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Introduction

Energy transition seeks to embrace energy technologies and innovation to decarbonize, or at least reduce the environmental impacts of, energy systems. In addition, energy transition seeks to maintain energy security and ensure affordable energy to underpin broader (human) development goals. That energy policy has three major concerns (environmental, security, and socioeconomic) is beyond question. What is open to much debate is the nature of how this transition might be achieved and how it will ultimately look (Battaglini et al. 2009; Verbong and Geels 2010). Whatever shape the energy transition takes, another factor that is beyond question is that it will require significant investment. For instance, for Europe, the International Energy Agency (IEA) projects that up to US$2.2 trillion of total power sector investment is needed in the EU between 2014 and 2035 (Tulloch et al. 2017). This in turn posits the question of how this investment can be mobilized or incentivized.

This chapter explores the history and current status of green energy finance (and therefore energy transition more generally) in New Zealand and Australia. The focus is principally on electricity systems and energy generation, meaning that we do not focus on energy efficiency policies, although we acknowledge their importance. Further, the global push to electrify light-vehicle fleets means that energy for transport more generally is relevant, although not central to the chapter. It is noteworthy, however, that 2017 saw many countries set ambitious targets in terms of the use of electric vehicles (EVs) (CNN 2017). Both countries have experienced supply interruptions in recent years that have highlighted the importance of energy security in transition; in 2017, a ruptured pipeline to Auckland Airport led to widespread flight cancellations over a prolonged period, while South Australia experienced blackouts between 2016 and 2017, which were part of Australia’s broader “energy crisis.” Further, social and economic considerations are also prominent in both countries, with high energy costs contributing to concerns about fuel poverty.

These concerns come despite both countries having enviable renewable energy resources. Both have the potential to be world leaders in energy transition, yet the two countries present highly contrasting contexts for energy finance. Interestingly, between them and over time, they have employed most of the important policy tools available to incentivize renewables and green energy finance (e.g., carbon taxes, carbon trading, a green investment bank, a green certification market, and feed-in tariffs).

New Zealand has a system that, through state investment and subsidies starting as early as the 1950s, and continuing through to the mid-1980s, has high levels of large hydro power. More recently, there has been a growth of geothermal and wind power. That, coupled with relatively flat demand growth for electricity between 2006 and 2012, has contributed to a “hands-off” market approach by government, with no formal policies beyond the inclusion of transport and energy in the New Zealand Emissions Trading Scheme (NZ ETS). NZ ETS has come in for stringent criticism due to a collapse in carbon prices associated with imported allowances. Despite a lack of investment incentives and a hostile regulatory framework, distributed generation has experienced some growth. Most of the large energy incumbents fear the stranding of assets and ultimately a “death spiral” from the uptake of distributed power. This may be contributing to the reluctance of large incumbents to finance new energy projects.

Australia , by way of contrast, but also for historical reasons, has an energy system that has been dominated by coal. Thus, the more pressing need to decarbonize the energy system has been reflected in more interventionism. From a governance perspective, the Australian context is complicated by the dual layer of federal and state interventions. For instance, between 2008 and 2012 most states in Australia implemented some type of feed-in tariff to incentivize rooftop solar photovoltaic (PV) systems. At the federal level, energy policy has lacked stability and, therefore, the certainty that investors desire. In 2011, Australia introduced a carbon tax with a view to transition to an emissions trading scheme in 2014. However, the legislation that enabled both was repealed in 2014. Despite the failure of the carbon tax, Australia has had a tradable green certificate market (the Renewable Energy Target scheme) since 2001 to incentivize the transition to renewables that has underpinned investment in renewables—but the scheme has also been hampered by political uncertainty. In 2012, the Australian government established a green investment bank called the Clean Energy Finance Corporation.

From the above brief introduction, it is clear that New Zealand and Australia provide interesting contexts in which to explore various policies to promote investment in renewables. We do so as follows: section “Energy System and Emissions Context” provides more background on the energy systems of Australia and New Zealand, section “Green Energy Finance Flows” presents a simple analysis of green energy financial flows in both counties, which are subsequently understood in section “Policies, Incentives, and Barriers” in the context of the various financing policies, incentives, and barriers that exist in both jurisdictions. The experiences of the two countries provide valuable lessons for other jurisdictions wishing to mobilize investment in renewables—it is with these lessons that this chapter concludes in section “Conclusion”.

Energy System and Emissions Context

Australia

The Australian economy has undergone a rapid transformation over the last five decades, turning it into one of the most advanced and wealthy countries in the world. As is apparent from Figure 1, this rapid gross domestic product (GDP) growth is associated with rising energy consumption; however, the rate of increase in energy consumption is lower than GDP growth due to increases in energy productivity.

Figure 1:
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Australian Gross Domestic Product (GDP) and Energy Consumption Indices. (Compiled from DoEE 2017 Table B of Australian Energy Statistics, energy consumption measure used is equivalent to primary energy)

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Australia’s coal-dominated electricity generation system is a historical legacy dating back from the end of the Second World War when there was rapid expansion of the use of coal-fired generating plants due to the existence of abundant and cheap coal reserves. Australia today continues to have plentiful coal reserves and production, much of which is exported, with the remainder used for domestic power generation (Department of Industry, Innovation and Science n.d.).

Despite its continued dominance in the generating mix, reliance on coal has decreased from 80.18% in 1990–91 to 62.93% in 2016 (Table 1). This reduction occurred over a period of rising demand (Figure 1) and was achieved through increased use of gas and renewable generation. The increased share of gas generation in the total generating mix over the period was 11.60% (from 6.88% in 1990/91 to 18.48% in 2016), which is more than double the increase of renewables of 5.51% over the period (from 10.77% in 1990–91 to 16.28% in 2016).

Table 1: Australian Electricity Generation
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Figure 2 breaks down the evolution of renewable generation in Australia highlighting the existence of hydropower pre-1990 and the use of wind energy starting in the early 2000s and its subsequent increase. The use of solar starts to be meaningful about a decade later, circa 2010/11.

Figure 2:
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Evolution of Renewable Energy Generation in Australia. (Compiled from DoEE 2017)

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Another distinguishing factor of the Australian electricity system is the large differences across the seven large states, suggesting that state policies, as well as resource and geographical factors, play a role in generation mix choices. New South Wales, Victoria, and Queensland are dominated by coal, while Western Australia and Northern Territory are dominated by gas generation (see bottom panel of Table 1). Tasmania has a generation profile similar to New Zealand’s (section “New Zealand”), which is dominated by hydroelectricity.

South Australia has invested heavily in wind energy and distributed solar power, meaning a mix of about 45% renewables and 40% gas.

New Zealand

New Zealand’s geology and location in the “roaring forties” has endowed the country with an abundance of renewable resources, including hydroelectricity, geothermal, and wind, and its forestry industry also provides a modest supply of waste wood that can be used for generation of heat, perhaps along with electricity. Hydroelectricity was first developed at Bullendale in Central Otago, in the lower South Island in the 1800s (Reilly 2008). The central government sought to consolidate control of the nation’s waterways via the Public Works Amendment Act 1908 (Reilly 2008) and developed other hydroelectric projects and progressively developed the national grid to connect these projects. Table 2 charts this expansion of the largest hydropower project in the 20th century, with the largest projects occurring in the 1960s, 1970s, and 1980s.

Table 2: Introduction of Generating Plants in New Zealand (90 MW or Larger)
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In addition to hydroelectricity, the government proceeded to develop the Wairakei geothermal station in 1958, the Ohaaki geothermal station in 1989, and the Meremere, Huntly, New Plymouth, Whirinaki, and Stratford fossil-fueled power stations between 1958 and 1985. In the late 1980s, the government acted to introduce greater commercial discipline into decision-making in the power sector by creating the Electricity Corporation of New Zealand, which was required to act in the same way as a successful business would. Then, in 1996, the competitive, deregulated, wholesale market was set up. At this point, renewable generation comprised 80% of the mix.

As New Zealand’s reliance on hydroelectricity increased during the 20th century, so did reliance on inflows into the hydro catchments. However, the stream of inflows is highly volatile (potentially increasingly so due to climate change and irrigation schemes), and the nation’s hydro storage lakes are relatively small compared with total demand, so it was recognized that backup generation or more storage was required.

Ultimately, a competitive electricity industry met this challenge by the development of fossil-fueled thermal generation—this was facilitated by the development of gas fields in Taranaki, on the west cost of the North Island. It is clear from Table 2 and Figure 3 that the introduction of competition altered the nature and scale of generation projects, with the construction of several large thermal plants between 1996 and 2007. In 1995, renewables comprised 84.5% of generation, with this subsequently dropping to 65.4% in 2008. After 2008, the share of renewables in the generation mix starts to increase again, but this time due to wind and geothermal power rather than hydrogeneration (Figure 3).

Figure 3:
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Renewable Energy Generation in New Zealand (GWh and %). (Compiled from MBIE 2018)

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Although growth in the geothermal sector halted after 1989, it then reignited in 1997 with the development of better turbine technology and the recycling of geothermal fluids. Since 1997, over 770 MW of new capacity has been added and the sector contributed 17% of generation in 2015; only 2% behind the fossil-fueled thermal sector. The wind sector also grew quickly starting with the 32 MW Tararua Stage 1 wind farm in the lower North Island in 1999; by 2014 the total installed capacity exceeded 670 MW, and in 2015 the sector generated 5% of total generation. Total renewable generation now supplies in excess of 80% of the electricity market, as shown in Figure 3.

Emissions Profile and Potential of Renewable Energy

New Zealand’s electricity sector remains dominated by large hydroelectric schemes, all built prior to 1992, which currently produce about 56% of all generation for a total annual demand of just over 40 TWh. Further, the construction of geothermal and wind projects since the turn of the century means NZ has a very “clean” energy generation system. However, due to high agricultural emissions and emissions from transport (by developed country standards, the country has an aging and inefficient light-vehicle fleet), New Zealand’s greenhouse gas emissions per capita are high by international standards (Figure 4). Electrifying transport, especially the light-vehicle fleet, and reaching 100% renewable generation (Mason et al. 2010, 2013) present realistic and considerable opportunities to reduce emissions for New Zealand.

Figure 4:
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Total Greenhouse Gas Emissions Per Capita. tCO2e Tonne of Carbon Dioxide Equivalent for Greenhouse Gases. Data are Inclusive of Land-Use Change and Forestry. (Compiled from WRI, CAIT (n.d.))

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By way of contrast to New Zealand, Australia’s electricity sector remains dominated by coal despite increased use of gas and renewables in recent years. Unsurprisingly, Australia’s greenhouse gas emissions per capita are among the highest in the world (Figure 4). Emissions per capita have declined since the peak of 33.1 tCO2e per capita in 2001 to 22.3 tCO2e per capita in 2014. This still represents three times the emissions per capita of the EU 28 countries or twice those of Japan. Studies suggest that Australia, like New Zealand, could conceivably achieve 100% renewables (Elliston et al. 2012, 2013). Indeed, modeling by Vithayasrichareon et al. (2015) suggests that a generation portfolio with 75% renewables in 2030 is the most optimal in terms of cost, cost risk, and emissions. In this context, one would expect that Australia would have had, by international standards, heavy investment in renewables in recent years. As we will see in section “Green Energy Finance Flows”, this is not the case.

Overall, it is clear from Figure 4 that both Australia and New Zealand have high greenhouse gas emissions per capita and they have not met their potential in terms of harnessing renewable energies. Both have abundant renewable resources with which to reduce emissions and the potential to reach 100% renewables in generation (Elliston et al. 2012, 2013; Mason et al. 2010, 2013). This will require investment in renewable energies, networks, and electrification of transport. Clearly, the challenge for Australia is much greater than that faced by New Zealand.

Green Energy Finance Flows

In this section, we analyze the flow of money toward green energy (green finance), which explains the current state of renewables in the two countries described above. Our focus is on financial flows since 2004. This is a precursor to exploring, in section “Policies, Incentives, and Barriers”, the policies, incentives, and barriers that have contributed to these flows.

Figures 5 and 6 show the pattern of financial flow to the various green energy technologies respectively in Australia and New Zealand. Both suggest a boom-bust type cycle in investment. In Australia, most of the investment has gone to wind and solar power, with the latter dominating. There have been suggestions that the volatile investment pattern in Australia is the result of political instability and lack of commitment by some administrations. Indeed, Australia had five changes in prime minister between 2007 and 2017.

Figure 5:
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Australian Green Energy Investment 2004 to 2017 ($US Billion). Chart Excludes Geothermal, Marine, and Small Hydro, All of Which were <0.5 $US Billion Over the Period; 2017 Data Cover Up to Q2 Only. (Compiled from Bloomberg New Energy Finance (BNEF) data)

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Figure 6:
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New Zealand Green Energy Investment 2004 to 2017 (NZ$ Million). From 2015 to 2017 There Was No Investment in New Generating Capacity. (Compiled from Energy Link Ltd data)

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Cheung and Davies (2017) test the hypothesis that different administrations have had contrasting commitments to climate change and energy transition by employing a mixed methods case-study and multi-criteria analysis to develop performance ranking scores for the four administrations between 1996 and 2015. The ranking scores achieved by the four administrations were 0.43 for John Howard (11 March 1996–3 December 2007), 0.89 for Kevin Rudd (3 December 2007–24 June 2010), 0.99 for Julia Gillard (24 June 2010–27 June 2013) and 0.11 for Tony Abbott (18 June 2013–15 June 2015). These scores would seem to be reflected in investment patterns (Figure 5); there was an increase in investment from 2009 following the election of Kevin Rudd (Labour) in December 2007 and a reduction in investment following the election of Tony Abbott (Liberal) in September 2013.

Overall, the tumultuous political context in Australia has produced a range of policy interventions, which have included a thwarted carbon tax/trading scheme, a green investment bank, a green certification market, and feed-in tariffs—these are discussed individually in section “Policies, Incentives, and Barriers”. Historically, there would seem to be divergent commitments to tackling climate change and energy transition across Labour and Liberal political lines. However, bucking this trend, there seems to be an uptick in investment since Malcolm Turnbull (Liberal) came into office in September 2015. Indeed, the Turnbull administration has undertaken a range of policy measures and interventions in part prompted by the energy crisis that has seen electricity supply interruptions and large rises in electricity costs (ACCC 2017). The measures include the National Energy Productivity Plan and the Snowy 2.0 pumped hydro energy storage project, which is set to be the largest “battery” in the Southern Hemisphere. This follows the high-profile and politicized construction, in less than 100 days, of the world’s largest lithium-ion battery (129-megawatt-hour) in South Australia by Tesla and its founder Elon Musk.

Moreover, the Turnbull administration has recently announced the National Energy Guarantee, which seeks to solve the crisis and add coherence to energy and environmental policies, thereby dealing with the energy “trilemma” of affordability, reliability, and emissions (DoEE n.d.). While its details are still awaited, the policy places obligations both in terms of the reliability and emissions of the electricity supply. Some commentators suggest the latter amounts to a carbon price via an emissions-intensity trading scheme (Murphy 2017).

New Zealand, by way of contrast, has had political stability, yet it too displays a stop-start pattern to green energy investment (Figure 6). The two technologies that have received investment have been wind and geothermal. Of note are the 2008 boom in investment coinciding with the election of John Key (National) and the passing of the legislation by the previous Labour administration to establish the NZ ETS (section “Carbon Markets and Taxes”). However, the uptick in investment, at least for wind, is likely the result of the Ministry for the Environment’s Projects to Reduce Emissions (PRE) scheme, which provided credits for wind farms between 2002 and 2004 (NZWEA n.d.-a). Under the PRE scheme, the units issued were Kyoto-compliant and were issued to projects that would not have been initiated without the PRE units (Jamieson et al. 2005).

Beyond the short-lived PRE and the NZ ETS, and in contrast to Australia, there has been little in the way of policy. In 2007, a target to have 90% renewable energy generation by 2025 was put in place (MoED 2007) and in 2011 the National Policy Statement for Renewable Electricity Generation (MfE 2011) sought to provide a consistent approach to planning for renewable electricity generation in New Zealand, requiring local government to incorporate policy statements for the “development, operation, maintenance and upgrading” of new and existing energy generation activities “to the extent applicable to the region or district” (MfE 2011). However, the policy statement does not specify the actual extent to which renewable energy should be supported in any particular region.

Epitomizing a lack of ambition in energy policy and commitment, neither the National Policy Statement for Renewable Electricity Generation nor the 90% renewable energy generation target by 2025 came with any substantive policy measures (over and above the ETS) that might have increased investment. After the election of September 2017, a Labour–NZ First–Greens government led by Jacinda Ardern has gained power from the “National” government of 2008–2017. The new government intends to establish an independent Climate Commission, implement a Zero Carbon Act, and requests that it “plan the transition to 100% renewable electricity by 2035 (which includes geothermal) in a normal hydrological year” (NZLP and GPANZ 2017, p. 3). In the meantime, the ETS remains the only policy mechanism that is firmly established and functioning at the national level.

International Comparisons

The above discussion shows that despite the global context of rising investment in energy transitions, relative to other nations, the policy and political context in Australia and New Zealand would seem to be lagging behind most of the rest of the world. However, no country can claim to have an ideal context, as interventions and policies throughout the world are subject to imperfections and political changes (see, for instance, Davies and Diaz-Rainey 2011). As such, we conduct a simple analysis in Table 3 to place Australian and New Zealand investment in green energy in an international context.

Table 3: Green Energy Investment by the World’s Largest Economies and New Zealand
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The second column of Table 3 presents the total investment in green energy between 2004 and Q2 of 2017 for the 13 largest economies in the world and New Zealand. This shows that among the large economies, Australia ranks near the bottom in investment—but this does not take into account the scale of the energy system or the economy. To explore whether Australia’s investment instability (Figure 5) is pronounced relative to other large economies, we calculate for each country the standard deviation of annual % change in investment over the 13.5-year period. We use the annual percentage to adjust for different scales. The results are reported in the third column and show that Australia has had more variable green finance flows than Germany, Japan, and the US. However, flows have been more stable in Australia than in France, Spain, and Italy. This suggests that policy stability may not be the only or even main issue in the Australian context.

Next, we calculate in column five the spend or investment per capita (dividing total investment over the 13.5-year period by population). Here too Australia fares reasonably well, being behind Germany, Japan, and the United Kingdom (UK) but ahead of many developed countries. On this measure, New Zealand fares poorly, having invested per capita amounts equivalent to developing countries such as Brazil and People’s Republic of China. This measure has two issues, however: it does not account for the wealth of the country (hence developing countries doing so poorly with it), and it does not account for the energy context of the country (e.g., generating mix). To address the first problem, we developed what might be termed an “energy-transition-intensity measure”—dividing total investment over the 13.5-year period by GDP per capita.

Our energy-transition-intensity measure suggests that both Australia and New Zealand have lower levels of green energy investment relative to GDP per capita than many other developed countries. This is an intuitive number and tells us how much of per annum and per capita wealth is spent on renewables investment over a prolonged period (looking over a 13-year window means that the measure is not biased by a short-term boom or bust in investment). For the largest 13 economies in the world, Australia has the third-lowest measure, being ahead of the Republic of Korea and Canada, and representing under half the investment of Spain and Germany. Australia has a similar measure to Canada and France; however, both the latter have high penetration rates of “clean” (in the case of France, nuclear) or renewable energy.

New Zealand’s investment under this measure is the lowest of all the countries sampled. This poor performance is mitigated to some degree by the already high levels of renewable energy and low demand growth for electricity in recent years (the latter is discussed further in section “Electricity Markets”). Also, some caution should be attached to interpreting the New Zealand numbers relative to the other countries since they come from different datasets and there may be measurement differences (see notes to Table 3).

Policies, Incentives, and Barriers

From the preceding discussion, it is evident that the Australian and New Zealand electricity sectors stand in stark contrast to each other. Australia, on the one hand, is dominated by fossil fuels, coal in particular, but increasingly by gas, whereas New Zealand, on the other hand, is dominated by renewables (section “Energy System and Emissions Context”). Both countries, however, have not met their potential in terms of renewables and have lower levels of green energy investment relative to GDP per capita than many other developed and indeed developing countries (section “Green Energy Finance Flows”). In this section, we seek to understand why this is.

Electricity Markets

Another similarity that Australia and New Zealand share is that they were earlier adopters of electricity industry reform. In 1996, a competitive, deregulated wholesale market was set up in New Zealand, and in 1998, Australia introduced the National Energy Market (the market currently covers five of the seven large states—it does not cover Western Australia and the Northern Territory). Further, both countries have embraced retail competition. The motivations for the establishment of electricity markets were to increase competition and to improve the overall economic efficiency of the market, placing the risk for investment in new generation more with private investors, and to put downward pressure on prices. Furthermore, it was argued that liberalized markets would generally deliver service improvement and foster innovation.

The interplay between electricity markets and investment in green energy is complex. This topic could be the subject of a chapter in its own right and, as such, the discussion here is deliberately very general. In both countries, there are tensions between electricity markets that were designed to squeeze efficiencies out of “steady state” systems with a linear supply chain architecture (generation, transmission, distribution) and the transformation required by electricity systems with a flexible network and bidirectional architecture that accommodates demand response, prosumers (distributed supply), electric vehicles, and large levels of intermittent renewables (Battaglini et al. 2009; Biggs 2016; Verbong and Geels 2010). These pressures are not unique to Australia and New Zealand, and the competing energy “trilemmas” have more generally raised questions of how electricity markets and networks can evolve and how utilities can adapt to these changing risks (Newbery 2018; Tulloch et al. 2017).

It would seem, however, that electricity industries/markets and their designers (politicians and regulators) have been particularly slow to embrace the change and to understand the challenges in Australia and New Zealand. This is epitomized by the recent Australian energy crisis. As conceded by the Turnbull administration in its National Energy Guarantee:

South Australia’s state-wide blackout in 2016 and the February 2017 load-shedding events in New South Wales and South Australia were wake-up calls. They threw the spotlight on the energy challenges facing Australia with a greater reliance on intermittent sources of generation and a more decentralized grid. They indicated that the National Electricity Market (NEM), designed in 1998, was no longer fit for purpose. (DoEE n.d.)

The causes of the crisis have yet to be fully analyzed. Commentators opposed to renewables have pointed out that the blackouts were most severe in South Australia, a state where high levels of grid-level wind power and distributed solar have been installed (Table 1). In this context, the assertion that the NEM is not fit for purpose by the Turnbull administration is striking, as it points to a failure of the market and regulators to adapt to a new reality.

A central concern, perhaps over and above the blackouts, has been the rising cost of electricity for Australians. An Australian Competition and Consumer Commission inquiry (ACCC 2017) into the NEM noted the following:

  • Electricity prices have more than doubled in the last 10 years, with these increases dramatically outpacing inflation and wage growth.

  • The increase in residential electricity costs was primarily driven by higher network costs (which accounted for 48% of bills, while environmental costs accounted for 7% of bills).

  • Higher network costs were largely the result of a network regulation framework that allowed for over-investment (see also Simshauser 2014 for a discussion of how network costs rose).

  • Concerns about the effect of market concentration, both at the wholesale and retail level, on prices and competition. The three large “gentailers” (generators and retailers), namely AGL, Origin, and EnergyAustralia, supply around 70% of retail customers in the NEM and control approximately 48% of generating capacity.

Some of the concerns raised by the ACCC 2017 inquiry would seem to echo across the Tasman Sea in New Zealand. As in Australia, there are concerns about energy affordability and that the New Zealand Electricity Markets (NZEM) remain highly concentrated with the four largest “gentailers” (Contact Energy, Genesis Energy, Mercury NZ, and Meridian Energy) accounting for 87% of all generation and 77% of all metered installations in 2017 (Diaz-Rainey et al. 2018). Similar to Australia, distribution and transmission costs make up a large proportion of electricity cost in New Zealand (around 42%, based on Energy Link data, excluding goods and services tax in total costs to make comparison possible with ACCC 2017).

Further, in the NZEM, uncertainty around demand growth appears to have suppressed investment. For instance, there are 17 wind farms operating on mainland New Zealand, with a total capacity exceeding 380 MW; however, another 15 wind farms, which are consented, with a total potential capacity of 2,363 MW, are not being built due to a lack of demand (NZWEA n.d.-b). New Zealand had demand growth of approximately 700 GWh per annum from 1996 to 2006, but between 2006 and 2016 demand fell by just under 300 GWh (MBIE 2017). The average residential demand per household has fallen from an average of 8,101 kWh per annum for the years 1991 to 2006, to an average of 7,441 kWh per annum for the three years 2013 to 2015 (residential demand was 31% of total demand in 2016, per MBIE 2017). However, perhaps the greatest uncertainty concerns the demand from industrial load (37% of total demand). Between 2005 and 2016, the wood, pulp, and paper processing sector shed 1,428 GWh of annual demand, and the Tiwai aluminum smelter located near Bluff, although accounting for 12% of total annual demand in New Zealand, ran only three of its four pot lines.

Overall, the incumbents and regulators in both Australia and New Zealand are fearful of a “death spiral” induced by distributed generation (DG) and low prices from intermittent renewables leading to stranded (uneconomic) thermal plants. A death spiral occurs when an increasing number of customers install DG and disconnect from the network, raising the cost for those that remain on the network, thereby inducing even more installation of DG and disconnection from the network (see for instance Simshauser 2014).

Concerns about death spirals and stranded assets were also voiced in Europe over a decade ago. They represent opposition to change, yet politicians and regulators (largely through EU policies), with their eye firmly on the public interest, pressed ahead. This imposed real costs and risks on energy utilities (Tulloch et al. 2017), which have been forced to adapt—many EU utilities are changing their business models by divesting thermal plants and focusing increasingly on services for smart grids as a way of dealing with DG, EVs, and lower demand. Ultimately, the commitment to energy transition in the EU has led to a cut in emissions from a relatively low base (Figure 4). This has been done with electricity prices that are not too dissimilar to (and by some estimates lower than) those in Australasia (ACCC 2017, pp. 24–25). The fact that Australia and New Zealand are islands with networks covering big distances does suggest there are contextual differences that may imply greater cost. This is counterbalanced to some extent by excellent renewable resources (section “Green Energy Finance Flows”). Indeed, as noted earlier, modeling for Australia done by Vithayasrichareon et al. (2015) suggests that a generation portfolio with 75% renewables in 2030 is the most optimal in terms of cost, cost risk, and emissions.

Carbon Markets and Taxes

Both countries have had policies that sought to price carbon via emissions trading schemes (ETSs), and their experience has highlighted the political and technical challenges of designing effective ones. Australia’s scheme was to start as a carbon tax and evolve into a trading scheme after three years. More specifically, from mid-2012 to mid-2015, the scheme was to operate with a fixed price of A$23 per tonne, which would have risen to A$25.40 by the end of the three years (Jotzo 2012). After that point, a “collar” (a price cap and price floor) that would gradually rise would be imposed on the market. The initial collar in 2015 was set to be an A$15 per tonne floor and an A$20 ceiling. The legislation to enact the scheme was passed in the Gillard government and had followed some 20 years of discussion of carbon pricing at political levels (Crowley 2017). However, the scheme was repealed in its infancy by the Abbot government, shortly after winning the 2013 election (section “Green Energy Finance Flows”). The short life of the Australian ETS/tax and its historical context highlights the need for a cross-party consensus if credible carbon pricing mechanisms are to be implemented. As noted in section “Green Energy Finance Flows”, the National Energy Guarantee of the Turnbull administration seems to be providing a new impetus to carbon pricing in all but name. Notwithstanding this, Australia’s climate change policies can only be described as “erratic” (Nelson 2015).

New Zealand’s experience of carbon pricing has, relative to Australia, been much more successful. The New Zealand Emissions Trading Scheme (NZ ETS) is the second-oldest national ETS in the world (Diaz-Rainey and Tulloch 2018). It is a complex scheme that has undergone numerous changes over the years and, as such, a full exploration of it is not possible here (see Diaz-Rainey and Tulloch 2018, and Kerr and Ormsby 2016, and references therein). The scheme is differentiated from other ETSs in several respects: (1) it initially allowed unlimited importation of Kyoto units; (2) it covers forestry, which can create units via afforestation; and (3) it is an intensity system rather than having a hard cap. Initially, it was also designed to include agriculture, which produces roughly half of New Zealand’s total greenhouse gas emissions (section “Emissions Profile and Potential of Renewable Energy” and Diaz-Rainey and Tulloch 2018).

The legislation for the scheme was passed in 2008 by an outgoing Labour government. In 2009, the new National government introduced a number of “transitionary” measures that muted its impact, namely (1) a need to produce only one allowance for every two tones of emissions (this is now gradually being phased out), (2) a price ceiling of NZ$25, and (3) the exclusion of agriculture from the scheme.

The ETS trades in NZ units (NZUs) and, as noted above, in its early years allowed unlimited importation of Kyoto emission reduction units (ERUs) and certified emission reductions (CERs). As the price of these Kyoto units fell, so did the price of NZUs. From an initial level above NZ$20 in 2011, NZU prices dipped below NZ$3 in 2013 (Figure 7 and Diaz-Rainey and Tulloch 2018). The government, following stringent criticism of the nature of some the imported allowances, ultimately prohibited the use of the Kyoto units from 2015 (it did so by not entering into the second compliance period of Kyoto, known as CP2). However, by the time it had exited CP2, companies affected by the scheme had “banked” a large amount of units (Kerr and Ormsby 2016). Since exiting CP2, the price of NZUs has recovered to almost $21 (Figure 7).

Figure 7:
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Price of New Zealand Units in NZ$ from March 2009–December 2017. (Compiled from Bloomberg Professional Terminal data)

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Electricity generators are covered by the scheme and are required to surrender NZUs each year in proportion to their total emissions. In New Zealand’s electricity market, gas and coal-fired generation plays a key role in setting the marginal price, so in theory the addition of a carbon price to the overall fuel price should be reflected in higher spot prices in the wholesale market, leading to higher prices overall, thus making DG more competitive. Modeling shows that with the current contribution of fossil-fueled generation to meet overall demand, there should be a rise in the average spot price of approximately NZ$0.4/MWh for every NZ$1 of carbon cost (modeling by Energy Link).

However, even as carbon prices have risen over the last two years, this signal has been muted for two reasons. Firstly, the ETS has still not moved out of its “transitionary” phase, so that in 2017 only one NZU must be surrendered by emitters to the government for every 1.5 tones of emissions. Secondly, it would appear that large emitters took the opportunity to purchase and “bank” NZUs while they were very cheap and importation of units for compliance was possible, and in some cases they have enough NZUs to last several years without purchasing additional NZUs (Diaz-Rainey and Tulloch 2018; Kerr and Ormsby 2016; Mercury 2017).

The scheme is currently under review and the election of the Ardern government, with its Green Party coalition partner (section “Green Energy Finance Flows”), raises the prospect that the scheme could be further strengthened; and, critically, it seems that the high-emitting agricultural sector will be finally added to the scheme in the future.

Green Certificate Markets

Green certificate markets (GCMs), or mandatory renewable energy targets, impose obligations on electricity retailers to source increasing proportions of total electricity sales from renewable energy sources over a fixed time frame. Since those with surplus renewable certificates can sell them to those with a shortfall (much like carbon markets), it has been argued that they produced more effective and cost-efficient outcomes than subsidies such as feed-in tariffs (Davies and Diaz-Rainey 2011; Diaz-Rainey and Ashton 2008). The evidence does not necessarily support this assertion, pointing to them being less effective in promoting renewables (see for instance, Davies and Diaz-Rainey 2011 and related references), yet they have been implemented widely, including in Australia and the UK.

Australia’s Renewable Energy Target (RET) was introduced in 2001 (Simpson and Clifton 2014). The scheme was materially expanded in 2009 to incorporate state and federal efforts and to give effect to a 20% target by 2020; however, in 2011 the scheme was split into two parts: a large-scale renewable energy target and a small-scale renewable energy target (Nelson et al. 2013; Simpson and Clifton 2014). In June 2015, the obligation was reduced from 41,000 GWh to 33,000 GWh in 2020, while the Turnbull administration has recently announced that the scheme is not being extended beyond 2020 (De Gabriele et al. 2017).

Although the various incarnations of the RET have unquestionably supported renewables expansion in Australia, most notably wind energy and with some support for solar via the RET integration with FIT (Figure 2 and section “Distributed Generation and Feed-in Tariffs”), the frequent changes to the scheme have undermined confidence in it—ultimately limiting its impact (Nelson et al. 2013; Nelson 2015).

Green Energy Tariffs

The combinations of retail competition in electricity markets and the use of GCMs as incentives for renewables has meant that green energy tariff markets have proliferated around the world (see for instance Diaz-Rainey and Ashton 2008, 2011; Diaz-Rainey and Tzavara 2012). Green energy tariffs are an innovation where consumers choose to have “green electricity” and often pay a premium for it. They are an attempt to reap the policy benefits of green consumerism (Diaz-Rainey and Ashton 2008) and can provide additional incentives over and above those provided by government to invest in renewables. Certification systems ensure there is a MWh of renewables electricity for each MWh of green electricity sold by retailers. Since renewable source certificates are routinely created as part of GCMs, GCM systems facilitate the creation of compliance systems that allow for the certification that tariffs are “derived” from renewables (Diaz-Rainey and Ashton 2008).

Given that New Zealand’s electricity system is dominated by renewables and there are no GCM incentives in place, green tariffs are not relevant. In Australia, however, a green tariff market exists. In 2016, according to the Clear Environment (2017, p. 9) there were 30 accredited products offered by 29 providers in the National GreenPower Accreditation Program, with 759,293 MWh of green electricity sold in 2016: 367,324 MWh to residential customers and 391,968 MWh to business customers. This represents about a quarter of a million customers, with most of them being residential households. Although some research on the Australian market has been conducted (for instance, Ma and Burton 2016; Hobman and Frederiks 2014), establishing the additional benefits to renewables investment is not straightforward in any context.

Distributed Generation and Feed-in Tariffs

While in other jurisdictions feed-in tariffs have been used as an alternative to GCMs for encouraging large-scale renewable deployment (Davies and Diaz-Rainey 2011), a number of countries have employed both policies, with GCMs being used for large-scale projects and FITs used to encourage DG. Australia is a case in point—although there are examples of FITs being used for larger projects in Australia (Buckman et al. 2014). FITs provide a subsidy or a premium for electricity generated from renewables or DG. They have been shown to be highly effective, but their success is moderated by the tariff design and the stability of the policy (Dijkgraaf et al. 2018).

In Australia, the FIT schemes have been largely used to encourage rooftop PV deployment and have been designed at the state level (Byrnes et al. 2013). Since they have been state-level policies, there has been a great deal of variation in terms of design, and some incentive schemes have interacted with the RET scheme (Burtt and Dargusch 2015). The schemes have clearly been a success, with 17% of Australian households having solar panels on their roofs, representing more than 1.76 million units across Australia (as at 1 November 2017; DoEE n.d.). This high deployment rate is evident in our data, both in terms of installed capacity and investment (Figures 2 and 5). This PV deployment has had considerable environmental benefits—along with the PV units, the tariffs have helped reduce Australia’s emissions by just under 4% by 2020 (Burtt and Dargusch 2015).

In contrast to Australia, New Zealand has no direct incentives for DG. It has been argued that an implicit subsidy for DG was in place until recently, as retailers agreed to buy excess solar power back from consumers at the same rate that the customer purchased electricity from retailers, typically at least 16 c/kWh. However, from 2014 large retailers have all lowered their solar buy-back rates to match wholesale rates, and these are as low as 3.5 c/kWh depending on the time of year. The removal of retail buy-back rates is also encouraged by the Electricity Authority (EA 2015), which argues that it is uneconomic to install solar power at home if it cannot be built, owned, and operated for a total cost that is less than the cost of connecting new, large-scale renewable generation to the grid, for example, large wind farms and geothermal stations. This approach contrasts dramatically with the approach to distributed power in Europe and Australia, where DG is often supported with generous FITs. Despite an arguably hostile regulatory environment toward DG, solar installations have been growing and now represent just under 1% of installation control points (ICPs—broadly representing metering points) (Figure 8). This is well below the 17% seen in Australia, highlighting the difference that support schemes can make.

Figure 8:
figure 8

Installation control points (ICPs) with solar generation. (Compiled from Electricity Authority data, EA n.d.-a)

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Finally, despite the absence of meaningful incentives, the uptake of electric vehicles (EVs) in New Zealand is showing rapid growth (Figure 9). EVs represent an opportunity for the electricity industry to trigger some demand growth (see discussion about low demand growth in section “Electricity Markets”).

Figure 9:
figure 9

Registered electric vehicles (EVs) in New Zealand. (Compiled from Ministry of Transport data, MoT n.d.)

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Green Investment Bank and Other Funding Mechanisms

Australia has been one of a handful of countries to establish a dedicated green investment bank—the UK is another. It established the Clean Energy Finance Corporation (CEFC) in 2012, and by 2017 CEFC has made commitments of more than US$4.3 billion for projects worth over US$11 billion (DoEE n.d.). Its investment ranges from building energy-efficient homes for low-income families to helping to finance wind and solar projects. In addition, the Australian Renewable Energy Agency, also established in 2012, has more of a research and development focus and has been involved in cofunding innovative projects.

In New Zealand, the new government intends to “stimulate up to [NZ]$1 billion of new investment in low carbon industries by 2020, kick-started by a Government-backed Green Investment Fund of [NZ]$100 million” (NZLP and GPANZ 2017, p. 3).

Two further funding mechanisms are worthy of mention: green bonds and crowdfunding. In terms of the former there is an emerging green bond market in Australia dating from 2014, but a lack of supporting policy seems to be limiting the market relative to European markets (Yates 2015; Duran 2018). New Zealand has only had one green bond issuance to date and that was in 2017 (NZ Herald 2017). “Green” crowdfunding would also seem to be in its infancy in both jurisdictions, with only few and relatively small-scale examples apparent in both countries (for Australia, see Cooper 2016 and for New Zealand, see PledgeMe n.d.).

Conclusion

It is clear from the preceding analysis that neither New Zealand nor Australia has met its respective potential with respect to growing renewable energy, and a major factor in this is the absence of strong and consistent incentives to engender green energy financing. Neither country can be considered an exemplar in terms of its response to the increasingly important issue of energy transition in response to climate change.

New Zealand, on the face of it, looks impressive with a generating mix of over 80% renewables, but this is largely the legacy of state interventionism in decades past and masks high per capita greenhouse gas emission due to intensive agricultural systems (sections “International Comparisons” and “Carbon Markets and Taxes”). Much more could be done to incentivize distributed generation and the electrification of transport.

Australia still has a system dominated by coal, and although it has had more policies in place to incentivize renewables, their effect has been muted due to political instability and fragmentation (federal and state policies), and most of all because of a lack of commitment to energy transition across all parties and regulators. Importantly, this, at best, mixed success of the two countries provides valuable lessons for other jurisdictions wishing to mobilize investment in renewables. These lessons include the following:

  • Lesson 1: Policy stability is needed, otherwise market confidence and ultimately investment erodes. This was evident in both jurisdictions, with policy changes in the NZ ETS in New Zealand and changes in terms of carbon pricing and the RET in Australia contributing to a volatile investment pattern in both countries (Figures 5 and 6).

  • Lesson 2: Political and regulatory acceptance of the need for energy transition is as important as policy stability. The analysis in section “International Comparisons” showed that the volatility in investment flows in Australia was not particularly high relative to some other developed countries. Rather, our energy-transition-intensity measure (Table 3) suggests that both Australia and New Zealand have lower levels of green energy investment relative to GDP per capita than many other developed countries. This reflects a lack of commitment to energy transition and climate action by political parties (notably National in New Zealand and until recently the Liberals in Australia) and regulators (sections “Green Energy Finance Flows”, “Electricity Markets”, and “Carbon Markets and Taxes”).

  • Lesson 3: Conventional efficiency-focused, oligopolistic, liberalized electricity markets may not be ideally suited for rapid energy transformation. The introduction of electricity markets in New Zealand in 1996 initially led to the construction of smaller plants and an increased use of thermal generating units. Incumbents and regulators in both Australia and New Zealand fear a “death spiral” induced by distributed generation (DG) and low prices from intermittent renewables leading to stranded (uneconomic) thermal plants. Similar concerns were voiced in Europe over a decade ago. They represent opposition to change, yet politicians and regulators (largely through EU policies), with their eyes firmly on the public interest, pressed ahead. This imposed real costs and risks on energy utilities (Tulloch et al. 2017) but has contributed to decarbonization and innovation in the sector, without a ballooning of electricity costs. The need for an electricity market and industry reform is highlighted by the Turnbull administration’s assertion in its National Energy Guarantee that the National Electricity Market (NEM) is “no longer fit for purpose.”

  • Lesson 4: Even fragmented, varied, and state-defined FIT schemes have fostered green investment and a rising share of solar power in Australia. The success of these policies is evident in terms of installed capacity (Figure 2), investment flows (Figure 5) and environmental benefits (section “Distributed Generation and Feed-in Tariffs”).

From the preceding discussion it is clear that electricity industry and market reform is a critical issue for meaningful energy transition in Australia and New Zealand (section “Electricity Markets”). Electricity markets remain too concentrated, and technologies such as smart meters, DG, and EVs offer the possibility that electricity markets can be transformed from oligopolistic linear supply chain models to a more network-type infrastructure, more akin to perfect competition (with lots of suppliers and consumers and an increased focus on energy services). This will involve opening markets to greater competition from DG and will require market innovations such as storage markets or capacity markets. Europe is moving in this direction. The alternative is to have much greater state intervention and potentially even the rolling back of markets—unsurprisingly, this option is even more unpalatable to existing oligopolistic electricity markets and industry.

How might the electricity industry and market reform eventuate in Australia and New Zealand? The first step must be a recognition at political levels that change is needed. In this respect the Australian energy crisis, the Paris Agreement, and the associated impetus of the Turnbull and Ardern administrations means that electricity market reform is on the agenda and consequently green energy investment is set to increase in Australia and New Zealand in the coming years. The success of their strategies will largely rest on the degree to which they are willing to tackle entrenched interests and ensure that electricity market and industry reforms are substantive. An important factor in the process of reform will be energy regulators; their expertise and influence must drive reform forward in the public interest. This is not assured at the moment. For instance, in New Zealand, the Electricity Authority is singularly focused on “the efficient operation of, the electricity industry for the long-term benefit of consumers” (Electricity Authority n.d.-b). It interprets environmental goals as being beyond its mandate. This must change if reform is to have substance.

Limitations and Future Research

A limitation of our analysis is that the datasets used for green financial flows are aggregated by generating technology (Figures 5 and 6). As such, we do not know the source of that finance, which, for energy companies, can come from a range of sources including internal company funds, private debt, public debt (including green bonds), and public equity. Future investigation of this is clearly necessary—to what degree energy utility company balance sheets can support energy transition is a critical question to resolve in Australia and elsewhere (Tulloch et al. 2017). As noted in section “Green Investment Bank and Other Funding Mechanisms”, there are other funding mechanisms for RE projects, including crowdfunding and government-backed green investment funds and banks. Further, how much commercial banks and distributed RE system suppliers are willing to lend or lease to households and small and medium size enterprises (SMEs) remains unclear and is a subject that requires careful and systematic research. Anecdotally, banks would seem to be offering products to support investment in distributed RE. (For instance, Kiwibank offers a sustainable energy loan in New Zealand.) Whether they are on terms that really support accelerated RE diffusion is less clear. The contrasting experience between New Zealand and Australia in terms of solar PV (section “Distributed Generation and Feed-in Tariffs”) suggests government incentives are crucial in accelerating diffusion and adoption of distributed RE. Whether that accelerated adoption of distributed RE can happen without intervention requires, as noted above, further research on the financial offerings of banks and energy system suppliers to households and SMEs.