Abstract
We develop an analytical model to derive the competitive market equilibrium for electricity spot and reserve markets under uncertain demand and renewable electricity generation. The first-best market equilibrium of the model resembles the result of a centralized co-optimization of the markets involved. We then derive the welfare-optimal provision of reserves. At first-best, cost of reserve capacity is balanced against expected cost of outages. Comparative statics and a numerical application based on German secondary reserve provision imply an increase of reserve provision with a growing share of renewable generation. Furthermore, a growing share of renewable generation decreases the level of reliability as measured in energy not served since required reserves to balance higher expected deviations will be more expensive, resulting in a trade-off between higher reserve costs and costs of energy not served.
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Notes
This work is developed for a power system within the European context and therefore the wording refers to European markets. This holds especially for the use of the term “real time” that does not refer to a US-type real-time market but denotes the point in time when uncertainty is revealed.
Positive reserves means being able to ramp up whereas negative reserves means to ramp down electricity generation in case of imbalances.
The continental European countries are organized in one (formerly Union for the Co-ordination of Transmission of Electricty, UCTE) of the five regional groups forming the European Network of Transmission System Operators for Electricity (ENTSO-E).
A novel dimensioning approach is currently developed. Thereby the selection of historical data to be used for the dimensioning period is modified, yet no economic considerations are included (Consentec, 2018).
The way that reserves are determined in the German market may be better suited to traditional contingencies than to the uncertainty of renewable generation. With contingencies, the probabilities of failure remain reasonably constant over time, and as a result, committing reserve capacity in advance is reasonable. In contrast, the uncertainty of renewable generation gets smaller as one gets closer to real time. Hence, the question of when should reserves be committed is an interesting one. We thank an anonymous referee for pointing this out.
During the so-called prequalification process, the grid operators verify that the supplier meets the technical requirements.
A recently introduced mechanism that also partially considers the energy price has been removed again and replaced by the old system (Bundesnetzagentur, 2019).
In reality, in addition to load and RES generation forecast errors, more uncertainties and resulting deviations from scheduled quantities, such as power plant failures, schedule shifts, and noise from RES generation and load, occur and are considered in the current practice of reserve dimensioning (cf. Sect. 2.1). Yet for the sake of analytical (and also numerical, cf. Sect. 4) feasibility we limit the uncertainties considered to the presented forecast errors as the primary objective of this paper is to develop a novel methodology rather than reproducing actual outcomes.
We do not allow reserve provision from RES. So far, RES are only allowed to bid into the tertiary reserve market. With some change in notations and conventions, our model may also be extended to the case of RES providing spinning reserve.
The level of reserve requirements is the decision variable of the welfare maximization (cf. Sect. 3.4). As this is made well ahead of the spot market, it is given at the time of market clearing.
By definition, this implies infinite generation capacity where availability is a matter of prices (spot price and reserve capacity price), i.e. results from the level of demand and the value of lost load (s. below).
Strictly speaking, ramping is the change in the dispatch of a generating unit from one period to the next. In our model we approximate ramping capabilities by expressing them as maximum shares of generation capacity; see details in Sect. 3.3.
This condition is valid for primary and secondary reserves in the German reserve market design. For providing tertiary reserves, generation units can be online or offline. We abstract from differences of these reserves with respect to activation and response speed as existent e.g. in the German reserve power market (cf. Sect. 2.1).
Hence, whether the reserve market uses pay-as-bid (as currently in Germany) or uniform price clearing, makes neither a difference in the bid selection nor in the marginal cost.
In general, we use capital letters and Greek letters with capital-letter subscripts for stochastic variables. Realized values are denoted by the corresponding small letters and Greek letters with small-letter subscripts.
Hence, there is zero probability of negative residual demand values. This assumption simplifies the analysis, but could easily be relaxed.
For convenience, we include here the event \(D=\bar{D}\) where no reserves are needed; note, however, that this event has zero probability.
Ramping constraints are technically similar both for positive and negative reserves. In order to allow for exceptions from the rule and to identify separately the effects on positive and negative reserve provision, \(\alpha \) and \(\beta \) are allowed to differ.
Technologies differ with respect to flexibility. More specifically, units higher up in the merit order (e.g. gas-fired power plants) are usually more flexible. However, for the sake of analytical tractability a constant ramping constraint is assumed for conventional generation capacity irrespective of merit-order position.
For typical conventional power plants, \(\gamma \) is in the order of 0.5 whereas \(\alpha \) and \(\beta \) are approximately equal to 0.2 (Swider, 2006).
In the German system, the energy prices for the electricity generated from reserves are determined as result of the reserve procurement auctions based on the corresponding bids by the generating companies. Those will submit bids based on their marginal cost such that they do not incur losses. Correspondingly, the two last terms are positive. Given the low probability of activation (cf. Bundesnetzagentur, 2017), the corresponding profit contributions are nevertheless low; cf. also Just and Weber (2008). Dropping those two terms hence does not significantly impact results while it considerably simplifies the subsequent analysis.
Note that producers with high marginal costs may be producing at a loss for the spot market, but nevertheless do so in order to be able to sell positive reserves capacity if overall profits are non-negative.
Note that in this paragraph the values of \(p_{s}\), \(p^{+}\) and \(p^{-}\) are taken as given so \(k_{m}\), \(k_{0}^{+}\) and \(k_{0}^{-}\) will depend on these values. The next paragraph derives the equilibrium values of the latter triad and later in the section the equilibrium prices—the former triad—are derived.
Note that our assumption that the energy components of reserve provision are set equal to marginal costs allows us to derive the equilibrium prices without taking into account the stochastic realizations at stage 3.
As the optimization problem takes the expected social welfare as objective, the first term turns out to be constant.
This formulation is equivalent to minimizing total costs since demand is stochastic but inelastic.
Depending on where \(k_{r}^{-}\) is located, there are three different cases that need to be considered but they result in the same formula, i.e. (3.33).
Calling negative reserves from RES in contrast to using conventional negative reserves does not save variable generation costs such as fuel costs. An alternative shutdown of conventional capacity incurs further costs. Hence, the applied calling order is economically rational if allowed under the respective regime. Furthermore, reducing wind generation RES simultaneously increases residual demand, i.e. decreasing the need for additional negative reserves.
We apply the Fundamental Theorem of Calculus to the integral terms.
The calibration of \(\alpha \) is confirmed by own calculations. In line with the 5-min requirement of secondary reserves, applying power plant gradients (Swider, 2006) on installed capacities of German power plants (ENTSO-E, 2018) provides an average maximum upramping potential of 16–27% of installed capacity.
Note that in Table 2 the pairs of values for \(\sigma \) the former value indicates the standard deviation of the forecast error and the latter value that of RES noise.
This can be seen analytically by a comparative statics analysis of the first-order condition (3.40) for optimal positive reserves.
And, obviously, given constant RES generation high/low values of residual demand correspond to high/low values of load.
We would like to thank an anonymous referee for this point.
That is, where all conventional generation capacity is provisioned for reserves, subject to the ramping constraint.
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Appendix: Proofs
Appendix: Proofs
1.1 Proposition 1
Proof
Evaluating the derivative (3.39) at the lowest possible value of positive reserves, i.e. zero, we get:
where the inequality follows from \(v>c\left( \overline{D}\right) \), \(c^{\prime }{>0 }\), \(K_{r}^{-}\le \overline{D}\) and \(k_{0}^{-}\le \overline{D}\).
Evaluating the derivative at the largest possible value of positive reserves,Footnote 37\(r_{max}^{+}=\frac{\alpha }{1-\alpha }\overline{D}\) we get
The last three terms are easily seen to be negative, since c is increasing. The first term is positive, but for reasonable distributions of D it is very small. In what follows we assume \(\left. \frac{\partial E\left[ S\right] }{\partial r^{+}}\right| _{r^{+}=r_{max}^{+}}<0\), so that there is at least one solution to the first-order condition (3.40).
As for the second-order condition for maximum expected welfare, since \(r^{-}\) is set and fixed at its maximum value, it suffices to show that the second derivative with respect to \(r^{+}\) is negative. After some simplification we get
where we omit the subscript D on the distribution function \(F_{D}\) and probability density \(f_{D}\) in order to reduce clutter. Since \(c^{\prime }{>0, v>c\left( k_{m}\right) }\) and \(1-\alpha -\beta >0\), we get \(\frac{\partial ^{2}E\left[ S\right] }{\left( \partial r^{+}\right) ^{2}}<0\). \(\square \)
1.2 Proposition 2
Proof
First, if \(\tau \) is a parameter (e.g., v, \(\alpha \), \(\beta \)), then, differentiating through the first-order condition (3.40) with respect to that parameter and rearranging yields:
where the right-hand side is evaluated at \(\hat{r}^{+}\). Since the denominator is positive (by virtue of the second-order condition for maximum), the sign of the numerator will also provide the sign of the derivative of \(\hat{r}^{+}\) with respect to the parameter.
In the remainder of this proof, to reduce clutter, we shall omit the ‘hat’ on the optimal value of positive reserves and simply write \(r^{+}\) for the optimal value.
First, differentiating (3.39) with respect to v we get
which establishes (a).
To prove (b), we differentiate (3.39) with respect to \(\alpha \) and get
where we have used \(\frac{dK_{r}^{+}}{d\alpha }=-\frac{1}{\alpha ^{2}}\left[ D-k_{m}\right] \), \(\frac{dk_{0}^{+}}{d\alpha }=\frac{1}{\alpha ^{2}}r^{+}\), \(\frac{dK_{r}^{-}}{d\alpha }=0\) and \(\frac{dk_{0}^{-}}{d\alpha }=0\). Since \(c'>0\), \(k_{m}\ge K_{r}^{+}\), \(k_{m}\ge k_{0}^{+}\) all the integrands are found to be negative. Thus, the right-hand side as a whole is positive and (b) is confirmed.
To see that (c) holds we differentiate (3.39) with respect to \(\beta \) and get
where we have used \(\frac{dK_{r}^{+}}{d\beta }=0\), \(\frac{dK_{r}^{-}}{d\beta }=\frac{1}{\beta }\left[ \overline{D}-D\right] \) and \(\frac{dk_{0}^{-}}{d\beta }=\frac{1}{\beta }r^{-}\). Note that both expressions inside the square brackets are of the form
with \(D_{0}<D_{1}\). This expression is strictly positive if c is strictly convex, zero if c is linear, and negative if c is concave. Hence, (c) is established.
As for (d), assume, for simplification of presentation, but without loss of generality, that the variance of D is equal to 1. Introduce a mean-preserving perturbation of the variance by introducing a new distribution, viz.
Here it is crucial that we assume D to be an unbiased prediction of d so \(E\left[ D\right] =\overline{D}\) under the original distribution \(F_{D}\).
Under \(F_{\sigma }\) the expectation of D is still \(\overline{D}\), but its variance is \(\sigma ^{2}\). Obviously, the probability density of \(F_{\sigma }\) is \(f_{\sigma }\left( D\right) =\frac{1}{\sigma }f_{d}\left( \frac{D-\overline{D}}{\sigma }+\overline{D}\right) \) and its derivative is \(f_{\sigma }'\left( D\right) =\frac{1}{\sigma ^{2}}f_{d}'\left( \frac{D-\overline{D}}{\sigma }+\overline{D}\right) \).
The derivatives of \(F_{\sigma }\) and \(f_{\sigma }\) with respect to \(\sigma \) are given by
A lengthy calculation, employing integration by parts of integrals involving \(f_{\sigma }'\left( D\right) \), leads, after much simplification, to the expression
All three terms of the right-hand side are positive and (d) follows.
To see (e) introduce a new marginal cost function
where a is a non-negative constant. Clearly, \(c_{a}\) satisfies all conditions imposed on c. Moreover, a drops out of all but the first term of (3.39) so differentiating with respect to a yields
which implies that (e) holds.
Finally, introduce a multiplicative shift of c by defining
Employing \(c_{b}\) as a new marginal cost function, differentiating (3.39) with respect to b and using the first-order condition (3.40) for the optimal value of positive reserves (this is the only place in this proof that we rely on the fact that we evaluate the derivatives calculated at that value) we get
which establishes (f). \(\square \)
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Baldursson, F.M., Bellenbaum, J., Niesen, L. et al. Welfare optimal reliability and reserve provision in electricity markets with increasing shares of renewable energy sources. J Regul Econ 62, 47–79 (2022). https://doi.org/10.1007/s11149-022-09454-7
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DOI: https://doi.org/10.1007/s11149-022-09454-7