Abstract
The analysis of incentives for electricity transmission expansion is not easy. Beyond economies of scale and cost sub-additivity externalities in electricity transmission are mainly due to “loop flows” that come up from complex network interactions. The effects of loop flows imply that transmission opportunity costs are a function of the marginal costs of energy at each location. Power costs and transmission costs depend on each other since they are simultaneously settled in electricity dispatch. Loop flows imply that certain transmission investments might have negative externalities on the capacity of other (perhaps distant) transmission links (see Bushnell and Stoft 1997). Moreover, the addition of new transmission capacity can sometimes paradoxically decrease the total capacity of the network (Hogan 2002a).
This paper was originally published as: Kristiansen T, Rosellón J (2006) A merchant mechanism for electricity transmission expansion. J Regul Econ 29(2):167–193. We are grateful to William Hogan for very useful suggestions and discussions. We also thank Ross Baldick, Ingo Vogelsang, and an anonymous referee for insightful comments. All remaining errors are our own. Part of this research was carried out while Kristiansen was a Fellow, and Rosellón a Fulbright Senior Fellow, at the Harvard Electricity Policy Group, Center of Business and Government, John F. Kennedy School of Government of Harvard University. Rosellón acknowledges support from the Repsol-YPF-Harvard Kennedy School Fellows Program and the Fundación México en Harvard, as well as from CRE and Conacyt.
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Notes
- 1.
- 2.
No restructured electricity sector in the world has adopted a pure merchant approach towards transmission expansion. Australia has implemented a mixture of regulated and merchant approaches (see Littlechild 2003). Pope (2002), and Harvey (2002) propose LTFTR auctions for the New York ISO to provide a hedge against congestion costs. Gribik et al. (2002) propose an auction method based on the physical characteristics (capacity and admittance) of a transmission network.
- 3.
Generators can exert local power when the transmission network is congested. (See Bushnell 1999; Bushnell and Stoft 1997; Joskow and Tirole 2000; Oren 1997; Joskow and Schmalensee 1983; Chao and Peck 1997; Gilbert et al. 2002; Cardell et al. 1997; Borenstein et al. 1998; Wolfram 1998; Bushnell and Wolak 1999.)
- 4.
An example is the power outage of August 14, 2003, in the Northeast of the US, which affected six control areas (Ontario, Quebec, Midwest, PJM, New England, and New York) and more than 20 million consumers. A 9-s transmission grid technical and operational problem caused a cascade effect, which shut down 61,000 MW generation capacity. After the event there were several “finger pointings” among system operators of different areas, and transmission providers. The US-Canada System Outage Task Force identified in detail the causes of the outage in its final report of April, 2004. It shows that the main causes of the black out were deficiencies in corporate policies, lack of adherence to industry policies, and inadequate management of reactive power and voltage by First Energy (a firm that operates a control area in northern Ohio) and the Midwest Independent System Operator (MISO). See US-Canada Power System Outage Task Force (2004).
- 5.
In the US, transmission fixed costs are recovered through a regulated fixed charge, even in those systems that are based on nodal pricing and FTRs. This charge is usually regulated through cost of service.
- 6.
- 7.
In fact, market power mitigation may be a major motive for transmission investment. A generator located outside a load pocket might want to access the high price region inside the pocket. Building a new line would mitigate market power if it creates new economic capacity (see Joskow and Tirole 2000).
- 8.
Examples of projects that do not change PTDFs include proper maintenance and upgrades (e.g. low sag wires), and the capacity expansion of a radial line. Such investments could be rewarded with flowgate rights in the incremental capacity without affecting the existing FTR holders (we assume however that only FTRs are issued). In our three-node example in Sect. 6.6.2, PTDFs change substantially. In certain cases, the change in PTDFs could not exist (see Appendix 3) or be small if, for example, a line is inserted in parallel with an already existing line (see Appendix 3). In a large-scale meshed network the change in PTDFs may not be as substantial as in a three-node network. However the auction problem is non-convex and nonlinear, and a global optimum might not be ensured. Only a local optimum might be found through methods such as sequential quadratic programming.
- 9.
Hogan (2002b) shows that the economic dispatch model can be extended to a market equilibrium model where the ISO produces transmission services, power dispatch, and spot-market coordination, while consumers have a concave utility function that depends on net loads, and on the level of consumption of other goods.
- 10.
Function B is typically a measure of welfare, such as the difference between consumer surplus and generation costs (see Hogan 2002b).
- 11.
When security constraints are taken into account (n − 1 criterion) this is a large-scale problem, and it prices anticipated contingencies through the security-constrained economic dispatch. In operations the n − 1 criterion can be relaxed on radial paths, however, doing the same in the FTR auction of large-scale meshed networks may result in revenue inadequacy. We do not use the n − 1 criterion in our paper.
- 12.
In the PJM (Pennsylvania, New Jersey and Maryland) market design, the locational prices are defined without respect to losses (DC-load flow model), while in New York the locational prices are calculated based on an AC-network with marginal losses.
- 13.
FTRs could be options with a payoff equal to max (\( ({P_{\mathrm{ j}}} - {P_{\mathrm{ i}}})\ {{\mathrm{ Q}}_{ij }} \),0).
- 14.
See Hogan (1992).
- 15.
The set of point-to-point obligations can be decomposed into a set of balanced and unbalanced (injection or withdrawal of energy) obligations (see Hogan 2002b).
- 16.
This has been demonstrated for lossless networks by Hogan (1992), extended to quadratic losses by Bushnell and Stoft (1996), and further generalized to smooth nonlinear constraints by Hogan (2000). As shown by Philpott and Pritchard (2004) negative locational prices may cause revenue inadequacy. Moreover, in the general case of an AC or DC formulation to ensure revenue adequacy the transmission constraints must satisfy optimality conditions (in particular, if such constraints are convex they satisfy optimality). See O’Neill et al. (2002), and Philpott and Pritchard (2004).
- 17.
Revenue adequacy is the financial counterpart of the physical concept of availability of transmission capacity (see Hogan 2002a).
- 18.
Each element in the directional vector represents an FTR between two locations and the directional vector may have many elements representing combinations of FTRs.
- 19.
Proxy awards are then currently unallocated FTRs in the pre-existing network that basically facilitate the allocation of incremental FTRs and help to preserve revenue adequacy by reserving capacity for hedges in the expanded network.
- 20.
Another possibility would be to define every possible use of the current grid as a proxy award. However, this would imply that any investment beyond a radial line would be precluded, and that incremental award of FTRs might require adding capacity to every link on every path of a meshed network. The idea of defining proxy awards along the same direction as incremental awards originates from a proposal developed for the New Zealand electricity market by Transpower.
- 21.
We use “two-norm” to guarantee differentiability.
- 22.
See Shimizu et al. (1997).
- 23.
The model could also be interpreted as having multiple periods. Although we do not explicitly include in our model a discount factor, we assume that it is included in the investor’s preference parameter b.
- 24.
- 25.
According to Shimizu et al. (1997), the necessary optimality conditions for this problem are satisfied. The objective function and the constraints are differentiable functions in the region bounded by the constraints. A local optimal solution and Kuhn-Tucker vectors then exist.
- 26.
There are other methods available such as transformation methods (penalty and multiplier), and non-transformation methods (feasible and infeasible). See Shimizu et al. (1997).
- 27.
This method considers a tentative list of constraints that are assumed to be binding. This is a working list, and consists of the indices of binding constraints at the current iteration. Because this list may not be the solution list, the list is modified either by adding another constraint to the list or by removing one from the list. Geometrically, the active set method tends to step around the boundary defined by the inequality constraints. (See Nash and Sofer 1988).
- 28.
The mathematical derivation of these values is presented in Appendix 1.
- 29.
- 30.
Note that this result will depend on the network interactions. In some cases the amount of incremental FTRs in the preference direction will differ from the new capacity created on a specific line. However, it will always amount to the new capacity created as defined by the scalar amount of incremental FTRs times the directional vector.
- 31.
Whenever there is an institutional restriction to issue LTFTRs there will be an additional (expected congestion) constraint to the model. A proxy for the shadow price of such a constraint would be reflected by the preferences of the investor that carries out the expansion project (assuming risk neutrality and a price taking behavior). The proxy award model takes the “linear” incremental and proxy FTR trajectories to the after-expansion equilibrium point in the ex-post FTR feasible set to ensure the minimum shadow value of the constraint.
- 32.
The incremental 1–2 FTR can be decomposed into a 1–3 FTR and a 3–2 FTR.
- 33.
Additionally, Bushnell and Stoft explicitly define loads, nodal prices, and generation costs so that the effects on welfare are measured as the change in net generation costs. In contrast, we do not define a net benefit function of the users of the grid in terms of prices, generation costs or income from loads. Alternatively, our model maximizes the investors’ objective function in terms of incremental FTRs.
- 34.
We are grateful to William Hogan for the insights in the formulation of the following model.
- 35.
See Bushnell and Stoft (1997, pp. 100–106).
- 36.
This is however a particular type of welfare maximization since, as opposed to Bushnell and Stoft, costs of expansion are not addressed.
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Appendices
Appendix 1
6.1.1 Solution to Program (6.30)
The Lagrangian of the problem is:
where \( \gamma, \theta, \zeta, \varepsilon, \varphi, \kappa, \) and \( \pi \) are the multipliers associated with the respective constraints.
At optimality the Kuhn-Tucker conditions are:
Equation (6.46) gives \( {\delta_{12 }}=1 \). Equation (6.38) gives \( \gamma ={b_{12 }} \). Equation (6.43) gives \( \gamma ={b_{12 }} \), (6.40) \( \zeta =\gamma /{p_{12 }}={b_{12 }}/{p_{12 }} \) (\( \varepsilon \) is zero because the constraint is redundant), and (6.41) \( \theta =0 \). From this it follows (6.39) that \( \varphi =0 \) Furthermore (6.44) gives \( \hat{t}={C_{12 }}-{T_{12 }} \). Equation (6.42) implies that \( a=C_{12}^{+}-{T_{12 }}-\hat{t}=C_{12}^{+}-{C_{12 }} \).
6.1.2 Solution to Program (6.32)
The Lagrangian of the problem is:
where \( {\gamma_1}\;\mathrm{ and}\;{\gamma_2} \) are the Lagrange multipliers associated with transmission capacity on the lines 1–3 and 1–2 in the expanded network, respectively. \( \zeta \) is the multiplier associated with the Kuhn-Tucker condition of transmission capacity in the pre-expansion network for line 1–3. This line has the Lagrange multipliers \( \lambda \) associated with it before expansion. \( \varepsilon \) is the investor’s marginal value of transmission capacity in the pre-expansion network when allocating incremental FTRs. The normalization condition has the multiplier \( \varphi \) and the non-negativity conditions have the associated multipliers \( \kappa \) and \( \pi \). The first order conditions are:
The solution for the first order conditions is given by:
with
Appendix 2
This appendix derives the power transfer distribution factors (PTDFs) for the three-node network with two parallel lines, and where all lines have identical reactance. The net injection (or net generation) of power at each bus is denoted P i . We have the following relationship between the net injection, the power flows P ij and phase angles \( {\theta_i} \) (Wood and Wollenberg 1996):
where \( {x_{ij }} \) is the line inductive reactance in per unit.
We can write the power flow equations as:
The matrix is called the susceptance matrix. The matrix is singular, but by declaring one of the buses to have a phase angle of zero and eliminating its row and column from the matrix, the reactance matrix can be obtained by inversion. The resulting equation then gives the bus angles as a function of the bus injection:
The PTDF is the fraction of the amount of a transaction from one node to another node that flows over a given line. PTDF ij,mn is the fraction of a transaction from node m to node n that flows over a transmission line connecting node i and node j. The equation for the PTDF is:
where x ij is the reactance of the transmission line connecting node i and node j and x im is the entry in the ith row and the mth column of the bus reactance matrix. Utilizing the formula for the specific example network gives:
Appendix 3
6.3.1 Transmission Investment That Does Not Change PTDFs
An example on an investment that does not change the PTDFs of the network is shown in Fig. 6.5 where there is an expansion of line 1–3 from 900 to 1,000 MW transmission capacity. The associated feasible expansion FTR set is shown in Fig. 6.6. We observe that whatever feasible FTRs that existed before expansion, none of these will become infeasible after the expansion.
6.3.2 Transmission Investment That Does Change PTDFs
Figure 6.7 shows a three-node network where a line is inserted in parallel with an existing line between the nodes 2 and 3. Inserting a parallel line with identical reactance as the existing line halves the total reactance between nodes 2 and 3. As a result the PTDFs of the expanded network change.
change to
Furthermore, the inserted line has identical transmission capacity to the existing one so that the total transmission capacity is doubled between the buses 2 and 3. However, the simultaneous interaction of the reactances and transmission capacities changes the feasible expansion FTR set as illustrated in Fig. 6.8. Then some of the pre-existing FTRs may become infeasible.
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Kristiansen, T., Rosellón, J. (2013). A Merchant Mechanism for Electricity Transmission Expansion. In: Rosellón, J., Kristiansen, T. (eds) Financial Transmission Rights. Lecture Notes in Energy, vol 7. Springer, London. https://doi.org/10.1007/978-1-4471-4787-9_6
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