Training Module on Electricity Market Regulation - SESSION 3

Q&A Session

How is the volatility of fuel costs for electricity generators handled by the various control models?

Generally generation and retail can be regarded as competitive market segments that do not require a specific tariff regulation (at least for developed markets as discussed in webinar 1), while it is the network business (electricity grids) for which the regulatory models described in this session are generally primarily applied to. More precisely it is the network charges that are regulated and not the wholesale or retail electricity prices. Higher fuel prices do then result in higher end-user tariffs as can be observed in many countries in the most recent years. 

In countries where electricity markets are not liberalised generation business remains regulated.

Generation costs (fuel cost, operation and maintenance cost, capital cost) are included in the end-user prices, which are regularly reset to accommodate changes in the total supply costs including also generation costs.  In countries where generation business is unbundled explicit generation price control is used. 

The regulatory models applied in practice do:

• either have additional factors in the regulatory formula that allow a pass-through of costs that are beyond the control of the regulated firm, such as fuel input prices (automatic price adjustments); or
• if no explicit regulatory formula is used just allow to include the non-controllable costs in end-user prices.  

In both cases, cost factors such as fuel prices would most likely be passed through to end-customers.

This sounds just like a co-operative model where those served are ''owners'' of the co-op and share in profits/losses on a similar model.  Does your presentation involve consumer ownership of the supplier/utility? 

It is true that sliding-scale regulation shares some properties of a co-operative in that profits are somehow shared with the users. However customers of a co-operative act as owners of the co-operative company and therefore participate in all losses and profits of the company. Customers of an energy company regulated by a sharing mechanism do not hold any stakes in the energy company (which might be state-owned or listed on the stock exchange), but just get a share of the economic rent (extra profit defined as actual minus allowed return) in form of lower tariffs in the next regulatory period. The reverse is also true they will get a share of the economic loss, of course depending on the sharing arrangements.

The owners of the co-operative benefit from all profits whereas the customers of a company regulated by a sharing regime just participate in the economic rent (extra profit) while the "fair" return approved by the regulator remains with the company and its owners (shareholders).

Is there any international experience in X calculation in the formula CPI-X?

The regulatory regimes do vary quite significantly from one country to another and even within one country details can be quite different for different sectors and regulated services; this also includes the calculation of the company specific productivity targets (X-factors). The Assessment of the (in)efficiency of individual regulated service providers is done through a benchmarking with other similar companies (ideally in the same sector and the same country). The benchmarking techniques applied in practice can be grouped into 3 groups: non-parametric models (Data Envelopment Analysis), parametric models (Corrected Ordinary Least Square, Stochastic Frontier Analysis) and engineering models (Virtual Network Models). All parametric and non-parametric benchmarking methods do require a large-enough sample of comparable companies to make a reasonable assessment of the current efficiency level and the scope for future efficiency improvements, which can be quite difficult to get.

Transmission System Operators (TSOs) can only be benchmarked against TSOs in other countries as most countries are only served by one TSO. The distribution networks are generally served by a larger number of Distribution System Operators (DSOs), but DSOs do often vary in size and geographic conditions (such as serving primarily large rural or densely populated urban customers, operating in flat or mountainous terrain, serving many industrial customers with a high load or only residential customers with a small load each etc.).

We will have a separate webinar on efficiency assessment and benchmarking on the 11th of January 2010.

Has the regulation in Germany been changed because of cartel discussions back in 2007 or is it a model that existed before? (I am referring to the energy market inquiry at the end of 2007) 

The German revenue cap regulation goes back to the adoption of the EnWG in 2005 (adopted on the 07.07.2005), where the introduction of an incentive regulation regime was already set out (§21 EnWG). The details of which had to be developed by the BNetzA and a report with proposals to be published by BNetzA until 30.6.2006 (§112a EnWG). The Incentive Regulation Ordinance that sets out the current regulatory regime of a revenue-cap was adopted by the German Parliament on 29.7.2007. The investigations by the German competition authorities (Bundeskartellamt) and the Directorate General for Competition of the European Commission (including the Sector Inquiry) are not related to the introduction of incentive regulation in Germany; although it was expected that the establishment of the Bundesnetzagentur and the introduction of incentive regulation for the network business (which both were a result of the EnWG of 2005) will reduce the need of the competition authorities to investigate the network business in the future.

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