Abstract
Efficient short-term energy prices do not manage to recover the cost of most transmission lines. Complementary charges must be put in place to complete the recovery of the cost of the regulated transmission investments while sending efficient long-term signals to network users and not distorting the short-term ones. The allocation of the cost of network investments promoted by private investors directly stems from the business model adopted for these projects. A design of the complementary charges can be considered efficient if it incentivizes the siting of generation and demand that results in lower supply costs, in particular lowering the future cost of grid development. Efficient siting of demand, and in particular generation—with more potential for choice—may result in substantial savings, since the deployment of RES generation and the integration of markets will likely require large transmission investments. Moreover, in a regional integration context, local systems may block the construction of those reinforcements whose cost is allocated in a way that is perceived as unfair by these systems. We review the main principles to be taken into account to allocate the cost of transmission reinforcements efficiently and to design the corresponding grid charges. We conclude that the cost of new investments should be allocated in proportion to the benefits that network users are expected to obtain from them. We identify the challenges that will be encountered when designing and implementing charges this way. Then, we describe and comment on other network cost allocation methods that deviate from this principle, and assess their performance. In the last section of the paper, we discuss the methods that have been adopted for the allocation of the cost of the transmission network in three mature regional markets: the EU Internal Electricity Market, some US Regional Transmission Organizations, and the Central American Electricity Market. For each regional market, we describe and evaluate the market organization and the allocation of the cost of the network hosting cross-border flows (the so-called regional grid).
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Notes
- 1.
Instead, long term incremental cost pricing is better suited to address the computation of distribution network charges applied on end consumers, due to the usually radial configuration of distribution grids. This usually results in network charges with a capacity structure (per MW ones) that are based on the expected contribution of network users to the simultaneous peak load, see (MIT 2016). In that case, the drivers of distribution network reinforcements usually are the peak loading of network facilities. Therefore, the allocation of network costs follows the very same principle as that used in the “beneficiary-pays” approach for transmission networks.
- 2.
Note that probably for distribution network charges the volumetric format may be the more appropriate ones, provided they are time dependent (higher in periods with peak loading of network facilities), since the distortion in wholesale market results will be low and instead a proxy of the long term marginal cost is achieved (see footnote 1).
- 3.
Obviously this is not always the case since network congestion does exist even in properly expanded transmission systems.
- 4.
By definition, Ramsey pricing is always second best when marginal cost pricing is not enough to recover full costs, and therefore cannot be “inefficient”.
- 5.
Despite these difficulties, Argentina (1992) and California (1998) adopted network charging regulatory approaches inspired in the “beneficiary pays” concept.
- 6.
In the UK, the method differentiates conventional and renewable generation, taking into account the average load factor for the latter.
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Rivier, M., Olmos, L. (2020). Cost Allocation Issues in Transmission Network Investment. In: Hesamzadeh, M.R., Rosellón, J., Vogelsang, I. (eds) Transmission Network Investment in Liberalized Power Markets. Lecture Notes in Energy, vol 79. Springer, Cham. https://doi.org/10.1007/978-3-030-47929-9_5
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