The European regulatory framework
On May 4, 2017 the European Commission published a proposed revision of the European Market Infrastructure Regulation (EMIR). Essentially the proposal endorses monitoring thresholds that, if exceeded, trigger the central clearing obligation for OTC derivatives on the part of non-financial counterparties, and specifies that the clearing obligation applies only for the asset classes for which the clearing thresholds are exceeded. At the same time, the Commission’s proposal also confirms the hedging exemption and changes the method for calculating the position used in the annual comparison with the clearing threshold, basing it on the average month-end positions for March, April and May. Furthermore, the Commission proposes an overall simplification of the reporting requirements imposed on financial and non-financial counterparties.
On December 14, 2017 the EU Council published its general approach for the negotiations with the European Commission and the European Parliament during the trilogue process that will be conducted throughout 2018. The Council supported the general substance of the Commission’s proposal, offering a few proposed amendments concerning the annual calculation of the position and simplification of the reporting requirements.
Entry into force of MIFID II/ MIFIR
On July 1, 2016 Regulation 2016/1033/EU and Directive 2016/1034/EU entered force, postponing the entry into force of the rules governing the provision of investment services in Europe (the MIFIR Regulation and the MIFID II Directive, respectively) from January 3, 2017 to January 3, 2018. Accordingly, the deadline for transposing the legislation by the Member States has been postponed from July 3, 2016 to July 3, 2017.
The “Clean Energy for all Europeans” package
On November 30, 2016, the European Commission issued the “Clean Energy for all Europeans” package of measures for proposed legislation on European climate and energy policy. In particular, the package includes the following regulations and directives, some of which are revised versions, others newly issued: the Electricity Regulation, the ACER Regulation, a Risk Preparedness Regulation, the Energy Union Governance Regulation, the Electricity Directive, the Renewable Energy Directive, the Energy Efficiency Directive and the Energy Performance of Buildings Directive. They are expected to come into force as from 2019.
In line with the sustainability and climate change mitigation objectives, new binding targets at the EU level for 2030 will be introduced: 27% of gross final energy consumption from renewable sources, a 30% energy efficiency target and a 40% reduction in greenhouse gas emissions. The Renewable Energy Directive introduces a stable regulatory framework for investors. Member States will have to adopt a market approach to support renewables. Incentive mechanisms should follow harmonized principles such as cross-border opening, the non-retroactivity of measures and long-term visibility for support mechanisms (at least three years). Administrative barriers for corporate longterm PPAs to finance renewables must be removed where appropriate and authorization procedures simplified. The Commission proposal also requires Member States to increase the share of renewable resources in heating and cooling and sets more stringent criteria for the sustainability of bioenergy.
The Electricity Regulation and Directive propose an integrated revision of the design of the electricity market to make the integration of renewable energy more efficient and the treatment of different generation technologies (conventional and renewable) more equitable, introduce greater granularity in trade, move market close closer to real time, open the balancing market to all generation sources and demand (through aggregation), set non-discriminatory and market-based dispatching rules (elimination of priority dispatch for new renewables plants above 500 kW).
It also introduces an opening to long-term contracting and remuneration of capacity mechanisms, subject to the results of a study of European capacity adequacy and to limitations in the atmospheric emissions of CO2 to access the same. Conditions for the emergence of signs of scarcity are improved and price caps removed.
With regard to new technologies and new market players, the package envisages measures to support the integration of storage technologies, aggregators and customer participation (demand-side response). Other provisions concern compulsory installation of charging points for electric vehicles in new public buildings and the promotion of smart grids and buildings.
The Distribution System Operators (DSOs) are recognized as increasingly important actors in the electricity system and the proposals include the creation of a new European DSO entity, the introduction of harmonized principles at the European level for grid rates, the possibility of purchasing and providing flexibility services locally to solve congestion problems. There are no additional requirements on unbundling.
Finally, the package establishes the centrality of consumers in the electricity market through their active participation by way of demand aggregation and demand flexibility services (demand response), removal of price regulation, the introduction of mandatory dynamic pricing options, price comparison tools and basic information in electricity bills.
The Energy Efficiency Directive establishes that Member States should contribute to the achievement of the European target with indicative national contributions. In addition, proposals include extending beyond 2020 the energy efficiency obligations of Member States for final consumption to be met through energy efficiency obligation schemes or alternative measures.
The European Commission proposes the introduction of a decarbonization target for 2050 in the building sector and changes aimed at encouraging the use of smart tools like automation and control systems and performance indicators, promoting charging infrastructure for electric vehicles and the correlation between the financing of measures with the results achieved in energy terms.
The European Commission also proposes a new plan containing a list of energy products to be evaluated, reviewed and subjected anew to regulations containing minimum energy efficiency requirements (including new products: building automation and control systems, photovoltaic panels and ICT products).
Between its presentation in 2016 and the end of 2017, the European Parliament and European Council worked on a number of dossiers to arrive at a common position on the Commission’s proposals. In 2018 trilogue meetings between the European Parliament, European Council and European Commission will be held to prepare the final text of the directives and regulations that comprise the Clean Energy package.
”Clean Mobility” package
In 2017 the European Commission unveiled its “Clean Mobility” package, containing a series of legislative proposals and other initiatives to make traffic safer, encourage smart road charging, reduce CO2 emissions, air pollution and congestion. The package consists of two parts: a first part published in May 2017 and a second in November 2017. Additional proposals, including one on CO2 emission standards for heavy-duty vehicles, will be published in the 1st Half of 2018.
The main initiatives in the first part of the package are designed to encourage the adoption of road charging systems based on distance traveled to reflect more realistic use, and emissions and pollution produced by vehicles.
More specifically, the proposal envisages the inclusion of the external costs of noise and air pollution in road charges in addition to advantages for zero-emission vehicles. The second part of the package contained three primary initiatives. The first initiative establishes CO2 emission standards for new cars and light vehicles up until 2025 (a 15% reduction compared with the 2021 limits) and until 2030 (a 30% reduction). It also envisages a reward mechanism to accelerate the transition towards low and zero-emission vehicles. The second initiative, a proposed revision of the Clean Vehicles Directive (Directive 2009/33/EC), provides a clear definition of “clean vehicle” (based on combined CO2 and air pollutant emissions thresholds) and aims to promote clean mobility solutions in public tenders through a system of procurement targets for Member States, thereby offering strong demand-side stimulus and further deployment of clean mobility solutions.
Finally, the third initiative involves an action plan and a series of investment solutions for trans-European deployment of alternative fuels infrastructure, with the aim of increasing the level of ambition of national plans presented within the framework of the directive on the deployment of an alternative fuels infrastructure (Directive 2014/94/ EU), increasing investment and improving consumer acceptance.
The Italian regulatory framework
The current structure of the Italian electricity market is the result of the liberalization process begun in 1992 with Directive 1992/96/EC, transposed into Law with Legislative Decree 79/1999. This decree provided for: the liberalization of electricity generation and sale; reserving transmission and ancillary services to an independent network operator; the granting of concessions for distribution to Enel and other companies run by local governments; the unbundling of network services from other activities.
The introduction of Directives 2003/54/EC and 2009/72/ EC (transposed with Law 125/2007 and Legislative Decree 93/2011, respectively) in Italy lent further impetus to the process, particularly through the complete opening of the retail market and the confirmation of the total independence of the national transmission network operator (already provided for in the decree of the Prime Minister of May 11, 2004) by separating its ownership from that of other electricity operators.
The process of liberalizing the natural gas market began with Directive 1998/30/EC, transposed in Italy through Legislative Decree 164/2000, calling for the liberalization of the import, production and sale of gas and the separation of network infrastructure management from other activities through the establishment of distinct companies. As regards the model for unbundling transport from other nonnetwork activities, with Resolution 515/2013/R/gas, the Authority for Electricity, Gas and Water System (AEEGSI) mandated the transition to ownership unbundling pursuant to Directive 2009/73/EC.
With the decree of November 10, 2017 the Ministers of the Environment and of Economic Development adopted the 2017 National Energy Strategy. The document, in line with the European Energy Union Plan and the Energy Roadmap 2050, establishes the development targets for the energy sector by 2030 in terms of competitiveness, sustainability, the environment and procurement security. Under the 2018 Budget Law (Law 205 of December 27, 2017), the Authority for Electricity, Gas and Water System has become the Italian Regulatory Authority for Energy, Networks and Environment ( “ARERA”) and is responsible for regulating the waste sector as well.
The following sections discuss the general regulatory framework and the main regulatory measures taken in 2017 for the industry as a whole and for specific segments.
Generation and the wholesale market
Wholesale electricity generation and market
Electricity generation was completely liberalized in 1999 with Legislative Decree 79/1999 and can be performed by anyone possessing a specific permit.
The electricity generated can be sold wholesale on the organized spot market (IPEX), managed by the Energy Markets Operator (GME), and through organized and overthe- counter platforms for trading forward contracts. The organized platform includes the Forward Electricity Market (MTE), managed by the GME, in which forward electricity contracts with physical delivery are traded. Trading can also be conducted in derivatives with electricity as their underlying are traded. The organized market for such transactions is the forward market (IDEX), operated by Borsa Italiana, while financial derivatives can also be negotiated on OTC platforms.
Generators may also sell electricity to companies engaged in energy trading, to wholesalers that buy electricity for resale at retail, and to the Acquirente Unico (Single Buyer), whose duty is to ensure the supply of energy to enhanced-protection-service customers.
In addition, for the purposes of the provision of dispatching services, which is the efficient management of the flow of electricity on the grid to ensure that deliveries and withdrawals are balanced, electricity generated may be sold on a dedicated market, the Ancillary Services Market (MSD), where Terna procures the required resources from generators.
The AEEGSI and the Ministry for Economic Development are responsible for regulating the electricity market. More specifically, with regard to dispatching services, the AEEGSI has adopted a number of measures regulating plants essential to the security of the electrical system. These plants are deemed essential based on their geographical location, their technical features and their importance to the solution of certain critical grid issues by Terna.
In exchange for being required to have electricity available and providing binding offers, these plants receive special remuneration determined by the AEEGSI.
Resolutions 910/2017/R/eel, 928/2017/R/eel and 911/2017/R/ eel admitted Enel Produzione’s essential plants of Assemini, Brindisi Sud and Portoferraio to the cost reimbursement system for 2018. Enel Produzione’s Porto Empedocle plant has instead been included in the multi-year cost reimbursement system until 2025. The remaining capacity is subject to alternative contracts.
Since the launch of the market in 2004, the regulations have provided for a form of administered compensation for generation capacity. In particular, plants that make their capacity available for certain periods of the year identified in advance by the grid operator to ensure the secure operation of the national electrical system receive a special fee.
In August 2011, the AEEGSI published Resolution ARG/ elt 98/11, which establishes the criteria for introducing a market mechanism for compensating generation capacity that replaces the current administered reimbursement. This mechanism involves holding auctions through which Terna will purchase from generators the capacity required to ensure that the electricity system is adequately supplied in the coming years.
With a decree of the Minister for Economic Development of June 30, 2014, the capacity market operational mechanism previously issued for consultation by the AEEGSI was approved.
The mechanism is based on the allotment, by auction, of option contracts (reliability options) that provide for payment of a premium, established in the auction with the setting of a marginal price, against which a generator undertakes to return any positive difference between the price formed on the spot electricity and auxiliary services market and a benchmark price set ex-ante in the option contract.
The rules approved provide for a cap for the premium to be paid for existing capacity and for newly constructed capacity.
With Resolution 95/2015/I/eel, the Authority proposed to the Ministry for Economic Development that the opening of the capacity market be moved forward, with an initial phase of implementation beginning in 2018 and ending in 2021, with the launch of full operation of the mechanism.
Under the AEEGSI’s proposal, during the initial phase, there would be no direct resources permitted in the market, but their contribution would be measured for statistical purposes. During the initial implementation phase, Terna would assign annual products with an increasing planning horizon of less than four years (the period between the auction and the start of delivery of the assigned products). Once fully implemented, explicit participation would be open to foreign resources, the horizon would be four years, while the duration of the product would remain annual.
The rules governing the capacity market must be approved by the Ministry for Economic Development subject to notification and approval of the mechanism by the European Commission.
On February 7, 2018 the European Commission issued a favorable opinion on the Italian mechanism for the capacity market, providing a number of clarifications concerning certain features of the market design.
With Resolution 398/2017/R/eel, the AEEGSI, within the scope of the temporary system for the remuneration of generation capacity, defined the criteria for determining the “S” fee for the period from January 1, 2015 to December 31, 2015, allocating €60 million for payment of that fee.
The AEEGSI provided for Terna SpA to recognize payments for 2015 by June 30, 2017.
With Resolution 418/2017/R/eel, the AEEGSI, within the scope of the temporary system for the remuneration of generation capacity, defined the criteria for determining the CAP1 fee for the period between January 1, 2016 and December 31, 2016. Under the provisions of that resolution, the amount allocated to cover charges for payment of that fee was €130 million. The AEEGSI provided for Terna SpA to recognize payments for 2016 by June 30, 2017.
With Resolution 844/2017/R/eel, the AEEGSI also specified the criteria for determined the CAP1 fee for the period between January 1, 2017 and December 31, 2017.
Under the provisions of that resolution, the amount allocated to cover charges for payment of that fee was €117.4 million. The AEEGSI provided for Terna SpA to recognize payments for 2017 by December 31, 2017.
On February 24, 2015, the market coupling model for the Italian, Austrian, French and Slovenian day-ahead trading markets was launched. Market coupling is a mechanism for integrating day-ahead markets that, in setting the electricity prices for the different segments of the European market involved, also allocates the transport capacity available between those segments, thereby optimizing the use of interconnections.
With Resolution 326/2016/R/eel, the AEEGSI charged Terna with conducting the competitive tender for assigning contracts for the supply of replacement tertiary reserves in Sardinia for the period from July 1, 2016 to December 31, 2018. The contracts awarded by Terna establish a requirement to supply the Ancillary Services Market (MSD) at the variable cost paid to the plant for a premium established in the competitive tender. Following the tender, all of the capacity was contracted with Enel’s Sulcis plant.
With Resolution 342/2016/E/eel, the AEEGSI ordered the start of a proceeding to adopt measures (prescriptive measures or asymmetric regulations) to prevent certain conduct by users of dispatching services in the wholesale electricity market that could constitute market abuse pursuant to Regulation 2011/1227/EU (REMIT).
With the subsequent Resolution 477/2016/E/eel, the AEEGSI reported the conduct of a number of dispatching users delivering power operating on the Ancillary Services Market to the Competition Authority for an investigation of possible violations of competition rules. One of these users was Enel Produzione SpA with regard to the supply of power from the Brindisi Sud plant to the wholesale market. Following the report filed by the AEEGSI, on October 6, 2016 the Competition Authority began an enquiry involving Enel SpA and Enel Produzione SpA to determine the existence of a possible abuse of a dominant position in the Ancillary Services Market by the Brindisi Sud plant.
The proceedings were concluded in May 2017 with the acceptance of the commitments proposed by Enel SpA and Enel Produzione without the imposition of sanctions. More specifically, the commitments consist of the introduction, for years 2017-2019, of a cap on total annual revenue that can be generated by the Brindisi Sud plant, net of variable costs paid under current regulations. The cap will also apply in the event the plant is included under the cost reimbursement system pursuant to Resolution 111/2006.
The proceedings initiated by the AEEGSI through Resolution 342/2016/E/eel were closed with the approval through Resolution 314/2017/R/eel of the application made by Enel Produzione for the admission of the Brindisi Sud plant to the cost reimbursement system for 2017. The approving resolution also provides, with regard to the commitments made by Enel Produzione as part of the proceedings before the Competition Authority, that any amounts exceeding the caps for the plant for the 2018-2019 period will be transferred to Terna.
AEEGSI Resolution 300/2017/R/eel established the criteria for permitting consumption units and production units not already authorized (including those using unscheduable renewable resources and distributed generation) to participate in the Ancillary Services Market (MSD) through pilot projects.
With Resolutions 444/2016/R/eel and 800/2016/R/eel, the AEEGSI reformed the rules governing imbalancing prices for calculating actual imbalances, providing for the application of a mixed single price/dual price system to consumption units and production units not authorized to participate in the Ancillary Services Market. The system provides for the application of the single price for imbalancing in a bracket equal to 15% of the binding withdrawal/delivery program. For unscheduable production units, the single price system will apply.
With Resolution 419/2017/R/eel, the AEEGSI activated as from September 1, 2017 the new method for calculating aggregate zonal imbalancing – given the difference between the programs of consumption units and those of generation units net of trade between zones in the Italian market and with foreign markets.
The resolution also provided for the restoration of the single pricing mechanism for calculating the actual imbalances for dispatching points of all unauthorized generation and consumption units as well as the publication by Terna SpA of the preliminary sign of the aggregate zonal imbalance more rapidly than provided for under EU regulations. With the same resolution, the AEEGSI also introduced with effect from July 1, 2017 the macro-zonal non-arbitrage fee for unauthorized generation and consumption units.
The extraction, import (from EU countries) and export of natural gas have been liberalized.
According to the provisions of Legislative Decree 130/2010, operators are permitted to hold market shares of up to 55% of domestic consumption.
The spot trading platform (the “Gas Exchange”) began operation in 2010 and the AEEGSI established the balancing market in 2011. The forward market later completed the structure of the Italian wholesale market, joining the Gas Exchange. As for the balancing market, the AEEGSI, implementing Commission Regulation 2014/312/EU, redefined, starting 2016, the rules for its functioning, in order to boost the availability of flexible resources to balance the system and improve the set of information for users. In 2017 the Ministry for Economic Development (MED) indicated that, starting 2018, the figure of market maker would be introduced in markets organized by the Energy Markets Operator (GME).
Transport, storage and regasification
Transport, storage and regasification (of LNG) are subject to regulation by the AEEGSI, which sets the rate criteria for engaging in these activities at the start of each regulatory period.
Storage is carried out under a concession issued by the MED to applicants that satisfy the requirements of Legislative Decree 164/2000. Each year, the MED issues a decree establishing the criteria for allocating capacity through an auction mechanism.
LNG activities are subject to the grant of a special ministerial permit to ensure third-party access (TPA). The MED may grant an exemption from the TPA rules. As for regasification, in 2017 the AEEGSI envisaged replacing the current rate-based method for allocating capacity with a system of auctions starting in 2018.
Transport activities, defined by regulatory criteria for rate periods, continue to be subject to fees updated annually by the AEEGSI. In 2017 it extended, with a few corrective measures, the rate criteria for 2014-2017 to 2018-2019.
These criteria were challenged by Enel Trade consistent with previous disputes; at this time, the dispute regarding the 2010-2013 period is pending before the Council of State and that for 2014-2017 before the Regional Administrative Court.
Distribution and metering
e-distribuzione provides distribution and metering services under a 30-year concession set to expire in 2030. The distribution rates are set by the AEEGSI at the start of each regulatory period based on covering the total cost of providing the services, considering operating costs, depreciation and providing an appropriate return on capital.
The rate component covering operating costs is updated annually using a price-cap mechanism (i.e. based on the inflation rate and an annual rate of reduction of unit costs called the X-factor). The return-on-capital and depreciation components are revised each year to take account of new investments, depreciation and the revaluation of existing assets using the deflator for gross fixed capital formation. With Resolution 654/2015/R/eel the AEEGSI specified the criteria for the new rate period for electricity distribution and metering, in force for the next eight years (2016-2023).
The rate period has been divided into two sub-periods of four years each (NPR1 for 2016-2019 and NPR2 for 2020- 2023), with an interim revision scheduled for 2020.
For the first sub-period (NPR1), while the AEEGSI essentially confirmed the general regulatory framework, it introduced substantial amendments concerning the timing and procedures for remunerating new investments in rates. More specifically, the AEEGSI reduced the so-called “regulatory lag”, shortening to a maximum one year (from the two years in the previous regulatory period) the period before new investments are recognized in rates while at the same time eliminating the increase of one percentage point of WACC. The latter had been introduced by the AEEGSI in 2012 to offset the financial burden imposed by the delayed recognition of new investments.
Operators are therefore required to notify the AEEGSI by the end of the year of their preliminary accounts of investments made during the year, enabling the AEEGSI to insert the data in the calculation of the mandatory rate published by the end of the year for the subsequent year. These investments are then inserted in the regulatory asset base as from January 1 of the year following their realization.
Consequently, operators can match the revenue generated by the investments with their amortization.
The AEEGSI also increased by five years the useful lives of low and medium-voltage power lines that entered service after December 31, 2007.
Finally, the level of operating costs recognized and the procedures for returning any extra efficiency gains to customers were also specified. More specifically, the AEEGSI maintained the symmetric division of extra efficiency gains and the restitution until 2019 of gains achieved and temporarily maintained to firms in the third and fourth regulatory periods. The X-factor used in updating eligible operating costs was set at 1.9% for distribution operations and 1% for metering activities.
For the second sub-period (NPR2), the AEEGSI announced the transition to rate regulation based on total costs (the Totex method).
With Resolution 583/2015/R/com the AEEGSI revised the method used to determine the rate of return on capital and set a rate of 5.6% for distribution and metering activities for 2016-2018. In particular, the AEEGSI established a specific 6-year rate period for the WACC, with a mid-period update of the main parameters in the formula on the basis of macroeconomic conditions (interest and inflation rates) in 2018.
With Resolutions 188/2017/R/eel and 199/2017/R/eel, the AEEGSI approved the definitive reference rates for 2016, which represent the level of revenue recognized for each operator on the basis of actual balance sheet data for 2015. With Resolutions 286/2017/R/eel and 287/2017/R/eel, the AEEGSI published the provisional reference rates for electricity distribution and metering for 2017 on the basis of preliminary balance sheet data for 2016.
According to the provisions of Resolution 654/2015/R/eel, the definitive reference rates for 2017, which represent the level of revenue recognized for each operator, must be published by February 28, 2018 on the basis of actual balance sheet data for 2016.
With regard to second-generation (2G) smart metering systems, in its Resolution 222/2017/R/eel the AEEGSI approved e-distribuzione SpA’s plan for placing the meters in service during the 2017-2031 period, designating January 1, 2017 as the start date, and established the standard cost based on which the efficiency incentives will be calculated. Resolution 646/2016/R/eel guarantees that the metering service rates for end users will remain essentially unchanged. Among the conditions for plan approval, the AEEGSI required field monitoring of the quality of the communication between the 2G meters and users’ devices, along Chain 2, for a period of at least four months, subsequently extended to April 30, 2018.
With Resolution 229/2017/R/eel, the AEEGSI provided guidelines on the initial configuration of the 2G meters and established some of the obligations of disclosure to end users. The subsequent Resolution 248/2017/R/eel established the procedure and timetable to make 2G metering data available to the Integrated Information System (IIS) and to transport users. Finally, Resolution 700/2017/R/eel set out the rules for using hourly delivery and withdrawal points equipped with 26 smart metering systems for the purposes of settlement.
As regards service quality, the AEEGSI, with Resolution 646/2015/R/eel as amended, established output-based regulation for electricity distribution and metering services, including the principles for regulation for 2016-2023 (TIQE 2016-2023) and authorized the start of trials to test the advanced management functions for the distribution grid. Specifically as to issues involving the improvement of the resilience of the electricity transmission and distribution networks, Resolution 127/2017/R/eel extended the automatic indemnities for protracted service interruptions payable to users by network operators and the methods for sharing this liability among the operators once the 72 hour limit is reached.
The subsequent Resolution 861/2017/R/eel modified the TIQE, clarifying certain aspect of distribution service quality regulation, such as access by network operators to the fund for exceptional events, the communication of voltage quality data, and the computation of the timing for commercial quality performance of the electricity service.
With Resolution 377/2015/R/eel, the AEEGSI completed the regulatory framework governing losses on the distribution grid, revising the conventional loss percentages as from January 1, 2016 and the equalization mechanism for losses to apply to distributors as from 2015. More specifically, the equalization mechanism takes account of the geographical diversification of losses on distribution grids. With Resolution 268/2015/R/eel, the AEEGSI established the Model Grid Code for transport services, which governs the relationship between sellers and distributors concerning the guarantees given by sellers to distributors, the payment terms for the transport service and the terms of payment of the system costs and other components by distributors to the Energy and Environmental Services Fund and the Energy Services Operator (GSE). The resolution also provided for the elimination starting from 2016 of the uncollectible portion of turnover withheld by distributors as a result of the strengthening of the system of guarantees.
As regards the calculation of the transport service guarantees, a number of different administrative court decisions handed down between May 2016 and November 2017 voided in part the AEEGSI’s provisions requiring the inclusion of guarantees to cover system charges in transport contracts between distributors and sellers. In accordance with these decisions, AEEGSI Resolution 109/2017/R/eel established a temporary regime involving a 4.9% reduction in the amount of system charge guarantees (equal to an average percentage of the amounts not collected by sellers) and initiated the revision of the Grid Code with consultation document 597/2017/R/eel.
As regards the procedures and financial terms for the connection of generation plants to distribution and transmission grids, the AEEGSI, with Resolution 581/2017/R/eel, updated the Integrated Grid Connection Code in order to implement the simplification measures provided for in the Ministerial Decree of March 16, 2017 for the connection and operation of micro-generation plants powered by renewables. As for the regulatory framework for private grids (specifically, closed distribution systems and basic generation and consumption systems), Resolution 276/2017/R/eel updated the relative Codes, adopting the provisions of Article 6(9) of Decree Law 244/2016 concerning general system charges. The AEEGSI, with Resolution 582/2017/R/eel, postponed application of the regulatory provisions on internal user networks from October 1, 2017 to January 1, 2018. The subsequent Resolution 894/2017/R/eel updated the definition of consumption unit and postponed until June 30, 2018 the deadline for “hidden end users” to declare themselves. Competition Authority Resolution 162/17/CIR established the fees for telecommunications operators to access edistribuzione’s electricity infrastructure to lay fiber-optic cables, pursuant to Legislative Decree 33 of February 15, 2016. As a result e-distribuzione published the General Conditions for accessing its infrastructure, Technical Rules and Technical Standards, which incorporate the Competition Authority’s provisions.
Energy efficiency - White certificates
The interministerial Decree of January 11, 2017 set the new energy efficiency targets for 2017-2020 and the new guidelines for the functioning of the Energy Efficiency Certificate (EEC or white certificates) mechanism.
As to the distributor’s performance of its obligation, it was provided that the quota exceeding the minimum obligation of 60% must be covered by the end of the following year (and not within the subsequent two years as previously allowed).
Furthermore, the distributor was given the option of satisfying the obligation over two sessions in the same year (May 31 and November 30) rather than just one, as was done previously. The decree required the AEEGSI to establish the criteria and method for covering the distributors’ costs.
With Resolution 435/2017/R/efr the AEEGSI approved the revised rules for calculating the rate subsidy for electricity and gas distributors starting 2017.
More specifically, the methods for determining the “reference” rate subsidy (previously called “provisional”), set ex ante as the average of the definitive rate subsidy levels in the preceding two years, and the underlying parameters for calculating the “definitive” rate subsidy were revised. The AEEGSI also envisaged an advance payment of the rate subsidy by the end of the November 30 session. With respect to the criteria for distributing the rate subsidy, the AEEGSI provided that starting in 2017 the accruals principle would replace the cash principle so that the definitive rate subsidy for the reference obligation year is applied to residual quotas for the year that are discharged in the subsequent year.
Thereafter, with Resolution 634/2017/R/efr, the AEEGSI delayed by one year the introduction of the accruals principle, making its roll-out more gradual so that it should be fully in place in another four years.
AEEGSI Decision 10 of July 14, 2017 set the amount of the rate subsidy for 2016 at €191.40/EEC. The reference rate subsidy for 2017 was instead set at €170.29/EEC and will be revised based upon the final market price for the reference period.
Reform of electricity rates for residential customers
With Resolution 782/2016/R/eel the AEEGSI fully eliminated, with effect from January 1, 2017, the progressivity of the distribution rate.
The resolution provides for the first steps to be taken in 2017 to reduce the effect of progressivity on general system charges. The system charges reform is expected to be completed by January 1, 2018, with complete elimination of the progressive structure. In Report 733/2017/I/eel of November 2, 2017 to the Government and Parliament and with the Memorandum of November 30, 2017 (805/2017/I/ eel) requested by the Chairman of the 10th Standing Committee of the Chamber of Deputies, the AEEGSI, however, reported on the effects, starting in 2018, on the annual spending on electricity by residential customers owing to the rate updates following the revision of the subsidies for energy-intensive companies and the final phase of the reform of the general system charges for residential customers.
Based on the instructions of the Government and Parliament, the AEEGSI published Resolution 867/2017/R/ eel, deferring implementation of the final phase of the reform of the general system charges for residential electricity customer and maintaining the current rate structures until December 31, 2018.
Reform of general system costs structure
The AEEGSI, with Resolution 922/2017/R/eel, implemented Resolution 481/2017/R/eel, providing that, as from January 1, 2018, the rates for general system costs and other components applying to all the types of contracts covered by Section 2.2 of the Integrated Transmission are divided into “General costs in support of renewable energy and CHP” (ASOS), “Remaining general costs” (ARIM), UC3 and UC6. The resolution implements the reform of the general system costs for non-residential customers provided by Law 21 of February 25, 2016.
Reform of concessions for energy-intensive companies
As part of the reform of the general system costs for non-residential customers, the AEEGSI, with Resolution 921/2017/R/eel, established the implementing provisions for the grant of concessions for energy-intensive companies, as provided by the MED decree of December 21, 2017, with effect as of January 1, 2018.
The resolution envisages ASOS component rates (based on the new grouping of general costs introduced by Resolution 481/2017/R/eel) differentiated between customers without concessions and those with, i.e. energy-intensive customers, based on concession category, as defined by the decree of December 21, 2017.
These provisions also had an impact on private-network configurations.
As provided for by Directive 2003/54/EC, starting from July 1, 2007 all end users may freely choose their electricity supplier on the free market or participate in regulated markets. Law 125/2007 identified these regulated markets as the “enhanced-protection” market (for residential customers and small businesses with low-voltage connections) and the “safeguard services” market (for larger customers not eligible for enhanced-protection services).
Free-market operators are awarded contracts to provide safeguard services on a geographical basis through threeyear auctions. For the 2017-2018 period, following the competitive procedure governed by Resolution 538/2016/R/eel, Enel Energia was awarded the areas corresponding to the regions of Liguria, Piedmont, Valle d’Aosta, Trentino-Alto Adige, Lombardy, Lazio, Puglia, Molise and Basilicata. The financial terms applied to end users were defined on the basis of the provision of the applicable primary and secondary legislation.
Enhanced-protection service is provided by sellers connected with distributors. Prices are set by the AEEGSI and are updated periodically based on criteria designed to ensure that the operators’ costs are covered. More specifically, the AEEGSI updates the component for covering the operators’ costs in the enhanced-protection market (RCV) annually so as in ensure that their costs are covered (operating costs, delinquency charges and amortization and depreciation) and that they receive a fair return on capital. Resolutions 816/2016/R/eel and 927/2017/R/eel established rates for 2017 and 2018.
In recent years, the AEEGSI has adopted measures aimed at containing operators’ credit risk, which has risen due in particular to the economic crisis.
In 2016, the AEEGSI lent significant impetus to the development and implementation of the Integrated Information System (IIS). This system was established under Law 129/2010 and is designed to manage the flow of information between gas and electricity market operators, based upon a central database of withdrawal points.
With a number of measures, the AEEGSI has governed various services, some of which are already active with others at the implementation stage. For example, the AEEGSI has sought to gradually centralize the management of the commercial processes for contract transfer and switching and of metering data for both sectors (electricity and gas) and, for the electricity sector only, the aggregation of metering at hourly withdrawal points for the purposes of monthly settlement.
Thanks to the development work carried out, the IIS is increasingly operating as a central hub for the exchange of information among all system operators, thereby facilitating the management of certain processes. In view of these characteristics, Ministerial Decree 94 of May 13, 2016 designated the IIS as the mechanism for managing the process of billing TV license fees through electricity bills. To cover the costs of managing this process, AEEGSI Resolution 291/2017/R/eel established the distribution criteria to be used by the Italian Revenue Agency in calculating the lump-sum grant payable to sellers for years 2016 and 2017; it has paid the amount owed for 2016.
The annual competition law (Law 124/2017) was approved on August 4, 2017, providing that the price protection market (electricity and gas) would be eliminated as of July 1, 2019. The AEEGSI was given the task of regulating the safeguard service for customers previously falling under the enhanced-protection category through competitive procedures by geographical area and on conditions that encourage switching to the free market.
The law also provides for the creation within the MED of a list of electricity sellers that are authorized to sell electricity on the retail market having met certain technical, financial and reputational requirements proposed by the AEEGSI.
The AEEGSI, in accordance with the law above, issued Resolution 555/2017/R/com, requiring all sellers to include in their portfolios offers at free market prices with conditions equivalent those of the protected market (PLACET offers), targeted at households and small businesses starting in early 2018. This was done to make it easier for end users to understand and compare offers and participate in the free market.
On May 11, 2017, the Competition Authority, in response to reports by AIGET and Green Network SpA, initiated a proceeding against Enel SpA, Enel Energia SpA and Servizio Elettrico Nazionale SpA for alleged abuse of dominant position on the retail electricity market for residential and non-residential end users connected to the low voltage grid. Analogous proceedings were also begun against other operators. Unless extended, the proceeding is expected to conclude by June 30, 2018.
Legislative Decree 164/2000 established that, as from January 1, 2003, all customers may freely choose their natural gas supplier on the free market.
However, sales companies must also offer a safeguard service to their customers (only for residential customers pursuant to Decree Law 69 of June 21, 2013), together with their own commercial offers, at the regulated prices established by the AEEGSI.
If there is no company supplying this service, the continuity of supply for small customers not in arrears on bill payments (residential and other uses with an annual consumption of less than 50,000 standard cubic meters) and for users involved in providing public services shall be ensured by the supplier of last resort. If the customer is in arrears with bill payments or it is not possible for the supplier of last resort to provide service, supply continuity is ensured by the default distribution supplier selected, like the supplier of last resort, through voluntary tenders for geographically-based contracts.
With Resolution 465/2016/R/gas, the AEEGSI updated the rules governing public tenders for the award of last-resort services for October 1, 2016 - September 30, 2018. Following the auctions held in September 2016, Enel Energia was designated as supplier of last resort for 7 of the 8 areas involved in the auction (Valle d’Aosta, Piedmont and Liguria; Lombardy; Trentino-Alto Adige and Veneto; Tuscany, Umbria and Marche; Abruzzo, Molise, Basilicata and Puglia; Lazio and Campania; Sicily and Calabria) and as default supplier in 3 areas out of 8 (Abruzzo, Molise, Basilicata and Puglia; Lazio and Campania; Sicily and Calabria).
Starting from October 1, 2013, the reform of the financial terms and conditions applied to safeguard customers entered force. In this situation, the AEEGSI modified the procedures for determining the raw material component, indexing it fully to spot market prices, introduced components to ensure a gradual transition (including one specifically for the renegotiation of long-term contracts) and increased the component covering retail sales costs to enhance cost-reflectivity.
With regard to the raw material (gas) cost component, on January 24, 2014, the Regional Administrative Court of Lombardy, in the course of an action brought by Enel Energia and Enel Trade, voided the resolutions by which the AEEGSI changed the formula for determining (and thereby reducing) the QVD component for the 2010-2011 and 2011- 2012 gas years. In 2014, the AEEGSI filed an appeal with the Council of State. In 2016, the Council of State denied the AEEGSI’s appeal, granting the appeal of Enel Energia and Enel Trade, finding the measures were in conflict with the statutorily established principle of the necessary “correspondence between recognized costs and actual costs”.
Resolution 737/2017/r/gas, in accordance with the Council of State’s decision, recalculated the value of the raw material for the October 2010 - September 2012 period. The manner of handling the amounts resulting from the recalculation will be addressed in a separate resolution expected for the 2nd Half of 2018.
With regard to the definition of the component covering natural gas supply rates, the AEEGSI also confirmed the current procedures, with full indexing to the spot prices reported on the Dutch Title Transfer Facility (TTF), pending the development of greater liquidity in the Italian wholesale markets until September 30, 2018 or in any event until the elimination of the enhanced-protection market as set by the legislature, if sooner.
With regard to gas settlement, specifically the mechanism for annually adjusting prior-period items, the AEEGSI published Resolutions 670/2017/R/gas and 782/2017/R/gas approving provisions for calculating the physical and financial items for the prior-period adjustment sessions starting 2013.
More specifically, a settlement mechanism was established for the 2013-2017 period through which operators can recover a share of the costs associated with grid loss previously allocated in proportion to their withdrawals. The AEEGSI has provided that, from January 1, 2018 until the definitive settlement mechanism is in place, operators will be paid almost all of the costs connected with grid loss.
General industry-wide provisions
In 2015, with its Resolution 296/2015/R/com, the AEEGSI regulated the functional unbundling requirements for operators in the electricity and gas sector. More specifically, the Authority confirmed that companies must maintain a separation between the brand, other distinguishing marks (including the company name) and communication policies of distribution companies and those of the companies that sell power that operate within the same group. Separation must also be maintained between those companies that sell electricity on the free market and those that do so on the enhanced-protection market, while different physical premises, personnel and information channels must be used for distribution and sales and for sales on the enhanced- protection market and those on the free market.
Between April and July 2016 the Regional Administrative Court of Lombardy rejected the appeals lodged by Enel Distribuzione, Enel Servizio Elettrico and Enel Energia. In implementation of the court’s ruling, Enel Distribuzione and Enel Servizio Elettrico modified their company name (and the associated brand) to “e-distribuzione SpA” and “Servizio Elettrico Nazionale SpA”.
The companies e-distribuzione, Servizio Elettrico Nazionale and Enel Energia appealed the ruling of the Regional Administrative Court before the Council of State, which with decision 5519/2017 denied the appeals of the two sales companies, thereby affirming the legality of Resolution 296/2015/R/com. The appeal by e-distribuzione is pending before the Council of State.
The regulatory framework for supporting renewable energy technologies in Italy envisages a range of remuneration systems. Incentives for technologies other than photovoltaic are awarded through competitive procedures established with Legislative Decree 28/2011, transposing Directive 2009/28/EC, and the associated implementing ministerial decrees of July 6, 2012 and June 23, 2016. The decrees envisage the use of Dutch auctions and feed-in tariffs, based on the installed capacity and technology. Specifically:
- Dutch auctions for plants with capacity of over 5 MW;
- registries for plants with capacity of less than 5 MW;
- direct access for wind plants with capacity of less than 60 kW, biomass plants of less than 200 kW and hydroelectric plants of less than 250 kW.
The above incentive mechanisms will terminate when the indicative cumulative annual cost of the incentives reaches €5.8 billion. At November 30, 2017, the indicative cumulative annual cost was €5.122 billion.
With regard to solar generation, the incentive system provided for the application of a number of Energy Accounts, of which Accounts I, II, III and IV (from September 19, 2005 to August 26, 2012) were based on a feed-in premium (a rate premium over the hourly zonal price), while Energy Account V (from August 27, 2012) was based on a feed-in tariff (comprehensive price) and was terminated once a cost of €6.7 billion was reached on July 6, 2013.
Ministerial Decree of February 14, 2017 on “Minor islands”
The February 14, 2017 decree of the MED gave instructions for gradually covering the electricity needs of the noninterconnected minor islands with renewable energy. The decree envisages remuneration for energy generated from renewable resources related to the cost of the fuel avoided and the launch of pilot projects to integrate renewable resources in the electricity systems of those islands.
National Energy Strategy
With the decree of November 10, 2017, the Ministers for Economic Development and for the Environment approved the National Energy Strategy (NES) which lays the groundwork for energy development in Italy based on the principles of competitiveness, energy security and environmental sustainability.
Specifically, the NES set a target of 55% for renewables as a share of electricity consumption by 2030, which should translate into a 75 TWh increase in renewable energy production.
The NES provides for keeping technology-neutral auctions until 2020 as a way of supporting the development of renewable energy. Thereafter, renewable capacity development will be tied to the signing of power purchase agreements, which are long-term contracts between producers and consumers, with the assistance of the State, at least during the initial phase, to enable it to get off the ground and develop.
Remuneration of distribution
On March 31, 2016 the Ministry for Industry, Energy and Tourism initiated the procedure for the introduction of a new ministerial order that will establish the remuneration of distribution activities for 2016, in accordance with the provisions of Order IET/2735/2015. Temporarily, the remuneration for 2015 will be retained until the new order is approved.
That order (IET/980/2016) was published on June 16, establishing the remuneration for distribution activities for 2016. Endesa was allocated a remuneration of €2,014 million. In addition, the incentives for service quality and non-technical losses for Endesa were set at €7 million and €2 million respectively. That order also sets the base remuneration for the first regulatory period from January 1, 2016 to December 31, 2019.
On October 9, 2017, the Official State Gazette (BOE) published Royal Decree 897/2017 concerning regulations affecting vulnerable consumers, the Social Discount and the terms and conditions for suspending the Social Discount for consumers with 10 kW or less of capacity. Specifically the decree sets out three categories of customers based on income level (measured using the Multiplier for the Public Income Index - IPREM), with different percentage discounts for each category.
Order IET/258/2017 of March 24, 2017 charged Endesa with a contribution to the National Energy Efficiency Fund of €29.3 million, corresponding to the energy savings obligations for 2017.
MSales margin incorporated in voluntary price for residential customers (PVPC)
On November 25, 2016, Royal Decree 469/2016 was published, establishing the method for setting the sales margin of the voluntary price for residential customers, thereby implementing a number of rulings issued by the Supreme Court voiding the margin set on the basis of the provisions of Royal Decree 216/2014.
On December 24, 2016 Ministerial Order ETU/1948/2016 was published, establishing, as from January 1, 2017, the value of the sales margin of the PVPC for 2014, 2015, 2016 and for the future.
Electricity rates for 2017
On December 29, 2016, Order ETU/1976/2016 was published, establishing electricity access rates for 2017. The existing rates were left unchanged.
Natural gas rates for 2017
On December 23, 2016, Order ETU/1977/2016 was published, establishing the natural gas access rates for 2017. In general, the existing rates were left unchanged, with the exception of the updating of the rate of last resort (TUR), which was reduced by an average of 9% as a result of the decline in the price of raw materials.
Fee for the use of continental water for the generation of electricity
On June 10, 2017, the Official State Gazette (BOE) published Royal Decree Law 10/2017 adopting urgent measures to mitigate the effects of the drought in certain catchment basins, amending the current Water Law. More specifically, the Royal Decree Law modifies the fee for the use of continental waters for the generation of electricity, which went from 22% to 25.5%, establishing a lower percentage for installations up to 50 MW to offset the increase in withdrawal.
In February 2017, Ministerial Order ETU/130/2017 was published, containing the remuneration parameters for renewable energy plants for 2017-2019. They are revised every three years, as provided by Royal Decree 413/2014 regulating generation from renewable resources. This revision is undertaken mainly to bring investment remuneration in line with the differences in market income projected for the coming years, as well as with differences that occurred in the three preceding years between actual market revenue and that projected under the regulation.
In the 1st Half of 2017, the rules and procedures for a technology neutral auction for 3,000 MW of renewable energy were issued. The auction was held on May 17. Enel Green Power España was awarded a specific remuneration system to develop 540 MW of wind power with COD (Cash on Delivery) before the end of 2019. Enel Green Power was allocated the third-highest capacity amount through the auction.
The auction was open to the competition of all types of renewable technologies. However almost all the capacity awarded was wind capacity.
The auction result serves to protect the internal rate of return of projects in low market price scenarios. However, if the market prices are above the protection level, the projects are authorized to capture this income.
The results of the first auction, in which there were competitive bids left that had not been awarded capacity and which demonstrated the need for more renewable energy to meet the 2020 targets, prompted the Spanish government to organize a second auction, held on July 26, 2017.
In the second auction, Enel Green Power received 338 MW in photovoltaic capacity. As in the first auction, the winners’ internal rate of return is protected when market prices are low.
Between July and September 2017, the Spanish government arranged a public consultation marking the start of the process of drafting new network access and connection rules. Work on this new regulation will be carried out in 2018.
Europe and North Africa
On June 27, 2016, Government Decree 563 was published, amending the calculation method used to determine capacity payments (DPM) that will ensure accurate determination of those payments for 2017 and beyond. On July 25, 2016, the terms of participation in capacity market auctions were revised to permit demand to access the mechanism through the reduction of consumption. The most recent capacity auctions (results published on September 20, 2016) set the parameters (price and quality) for 2020.
Government Decree 1458 of December 23, 2016 retained the coefficients for penalties for the lack of availability at the minimum levels for 2017 as well.
By the decision of January 9, 2017 the governement also established the rates for 2017 for the Trading System Administrator (-2.5% compared with 2016) and the System Operator (confirming the previous year’s rates).
On March 3, 2017, the Ministry of the Economy published the new methodology for setting the yield rate on long-term government bonds in order to calculate capacity payments (DPM), resulting in a rate of 10.21% (it had been 8.9%). On June 16, 2017, the government issued a decree establishing the rules for the new capacity auctions in Crimea: award of a 15-year capacity contract at the price established during the tender process (with a monthly cap of about 2 million rubles).
On June 19, 2017, the government published its general plan for developing the electricity industry through 2035.
It consists of non-binding guidelines that will be updated every three years. The plan includes numerous data, including the long-term demand and supply projections, expected capacity and necessary adjustments, grid infrastructure, and proposals for containing the environmental impact.
On September 2, 2017, the government signed Decree 1065 regarding the capacity market (KOM) auctions for 2021: it eliminated the price cap and the indexing of the price to the consumer price index (CPI) minus 0.1% (compared with the previous CPI -1%). On September 20, 2017, the system operator published the results of the auctions for 2021, with prices 16-18% higher than the 2020 auctions. The government, with its decree of December 27, 2017, set out the rules for the new thermal capacity (465 MW) tender in the Tamam area (southern Russia), to be held by April 1, 2018. The winning bidder will receive a 15-year capacity payments contract.
On June 20, 2017, Antitrust Authority Decision 776/2017 on the new floor and ceiling prices for industrial customers was published. Prices rose by 3.9% over the 2015- 2016 period.
With Government Decree 850 of May 10, 2016, the following changes were made to the regulations governing renewables:
- the incentive system for photovoltaic installations and small hydro systems was extended to 2024 (from 2020);
- the capacity volume targets for solar and small hydro, which were not selected for previous auctions (2013- 2015), were achieved and reallocated until 2024 (85.8 MW for solar and 168 MW for small hydro);
- the total volume target was kept at the initial level (5,871 MW).
On June 14, 2016 the final results of the auctions for investment in renewable resources for 2016-2019 were announced, with the award of projects for wind plants only.
On September 29, the Government Decree on state compensation for the connection of renewable resource plants or peat-fired plants to the grid was published. The rules, which apply to plants with an installed capacity of up to 25 MW, establish that compensation may not exceed 70% of the grid connection cost or in any case 15 million rubles per plant.
On July 5, 2016, the Federal Antimonopoly Service (FAS) issued an official warning for T Plus to cease its unfair practices against Enel Russia in the heat market. More specifically, the warning requires T Plus to enter into a heat supply contract with Enel Russia for the SuGRES plant in Yekaterinburg.
With a decree of December 1, 2016, the government established more stringent rules for Unified Heat Supplier (UHS) in the event of non-compliance with deadlines for payment to other suppliers and for network services. More specifically, UHS will lose its supply license if it fails to pay suppliers for two consecutive billing periods as well as in the event of repeated violation of other contractual terms. Any violation must nevertheless be certified by a court or the FAS.
Recognition of distribution investments in rates
In March 2016, ANRE approved a new procedure for recognizing investments for rate purposes, which will enter force in 2017 and in 2016 will serve as a recommendation for distributors.
The procedure establishes: (i) no recognition of inefficient investments; (ii) no recognition of costs for the works that exceed 10% of budgeted costs; and (iii) the possibility of modifying the annual investment plan by a maximum of 10% once it has been submitted.
In July 2017, ANRE published a letter containing the basic principles for the calculation of the distribution rates for the fourth regulatory cycle, including substantial changes regarding WACC, operating expenses, regulatory asset base, other revenue, current assets, own use and annual adjustments. The methodology is expected to be approved in April 2018.
Rates of last resort
According to the calendar for the liberalization of regulated rates for residential customers, the percentage of electricity that suppliers of last resort must purchase on the free market will be 80% in the 1st Quarter of 2017 and 90% in the 2nd Quarter of 2017.
ANRE also approved the final rates. The regulated component for 2017 was reduced by 6.47% owing to the decrease in distribution rates. The competitive market component (CPC) fell by about 3%-4.8% during the 1st Half of the year compared with the 2nd Half of 2016 as a result of the decline in distribution rates. In the 3rd Quarter, the rate, however, increased by around 10.8% compared with the 1st Half of 2017 due to rate corrections for previous periods. Therefore Enel began legal proceedings against ANRE. During the 4th Quarter the rates rose by approximately 9% over the 3rd Quarter.
As of January 1, 2018, the unregulated percentage is 100%. The CPC rates for the 1st Half of 2018 were raised by 0.44% compared with the rates for the 4th Quarter of 2017.
Regulatory framework for suppliers of last resort
On June 8, 2017, ANRE approved the suspension of the market for the purchase of electricity for universal service customers (households and small businesses) called PCSU. The suspension was in effect until August 10, 2017 and was prompted by the limited volumes indicated in the bids for the 3rd Quarter 2017 auctions. As a result of this decision, the suppliers of last resort must buy electricity on other free markets, such as the day-ahead market and the centralized markets for bilateral contracts. In July, Enel officially appealed the decision.
In 2017, ANRE began revising the PCSU rules, the methodology for adjusting the criteria for suppliers of last resort and the rules for the suppliers of last resort. In September, Enel began legal action to dispute the legality of the methodology for determining the rates for suppliers of last resort.
Distribution rates for 2017
In December 2016, ANRE published distribution rates for 2017, equal to an average of 98.6 lei/MWh, down about 8% compared with distribution rates in 2016.
In 2017, Enel’s distribution companies charged an average rate of 98.6 lei/MWh, about 8% lower than in 2016 (107.2 lei/MWh).
In December 2017, following the consultation on the calculation of rates, ANRE approved the rates applied as from January 1, 2018.The average rate of Enel’s distribution companies are 101.53 lei/MWh, about 3% higher than in 2017 (98.6 lei/MWh).
2017 binomial tariff
With Decision 71 of January 26, 2017, ANRE approved the timetable for introducing the binomial tariff for transmission and distribution services. The project will be carried out in two phases:
- phase 1 (January 1, 2017 - October 31, 2017): simulation at the distribution service operator (DSO) level, without affecting customers. In 2017 the DSOs monitored the data according to the simulation calendar and transmitted to ANRE the analysis and impact on regulated costs and revenue for the 1st Half of 2017;
- phase 2 (starting January 1, 2018): simulation at the consumer level.
ANRE has designated 2019 as the deadline for implementation of the binomial tariffs.
As part of the smart metering pilot project, at the end of 2016 110,000 meters had been installed. The results of the pilot project were transmitted to ANRE, which is preparing a cost-benefit analysis for approval of the mass roll-out project for 2017-2020.
In December ANRE published a draft order on the smart meter roll-out, envisaging a 10% cap on investment in meters out of the distributors’ entire investment plan for 2017 and 2018, and a ceiling of about €61 on the total unit cost for customers for 2018. In addition ANRE set June 30, 2018 as the final date for approval of the roll-out terms and conditions.
Rebranding of distribution companies
On August 16, ANRE sent electricity distribution companies a letter containing the minimum measures distributors must implement with regard to rebranding.
Between October and December 2016, Enel notified ANRE that it had adopted a new name and logo for its distribution companies in Romania and modified the corresponding licenses.
The Romanian government adopted Order 24/2017, which took effect on April 1, 2017, modifying Law 220/2008 and introducing a number of changes:
- Green certificates (GCs):
- the granting of 2 GCs for photovoltaic system generation is postponed to between January 1, 2025 and December 31, 2030;
- the recovery of GCs from wind power generation, already postponed, is set for between January 1, 2018 and December 31, 2025;
- the price of the CGs can fluctuate between €29.40 and €35, with no indexing to inflation;
- the GCs granted do not expire, remain valid until the incentive period ends and can be sold only once.
- bilateral contracts for the sale of GCs remain valid but cannot be extended beyond their current expiry date;
- creation of two anonymous trading platforms as from September 1, 2017 for: (i) spot or forward sales of GCs; (ii) the sale of renewable energy in combination with GCs (not yet in operation).
- GCs can be granted for green energy storage in batteries.
On December 28, 2017, the president signed the Power Market Act introducing a capacity market in Poland. The first auction is to be held in 2018 for the 2021-2023 delivery period. Subsequent auctions will be held every five years to cover a 10-year delivery period. In addition it will be possible to hold quarterly auctions announced one year prior. Demand-side response will be able to participate in the 5-year auctions if adequate investment is demonstrated.
The Power Market Act must still be approved by the European Commission with respect to state aid rules.
The transmission authority began to prepare the calls for tender for demand-side response in the balancing markets. Total demand for 2017-2018 was set at 500 MW (eight hours in the summer and four hours in the winter), of which 40% for summer capacity and 55% for winter capacity. The current call for tender provides for an additional 500 MW.
The green mobility law was approved on January 4, 2018, envisaging the installation of charging stations in 2018- 2019. The goal is to install 6,400 charging stations for electric vehicles, of which 400 will be high-voltage stations, and 70 service stations offering natural gas. They will be located in 32 densely populated areas and their installation will be public-private finance initiatives. If the installation targets are not met by the end of 2019, the local authorities of those areas will be required to draw up development plans for the stations lacking. The distribution system operators will be responsible for building charging stations in the areas they cover.
The British government and Ofgem published the Smart Systems and Flexibility Plan on July 24, 2017. The objective is to open all markets to demand-side response, introduce real-time ancillary services and simplify metering requirements. New de-rating factors for storage for capacity market participants have been introduced starting with the 2018 auctions.
On June 13, 2017, National Grid opened a consultation on “System Needs and Product Strategy”, followed by a products roadmap, published on December 19, for frequency response and reserve balancing services.
In December 2017, the government published the draft statutory instrument that transposes the Medium Combustion Plant Directive, which introduces tighter controls on emissions by generators.
Republic of Ireland and Northern Ireland
On November 24, 2017 the European Commission approved the new joint capacity market for the two countries under state aid rules. The first auction was held on December 15, 2017, with the delivery period set for May 23 through September 30, 2019.
The market design enables the participation of demand-side response operators in a manner similar to that for generators.
The EU authorization requires demand-side response operators to have equal access to the capacity market by October 2020.
The ancillary services market was reformed with the goal of ensuring system stability, even in a situation of high renewables penetration. New ancillary services were also established, guaranteeing the same treatment for demand-side response and conventional generation. The first call for tenders was published on December 12, 2017, with a deadline of February 8, 2018 for products with a 5-year delivery period starting May 1, 2018.
Greece’s renewables incentive system ensures remuneration using feed-in tariffs for all projects submitted prior to December 31, 2015. Starting January 1, 2016 projects are guaranteed a feed-in premium that varies by resource. In order to raise more funds to support these incentives and eliminate the deficit accumulated thus far, the Greek government introduced a component specifically to be paid by electricity suppliers.
With Resolution 616/2017 the Greek regulator considerably reduced the forced disconnections of wind power plants operating on non-interconnected islands.
In October 2017, the system that allowed large industrial customers to obtain remuneration for agreed service interruptibility expired. The system was reactivated starting January 2018 through the end of 2019. The scheme is financed by renewables operators that do not operate in the islands through a percentage of their revenue, differentiated by technology: wind, 2%; photovoltaic, 3.6%; and small hydroelectric plants, 1%.
The current system of incentives is based on feed-in tariffs that vary by renewable resource. The mechanism is available to photovoltaic, wind and hydroelectric plants under 10 MW and biomass systems under 5 MW.
Since 2012 a number of measures have been introduced to reduce the system deficit caused by increasing incentives for renewables. These include a local tax of 20% (subsequently revoked), network access charges, increases in balancing costs, a 5% tax on revenue and limits on volumes eligible for incentives.
As of March 2015, once the European renewable generation targets are reached, plants above 30 kW will no longer be eligible for incentives.
With the approval of Law 12/2015, Tunisia began to develop a regulatory system to support renewable energy with three different systems of incentives (concessions, authorizations and self-consumption). The country is committed to reaching ambitious development targets for renewables: 1 GW by 2020 and 4.7 GW by 2030.
In November 2017 the first tender for wind and photovoltaic projects was completed. Enel Green Power participated and is awaiting the results.
The new RES law (EEG), which entered force in January 2017, introduces a system of auctions for most renewables technologies. Offers will specify an amount of installed capacity each year in order to foster new lines of growth, which are: a) for onshore wind plants, 2.8 GW per year for 2017-2019 and 2.9 GW per year after 2020 (repowering included); b) for offshore wind plants, 15 GW by 2030. Two offers are planned for 2017 and 2018 of 1.55 GW each; c) for photovoltaic plants, to 2.5 GW per year, of which 600 MW in auctions.
As demonstrated by the initials auctions conducted in 2017, current legislation is so favorable to local communities that participate with their projects that they were awarded most of the available capacity. For this reason the legislation was provisionally modified for the first two auctions in 2018 and should lead to results that are more balanced among the various kinds of participants.
The coalition agreement between CDU/CSU and SPD includes, among other things, further increases equal to around 4 GW of the capacity auctions in 2019-2020.
The Group operates in South America in Argentina, Brazil, Chile, Colombia and Peru. Each country has its own regulatory framework, the main features of which are described below for the various business activities.
Under the regulations established by the competent authorities (regulatory authorities and ministries) in the various countries, operators are free to make their own decisions concerning investment in generation. Only in Argentina, following the change in energy policy in recent years, is there a regulatory framework that envisages greater public control of investments. In Brazil plans for new generation capacity are imposed by ministerial order, and this capacity is developed through auctions open to all.
All of the countries have a centralized dispatching system with a system marginal price. Usually, the merit order is created based on variable production costs that are measured periodically, with the exception of Colombia, where the merit order is based on the bids of market operators.
Currently in Argentina and Peru, regulatory measures are in place governing the formulation of the spot market price. In Argentina, regulators are working to ensure greater sustainability in the electricity market, increase the efficiency of that market and implement a sweeping rate revision to enable operators to meet their cash needs and resume maintenance of power stations and networks.
Long-term auction mechanisms are widely used for wholesale energy and/or capacity sales. These systems guarantee continuity of supply and offer greater stability to generation companies, with the expectation that this encourages new investments. Long-term sales contracts are used in Chile, Brazil, Peru and Colombia. In Brazil, the price at which electricity is sold is based on the average long-term auction prices for new and existing energy. In Colombia, the price is set by auction between the operators, which usually enter into medium-term contracts (up to four years). Finally, a regulatory framework recently introduced in Chile and Peru allows distribution companies to sign long-term contracts to sell electricity on regulated end-user markets. Chile, Peru and Brazil have also approved legislation to encourage the use of unconventional renewable resources, which sets out the objectives for the contribution of renewable resources to the energy mix and governs their generation.
Rate revision and other regulatory developments in 2017
On February 2, 2017, Resolution 19/2017 was published by the Secretaría de Energía Eléctrica (SEE). It sets out the guidelines for defining the rate remuneration for existing generation plants. Resolution 19/2017 establishes remuneration based on capacity by technology and scale. In addition, for thermal units it also provides for the possibility of undertaking commitments to ensure plant availability for additional remuneration. The generation company can declare its availability for each period (summer and winter), the amount of capacity guaranteed by each generation unit for a period of three years, differentiating supply by season. The only exception for 2017 is that the declaration of guaranteed availability and the seasonal winter planning document (in force from 1 May to 31 October 2017) will be authorized jointly given the time taken to implement the new legislation. The generation company will sign a commitment contract for guaranteed availability with CAMMESA, which can then transfer it on the basis of a request of the SEE. The remuneration established for each generation unit will be proportionate to actual compliance with the contractual terms, with the value calculated at the minimum price. Conversely, thermal generators will be able to offer additional capacity availability for bimonthly periods that can be subcontracted at maximum prices.
The remuneration established by Resolution 19/2017 is denominated in US dollars and is converted at the exchange rate published by Argentina’s central bank on the last day before the termination of each period set by CAMMESA.
In the renewables sector, the new legislation postpones achievement of the target of meeting 8% of national electricity demand with power generated from renewable resources to December 31, 2017, and establishes a series of phases for achieving 20% in 2025, setting intermediate targets of 12%, 16% and 18% for 2019, 2021 and 2023 respectively. Law 27191 creates a trust fund (FODER) to finance works, grant tax benefits to renewable energy projects and establish grants at the national, provincial and municipal levels until 2025. Large customers (with capacity requirements of more than 300 kW) will have to individually meet the above goals, stipulating in the associated contracts that the price shall not exceed $113/MWh, and establishing penalties for those who do not meet these targets.
In February 2017 the new rate rules and mechanisms were approved.
On February 1, 2017, ENRE published Resolution 64, which closed the RTI (Revisión Tarifaria Integral) process and established the annual remuneration paid to Edesur SA totaling 14,539,836,941 Argentine pesos (about €830 million).
Under the new rate system, the Mercado Eléctrico Mayorista limited increases in the Valor Agregado de Distribución (VAD) with specific instructions to ENRE. The new value for this rate component took effect on February 1, 2017, but invoicing of the amount is initially limited to a maximum of 42% of the total. Invoicing of the full amount will only be possible as from February 1, 2018, with an intermediate step in November 2017 where the 42% limit is raised in part.
The rules also establish that ENRE shall pay Edesur and Edenor the portion already accrued and not invoiced between February 1, 2017 and February 1, 2018 in 48 installments as from February 1, 2018, which will be incorporated in the value of the VAD to be invoiced subsequently.
The new rules also provide for updating the rates of distribution companies on the basis of inflation and criteria for service quality and regulation of supply.
SEE Resolution 1085/2017 modifies, as of December 1, 2017, the way in which operators pay for electricity transport, although the remuneration has not been changed apart from what is already incorporated in the rate revision. It establishes that:
- the costs associated with the remuneration for transport are divided in proportion to demand;
- generation companies will only pay the direct connection costs;
- CAMMESA shall propose the needed changes to the processes covered by the measure within 90 days.
Rate revision for Enel Distribución Rio SA (formerly Ampla)
On March 14, 2017, Enel Distribución Rio SA signed a new concession agreement (sixth revision) following public hearings 095 and 058. At the hearings, the parties involved discussed the regulation and application of the rate mechanism by the distribution companies, leading to the approval of the amendments discussed, which were to be incorporated in the concession agreement in accordance with Decree 2194/2016.
Rate revision for Enel Distribución Ceará SA (formerly Coelce)
On April 20, 2017, ANEEL endorsed the rate revision for Enel Distribución Ceará SA with Resolution 2.223.
In April 2017, the Ministry of Energy, following up on the measures already taken to reduce market over-contracting, published a resolution defining the mechanism for the auction to void contracts signed in the past within the context of reserve auctions. The auction is scheduled to take place on August 31, 2017. A second auction for the reallocation of terminating hydroelectric plant concessions is expected to take place by the end of September and will involve the assignment of about 3 GW of existing capacity.
In April 2017, a resolution introduced an indemnity mechanism for costs incurred by hydroelectric plants as a result of foregone generation due to the forced entry of thermal generation plants that are theoretically outside the merit order curve.
Updated Bandeiras Tarifárias
As of November 2017, the generation cost classes (Bandeiras Tarifárias) are as follows:
- “Green”: favorable hydroelectric generation conditions;
- “Yellow”: $R1.00 per 100 kWh;
- “Red level-1”: $R3.00 per 100 kWh;
- “Red level-2”: $R5.00 per 100 kWh.
Conta de Desenvolvimento Energético (CDE)
Created with Law 10438/2002, the CDE is a government fund designed to foster the development of generation from alternative energy sources, promote the globalization of energy services and subsidize low-income residential customers. The fund is financed with a surcharge levied through rates for consumers and generators.
ANEEL’s initial proposal was to reduce the rate surcharge for the CDE by 36%, taking account of the fact that the substantial reduction in the cost of fuels, which had already begun in 2015, had not been promptly reflected in reductions in the rate surcharges in 2016.
Resolution 1.576 authorized distribution companies to offset the reduction in amounts billed (following application of the court ruling upholding the demand of certain appellants to be charged a lower CDE rate surcharge) in monthly installments. The difference between the normal rate and that established in the court ruling will be recovered by the distribution companies through smaller monthly payments to the fund.
Enel Distribuição Goiás rate revision
On October 17, 2017, ANEEL approved the updated rate for Enel Distribuição Goiás through Resolution 2,317. The annual rate revisions for Enel Distribuição Goiás mean an average increase of 14.65% for consumers.
Specifically, this reflects the average of the increases of 12.03% and 15.89% respectively for low-voltage and highvoltage consumers.
On September 12, 2016, ANEEL approved regulation. 733/2016 establishing the conditions for applying the new hourly rates for low-voltage power, the so-called white rate. The white rate is a new hourly rate option that changes depending on the time of day and will differ on the basis of the consumption level of each customer as from 2018. Initially, the new rate will apply to consumers with low-voltage connections (127, 220, 380 or 440 V, group B) and new customers. As from January 2020, it will be an option for any consumer, with the exception of those who already benefit from certain preferential rates.
Enel is promoting a demonstration project to install 50,000 smart meters in 2016, with the ultimate goal of replacing all existing meters (about 1.6 million) by 2020.
This investment will be recognized by Chile’s regulator (CNE) if it recognizes the legitimacy of including the cost of the operation in the Valor Agregado de Distribución. In this regard, on September 5, Chilectra presented the CNE with a study prepared by Systeple to define the cost components of the VAD with a view to setting the rates that will enter force on November 4, 2016.
At the same time, Chile’s parliament approved the “Ley de equidad tarifaria”, which modifies the rate structure in areas were generation plants are located in order to equalize these areas with the urban areas where greater economies of scale can be achieved.
The “Ley de transmisión eléctrica” (Law 20.936) achieved the objective of unifying the various electricity dispatching centers in the country, as well as eliminating the payment of transmission charges by generators and passing them on to society as a whole through rates. In 2017 the regulations and implementing decrees were published, with the exception of the ancillary services regulation, which is expected to be published in 2018.
In addition, along with the “Ley de transmisión eléctrica”, Resolution 650 was published, establishing the payment of taxes on thermal power plant emissions under the tax reform.
Distribution service quality technical regulations
On December 18, 2017 CNE Resolution 706 was published, setting higher distribution services quality standards.
On March 30, 2017 Resolution 154 was published. It establishes the terms and conditions for the application of the Mechanism for Open Access to the system, legislating articles 79 and 80 of the General Electrical Service Act. The resolution, which anticipates the rules in the Transmission Act, includes, for the first time in Chilean law, a mechanism that permits the reservation of technical capacity for future projects in both private and public transmission systems.
In April 2017, the Ministry of Public Assets published a ministerial order modifying the conditions for concessions for use of public lands for the development of renewables projects. More specifically, the maximum period for the entry into service of the plant has been extended (from 3 to 10 years) and the cost of the concession has been reduced considerably (eliminating payment of a double tariff and lowering the values of the associated guarantees).
Emergency response to flooding in March 2017
Supreme Decree 007-2017-EM, issued in response to the heavy rains that fell in March 2017 in Peru and the damage produced by the consequent flooding, approved immediate measures to secure the supply of electricity to customers of the public power service at the national level. These included a suspension of service quality standards and the declaration of a 30-day state of emergency in the SEIN.
Supreme Decree 008-2017-EM also responded to the flooding emergency with an authorization protocol for electricity imports.
North and Central America
United States of America
Following the November 2016 elections, in March 2017, President Trump signed an executive order asking the Environmental Protection Agency (EPA) to take steps to undo the Clean Power Plan, the 2015 proposal that regulates greenhouse gas emissions from power plants in order to stimulate demand for renewable energy projects in the years following regulatory compliance period that begins in 2022.
In December 2017, the United States undertook a complete overhaul of the federal tax code, cutting the corporate tax rate to 21% and changing the rules on depreciation to allow 100% of expenditure to be depreciated in years 2018 through 2022, and reducing this percentage from 2023 to 2026.
In April 2017, US photovoltaic solar cell manufacturer Suniva submitted a petition with the US International Trade Commission (USITC) to safeguard Section 201 of the Trade Act of 1974, asserting it has suffered harm as a result of the importation of low-priced photovoltaic cells and modules. In May, the USITC decided to move ahead with an investigation to determine whether the photovoltaic products were imported into the US in such quantities as to threaten the US photovoltaic manufacturing industry. In September, the USITC found that domestic PV production was injured by imports and in October it recommended three separate remedies to President Trump. These remedies included potential tariffs and import licenses. Solar market experts predicted that the prices of PV solar panel prices will increase by between $0.01 and $0.32 per watt depending on the remedy. Under the Trade Act of 1974, the President has the authority to accept or modify the recommendations of the USITC. The President is expected to make a decision in January 2018.
In April 207 Oklahoma Governor Mary Fallin signed SB 593 and HB 2298 into law. Senate Bill 593 eliminates some of the requirements for wind energy facilities for private airports and also establishes a notification system for facilities that are to be built in areas where oil and gas are found.
House Bill 2298 ends the eligibility for tax credit for all projects that had not become operational before July 1, 2017, including Enel Green Power North America projects under construction and in the pipeline.
The Energy Ministry published the requirements for the Energía Limpia certificates that companies must meet for the years 2018 through 2022, specifically: 5.0% for 2018; 5.8% for 2019; 7.4% for 2020; 10.9% for 2021; 13.9% for 2022.
The Comisión Reguladora de Energía (CRE) and Comisión Federal de Electricidad (CFE) published the methodology for calculating the regulated rate and the rates for 2018. They will be revised each year.
In 2017 the third long-term auction was held, with 7,451 MW being awarded at an average price of 20.57 MWh/$ + clean energy certificates (CELs). The first two auctions were held in 2015 and 2016.
The Panamanian government is issuing a new law on electricity making changes to the national transmission company, introducing a new “market participants” designation and imposing a carbon tax on greenhouse gas emissions. The third electricity transmission line was inaugurated on October 26, 2017 and will be managed by the national dispatch center. The project is expected to improve the transport of electricity from the province of ChiriquÍ, where Enel Fortuna is located, to Panama City.
Sub-Saharan Africa and Asia
India is a federal republic composed of 29 states, each of which has specific responsibilities in various sectors as well as shared responsibility with the federal government in the electricity sector.
The Ministry of New and Renewable Energy (MNRE) defines and implements policy for the development of renewable energy at the national level. In addition to the Ministry, the power market is supervised at the federal level by the Central Energy Regulatory Commission (CERC), which sets guidelines and standard rates, and by the State Energy Regulatory Commissions (SERC), which implement them at the state level.
In June 2015 the government headed by Prime Minister Narendra Modi approved a target of 175 GW of renewables capacity by 2022, including 100 GW from solar, 60 GW from wind and about 15 GW from other technologies.
This ambition target was further strengthened in October 2016, when India ratified the Paris climate agreement in December 2015, committing itself to cut carbon emissions by 33-35% (Intended Nationally Determined Contribution - INDC) from their 2005 levels and to ensure that 40% of its installed capacity will be generated from nonfossil sources by 2030.
The renewables sector is highly fragmented since each state has its own regulatory scheme for developing new capacity. As a general rule, each state sets non-binding annual obligations, called Renewable Purchase Obligations (RPOs), for the share of electricity to be generated from renewable resources. The state distribution companies must meet the RPOs by buying or producing renewable energy or by purchasing Renewable Energy Certificates (RECs).
In general, the most often used way is to buy renewable energy through auctions. This instrument has been used since 2010 for solar power through the Jawaharlal Nehru National Solar Mission (JNNSM) program, whose implementation is overseen mainly by Solar Energy Corporation India (SECI), and through state auctions. Wind power, however, has only been formally subject to auctioning since January 2017, following the publication of the implementation directives by the MNRE in 2016; the auctions replace the earlier system based on preferred feed-in tariffs set by each state.
Usually the winners of the auctions are awarded 25-year power purchase agreements (PPAs) at fixed rates with SECI or Power Trading Company (PTC), which in turn sell the electricity through power sales agreements (PSAs) to state distribution companies (Discoms).
The federal Generation Based Incentive (GBI), which provided for premiums to be paid by Indian Renewable Energy Development Agency Limited (IREDA) in addition to the state preferred feed-in tariffs for wind plants, ceased as of April 1, 2017.
On May 18, 2017, the government announced the new tax rates for goods and services under the Goods & Services Tax Law reform, begun in the 3rd Quarter of 2016 to simplify the country’s indirect tax system, and taking effect July 1, 2017. The rate for most of the components needed to build renewables plants is 5%, leading to a slight overall increase since previously such components fell into tax exempt categories.
In May 2011, South Africa approved a target of 17.8 GW of installed renewable capacity by 2030 based upon the longterm energy strategy set out in the 2010-2030 Integrated Resource Plan. The primary tool to be used in achieving this target is the Renewable Energy Independent Power Producer Procurement Programme (REIPPPP), an auction system launched in 2011 that seeks to install around 13 GW in new renewable capacity between 2014 and 2020 (hydroelectric <40 MW, concentrated solar and photovoltaic, wind, biomass, biogas and landfill gas power). Currently, five rounds (bid windows) are scheduled, four of which have already been held, with the award of more than 5,000 MW of capacity.
In 2015 an additional round – called the Expedited Round, or Round 4.5 – was added and held for an additional 1,800 MW, which have not yet been assigned.
After a pre-qualification phase, which is concerned with technical and financial issues, qualified projects are chosen based upon two criteria: the bid price (weighted 70%) and the economic development content of the project (weighted 30%). The latter is based upon a series of parameters focusing on the economic development of the country, including local content and the creation of jobs for South Africans, especially non-whites.
The winners are awarded 20-year power purchase agreements (PPAs) with Eskom, the national power utility. Eskom’s payments are guaranteed by the government.
The program has been suspended due to Eskom’s delay in signing the PPAs for the winners of Rounds R3.5 and R4, while the winners of Round R4.5 have not been announced.
Negotiations are under way between Eskom, the independent power producers and the Department of Energy to resolve the situation.
At the end of March 2017 the public consultation on the draft revision published in November 2016 by the South African Department of Energy (DOE) was concluded. This draft was a revision of the Integrated Energy Plan (IEP) and the Integrated Resource Plan (IRP), the long-term plans incorporating the development strategy for the country’s energy and electricity sectors through 2050. The final documents are expected to be published in the 1st Quarter of 2018. NERSA, the national electricity regulator, is in the process of revising the rules on the use of the national grid by third parties (wheeling), on the granting of generation licenses and on distributed generation.
Australia is a federal constitutional monarchy composed of six states and two territories. The electricity sector is regulated by a collection of federal and state policies, overseen by various actors. The primary regulators at the central level are: the Council of Australian Governments (COAG), made up of the federal and state energy ministers who guide the development of energy policies; the Australian Energy Regulator (AER), which is the economic regulator; the Australian Energy Market Commission (AEMC), which is the rule maker and is responsible for market development; and the Australian Energy Market Operator (AEMO), which is the system and market operator. Each state has its own regulatory bodies. The electricity system is divided into two primary markets: the National Electricity Market (NEM), which covers the eastern part of the country where almost 90% of the population resides, and the Wholesale Electricity Market (WEM) in the west, which is much smaller. Both the NEM and the WEM, albeit in slightly different ways, operate as spot markets for electricity, facilitating exchange between generators and suppliers to end users (retailers) and to large industrial customers.
The country has a Renewable Energy Target (RET) scheme that is operated in two parts:
- the Large-scale Renewable Energy Target (LRET), set in 2015 at 33,000 GWh (around 23% of demand) of generation by 2020, to be maintained at this level until 2030. The LRET creates a financial incentive for renewable energy power plants, which can produce Large-scale Generation Certificates (LGSs) to be sold to retailers. These retailers are required buy them in an amount equal to a certain percentage of the electricity sold to end users, currently around 14%;
- the Small-scale Renewable Energy Scheme creates a financial incentive for households or small business customers to install small-scale renewable energy systems (usually rooftop solar panels), for which they can receive Small-scale Technology Certificates (STCs). Retailers are also required to buy these STCs in specified amounts.
The states have their own renewable energy policies and some – with more ambitious targets than the federal ones – have introduced in recent years programs in support of green energy. The state renewable energy targets are, for example:
- Victoria: 25% of electricity from renewable sources by 2020 and 40% by 2025 (about 3.3 GW). Auctions began at the end of 2017;
- Queensland: 50% by 2030. In August 2017 a tender was launched for 400 MW of electricity and storage;
- South Australia: 50% by 2025. At the end of 2017 auctions for technologically advanced renewable resources and storage were announced.
In the last few years the regulatory framework has been rapidly evolving to match the profound changes that have been occurring in the electricity sector, such as the integration of renewable power plants and the closing of obsolete coal-fueled plants.
In October 2017 the federal government introduced a new policy for the NEM, addressing primarily the security and reliability of the electricity system, consumer prices and reducing emissions. Under the new policy, called the National Energy Guarantee (NEG), retailers are required to buy an appropriate mix of resources to provide:
- a “reliability guarantee”, to ensure the right amount of dispatchable energy;
- an “emissions guarantee”, to help reduce emissions in line with Australia’s international commitments (reduction of emissions by 26-28% by 2030 compared with 2005).
The new policy must be approved by the states and the operational details must still be defined. It will not be implemented before the end of 2019.