Dept. of Accounting and Commercial Law, Hanken School of Economics, Vaasa, Finland
12.1 General Remarks
The choice of products for hedging transmission risk depends on how transmission capacity is allocated.
Market-Based Allocation Methods
In the EU, the Target Model is the use of market-based methods for the short-term or long-term allocation of cross-border or cross-zonal transmission capacity (Sect. 5.6). Market-based methods mean the use of explicit auctions, implicit auctions, or both. Continuous trading may be used for intraday trade.1 Long-term cross-zonal transmission capacity must be allocated to market participants in the form of physical transmission rights (PTRs) or financial transmission rights (FTRs).2
Not Market-Based Allocation Methods
Methods that are not market-based include, for instance, the reservation of transmission capacity under long-term contracts, the first-come-first-serve mechanism, and pro-rata allocation.
When transmission capacity is allocated for electricity flows in the more distant future, it is customary to use a combination of market-based and not market-based mechanisms (for very long-term capacity allocation, see Sect. 5.6.3).
Wholesale electricity market participants can use various kinds of financial contracts to hedge transmission price risk. They may use financial products for congestion alleviation, that is, FTRs and contracts for difference (CfDs). A US alternative would be to use particular transmission congestion contracts (TCCs).
Many products can be functional equivalents depending on the case. It may be possible to achieve the same commercial result with FTRs, CfDs and PTRs. While PTRs may allow market participants deliver electricity power across borders for a fixed price, FTRs may provide a pay out to the holder of the right representing the price difference across the border. Therefore, capacity rights do not absolutely need to be physical.3
In financial markets, many parties are both buyers and sellers of derivatives. Derivatives on electricity transmission capacity are different. The market is one-sided, because most market participants need to by protection. TSOs are natural sellers of transmission capacity rights and the only players in a position to offer the required firm transmission hedges.4 Moreover, the development of a liquid market for financial transmission contracts would require the existence of a sound underlying physical market. In the absence of such a physical market, the seller would have to accept a speculative risk. As a result, the risk premiums would be high and unacceptable for market participants.5
12.2 Physical Transmission Rights
Physical transmission rights (PTRs) are option contracts. They provide the option to transport a certain volume of electricity in a certain period between two areas in a specific direction.6 In principle, the holder of PTRs might prefer to withhold these rights from the market and reduce the capacity of the congested interface.7 To prevent this, PTRs are complemented by the use-it-or-sell-it principle (UIOSI, see Sect. 5.6.3). According to the UIOSI principle, the holder of the PTR may either use capacity by nominating it or receive an automatic payout for capacity that it has not nominated.8 The UIOSI mechanism thus means that not nominated capacities will automatically be sold in the day-ahead market.
PTRs can be used both in explicit as well as in implicit auctions but in different ways.
In an explicit auction, a TSO auctions off available cross-border or cross-zonal transmission capacity to market participants through PTRs. Regulation 714/2009 provides that rights to transmission capacity must be firm and subject to the use-it-or-lose-it (UIOLI) or use-it-or-sell-it (UIOSI) principle at the time of nomination.9
The available transmission capacity is allocated in the form of PTRs with UIOSI in explicit closed auctions for the purpose of allocating cross-border transmission capacity in an area that consists of CWE (the Central Western Europe Region), the CSE (the Central Southern Europe Region), and Switzerland. Capacity is auctioned on a yearly, monthly, and daily basis.10 Not nominated capacities are automatically resold to the relevant daily allocation.11 The available transmission capacity is auctioned by a Joint Auction Office. In practice, the TSOs have outsourced parts of their tasks to CASC.EU S.A. acting as the Joint Auction Office.12
The use of implicit auction mechanisms means that the market participant does not need to purchase transmission capacity separately. Implicit auctions are based on the use of different electricity price areas (market splitting) with electricity prices that depend on the amount of congestion. Electricity prices are equal between two areas when there is no congestion but different in the event of congestion.
Implicit auctions for the allocation of cross-border transmission capacity have been used in radial parts of the grid (such as EMCC) or between radially aligned countries (such as MIBEL and TLC) in the past. Transmission capacity was first allocated by TSOs to power exchanges in the form of PTRs. The power exchanges matched the PTRs to trades implicitly.13 NWE price coupling is based on the use of such implicit auctions.14
12.3 Financial Transmission Rights
Financial transmission rights (FTRs) are connected with the electricity price difference between different locations of the network (different nodes). (a) Electricity buyers and sellers submit bids to the system operator to buy and sell power at different nodes. The system operator chooses the lowest cost bids to balance electricity supply and demand subject to physical laws and the available transmission capacity. The bid price at a node becomes the market clearing price at the node. An upstream supplier that supplies power to customers downstream of the congested interface receives a lower net price than do suppliers located downstream in proximity to consumers. The difference between the downstream price and the upstream price is the congestion price.15 (b) Holders of financial rights over the congested interface receive a share of the congestion revenues.16
Financial transmission rights (FTRs) are either option contracts or obligations. In both cases, they are settled financially. FTR options entitle their holder to receive a financial compensation equal to the positive (if any) market price differential between two areas during a specified time period in a specific direction. In addition, FTR obligations even oblige their holder to pay for a negative market price differential.17 Flowgate FTRs or flowgate rights (FGR) are a particular form of FTRs (see Sect. 5.5).18
A market participant can benefit from FTRs in different ways. (a) Where an electricity producer upstream of the congested interface has covered all of its deliveries by acquiring FTRs, it is in the same position as an electricity producer that has acquired enough physical transmission rights to cover its deliveries. (b) Where an electricity producer has market power in the importing area, holding FTRs can increase its market power. If an electricity producer has market power in the exporting area, holding FTRs does not enhance its market power or affect prices paid by consumers.19
FTRs have been used in the Italian electricity market.20 While consumers pay the same spot market price (the Single National Price, SNP) for electricity throughout Italy, producers are grouped into geographical zones. Producers can hedge the difference between the zonal price and the SNP by acquiring FTRs auctioned by Terna. Such a FTR is called CCC (Contract Covering the Risk of Volatility of the Fee for Assignment of Rights of Use of Transmission Capacity).21
Excursion: PJM and the Use of FTRs in the US
There is nevertheless more experience in the US. FTRs are widely used in the US as an integral part of the provision of firm transmission service. They can only be created by RTOs/ISOs. PJM is one of the RTOs that use FTRs (Sect. 5.7.4). Other RTOs or ISOs make available similar products although the products may have different names depending on the RTO or ISO.22
In the past, PJM, CAISO (in California), and ERCOT (in Texas) used to apply a flow-based model that was based on the contract-path fiction. The system operator (RTO or ISO) allocated path-dependent PTRs. However, it was not possible to maintain the contract-path fiction in a meshed grid without several simplifying assumptions. The assumptions turned out to be unsustainable.
The three markets therefore replaced the flow-based model with a point-to-point model. The system operator computes locational marginal prices for each network node. To offset or hedge congestion costs, the market participants can acquire FTRs issued by the system operator. FTR auctions are governed by tariff rules set by FERC. FTRs are funded by the congestion rent (i.e., the price differences between grid nodes) collected by the system operator.23
The use of FTRs is based on FERC regulation and the Energy Policy Act of 2005. FTRs help to facilitate equitable access to the transmission grid. (a) Section 217 of the Energy Policy Act of 2005 (the “native load” provision) provides that FERC must exercise its authority in a manner that “enables load-serving entities to secure firm transmission rights (or equivalent tradable or financial transmission rights) on a long term basis for long term power supply arrangements made, or planned, to meet such needs”. (b) These “firm transmission rights, or equivalent tradable or financial transmission rights” are designed to be used by load-serving entities “to the extent required to meet the service obligation of the load serving entity”, that is, “to deliver the output or purchased energy, or the output of other generating facilities or purchased energy”.24 (c) They are also transferable to the extent that the service obligation is transferred to another load-serving entity.25
Because of transferability, FTRs can be used by various kinds of transmission customers. Both electricity suppliers and consumers can use them to hedge their congestion costs.26
First, they are designed to be used by electricity suppliers, that is, load-serving entities that are transmission customers. Utilities (also known as local distribution companies or LDCs) have preferential access to FTRs.
Second, excess FTRs can also be bought by other transmission customers. The FTRs auctioned by the RTOs are those that have not already been claimed by the LDCs.29
In Pennsylvania–New Jersey–Maryland Interconnection,30 FERC found that there needed to be “a process for auctioning FTRs beyond those retained by … transmission customers”.31 For example, FERC has accepted PJM’s design of an FTR auction process that would both (i) provide a means to distribute excess FTRs, and (ii) allow FTR holders the choice to sell those FTRs which they had been allocated and buy FTRs on different pathways that might more effectively hedge their power supply procurements.32