The Australian Energy Market Commission (AEMC) is responsible for ensuring that the framework of economic regulation applying to gas and electricity markets in Australia remains effective at delivering the objectives for these markets set out in statute. Toby has been engaged by the AEMC on many occasions to advise in connection with proposed changes to the Rules or other processes where AEMC needs economic advice. Some examples of this work are described here.

The statutory objectives for the gas and electricity markets were recently revised to include greenhouse gas emissions reduction targets. As a result, the AEMC commissioned advice on how to take account of impacts on emissions in its decision-making. Toby co-authored a discussion paper recommending how this could be done.

Reliability of energy supply is also a key objective of the regulatory framework, which is implemented in the National Electricity Market, in part, through the “reliability settings” and the design requirement that USE (Unserved Energy—the part of peak electricity demand expected to be un-met due to insufficient supply available in the wholesale market) be no more than 0.002%. The AEMC commissioned a study looking at whether behavioural economic concepts such as risk aversion suggest that the reliability settings might need to be adjusted. Toby was the lead author on the resulting paper.

Toby has also advised AEMC on market design questions.

Incentive mechanisms in regulating energy networks

Regulators of energy networks have historically focussed on encouraging network owners to become more efficient (controlling costs). Economic regulation provides a financial incentive to owners because, in most jurisdictions, owners keep the difference between the revenue they are allowed to collect from network users, and their costs in running the network. Some regulators have also considered the “outputs” delivered by the network and developed mechanisms to incentivise delivery of these outputs. A common example is reliability (customer interruptions), but other examples include the quantity of small-scale generation accepted onto the network, the use of demand response as a substitute for investment in network assets, or “innovation” generally.

Toby was the lead author on a paper for the Electricity Networks Association of New Zealand that proposed a way of classifying outputs in a way that helps identify optimal incentive mechanisms. The paper reviewed experience with incentive mechanisms in Great Britain, Australia, and several US states, and looked specifically at incentives for innovation.

Toby’s work on PBR (performance-based ratemaking) in Alberta and Hawaii is described below.

PBR (Performance-based Ratemaking) in Alberta

Traditional “cost-of-service” regulation of gas and electricity distribution networks in North America typically involves rate cases as frequently as every one or two years. This is administratively burdensome, and tends not to provide a financial incentive to control costs (because frequent rate cases allow an opportunity for increases or reductions in costs to be passed on to customers in changes to cost-based rates). In contrast, regulation of energy networks in Great Britain, Australia and New Zealand traditionally involves resetting prices only every five years, with prices in the intervening years changing formulaically to account for inflation, growth, and expected changes in costs (sometimes called “productivity”).

The Alberta Utilities Commission adopted a PBR framework in 2012. With colleagues at Brattle, Toby presented at an AUC technical workshop on PBR design ahead of the generic proceeding to implement PBR for the Alberta Utilities. Toby later advised the ATCO utilities on PBR plan design, and testified in several proceedings about rebasing between plans, and plan parameter selection.

Toby testified about PBR3 plan design in proceeding 27388. Toby’s written evidence on PBR3 plan design is here.

He also testified about rebasing between PBR1 and PBR2 in proceeding 25422. Toby’s written evidence on rebasing is here.

PBR (Performance-based Ratemaking) in Hawaii

Traditional “cost-of-service” regulation of gas and electricity distribution networks in North America typically involves rate cases as frequently as every one or two years. This is administratively burdensome, and tends not to provide a financial incentive to control costs (because frequent rate cases allow an opportunity for increases or reductions in costs to be passed on to customers in changes to cost-based rates). In contrast, regulation of energy networks in Great Britain, Australia and New Zealand traditionally involves resetting prices only every five years, with prices in the intervening years changing formulaically to account for inflation, growth, and expected changes in costs (sometimes called “productivity”).

The Hawaii Public Utilities Commission has been developing a PBR framework to apply to the Hawaiian Electric Companies for some time. Initially this comprised “revenue decoupling” to allow rates to adjust for changes in units distributed without a rate case. Then a “revenue adjustment mechanism (RAM)” was added to allow for some changes in O&M expenses and some rate base growth to be reflected in rates in between rate cases. The current framework adjusts revenue for inflation, with rebasing after five years (or later), and also includes Performance Incentive Mechanisms (PIMs).

Toby has prepared expert reports on several topics for the Hawaiian Electric Companies as this framework has evolve, with these reports filed in Hawaii Public Utilities Commission Docket 2018-0088.

In 2020 Toby wrote a survey paper about PBR plans elsewhere in the US, and he recently wrote a new paper updating the results of the 2020 survey.

The Commission and other stakeholders have been concerned that an unintended consequence of the regulatory framework could be an incentive for network owners to prefer capital investment over other solutions not requiring investment, or even an incentive to “over invest”. Toby wrote a paper analysing the perceived risk of “capex bias” and how it might be addressed.

Advice to the Australian Energy Regulator on rate of return

The Australian Energy Regulator (AER) determines the rate of return every four years in a generic proceeding. This rate of return is then used in all subsequent revenue determinations for individual infrastructure owners, updated for changes in the risk-free rate. During the AER’s process to reconsider its approach ahead of making the Rate of Return Instrument 2022, the AER commissioned a paper from Toby and colleagues at Brattle on how regulators in other jurisdictions set the rate of return. The paper covered eight regulators (the AER in Australia, the Dutch Authority for Consumers and Markets (ACM), the US Federal Energy Regulatory Commission (FERC), the US Surface Transportation Board, the Italian energy regulator (ARERA), the New Zealand Commerce Commission, and Ofgem and Ofwat in Great Britain), and compared methodologies and results.

Toby was also appointed as an expert to advise the AER board on the market risk premium.

Advice to the Energy Networks Association in Australia on rate of return

The cross-jurisdiction analysis of rate of return methodologies prepared for the Australian Energy Regulator was later updated in a paper commissioned by the Energy Networks Association.

Business risk of energy networks in North America

In some jurisdictions, regulators first estimate a range for the cost of capital for energy infrastructure, and then choose a point within that range when building up a cost-based revenue cap. Usually the default is the mid-point of the range, but the regulator may examine evidence about the “business risk” of the specific network and consider whether the network has unusually high (or low) risks, such that the rate of return should be above (or below) the mid-point of the range.

Toby testified about the business risk of two gas distribution networks and a gas storage facility in Quebec in a proceeding to determine the rate of return to be used in setting rates. Toby’s written evidence in proceeding R-4156-2021 is here.

Transfer pricing—wellhead value of natural gas

Some taxes or royalties are applied to the value of natural gas upstream, close to where the gas is produced. In contrast, gas is usually sold further downstream, at a hub or closer to where it will be used. A “netback” analysis may be able to derive a suitable upstream gas price by subtracting the cost of transportation from the downstream price, but this may be complicated if transportation prices are not published. A further complication arises if there is more than one field, if there are many different customers downstream, or if storage is involved. Toby has provided an expert opinion about wellhead gas value in several disputes in different markets. In one matter, the key issue was an appropriate charge for the use of processing infrastructure, and in another case it was an appropriate analysis of firm delivery obligations downstream.

Transfer pricing—financing arrangements for energy infrastructure

Where projects are financed by a parent entity rather than with external debt secured on the project itself, the terns of the parent financing may give rise to a transfer pricing concern. In several matters, Toby has provided an expert opinion about the business risks of an energy infrastructure business. The business risk analysis allows comparable externally-financed businesses to be identified, and hence arm’s-length financing terms to be determined.

Pricing of pipeline gas and LNG

Long-term gas supply agreements may contain re-opener provisions to allow the parties to adjust the contract price periodically. Toby has advised clients about what evidence of current market conditions implies for redetermining the contract price. Past projects include contracts delivering in the Western Australia gas market, in the Eastern states, New Zealand, and for LNG in the Asia-Pacific region.