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Dutch Electricity And Gas Transmission And Distribution Framework: Supportive


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Dutch Electricity And Gas Transmission And Distribution Framework: Supportive

Table 1

Dutch Electricity And Gas Market
Regulator Authority for Consumers and Markets
Key rated players Power TSO: TenneT
Gas TSO: Gasunie Transport Services (GTS)
Electricity and gas DSOs: Alliander, Enexis, Stedin (together more than 90% of market share)
Tariff-setting methodology Real-plus WACC (real WACC plus 50% of inflation) on RAB for electricity transmission and distribution. Set at 2.0% (pre-tax) for 2022.
Nominal WACC on RAB for gas transmission and distribution. Set at 3.1% (pre-tax) for GTS and 2.9% (pre-tax) for gas DSOs in 2022.
Regulatory period Five years (January 2022-December 2026)
Regulatory assessment Strong
RAB--Regulated asset base. WACC--Weighted average cost of capital.

Table 2


In The Netherlands, the electricity and gas regulator is the Authority for Consumers and Markets (Autoriteit Consument & Markt, ACM). Key operators include electricity transmission system operator (TSO) TenneT and gas TSO Gasunie. There are six electricity and gas distribution system operators (DSOs), with Alliander, Enexis, and Stedin covering almost the entire territory of the Netherlands. By law, these entities must be owned by public entities and must own the infrastructure assets.

Table 3

Operator Profiles
Key Players Rating Regulated Business


A+/Stable/A-1 Alliander is mainly devoted to electricity and gas distribution in the provinces of Gelderland, Noord-Holland, Amsterdam, Zuid-Holland, Friesland, and Flevoland. Its electricity and gas  grids cover 93,000 km and 42,000 km, respectively. The group provides electricity and gas to about 3.3 million consumers and businesses through its more than 5.7 million connection points. Alliander is 100% owned by 74 Dutch provinces and municipalities. The Province of Gelderland owns 44.7%, Friesland 12.7%, Noord-Holland 9.2%, and the city of Amsterdam 9.2%. The remainder is owned by other smaller Dutch municipalities. In 2021, reported EBITDA was €852 million.
LoS: Moderate (+1 notch)


A+/Positive/A-1 Enexis operates distribution grids for electricity and gas in the provinces of Groningen, Drenthe, Overijssel, Noord-Brabant, and Limburg. Its electricity grid covers 144,900 kilometers (km) with 2.9 million connection points, while its gas grid covers 46,200 km with 2.3 million connection points. It is owned by the Provinces of Noord-Brabant (30.8%), Overijssel (19.7%), Limburg (16.1%), and Groningen and Drenthe (9%), and the remaining shares are owned by 86 smaller municipalities. In 2021, reported EBITDA was €751million.
LoS: Moderate (+1 notch)


A-/Stable/A-2 Stedin operates distribution grids for electricity and gas in a large part of the province of South Holland, Utrecht, and Zeeland, and in parts of North Holland and Friesland. With its 57,573 km of electricity cables and 28,165 km of gas pipelines, Stedin provides energy to 2.3 million customers. Stedin is owned by 44 Dutch municipalities, the largest of which is the City of Rotterdam, followed by The Hague. In 2021, reported EBITDA was €484 million.
LoS: Moderate
(+1 notch)


A-/Stable/A-2 TenneT is an electricity transmission system operator (TSO) serving 42 million end-users in the Netherlands and Germany and operating 16 cross-border interconnectors through about 25 thousand kilometers (km) of high voltage transmission lines. It is 100% owned by the Dutch state. The company generated IFRS EBITDA of about €920 million in 2021.
SACP: bbb
LoS: moderately high (+2 notches)


AA-/Stable/A-1+ Gasunie is a gas transmission system operator (TSO). Its high-pressure gas pipeline network is one of the largest in Europe and consists of about 12,849 km in the Netherlands, 4,604 km in northern Germany, and about 1,300 gas receiving stations. Its throughput volume is about 100 bcm per year (or about 1,100 terawatt-hours). It is 100% owned by the Dutch state. In 2021, the company reported €763 million EBITDA.
LoS: high (+2 notches)
LoS--Likelihood of support.

Chart 1


Assessment Factors

Regulatory stability: Long and solid track record of predictable regulation

The Dutch regulatory frameworks have demonstrated a high degree of stability over time and a solid track record of predictable revenue and returns over the past 20 years. They have been in place in the current incentive-based form since 2002. The independent regulator ACM is the result of the merger of several previously existing regulatory bodies and has been in charge of overseeing the electricity and gas sector since 2013.

Continuity is ensured through five-year regulatory periods

The law sets the length of each regulatory period from three to five years. The length of the regulatory period was extended to five years in 2017, from three previously, which in our view has enhanced the framework's predictability by reducing regulatory reset risk. That said, in a volatile period, estimated parameters will less accurately reflect actual market conditions for longer. The current regulatory period covers the timeframe from January 2022 until December 2026.

Chart 2

Tariff-setting procedure is transparent, and formula based

ACM sets the tariffs for TSOs and DSOs in a three-step process, which is preceded by a consultation phase between the regulator, the network operators, and the representatives of network users; this period starts several months before the new regulatory period.

First, it publishes its decisions on the methods to calculate the revenue of each type of system operator before a specific regulatory period begins. These methods will remain in place for the length of the regulatory period. Usually, decisions on methodology are taken separately for the TSOs (TenneT and Gasunie), while they are combined for the DSOs (operating both power and gas grids). Second, ACM publishes the level of allowed revenue for the entire regulatory period, including the x-factor decisions for each individual operator. Third, ACM publishes the annual tariff decisions for individual system operators covering the regulatory period, based on the x-factor decision and the tariff parameters. These intra-period decisions also account for further tariff corrections due to macroeconomic changes and court rulings, if any. ACM's decisions can be appealed through ordinary administrative jurisdiction via the Trade and Industry Appeals Tribunal (CBb), which is an administrative court that rules on socioeconomic disputes on a sector-specific basis. And appeals over the past 10 years suggest that there is a track-record of Dutch operators challenging regulatory decisions and that the process proves efficient (see the section on financial stability for more insights).

For both electricity and gas, the overarching principle of the regulation is a revenue cap based on forecasts, which is determined on the level of efficient costs. The regulatory cost base includes both operational and capital costs that are estimated by the regulator based on data provided by network operators. For the current regulatory period, the reference cost period is 2018-2020 for electricity and 2017-2019 for gas. Regulated depreciation periods can vary from five to 55 years, depending on the type of asset, and RAB includes expansionary work-in-progress investments for the TSOs, which we view positively for the timing of their cash flows. The allowed revenue is adjusted based on actual results every year for the consumer price index (CPI), evidenced in the August to August period for electricity and February to February for gas, with a lag of about 18 months. It also factors in an efficiency incentive known as the x-factor.


For the period starting Jan. 1, 2022, ACM introduced a real-plus-WACC remuneration for power activities, i.e., a real WACC plus half of the estimated CPI. This mechanism is halfway between a purely nominal WACC, which was introduced for gas activities, and a real WACC. While this represents a positive move from the preceding period, we view it as less favorable than other European frameworks where 100% of inflation impact is reflected in the WACC remuneration.

  • In the real-plus system, the RAB is indexed yearly with half of the inflation estimate.
  • The interest components of cost of debt and cost of equity of the WACC are recalculated yearly with a two-year lag.
  • For the TSO TenneT, the WACC for new assets is set at 1.9%, with offshore assets remunerated even higher at 2.4%. This reflects the risk of TenneT's Dutch offshore investments given their size compared with the existing regulated asset base.
  • Electricity DSOs receive additional income for output for feeding in decentralized power generation, which includes solar photovoltaic and wind turbines.

For the period starting Jan. 1, 2022, ACM has introduced a remuneration based on nominal WACC for gas, to better align the costs with the actual use of the network, with connection points expected to decrease in the medium term. The remuneration for gas involves accelerated depreciation, with a factor of 1.3x for Gasunie Transport Services (GTS) and 1.2x for the gas DSOs. We this as favorable in the current period because it ultimately increases operators' allowed revenue through the depreciation cost component. At the same time, it lowers the gas regulated asset base for the WACC compensation system and may lead to largely depreciated--and therefore less remunerative assets--in the long term, putting pressure on regulated gas players' remuneration.

  • In the nominal system, because effectively the WACC already considers the inflation component, RAB is not indexed to inflation yearly. This also brings forward remuneration of the gas assets in the current period versus an inflation-indexed RAB mechanism.
  • The cost of debt and cost of equity components of the WACC are recalculated yearly under the same mechanism as for electricity.
  • For the gas TSO Gasunie, the WACC for new assets is set at 3%.
  • Gas DSOs receive compensation for the costs of dismantling the gas distribution networks and for removing connection points.

We consider that this remuneration maximizes the cash flows of gas grid assets for this period, with the use of nominal WACC and the accelerated depreciation boosting the allowed revenue. It acknowledges the declining use of gas assets compared with the electricity grid and reflects the uncertainties as to use of the gas infrastructure in an increasingly decarbonized economy.

Chart 3

The WACC should bottom out in 2022 before picking up more firmly in 2024 to reflect higher cost of debt

This is evidence of the agility of the framework. The WACC determines the return on investment when multiplied by the RAB. ACM looks at market returns in a competitive environment as a benchmark instead of the actual costs the players face, which represents a strong incentive for operators to invest.

The regulator calculates an estimated reasonable WACC for each year of the regulatory period. ACM considers the average embedded cost of debt of the system operators for the previous 10 years, which explains the very low assumed cost of debt over the current regulatory period.

Compared with other European jurisdictions, we believe WACC levels in the Netherlands are among the lowest in Europe, which has increased pressure on remuneration of electricity grids at a time of significant ramp-up in the investments required for the energy transition to unfold. That said, the stretched returns on investments are compensated by the very low country risk in the Netherlands, which is a positive consideration that helps form our view, along with the regulatory advantage, of our business risk profile for Dutch utilities and allows Dutch operators to obtain financing at a lower cost.

Because the cost of debt and the risk-free rate components of the WACC are recalculated yearly, and given the current central bank cycle that is tightening monetary policy, we expect WACC levels to increase across all activities, especially from 2024, versus what is shown in table 4. We estimate that the nominal pre-tax WACC assumption could rise to 4.8% in 2026 from 2.9% in 2022.

Table 4

Components Of RAB Remuneration Rates For Existing Assets (As Per Final Determination)
% 2022 2023 2024 2025 2026
Utilities bond index rate 1.26 1.07 0.95 0.90 0.89
Transaction costs 0.15 0.15 0.15 0.15 0.15
Cost of debt (before tax) 1.41 1.22 1.10 1.05 1.04
Risk-free interest rate (0.01) (0.01) (0.01) (0.01) (0.01)
Market risk premium 5.00 5.00 5.00 5.00 5.00
Asset beta 0.39 0.39 0.39 0.39 0.39
Equity beta 0.63 0.63 0.63 0.63 0.63
Cost of equity (after tax) 3.15 3.15 3.15 3.15 3.15
Cost of equity (before tax) 4.20 4.20 4.20 4.20 4.20
Gearing 45.25 45.25 45.25 45.25 45.25
Tax rate 25.00 25.00 25.00 25.00 25.00
Nominal WACC pre-tax 2.94 2.86 2.80 2.78 2.77
Inflation adjustment (estimate) 0.88 0.88 0.88 0.88 0.88
Real-plus WACC pre-tax 2.04 1.95 1.90 1.88 1.87
Inflation (estimate) 1.77 1.77 1.77 1.77 1.77
Real pre-tax WACC* 1.15 1.07 1.02 0.99 0.99
Source: ACM. *Used to compare with previous periods and with other jurisdictions.

Chart 4


The x-factor imposes a strong grasp on cost controls and efficiency for both TSOs and DSOs and could further constrain remuneration if not achieved

The efficiency factor is determined with a complex calculation that involves efficiency costs and the WACC setting. Once the base revenue is determined, the regulator estimates the evolution of costs to arrive at the regulated level of revenue for the last year of the regulatory period. The x-factor is then determined as the yearly variation in revenue.

Since there is only one designated gas and electricity TSO operating in the Netherlands, the regulator sets the efficiency targets by comparing the local TSO with other efficient and structurally equivalent European TSOs with Transmission Cost Benchmarking project 2018 (TCB18), a European benchmark study. For TenneT, it resulted in an efficiency score of 97.28% in 2022 and will decline to 89.1% in 2026. For Gasunie's operations in the Netherlands, Gasunie Transport Services B.V., the average efficiency score was set at 93.7%. This means that both TSOs need to significantly reduce their cost bases, by 11% between 2022 and 2026 for TenneT and by 6% for Gasunie.

For the DSOs, the so-called yardstick method is used, which involves adjusting the allowed revenue by the average cost per unit of output of all Dutch DSOs. In this way, the operator has an incentive to outperform the expected efficient costs. If it does so, it may keep the resulting profits. On the other hand, if the network operator underperforms the yardstick, it may end up incurring extra costs. The efficiency factor represents the annual change in revenue, and for the current regulatory period the regulator has set more stringent targets for gas distribution activities than for electricity.

The q-factor incentivizes service quality, while transmission costs are passed through for electricity DSOs and do not negatively impact their remuneration

For electricity DSOs, the regulator also provides an incentive for maintaining the quality of the network, known as the q-factor, which essentially redistributes tariff income from DSOs with lower-than-average quality to DSOs with higher-than-average quality. The q-factor is a function of outage occurrence and the time to resolve these outages. This factor is only applicable to electricity DSOs and has a zero-sum effect on a sectoral basis. Enexis has the highest q-factor among the three rated DSOs in the current regulatory period (0.25%), followed by Alliander (-0.05%) and Stedin (-0.3%).

Transmission costs charged by TenneT are a pass-through and DSOs receive compensation on a yearly basis based on the regulator's pre-calculation, which avoids large adjustments to remuneration with a time-lag.

The regulator recognizes the need to adapt the framework to higher costs from congestion management and currently allows for partial pass-through of these costs

In several regions of the Netherlands, the maximum capacity to feed in power or establish new electricity connections has been reached, given that many new renewable generation facilities have grown at a faster pace than grid expansion allows. Indeed, the electrification of the country is increasingly resulting in grid congestion, which highlights the need for changes in market and regulatory design. This is why the government, the regulator, and grid operators have agreed plans for long-term solutions. These are contained in the national action plan for grid congestion that was presented in December 2022. Although the ultimate solution would be to accelerate the expansion of the grid, there is also the need for better and more efficient use of the power cables, as well as inclusion of increasing costs for this steering activity into the tariff of the operators.

In case of congestion, TenneT needs to activate costly remedial measures, such as redispatch, and such services are already included as a pass-through in the tariff, with a small bonus-malus component.

ACM has recently set new rules on the application of congestion management. It has a congestion management code in operation since Nov. 24, 2022, whereby in areas where electricity TSO and DSOs cannot provide transport capacity for every customer, they have to strike agreements with some customers to reduce their usage at times of capacity shortage, essentially acting as intermediaries. Grid congestion costs are reimbursed via tariffs with a post-calculation. The regulator has agreed upon recalculating extra costs and revenue for 2022 and 2023 and then to re-evaluate after this period.

Financial stability: strong, based on full and timely cost recovery, despite significant investments needed in the next decade

Network operators are able to recover their costs in full, including capital returns, provided they are efficient. In fact, the regulator's goal is to provide network operators with an incentive to operate in an efficient manner by reducing costs and increasing quality. We note there is increasing pressure on electricity grid operations stemming from constant decrease of remuneration in a context of step-up investments need, which raises questions on whether the allowed return amounts to a fair return on investment or which stretches our view of regulated utilities earning a fair return on investments.

In the context of affordability pressure, ACM has the duty to balance the interests of consumers (by limiting tariff increases) with those of investors to allow utilities to remain attractive in the capital markets over the longer term. The legislation requires operators to maintain an investment-grade rating and to keep well-balanced capital allocation and planning. ACM calibrates the cost of debt included in the WACC formula with an 'A' category rating.

The main operators (both TSOs and DSOs) have appealed against the current 2022-2026 regulatory decision, claiming the costs per output resulted in a WACC that is too low and in an efficiency factor that is not based on a robust benchmark. We understand a court ruling is expected in the first half of 2023 and that, should it lead to a positive outcome for the network operators, it may call for an intermediate adjustment of certain aspects of the regulation by ACM and lead to a correction of allowed revenue. That said, we note that the relationship between the regulator and operators has involved frequent recourse to the courts in the past.

No exposure to volume risk is a key driver for our strong assessment

TSOs in the Netherlands receive their allowed revenue independently from the volume they sell. If a TSO sells more or less volume than expected, the tariff is corrected at the year t+2. In our opinion, this mitigates volume risk and enhances the sector's financial stability. For DSOs, volatility stemming from changes in volume is also limited, since tariffs are set by capacity volume at the connection point and not by the effective volume of transported energy.

Time lag on recovery of energy purchase costs for grid losses is a flaw, but the regulator has demonstrated its proactiveness in the last year allowing exceptional recovery in some cases.

For some cost estimates, ACM may decide on adjustments within the period that deviate from the initial regulatory decision, which may lead to an increase in allowed revenue. This was the case of the energy procurement costs for DSOs, for which the expected costs and consequent allowed revenue were determined at a low level in the current regulatory period. Given the notable rise in energy prices, the allowed income fell far short of the actual costs, which led ACM to publish a decision in June of 2022 to allow for an exceptional advance recovery of such costs without the usual two-year delay.

As such, in 2023 the DSOs will receive an advance recovery of the difference between allowed and actual costs for grid losses amounting to 75% for 2022 (only electricity) and 50% for 2023 (both electricity and gas). The remaining difference will be recovered with a two-year lag. Our current base case for DSOs assumes the regulator will decide for further advance recognition of energy procurement costs in 2024.

TenneT has also experienced a sharp rise in energy costs linked to grid losses and to other purchasing costs (for example, balancing capacity and redispatch). Because of this, ACM has recently decided that it will also receive an advance payment of 25%-40% of the subsequent expected calculation for 2023, instead of the previous two-year delay, which means that higher costs can be passed on more quickly to customers. For now, ACM has not yet decided whether it will grant advance payments for 2024 and beyond, though we expect it will monitor this annually.

Gasunie does not receive compensation for gas procurement costs to cover for grid losses in the current regulatory period. However, we note such costs are a small portion of the tariff and therefore less relevant than TenneT or the DSOs. We understand Gasunie is currently challenging the regulator's decision in court to allow for post-calculation of both the volume and price components of the energy costs (currently, only volumes are post-calculated).

Ambitious decarbonization targets put pressure on power network operators' cash flow generation and financial risk profiles

In the National Energy and Climate Plan (NECP) the Dutch government aims to reduce greenhouse gas emissions by 49% by 2030 versus 1990 levels. The electricity sector is required to significantly increase use of renewables in the energy mix, suggesting that network operators will have to deploy substantial capital expenditure to adapt the grid. We see increasing pressure on TenneT's and DSO's discretionary cash flows owing to such large investments, and on their credit metrics, combining decreasing returns and remuneration reflective of lower past cost bases, and the debt-funded investments. Meeting efficient cost base levels as determined by the regulator will be key to not depressing final remuneration further. We believe some relief should happen in the next regulatory period from 2027 when the cost base will be upscaled. Also, while bridging to 2027 will be key, we could witness less pressure on cash flows and balance sheets from lower effective capital expenditure, because we note all Dutch regulated grids face significant implementation hurdles, such as skilled workforce scarcity and, to a lesser extent, supply chain bottlenecks.

However, we expect the financial stability of the operators to be ultimately supported by the Dutch state

On Nov. 28, 2022, Alliander, Enexis, Stedin, their shareholders, and the central government reached a legally binding agreement that set out the conditions and the requirements under which the Dutch state would provide common equity to support the capital adequacy of the DSOs at a minimum 'A-' or equivalent rating level, which is why we now consider the DSOs to be Dutch government-related entities (see "Dutch Networks Stedin, Alliander And Enexis Ratings Affirmed On Government Support; Enexis Outlook Revised To Positive," published Feb. 14, 2023, on RatingsDirect). We view this as a key support at a time when the DSOs plan to invest €30 billion in aggregate by 2030 to upgrade their networks. The government's preliminary estimates point to a total of €4.5 billion in equity needs by 2027, split between the three DSOs.

In addition, the Dutch central government will continue supporting its grid infrastructure. We expect further equity contributions from the state, as TenneT has recently publicly announced approximately €10 billion equity needs in the current decade to fund its Dutch activities.

Transition to green gases is underway, but regulation will take longer

The Netherlands is among the more advanced countries in Europe in terms of transitioning to green gases, with a focus on hydrogen. The government has appointed Gasunie to build the hydrogen backbone (HyWay27 project). A total of €1.5 billion in investments will be allocated between 2022 and 2027 (of which €750 million in government grants); the majority will go to adapting existing infrastructure and the rest to deploy 200 kilometers of new pipelines. That said, the regulation does not account for such investments into the RAB. We believe the regulation on renewable gases could follow guidance set by the European Commission in its revised Third Gas Package, due to be finalized by end 2023.

Regulator's independence: Strong, fully independent from any other public or private interests

When assessing regulatory independence and insulation, we look at the market framework, how the law enshrines and separates the regulator's powers, and the risk of political intervention.

We view regulatory independence in the Netherlands as adequate, based on our perception of a supportive electricity and gas market framework. The regulatory entities in these markets are the Ministry of Economic Affairs and Climate Policy (MEA), ACM, and CBb, which is an administrative court that rules on sector-specific socioeconomic disputes.

MEA is in charge of the long-term design and implementation of the Netherland's energy policy, as well as monitoring its evolution. In this sense, it is in charge of publishing an Energy Report of the Netherlands every four years, providing the main directives concerning Dutch energy policy, including how to achieve targets related to climate change and energy agreements. In addition, MEA has the power to propose and implement secondary legislation, meaning that it could supplement primary legislation regarding the country's energy policy.

ACM is the result of the merger of previous regulatory bodies, and since 2013 is the national agency in charge of sector-specific regulation in the Netherlands, including energy markets. ACM monitors and enforces compliance with the Electricity Act (Electriciteitswet), Gas Act (Gaswet), and Heat Act (Warmtewet). It is also in charge of supervising compliance with EU regulation and legislation in the country. ACM has the power to impose sanctions on entities that don't comply with the energy regulation and to resolve disputes between customers and network operators, although those decisions can be appealed at CBb. In addition, it is ACM's task to adopt regulation regarding tariff decisions and tariff-setting methodology, such as tariff caps and regulatory WACC calculations.

Importantly, although ACM must adhere to the implementation of the country's energy policy, which is led by MEA, it operates independently from MEA. We view this as positive, since it removes the risk of political intervention that could affect a utility's credit profile.

Related Research

This report does not constitute a rating action.

Primary Credit Analysts:Federico Loreti, Paris + 33140752509;
Pauline Pasquier, Paris + 33 14 420 6771;
Claire Mauduit-Le Clercq, Paris + 33 14 420 7201;
Secondary Contacts:Emmanuel Dubois-Pelerin, Paris + 33 14 420 6673;
Massimo Schiavo, Paris + 33 14 420 6718;

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