The cost of capital is of major importance for infrastructure and utility businesses because they are capital-intensive. The Australian Energy Regulator (AER) estimates that the return on capital is typically about half of the total revenue of the electricity and gas networks itregulates.1
Furthermore, small changes in the cost of capital lead to very large changes in regulated revenues. The AER estimates that a 1% change in the cost of capital results in an 8.2% changeto regulated revenues. Regulated revenues for electricity networks in Australia were $12 billion in 2022, so a 1% change in the cost of capital would shift revenue by about $1 billion.
Consequently, estimates of thecost of capital are strongly contested. Consumers and regulated businesses tryto persuade regulators to employ lower or higher values. This has generated debate across almost all elements of the cost of capital and there is rich and extensive literature on the subject, including litigation in the courts.
In more recent times (at least in Australia and New Zealand), the field of debate has narrowed as approaches have become more settled. There is still active engagement on a range of hot topics including:
In this paper, I first provide an overview of each of the 10 hot topics. In the second half ofthe paper, I briefly touch on a range of other topics that did not make the top 10.
The terminology in this space is often truncated and used imprecisely. For the most part,this doesn’t seem to matter much because the meaning can usually be ascertained from the context (especially where formulae are employed). However, in some situations, precisionis critical.
For the purposes of this paper, I will use the term Cost of Capital to refer to the cost to afirm of raising debt and equity capital. This is termed the weighted average cost of capital(WACC). The rate of return is the other side of the coin; it is the return investors expect from providing capital to a firm. Regulators typically try to set the rate of return used in their determinations to match the cost of capital the firm faces, so the distinction does not bindin our context.
There are myriad subcategories that can arise. For example, returns can be realized,expected, or required; they can be pre-tax or post-tax, nominal or real. Where precisionmatters, I will spell it out.
Key regulatory decisions
In this paper, I have focused on the:
• New Zealand Commerce Commission (NZCC) – new Input Methodologies publishedDecember 2023
• Australian Energy Regulator (AER) – new Rate of Return Instrument published February2023; and
• Ofgem Network price controls 2021-2028 (RIIO-2)
There are many topics that could be included in the top 10, and different analysts are likely to have different choices. The following are the topics that seem most important and relevant in my view.
Many countries now include climate change objectives in their utility regulation. In New Zealand, the Climate Change Response (Zero Carbon) Amendment Act (the Zero Carbon Act) applies. The NZCC explicitly considered this legislation in its 2023 review ofthe Input Methodologies.
The NZCC considered this aspect from two perspectives:
In conclusion, the NZCC decided that specific adjustments to the cost of capital were not necessary. Instead, itpointed to the flexibility in the regulatory determinations to respond appropriately. It highlighted adaptability in demand and expenditure forecasts (including expenditure to increase resilience) and pass-through mechanisms andre-openers. It did make some adjustments to increase the flexibility availablein these mechanisms.
In Australia, the National Electricity, Gas and Retail Laws were amended in September 2023 to introduce an energy emissions objective. The addition is included in section 7(c):
The objective of this Law is to promote efficient investment in, and efficientoperation and use of, electricity services for the long-term interests of consumersof electricity with respect to —
(a) price, quality, safety, reliability and security of supply of electricity; and
(b) the reliability, safety and security of the national electricity system; and
(c) the achievement of targets set by a participating jurisdiction —
(i) for reducing Australia's greenhouse gas emissions; or
(ii) that are likely to contribute to reducing Australia's greenhouse gasemissions.
The AER’s most recent decisions were almost finalized before the legislation came intoeffect, but the amendments were anticipated in the proposals it received and its decisions.The results are most evident in forecasting and resilience expenditure.
It is common to see different regulators taking different approaches to key elements of the cost of capital. At times these differences can be quite material. Nevertheless, once anapproach is employed there is considerable momentum to continue the chosen approach. The AER provides a clear example of this momentum. In its process, both consumers and regulated businesses submitted there should be a “high barfor change”. The AER went on to explain the outcome of its considerations as follows:
We did not enter this process with the expectation of making only minimal changes.Instead, we have undertaken an extensive and open review, exploring all aspectsof the rate of return in detail. As we progressed through our review, we found thatthe approach outlined in the 2018 Instrument is supported by data and financial principles
When considering our decision, the approach in the 2018 Instrument has deliveredoutcomes that are align with the relevant risks. Therefore, we believe the NEO andNGO are best advanced by largely continuing our current approach. Minimisingchange is likely to promote stability and predictability which in turn supportsefficient investment. We do not consider the criteria for making material changes to our approach have been met.
Regulated utilities are attractive to investors because they are stable, low-risk businesses that offer consistent revenues andreturns. This preference for stability extends to the regulatory framework and approach.
Typically, when regulators set the cost of capital, they do so by exercising regulatory judgment about a rangeof individual inputs, which are then brought together to generate a result.This is most prominent in the cost of equity, where it is not possible to observe expectations directly.
Consequently, once the resultis derived, regulators tend to want to step back and ask themselves whether the result seems reasonable. However, there are considerable difficulties inassessing overall reasonableness. Firstly, the data available is no better (andmore likely worse) than the data used to estimate the individual components.Secondly, and more importantly, indicators of reasonableness are heavilyinfluenced by factors outside of the cost of capital. For example, theprofitability of regulated businesses depends on the impact of incentiveschemes and the ability to outperform the regulator’s opex and capexdeterminations. Therefore, any use of reasonableness checks is subject to ahigh degree of judgment.
Nevertheless, reasonableness checks play acentral role in regulatory decision making. In 2012, the NZCC undertook a rangeof reasonableness checks of its final WACC. These checks were then reviewed bythe New Zealand High Court on appeal. The High Court observed that:
[1210] The comparative information against which the Commission tested itsWACC estimates comprised:
(a) yields on five-year Government stock and BBB+ corporate debt.
(b) estimates of the long-run historical returns earned by New Zealand investorson investments of average risk (over the period 1900-2009);
(c) estimates of future returns expected by New Zealand investors on investmentsof average risk.
(d) estimates of post-tax WACC in other regulatory contexts especially in NewZealand, Australia and the United Kingdom.
(e) independent estimates of the post-tax WACC for New Zealand monopolies;and
(f) estimates of the post-tax WACC using other approaches including the classicalCAPM.
The Court then went on to concludethat the Commission’s cost of capital satisfied the reasonableness test, butthe appellants would not if they were successful:
[1228] We therefore agree with Commission’s conclusion that those independentestimates support the robustness and reasonableness of its WACC estimate. Theydo not, to use the Commission’s words, identify any oddity or other like outcome inthe Commission’s estimates, such as might have required the Commission to changeits approach. Moreover, those independent estimates strongly suggest that theWACC estimates that would result from allowing in full the appellants’ appealsagainst the Commission’s cost of capital IMs would be considerably more than thosethat would be appropriate given the Part 4 purposes.
Similarly,the AER undertook substantial cross-checking in its 2022 rate of returnInstrument process. The cross-checks included: regulated asset base (RAB)multiples, financeability tests, scenario testing, historical profitability,investment trends, other regulators’ rate of return and analysts’ discountrates. The AER concluded:
We have explored a range of measures that might provide some insight into thesuitability of our overall rate of return. All these measures suffer limitations, butcollectively may provide a sense-check of our overall outcome.After reviewing the available cross-checks, a balanced assessment of theperformance of the 2018 Instrument leads us to reasonably conclude that the 2018Instrument has broadly performed adequately.
Among the cross-checks, RABmultiples are the most controversial, with some participants arguing that theyhave no value while others say they have great value. In respect of RABmultiples, the AER concluded:
Overall, our further investigation leads us to conclude that our current and expectedrates of return are at least sufficient (as part of the overall regulatory compensationto investors) and that the allowed return has not been below investor expectations.
The AER observed that cross-checkshave also been employed by Ofgem and Ofwat:
For example,Ofgem uses the following cross-checks for its cost of equity estimate:
However, in its most recent decision, Ofgem made noadjustment to the rate of return based on the findings of cross-checks.Further, Ofgem’s latest draft decision (ED2 from June 2022) shows that CAPM isused without adjustment even though cross-checks supported lower values,stating that: ‘…we do not adjust the results […] because we are mindful that nocross-check is perfect, and we are confident that CAPM should remain the primary model.’
The Water Services Regulation Authority in the UK (Ofwat)has recently discussed the use of cross-checks in its draft methodology forPR24,611 stating that it intends to ‘set the allowed return on equity on thebasis of the CAPM [and does] not envisage departing from the CAPM-derivedestimate of the allowed return, unless there is strong and compelling evidencefrom market-based cross-checks.’ Further, Ofwat notes that ‘there should be a high evidential bar for movingaway from [a] central estimate [and] expect that any adjustment would be modestand would in any case lie within the endpoints of the CAPM derived cost of equity range.’
Ofwat proposed to use the market-to-asset ratio analysis(that is, RAB multiples) as the main cross-check in determining the allowedcost of equity, noting that ‘[Ofwat does] not envisage departing from theCAPM-derived central estimate of the allowed return, unless there is strong and compelling evidence from market-based cross-checks such as MAR analysis.’
Ofwat’s recently published final methodology for PR24 proposes that there is not ‘sufficiently strong evidence from ourMAR-based cross-check to choose a point estimate other than our centralCAPM-derived point estimate.’
In recent years, we have seen a trend where publicly listed utility firms have been acquired by private equity firms and subsequently delisted, resulting in the unavailability of data on their traded equity betas.
Most importantly, in Australia, the two best comparator firms, Spark Infrastructure and AusNet, have been acquired and delisted. Typically, these acquisitions have taken place at values well exceeding the regulatory asset base.
With this diminishing data set, regulators are faced with using increasingly old data or drawing on data from firms that are less comparable, including international firms.
In 2016, the NZCC drew on an energy comparator sample included 74 companies from New Zealand, Australia, United States, and United Kingdom. In its final decision in 2023, 51 comparator firms were included. The resulting equity betas were like those calculated in 2016.
Unless there is a change in the trend of acquisitions, regulators are likely to face a comparator set that is smaller and less representative. This decline is felt most acutely when estimating equity beta, but also impacts credit ratings and gearing.
The AER has signalled that it intends to undertake further work on the comparator set:¹²
We have also engaged on this issue as part of our working paper series, as well as our draft Instrument. Having considered the latest submissions and other relevant evidence before us, our view remains that there are likely considerable complexities around developing an approach using international firms as comparators. International firms likely have different characteristics and operating and market environments to the regulated ‘pure play’ Australian energy network businesses and, as a result, may not be directly comparable to those we regulate. We intend to undertake work on this issue in advance of the 2026 Instrument, particularly considering the diminishing number of comparators.
There has been a long-standing question about whether the cost of equity should be estimated based on the length of the regulatory period or a period more consistent with the life of the underlying assets. Regulators have taken different approaches in the past and have changed their approaches. For example, the Queensland Competition Authority and Economic Regulatory Authority in Western Australia previously employed a term matching the length of the regulatory period but switched to 10-year terms in 2021 and 2022 respectively.
The AER considered changing from a 10-year term to a 5-year term in 2022, but ultimately decided to stay with a 10-year term. Even though the shift would only have a small impact on the total return once consequential amendments to other parameters were made, the shift was strongly opposed by regulated networks. The networks indicated their opposition was because the shift would undermine the stability and predictability of the current framework “if the AER makes this change, what other changes might be coming in the future?”.
In its review of its Input Methodologies, the NZCC was under considerable pressure to switch from its practice of matching the term of the regulatory period to match the approaches employed in Australia. Ultimately, it decided to maintain its current approach. The NZCC concluded that:
Using a term for the risk-free rate for debt and equity that is matched to the length of the regulatory period ensures consistency in the way in which debt and equity are estimated:
There is a tendency among regulators to employ long-term averages in their cost of capital. For example:
In respect of the cost of debt, utility businesses typically raise debt in a portfolio that spans several years. This means a relatively small proportion of the total debt falls due for renewal each year. In this way, the business can mitigate its financing risk. However, if the regulator sets the cost of debt at each determination, then the business faces interest rate risk unless it can hedge a large proportion of its debt portfolio during the determination window.
If the regulator employs a trailing average approach where a proportion of the cost of debt is updated each year, then the business faces much less pressure to hedge its interest rate risk. In addition, the trailing average approach tends to smooth variations in interest rates, so consumers face a smoother price path across regulatory periods.
These approaches work fine when regulating a business with a stable regulatory asset base and steady year-on-year capital additions. However, long-term averages can be far from the prevailing cost of capital at points in time. In the current circumstances where very large investments in transmission links are needed to support new renewable generation, investment incentives can be distorted.
In Australia, the NSW electricity business, Trans grid, is in the process of constructing several new links that have the potential to double its regulatory asset base over a short period. The trailing average cost of debt employed by the AER is currently below the prevailing cost of debt and this may inhibit the new investment.
The AER recognized this potential issue in its draft Rate of Return instrument and proposed introducing a weighted trailing average based on expected additions to the capital base. The AER set out detail on how the weighted average would operate. However, there was very little support for making the change from stakeholders, including Trans grid. The AER noted that it expects the change in regulatory asset bases to be gradual, with the new projects going through regulatory investment tests and early stages of construction and this would minimize pressure on the trailing average.¹⁴ The AER intends to undertake further work in advance of the next rate of return instrument.
The NZCC employs a prevailing cost of debt approach and received submissions that it should switch to a trailing average. The NZCC decided to maintain its current approach noting:¹⁵
Figure 1: Regulated Suppliers’ Debt Portfolios: Tenor vs. Interest Rate Repricing Period
The market risk premium (MRP) is the most challenging element of the cost of capital for regulators. Part of this challenge is that there are very different potential approaches depending on the cost of equity model or models employed. The major classes of models include:
E[ri] = rf + βi(E[rm] − rf)
where E[ri] is the expected rate of return on asset i when the price is in equilibrium, m is the market portfolio with expected rate of return E[rm], the risk-free rate of return is rf and βi is a standardized measure of covariance risk, which represents non-diversifiable risk of asset i. The term E[rm] − rf is the MRP.
Most regulators employ the CAPM. As such, they need a way to estimate the MRP. A common approach is to set a fixed MRP for a period and revisit it every so often. Under thisapproach the cost of equity varies one-for-one with the underlying risk-free rate. Thiscontrasts with the Wright approach, where the cost of equity is fixed and does not move atthe risk-free rate
The AER has considered how to estimate the MRP. The approaches it has considered includehistorical excess returns, DGMs, surveys, conditioning variables and total market returns.17In its draft decision it considered using a blended approach with an estimate derived 50% from historical excess returns and 50% from the 3-stage DGM. There was little support fromstakeholders for this approach, so the AER continued with a fixed MRP for the life of its rateof return instrument.
The NZCC uses three main approaches to estimating the MRP including:
Professor Aswath Damodaran publishes an annual update for estimating the equity risk premium that provides further details.¹⁹
The Independent Pricing and Regulatory Tribunal in NSW (IPART), uses a blended approach which estimates the cost of equity as the midpoint between our estimates of the current and historic cost of equity. The historic cost of equity employs a historical estimate of excess returns as the MRP. The current cost of equity uses the median value of the MRP derived from 6 methods:
The first four of these methods are variations of the DDM. They differ in detail, but all infer a forward-looking market average return on equity based on expected dividends. The fifth is another variation of the DDM, which uses the forecasts of stock market analysts for individual stocks and a DDM. The sixth method uses four economic indicators to derive an indirect estimate of the MRP.²⁰
Controversially, in its 2022 Input Methodologies decision, the NZCC allowed for the shortening of asset lives for gas pipelines, in effect, bringing forward depreciation to reduce asset stranding risk. This decision was appealed by the Major Gas Users’ Group to the High Court of New Zealand.²¹ The appeal was dismissed in favour of the NZCC’s approach.The Court concluded that stranding risk needed to be addressed somewhere within the regulatory framework. Typically, for a firm in a workably competitive market, that risk would be compensated up-front through expected returns. However, in the case of regulated gas networks, that approach is not feasible, and some ex-post accommodation is required. The NZCC’s approach of an early return of capital was viewed as reasonable.
The Court considered a range of interesting questions including: Is stranding risk already addressed through the weighted average cost of capital component – or otherwise provided for in the input methodologies? Is there provision for asymmetric risk in the WACC? Is there double counting? and is the 2022 Input Methodologies Decision premature?
Like the NZCC, the AER has introduced a degree of accelerated depreciation for gas pipelines. In the case of Evoenergy in the Australian Capital Territory, the AER concluded that accelerated depreciation via shorter asset lives was warranted:
In light of the elevated risk of network closure and a substantial reduction in demand, we consider our final decision is a prudent and responsible first step to protect the long-term interests of Evoenergy’s gas consumers from asset stranding risk.²²
The AER noted that it would not be prudent for the network owner to add substantial new discretionary investment capital in the current environment.
But what gas network closure advances far more rapidly than anticipated? It depends on whether customers are locked in or can exit the network. If customers are locked in, they will pay higher prices to recover the outstanding capital over a shorter period. On the other hand, if demand and customer numbers decline, which is more likely, the remaining customers will face rapidly increasing prices. At this point, it may no longer be possible for the network to charge the regulatorily determined prices because it will accelerate the “death spiral.” Options at this stage include deregulating the network, leaving the risk to be managed by the equity holders, or government intervention to support customers or the asset owners.
With new large-scale links being built to support renewable energy generation, there is an option for these links to be built and operated through a competitive tender process. Provided the competitive tender is robust, this is an excellent opportunity to avoid the need for regulation altogether. Further, the information revealed in these processes could be used by regulators to cross-check the cost of capital they are employing in their regulatory decisions.
There are 2 recent prominent examples: UK offshore wind transmission and NSW renewable energy zones (REZ).
In the UK, the right to build, own and operate offshore wind transmission lines has been auctioned. From the auction results, it is possible to estimate an implied cost of capital. Ofgem has published the results of its analysis.
We previously referred to OFTO bids in December 2018, May 2019 and July 2020 where we used OFTO bids to derive the average implied equity IRR, nominal, post-tax. We acknowledge that there are risk differences between DNOs and OFTOs. OFTOs are not subject to cyclical price controls, such as RIIO-ED2, that apply to the onshore electricity distribution assets. However, we believe that this cross-check is valuable because it relates to electricity network assets, where Ofgem issues and modifies licences, as it does for the electricity distribution sector.²³
Figure 2: Offshore Transmission Owner – average nominal post-tax equity IRR
In NSW, EnergyCo is leading the development of the renewable energy zone (REZ)transmission network infrastructure as the Infrastructure Planner. EnergyCo is responsible for developing and overseeing the planning and approval processes for the REZ networkinfrastructure. Its first major project is the Central-West Orana REZ which will be serviced bynew transmission network infrastructure, including transmission lines and energy hubs.EnergyCo is currently running a competitive tender process to appoint a Network Operatorto design, build, finance, operate and maintain the REZ transmission network.24
While merits review is not strictly a cost of capital issue, its influence on cost of capital is ofthe highest importance.
Regulatory determinations embody the exercise of judgment. Otherwise, regulatoryoutcomes could be coded in legislation and there would be no need for regulators. Whenexercising judgment, it is possible for regulators to err. Merits review provides a mechanismfor regulatory judgements to be tested and corrected if made in error. On face value, thislogic is compelling. However, in practice, merits review has the potential to result in highlyundesirable outcomes. This was the case in Australia, and ultimately led to the removal of merits review.
In Australia, the use of merits review of regulator decisions was commonplace. Between2008 and 2016 reviews were sought on 32 out of 51 regulatory decisions (62%). Even afterreforms were made in 2014 to rebalance and minimise reviews, 12 out of 19 decisions weretaken to review (63%). Of all the matters that were varied or remitted back to the primarydecision maker, none resulted in a decrease in revenues for the regulated businesscompared to the original decision.
Figure 3: Number of AER regulatory decisions appealed under limited merits review
In its submission to the review of limited merits review, the AER stated:
The practical lack of downside risk in seeking a review, coupled with the potential for significant increases in revenues, means that service providers pursue limited merits reviews of our decisions as a routine part of the determination process. …
As a result, regulatory proposals are commonly drafted in a highly legalistic tone. In some cases, service providers have submitted reports prepared by legal counsel. The focus of the proposals has been diverted from being economically persuasive to being legally defensible on appeal. It also makes it harder for other stakeholders, without access to lawyers, to engage with the arguments in such submissions.²⁶
In the second reading speech on the Bill to abolish limited merits review the Minister noted a range of problems with the framework:
To date LMR has increased consumer bills by $6.5 billion.… the Council of Australian Governments (COAG) Energy Council reviewed the LMR regime again in 2016. The review found that the 2013 amendments to the regime had largely failed, including that LMR: remained routine; had significant costs to all participants; presented barriers to meaningful consumer participation; led to significant regulatory and price uncertainty; and was failing to demonstrate outcomes that were in the long-term interests of consumers In the face of escalating energy prices the government is taking action to stop energy networks using the LMR to extract monopoly rents from consumers.²⁷
Since the removal of limited merits review, the regulatory framework in Australia has fundamentally changed. Instead of regulation being “something that is done to consumers,” regulated networks are undertaking extensive and meaningful engagement with consumers, giving them a real say in the proposals they submit to the regulator.
The Powerlink Queensland electricity transmission decision in 2022 was a watershed moment in the cycle of regulatory determinations. Powerlink approached its determination with the objective of putting forward a proposal that was capable of acceptance by consumers, the regulator, and itself.
In its final decision, the AER noted:
This final decision recognises the collaborative efforts of Powerlink and its stakeholders, particularly Powerlink’s Customer Panel and its Revenue Proposal Reference Group (RPRG), who worked together constructively in developing Powerlink’s proposal over almost three years for the long-term interests of consumers.
Powerlink put forward a well-informed initial proposal, underpinned by significant consumer engagement and its overarching goal of lodging a proposal that is acceptable to Powerlink, its consumers and the AER. This allowed us to undertake a targeted review of the proposal, focussing on the key areas of concern raised by stakeholders and our own assessments. This led us to determine that the proposal was capable of acceptance at the draft decision stage of this revenue determination process.
The high-quality nature of Powerlink’s initial proposal has meant that the final stage of this process, where we assessed Powerlink’s revised proposal, has been non-contentious and a more efficient regulatory process for all stakeholders, including Powerlink, consumers and the AER. It is worth noting that Powerlink’s revised proposal was lodged two weeks early, allowing stakeholders extra time to consider the proposal and Powerlink staff to resume their focus on network operations.²⁸
This trend has continued. It is brilliant to see consumers at the centre of the regulatory process rather than lawyers. In the most recent round of regulatory proposals, consumer engagement and influence has been a dominant feature. In almost all cases, the AER has been able to accept the proposals put to it, rather than intervening.
Table 1: Outcomes of AER’s most recent regulatory determinations
While not making our top 10, the following issues are worth a mention.
It is possible for regulators to very accurately measure and then estimate the forward costof debt. The AER uses an approach where it obtains details of each debt instrument issuedby the private businesses it regulates. This data is sensitive, so the process is conducted inconfidence. The AER then publishes a summary of its analysis which shows how the actualcost of debt is tracking against the yield curves it employs for estimating the cost of debt.
This analysis shows that there is a very close correlation between the actual cost of debt andthe AER’s estimates.
Figure 4: Comparison of energy infrastructure credit spread index (EICSI) vs AER estimates ofcost of debt: 12-month rolling average (tenor weighted) against AER A/BBB (matched-term)estimate (June 2015 to June 2023)30
This issue arose in a Competition Markets Authority decision in 2021.³¹ Since then, it has been raised in front of multiple regulators, but to date accepted by none. The argument is “in contrast to the highest-quality non-government bonds, government bonds have special properties that create additional demand for these instruments, which pushes the government bond yield to fall below a ‘true’ risk free rate based on a zero beta asset”.³²
The proposed solution is to add a convenience yield to the risk free rate or include high quality non-government bonds in the estimate of the risk free rate.
The NZCC did not agree to depart from using government bonds to estimate the risk free rate. It noted:
Similarly, the AER considered a convenience yield in depth and decided not to employ the approach.³⁴
The “W” in WACC stands for weighted. Regulators typically estimate the cost of debt and equity separately and then bring them together using a ratio. A common ratio is 60% debt and 40% equity. This ratio has tended to be relatively uncontroversial.
The AER updates its estimate at each rate of return review. The data shows that businesses employ a ratio that is largely stable. The AER received an interest paper from Professor Graham Partington and Stephen Satchell that concluded:
Our discussion and analysis focuses on a number of features of WACC. We argue that WACC does not change a great deal with changes in leverage, largely because there are arbitrages that come into play. Except at extreme levels of leverage, the effects of arbitrage are likely to render the value of the firm relatively invariant to changes in leverage.³⁵
It is not uncommon to find submissions that advocated for the use of financeability testing. The NZCC concluded:
We consider that financing the preferred path of recovery of investment, the one that best promotes the Part 4 purpose, is primarily the responsibility of suppliers. They have a range of tools for doing so, including reducing dividend payments, or raising debt and/or equity. In addition, we are not aware of a shortage of capital currently in this sector. To the contrary, we continue to see transactions at RAB multiples above one, and improving credit ratings.³⁶
The mix of opex and capex used in a regulatory determination of itself, is not a cost of capital issue. However, the mix has a material impact on cash flow and measures of financeability.
Ofgem employs a totex approach where a total expenditure of opex and capex is determined and the regulated business then has a degree of flexibility in the balance of opex and capex going forward. Under the totex approach, there is a risk that regulated businesses will favour opex over capex to increase cash flows in the short term.
The NZCC received some submissions that carbon reduction required further incentives for capex, such as the totex framework employed by Ofgem. It concluded:
Of the alternative expenditure incentive approaches that we considered, such as a totex approach, including a totex incentive mechanism, our decision is that none better promote our Framework’s overarching objectives than the current expenditure incentive mechanisms.³⁷
A split cost of capital would involve applying different WACC values to existing “sunk” assets and capital on new assets.
The NZCC considered that its approach provides suppliers with incentives to invest without providing for a different WACC. Non-systematic risks can be more appropriately dealt with through measures outside of the WACC.³⁸
The NZCC employs a peculiar approach where it estimates a standard error for the cost of capital and then adjusts the final value of the cost of capital based on its judgement on where the probability of error should sit.
When exercising this judgement, the NZCC considers potential asymmetry in the consequences of setting an incorrect cost of capital.
Setting the WACC too high is expensive for consumers because they pay higher bills. However, setting the WACC too low may result in even higher costs for consumers if it leads to outages. Outages from an unreliable network are expensive for consumers and remediating an unreliable network is likely to take some time.³⁹
The NZCC ultimately decided to set the cost of capital for electricity business at the 65th percentile, down from the 67th percentile. This approach seems to have had its genesis in a major electricity cable failure into New Zealand’s largest city, Auckland, in 1998. The failure resulted in electricity outages and major disruption for 5 weeks.
Previously, the NZCC did not index the regulatory asset base for Transpower. When the regulatory asset base is indexed, investors receive part of their total return through capital accumulation rather than cash.
The NZCC decided that it would change its approach for Transpower and index the regulatory asset base going forward. It considered “the benefits of indexation, protection from inflation and promoting pricing profiles that are more likely to be consistent with allocative efficiency)justify the change”.
Estimates of actual and forecast inflation are employed in many places within the regulatory models and cost of capital estimates. The issues are extensive and complex. The AER undertook an extensive review of inflation in 2021.⁴⁰
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