| 摘要 | ��
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1. Research Purpose
There are five Long-Term Power Expansion Plans(LTPEP) since 1999. Electricity demand forecast results have been revised to elevated repeatedly as the forecasted demand in LTPEP is under-forecasted than actual. Since 1999, five Long-Term Power Expansion Plans have been established.
What is the results of under-estimated demand forecast? What is the proper method to minimize the regret due to inaccurate demand forecast? We intuitively know that the continuous under-estimated demand forecast causes the distortion of power plant mix and increases supply cost of electricity. When the demand grows greater than expected, the gas plant which has short lead time will be the only measure as a contingency plan. If it is unable to construct the gas plant in that situation, the electricity company faces supply unstability.
Supply unstability is depended on the fuel supply, generation adequacy, plant capacity and plant mix and network adequacy. This study focuses on the plant capacity and optimal plant mix related to the demand forecast. Regret cost and maximum regret cost are calculated using the WASP program. And Minimize Maximum Regret Cost Method(MMRC) is applied to find proper approach to establish the next Long-Term Power Expansion Plans. And, this paper tries to present policy analysis in the perspective of supply-side as well as demand-side for important issues with respect to enhancing security of supply in electricity market
2. Summary
The results of analyzing CBP(cost based pool) and LTPEP are as follows. Careful examination of the CBP(cost based pool) and LTPEP revealed the following results. The whole sale price settlement system in CBP doesn't give any competition among electricity companies. The wholesale price system in CBP is mainly focused on the revenue allocations among electricity
companies. Under-estimated electricity demand forecast and over-estimated DSM cause to apply lower peak load and higher load factor when LTPEP is established. This means the demand forecast has uncertainty.
The differences of the construction lead time of plants give lower flexibility of revising LTPEP. When the demand grow more than expected, the short lead time plant is the only alternative for preventing power shortage. These make harder the optimal plant mix that has lower cost than sub-optimal mix does. At present, the base load plant ratio is low compare with optimal ratio which calculates from computer program. So the large scale regret cost may occur in the future due to the demand uncertainty. Electricity Companies face many internal and external uncertainties. Internal uncertainties can be dealt with the company but externals can't.
World Bank recommends to lessen uncertainties. A scenario analysis, a sensitivity analysis, a portfolio analysis and a probability analysis are applied to lessen uncertainties when LTPEP is established. The uncertainty of demand forecast is the most among other uncertainties. Minimize the maximum regret cost method is suitable to manage the uncertainty of demand.
WASP program is used to get the results of MMRC analysis and the results are as follows : WASP program uses the data from The 4th Basic Plan of Long Term Electricity Supply & Demand as input data. Upper limit of reserve margin applies 25% and LOLP is 1day/year.
To calculate the MMRC procedure is as follows;
1. Operate WASP program under low, base and high demand case. There are 9 cases for analysis.
2. The solutions may not proper solution due to the demand uncertainty. It results in over or under-estimated capacity.
��- In the case of under-estimated capacity, the electricity company constructs the short lead time plant to meet the demand. In this case, LNG ratio is higher than proper level.
��- If the actual demand is lower than expected one, the company has the over-estimated capacity because the construction of long lead time plant can't cancel or delay.
��- The company fail to reach the optimal power mix in both cases, and then, large regret cost are occurred. The objective functions(OF) of 9 cases are calculated.
3. Calculate the regret costs using by OFx minus OFmin in 3 cases.
4. Calculate the maximum regret cost among 3 cases.
5. Find cost minimum case among 3 maximum regret cost cases.
This paper studies several measures that have been propose dinternationally to cope with this problem including strategic reserves, capacity payments, capacity requirements, and capacity subscription. One option that often is proposed is a so-called ��'mothball reserve��', a collection of mothballed, old plants that can be returned to service if necessary. The moth ball reserve would imply a strategic reserve of generation capacity, with an operation centrally controlled by the government and that would only be used during emergencies. There is of course a social cost to this procedure since subsidies would be financed through public funds at large. Supply of capacity reserves would then be categorized as a public service obligation.
Capacity payments provide remuneration to generators for making available their generation capacity (whether they get dispatched or not).
The price of capacity is set while the market determines the amount of capacity available. That is, prices are centrally determined while capacity decisions are decentralized. Capacity payments are collected from consumers through an uplift charge and determine the cost behavior of the firm but leave the amount of reserves uncertain. Capacity payments are rooted in the theory of peak-load pricing so that energy is priced at marginal cost and a capacity payment is used to recover the fixed capacity cost imposed on peak-period energy users. The optimality condition is such that the shadow price of the capacity constraint is equal to the incremental cost of capacity. Capacity requirements are set as an obligation to maintain a certain amount of reserve capacity. Such an amount is centrally determined through an administratively forecast of demand, and is usually imposed by the ISO (or the regulator) to LSEs.
Conversely to capacity payments, the price is decentrally determined by the market once the amount of reserve capacity is set. LSEs must buy enough ��capacity tickets�� to meet the expected peak load of their customers multiplied by (1+X), where X is the expected reserve margin that will cover an estimated level of reliability to cope with random outages. A disadvantage of capacity requirements is that they do not provide an incentive to maximize the availability of reserve capacity. An improvement in this respect is provided by reliability contracts, a system of call options that the system operator purchases from the generation companies. When the options are called, the producers are required to pay the system operator the difference between the market price and the strike price. Operating power plants are a perfect hedge for the generators: their net income is reliability level. The most critical problems faced with current scheme are that the regional capacity factor does not work well and the scheme does not reflect by change in demand by demand-side response. The regional capacity factor(RFC) scheme is operated that there has been no difference between metropolitan area and on-metropolitan area during the last 3 years. This implies that the RFC scheme is not properly working and does not achieve the original policy purpose when proposed. The most important element in determining RFC scheme are adequate reserve margin and transfer capability. The current adequate installed capacity margin is around 12~20%. Considering our the volume of electric power system, the current adequate installed capacity margin is relatively overly excessive. And since the whole transfer capability is included in calculating the supply capacity of metropolitan area due to south-north current, it is known that the supply capacity of metropolitan area is not in shortage. However, in-depth study is necessary for this known fact.
With respect to operation of capacity payment scheme, the scheme is implemented based on fixed cost of open cycle of gas turbine for combined combustion of gas turbine(CCGT). However, it is necessary that the role of demand-side as well as supply-side should be taken account in capacity payment scheme for playing the role of compensation to contribution to stable operation in electricity power system in short term as well as long term perspective. Demand response can work as a critical element in short-term system security as well as long-term resource adequacy aspect. However, since the current electricity market does not consider the role of demand-side, it is absolutely necessary to improve the efficiency of ensuring the security of supply mechanism in electricity market. Hence, the electricity market needs that the capacity payment scheme should be modified to incorporate the role of the demand-side or the policy measures should be taken by removing the capacity payment scheme and introducing the capacity market scheme. And in operating the capacity market scheme, it is necessary to design for the demand-side to participate in the capacity market scheme as a equal source.
3. Research Results and Policy Suggestions
If the LTPEP with the high demand forecast is established, electricity company can supply the electricity with lowest cost even though demand forecast has uncertainty. This result is unchanged even though input data change like applying the probability of demand, revising the demand forecast to upward and the construction cost to upward. As a result of analysis, the MMRC methods should be applied to establish the LTPEP for lower supply cost. Otherwise, reliability level of electricity should be applied more strictly than present level. It is necessary to upgrade current capacity payment scheme and introduce demand response scheme as policy measures for enhancing security of supply in electricity market. Since 2007 the electricity market modified its capacity payment scheme by applying regional capacity factor scheme, but the regional capacity factor scheme does not provide proper signal in inducing regional investment. The main reason is that there is no effect by dividing two regions because the regional capacity factor for metropolitan area is exactly the same as one for non-metropolitan area. Hence, it is necessary to reflect the value of regional difference between metropolitan area and non-metropolitan area through coordinating the level of adequate reserve margin. Moreover, we need to introduce demand response schemes aggressively which is continuously evolving in advanced electricity market. This current domestic electricity market does not demand response program implemented in foreign market except demand resource market(DLM) program replaced the old direct load control(DLC). In particular, emergency demand response program is not compulsory but voluntary demand reduction program which can enhance participation motivation by customer. The emergency demand response program is a likely successful program due to cases such as the emergency demand response program in New York reported a high participation by demand customers. We need to study and introduce demand response programs similar to demand
response programs in other markets.
215 pages, 48 refs., 34 tabs., 35 Figs., Language: Korean |
