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Tuca Zbarcea & Asociatii

Electricity in motion – new rules for wholesale trading and connection to the grid

27 Ianuarie 2022   |   Cosmin Stăvaru, Partner - Bondoc si Asociații SCA

The Romanian legislation on electricity trading and grid connection is getting in the right direction despite the persisting grey areas and we hope to see new production capacities installed (mostly renewable), sooner rather than later, to meet the Green Deal targets and put a stop to the price escalation in the current energy crisis.

 
 
Significant changes to the legal framework governing the electricity sector were enacted at the end of 2021 under Government Emergency Ordinance no. 143/2021 (Ordinance 143) and ANRE Order no. 137/2021 (Order 137).  Among these changes, two categories are of outmost importance for producers, as detailed below.

Liberalization of PPAs – enhanced bankability

The change that was most expected by electricity producers was, of course, the express allowance of bilaterally negotiated electricity sale contracts (PPAs) banned since 2012 under art. 23 of Law no. 123/2012 (Energy Law), according to which electricity transactions on the wholesale market ought to be made in a transparent, public, centralized and non-discriminatory manner, while bilateral contracts were expressly allowed as a rule only on the retail market. The Energy Law also defined the “centralized market”, put it simply, as the market intermediated by the “centralized market operator” and to this date only Opcom (a subsidiary of Transelectrica – the transmission and system operator (TSO)) has been licensed as such. Consequently, all wholesale electricity transactions have so far been concluded on the various Opcom platforms.

Ordinance 143 repeals this provision and, thus, eliminates the obligation of privately-owned producers to trade electricity on centralized markets. Moreover, Ordinance 143 makes it clear that wholesale transactions include directly negotiated bilateral transactions. Thus, the Energy Law is now aligned with the EU regulations on PPAs, although the impact is rather confirmatory since ANRE has made steps as of the end of 2019 to reintroduce the possibility of directly negotiated contracts under the umbrella of Regulation (EU) 2019/9431. It would appear that this is the end of the long saga of PPAs regulation in Romania (discussed in the previous articles on this topic) but is it so? Ordinance 143 needs to be either approved as such or amended by the Parliament, so that, purely hypothetically speaking, the liberalization of the PPAs could be reversed but this should not happen in practice. Therefore, the renewable projects will become more bankable and soon the banks will likely plunge again into this market, perhaps with some reticence after the issues faced during the financing of the first renewable wave but with increased confidence in the EU framework driving things forward. 

Liberalization of the PPAs goes hand in hand with breaking up the monopoly of Opcom as single centralized market operator2. A single market operator seems to have been the intention of the legislator in 2012 all along, an indicator being that, unlike the definition of all other operators (such as distribution or transmission operators) which referred to “any person” meeting a set of requirements, the definition of the market operator referred to “the person” who operates centralized markets. In any case, Bursa Română de Mărfuri - Romanian Commodities Exchange (BRM) unsuccessfully tried to obtain from the regulatory authority (ANRE) a license as an electricity market operator. However, Ordinance 143 makes a distinction between a (standard) “market operator”, whose role is to match the electricity sale and purchase offers, and a “market operator designated” by ANRE, whose role is to fulfil the tasks involved by the single coupling of the day-ahead and intra-day markets, opening, thus, the perspective of several market operators. Based on this understanding, it appears that BRM has reapplied for a license as a wholesale market operator in the context of these new changes3. Also, based on the broad definition of electricity markets laid down in Regulation (EU) 2019/943 and Ordinance 143 that encompasses other types of markets besides regulated electricity exchanges (such as, for example, over-the-counter markets), BRM announced the launching of a platform for electricity bilateral contracts with the aim to becoming an alternative to Opcom.

Another important aspect regulated by Ordinance 143 is the assertion of the general principle that participation to any electricity markets is on a voluntary basis for all market participants, in line with the EU regulations, including the balancing market traditionally deemed as a mandatory market (of course, the balancing responsibility remains unaffected). EU regulations mirrored by Ordinance 143 aim to minimize the recourse to the balancing market by allowing the market participants to trade energy as close as possible to real time and at least until the intra-day market cross-zonal gate closure time, with the possibility to trade energy within timeframes at least as short as the imbalance settlement period on both day-ahead and intra-day markets.

New rules for grid connection – juggling concepts

Renewable and high efficiency cogeneration electricity will no longer expressly benefit from guaranteed / priority access to electric grids but will benefit from priority dispatching. However, the takeover in the power grid is “guaranteed” for the electricity produced from renewable sources in power plants currently receiving green certificates (i.e., first wave of renewable capacities). In both situations, the technical details are to be set forth in subsequent ANRE regulations. At the same time, the definition of “priority access” is maintained in the Energy Law, although the concept is not used as such anywhere, being a distinctly defined term from “priority dispatching” (which, in essence, is a sort of overall guaranteed access) and “guaranteed access” (which mainly refers to the electricity sold on the competitive market). In any way, both priority dispatching and priority access function as long as the security of the national energy system is not affected, while guaranteed access seems to apply unconditionally from this perspective (at least there is no explicit restriction).  Before Ordinance 143, the renewable power plants of maximum 1 MW installed capacity benefitted from priority access and all renewable power plants benefitted from guaranteed access and priority dispatching. A hotchpotch of similar technical concepts or a fine distinction?

Ordinance 143 further details the regime of grid access by (i) forbidding the TSO to refuse connection, on one hand, on the grounds of additional costs incurred for the necessary increase of the grid capacity in the proximity of the connection point, or on the other hand, by invoking possible future limitations to the connection capacity such as a grid congestion in distant areas, and (ii) regulating some coordinates for grid access limitations that the TSO is allowed to impose. Thus, the TSO may impose limitations on the guaranteed grid access capacity (i.e., presumably, the one approved under the technical connection permit) or approve the connection subject to operational limitations, provided that any such limitations were approved by ANRE based on transparent and non-discriminatory procedures. Also, notably, Ordinance 143 forbids the application of limitations to power plants that incur the cost related to securing unlimited grid connection (not clear if this refers to grid reinforcement/upgrading costs or something else).  Such provisions appear to be quite relevant for areas where the electric grid is overloaded such as Dobrogea region.

Another novelty on the grid connection front is the regulation of the possibility given to grid operators to apply market-based methods for the allocation of existing capacity (as per further ANRE implementation regulations) where the existing capacity cannot accommodate all applicants. The allocation of capacity is currently based on first come first served principle (the requested capacity being allocated within the available limit in the chronological order of the connection requests, although the current grid connection regulation approved under ANRE Order no. 59/2013 is not quite clear on this aspect).   

In relation to the available grid capacity, the legislator has made efforts to increase the transparency of the connection process in the past years and the level of communication / information to the market in this respect. By the same logic, Order 137 (applicable as of March 2022) sets forth a set of technical criteria and rules for the establishment of the available capacity in the electric grids by the TSO and requires the publication of the available capacity on the TSO’s website (at both transmission and distribution grid levels) on a monthly basis starting 1 April 2022, twice a month starting 1 July 2022 and every two weeks as of the 1st of October 2022. TSO must issue an operational procedure for determining the available capacity to be notified to ANRE (until 3 March 2022 and 15 days after any update). Also, Order 137 requires grid operators to respond to an information request regarding the connection following the information published on the TSO’s website on the grid capacity within 15 days.

Furthermore, important clarifications are brought with respect to the connection to a direct line –producers may supply all their customers through a direct line, without being subject to disproportionate costs or administrative procedures. Before Ordinance 143, the possibility to supply customers through a direct line was allowed only if there was no reasonable alternative (economically and technically) for access to the public interest grid. Therefore, the direct lines have become now permitted without conditionality and this could be beneficial to, for example, solar power plants or cogeneration (combined heat and power) plants designed to provide for large industrial customers. Such investments could be structured as turn-key projects or design-build-own-operate-transfer (DBOOT) type of projects. Ordinance 143 exempts producers and prosumers from the obligation to acquire green certificates, but the extent of this exemption is kind of fuzzy: while it seems to apply only for prosumers of up to 400 kV installed capacity, it is less clear how it applies in respect of the producers (just for their internal consumption of electricity or also for the electricity supplied to their customers through a direct line)4. Therefore, comparing DBOOT type of projects to turn-key projects from this perspective may prove difficult.

All in all, the Romanian legislation on electricity trading and grid connection is getting in the right direction despite the persisting grey areas and we hope to see new production capacities installed (mostly renewable), sooner rather than later, to meet the Green Deal targets and put a stop to the price escalation in the current energy crisis.   



[1] Starting with ANRE Order no. 236/2019 and continuing with Orders no. 65/2020 and no. 26/2021.

[2] The concept of “centralized market” was re-defined as “organized market” by Ordinance 143, in line with EU regulations.
[3] https://www.zf.ro/burse-fonduri-mutuale/bursa-romana-marfuri-lansa-februarie-platforma-negociere-20457503.
[4] A technical error exists in Ordinance 143 when regulating the exemption for producers - an incomplete text appears to be copy-pasted from art. 8 of Law no. 220/2008 which sets forth 2 situations where producers are required to buy green certificates (one of them being for the electricity delivered directly to end customers through a direct line).
 
 

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