participation, and increase the likelihood of scarcity and jeopardize reliability.
4.3 THE EXAMPLES OF ANTI-COMPETITIVE BEHAVIOR IN THE ORDER ARE INCONSISTENT WITH THE COMMISSION’S MERGER POLICY
The examples of anti-competitive behavior provided in this proposal are inconsistent with FERC’s explanation of monopolistic pricing in Order 592. The Commission explains monopolistic pricing in its merger policy (Order 592) as the ability to “profitably sustain a small but significant price increase.” This definition correctly indicates that market participants must be shown to have an incentive to engage in anti-competitive behavior, namely to “profitably” increase prices above competitive levels, to be guilty of anti-competitive behavior. The Commission’s examples of physical and economic withholding in this proposal violate these principles by providing no indication that market participants should benefit from withholding capacity from the market. Specifically, assuming for the moment that a market participant has been found to have purposely withheld capacity from the market and that such withholding did in fact result in price increases (notwithstanding the significant difficulties in establishing these findings), the participant should not be deemed to engage in anti-competitive behavior unless it has been shown to have earned excessive profits from the price increase. Logically, in the absence of an incentive, the behavior may be inexplicable, but hardly equivalent to anti-competitive. The importance of establishing incentive is, first, that the policy must leave room for the possibility that in an imperfect world a market participant may unwittingly act against its own interest, by not generating when the market price is above their full incremental (inclusive of opportunity) cost. Second, given the difficulty of establishing unequivocally that a participant purposely withheld capacity and that prices increased as a direct result, the demonstration of an incentive or lack thereof would reduce the chance of false findings of anti-competitive behavior.
ATTACHMENT A
NOX EMISSION COMPLIANCE EXAMPLE
Generators participating in cap-and-trade programs to regulate air emissions require allowances (emissions credits) to generate electricity. These allowances can be bought and sold in an emissions market. The supply of allowances comes from units that install emissions-control technologies and have excess allowances. Buyers of allowances are those that have insufficient allocated allowances to generate their desired electricity output. In order to ensure recovery of their allowance purchase costs, generators need to include in their bids the allowance purchase costs required for that energy sale. Similarly, generators that hold allowances have to bid the foregone revenues associated with using their allowances when they generate electricity. Thus, all generators need to bid the emissions value of an incremental sale in their electricity bid. There is no distinction from an economic perspective between bidding the cost of an actual purchase of allowances and bidding the foregone revenues from used, held allowances.
Bidding the cost/opportunity cost of allowances allows environmental externalities to be quantified and incorporated into economic decisions, thereby relying on market forces to minimize total costs of environmental compliance. Disallowing such bidding behavior will lead to uneconomic outcomes and higher costs of compliance. To see this, consider the compliance options available to generators and the importance of opportunity cost bidding for each option:
1) Generators purchase allowances
2) Generators invest in emission-control technologies to reduce emissions (and sell excess allowances)
3) Generators reduce their output (displaced by a ‘cleaner’ generating unit)
If generators are not allowed to bid cost/opportunity cost associated with emissions, the generators would have no ability to internalize their environmental cost into their bids and compete on their total incremental costs. This would:
1) Increase allowance purchase costs
2) Reduce the incentive for over-compliance that would yield excess allowances for sale, thereby reducing the supply of allowances in the market
3) Eliminate option 3 as a compliance option.
Overall, this would drive up the market price for allowances, increasing overall emission compliance costs.
Take a coal-fired generator A with a fuel cost of $15/MWh and another generator B with a slightly lower fuel cost of $14/MWh. Assume generator A has a NOx emissions rate of 0.5lb/MMBtu, but generator B has an emissions rate of 1.0 lb/MMBtu. Generator A would have to incur a cost $2.25/MWh to purchase allowances in the emissions market (total cost of $17.25/MWh), but generator B would incur a cost of $4.5/MWh (total cost of $18.5/MWh), assuming a prevailing allowance market price of $1,000 per ton of emissions. If these generators are not allowed to bid this cost in the electricity market, generator B would bid $14/MWh, generator A would bid $15/MWh, and generator B be dispatched instead of generator A, and the marginal emission compliance costs would be $4.5/MWh, rather than $2.25/MWh, a total uneconomic cost of $1.25/MWh ($2.25 higher emissions cost less $1/MWh fuel savings).
However, if these generators are allowed to bid their emissions cost, generator A would appropriately be dispatched in place of generator B, and society would be better off by $1.25/MWh. Generator B would also be better off not generating, since if it were allowed to bid only its fuel cost of $14/MWh, it may get dispatched and earn a market price less than its actual total incremental cost (<$18.5/MWh), thereby losing money on every unit sale.
ATTACHMENT B
HYDROELECTRIC OPPORTUNITY COST EXAMPLE
A hydro-based supplier has to manage the risk of replacing the water from current sales with a future purchase in potentially high price periods. The hydro supplier should only sell water today if they receive a price that is at least equal to the replacement cost of the water in a future time period in which the water may be needed. Thus, in order to make an economically rational decision (that will maximize the value of the resource), the hydro supplier should bid the expected replacement value of the water.
Consider the exhibit above, which shows the actual forward energy prices for the following months on each day of the period between October 1st, 2000 and June 28th, 2001 at Mid-C, California. For example, on October 1st, the average forward price for a November contract was just over $100/MWh, and on December 7th, the average forward price for the January contract was $775/MWh. If the supplier on December 7th expects a shortage in January 2001, the replacement cost for a unit sold in December is approximately $775/MWh. If the variable cost of supplying this unit is $5/MWh, the hydro supplier should bid $780/MWh for that unit of energy on December 7th. This will ensure that if the energy is sold, the supplier will be left with at least enough money to replace the energy foregone in that sale when needed in January 2001.
If the supplier does not bid the opportunity cost, it will displace thermal units (due to a zero bid) and deplete its resources in off-peak periods. This would jeopardize reliability during peak periods and increase the likelihood of scarcity and high market prices.