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54 Barriers to entry into the
BARRIERS TO ENTRY INTO THE ELECTRICITY GENERATION SECTOR: INSIGHTS FROM AN INVESTOR SURVEY
by Alan Rai, Director, Baringa Partners, and Senior Fellow, Macquarie University
Research recently undertaken by Alan Rai and Tim Nelson has identified the common barriers to investment in electricity generation in Australia. Here, Alan outlines some of the findings of the research, and provides suggestions to remove the barriers that are holding large-scale investment back.
Three key trends have occurred over the 21 years since Australia’s national electricity market (NEM) commenced: 1. Entry of more than 6GW of gas-fired plant over the decade to 2009, with more than half of this (3.6GW) entering in 2008 and 2009 alone. This investment occurred in response to state-based policy signals – namely, Queensland’s 18 per cent gas scheme and NSW’s greenhouse gas abatement scheme – and to the drought-induced electricity spot price spikes of 2007- 2008 (see Figure 1). 2. Exit of baseload plant over a relatively short period: between June 2014 and June 2017, over 4.1GW of coal-fired plant exited. This unwound all the excess baseload capacity existing at the time of the NEM’s commencement. These exits occurred suddenly and unexpectedly, contributing to the
Figure 1. Net entry and exit of large-scale plant across the NEM, year to 30 June. Source: Authors’ calculations based on data from AEMO and from the AER.
1 While the term “dispatchability” does not have a universal meaning, it incorporates notions of controllability and flexibility. Dispatchability is the extent to which a resource can be relied on to follow a target in relation to its load (for demand-side resources) or output (for supply-side resources).
doubling in wholesale prices across the NEM between 2016 and 2018. 3. Entry of variable renewable energy (VRE) wind and solar PV plant. Between July 2012 and June 2019, over 7.5GW of utility-scale wind and solar PV entered the NEM.
There are two other key findings from Figure 1: 1. A declining volume of new-entrant
VRE generation since mid-2019. 2. Virtually no entry of dispatchable plant1 (such as gas-fired generation and hydro plant) since 2017, despite record high electricity prices during 2017- 2019. This stands in stark contrast to the supply response to the 2007-2008 price spikes. This lack of entry resulted in wholesale prices over 2017-2019 remaining at levels well above that of 2007-2008.
To understand the reasons for these drop offs in new-entrant capacity, I asked various generation-sector investors, in late 2019, for their views on why there has been a drop-off in new-entrant capacity. The key findings from these discussions are briefly discussed below, as well as the associated policy implications, with more details available on request.
Stating the policy-implications punchline upfront: policymakers need to be mindful of the interaction between economic theory and real-world financing considerations when designing big-picture reforms, such as the Energy Security Board (ESB)’s post-2025 work program, to avoid any unintended consequences.
Themes covered
The discussions covered the following two themes: 1. The relative importance of various factors cited as preventing the entry of plant into the NEM. 2. The impact of these barriers to entry on the cost and availability of debt and equity finance, and changes in the availability and cost of finance over the preceding 12 months.
I spoke with corporate members of the Clean Energy Council (CEC), and ‘full’ members of the Australian Energy Council (AEC). In total, 18 organisations provided their views. Collectively, these 18 organisations invest in or operate around one-quarter of installed utility-scale generation capacity in the NEM. These
Electricity spot and/or contract prices too low Technology-induced stranding risk
Insufficient network capacity relative to generation capacity No emissions policy certainty/no "green" price signal
System security constraints on output
Government intervention in generation (e.g. "big stick", Snowy, UNGI) Pace of energy sector reform too fast
Regulated retail prices (DMO, VDO)
Reliability price settings (e.g. MPC) too low
Table 1. Barriers to entry into the generation sector.
organisations relate to one or more of the following categories: » Project debt financiers » Project equity financiers » Vertically and/or horizontallyintegrated developers of VRE and traditional plant » Independent (i.e. non-integrated)
VRE developers » Independent (i.e. non-integrated) battery storage developers
Finding #1: prioritisation of barriers to entry
Investors were asked to prioritise eleven barriers to entry (see Table 1). These eleven barriers were informed by various studies, including the Finkel Review, the Grattan Institute, and recent analysis. In decreasing order of importance, the top three barriers identified by investors were: 1. Concerns about the ongoing trend towards longer and more complicated grid connection processes, especially for new-entrant VRE plant, given their asynchronous nature. This issue is not NEM-specific, but rather it is a global issue. 2. An insufficient amount of network capacity relative to the amount of generation capacity installed at various locations, an issue particularly acute for VRE plant given both the tendency for new-entrant VRE plant to colocate with incumbent VRE plant, and the correlated nature of VRE output (greatest for solar PV, but also for wind). Insufficient network capacity has resulted in higher congestion and higher electrical losses, the latter exacerbated for wind and solar PV generators: in Australia, the best wind and solar resources are typically where there are relatively low amounts of existing network capacity. Examples of these locations include solar PV in far north Queensland, and wind farms in north-west Victoria, with the latter area often referred to as the “rhombus of regret”. 3. A lack of a continued “green” price signal, either in the form of a carbon price or an extension of the large-scale renewable energy target (LRET). This is in light of the LRET’s existing target for the 2020-2030 period, projected to have been met in October 2019.
These findings are consistent with those of the CEC, Infrastructure Partnerships Australia, and MinterEllison.
Finding #2: trends in the cost of equity and debt finance
The key findings can be summarised as follows: 1. Compared to the prior 12 months, the cost of raising debt and equity finance (i.e. the weighted average cost of capital, WACC) for generation had increased for three-fifths of investors (and unchanged for the remainder). Three-fifths of investors also observed an increase in their hurdle rates visà-vis the prior 12 months. The hurdle rate reflects the return required by the project developer, is often
set well above the corresponding WACC, and is more important than the WACC in terms of whether projects get approved for investment. More recently, costs of new-entrant generation have risen further due to COVID-19. Supply chain disruptions and a sharply depreciating Australian dollar have raised the cost of imported electrical equipment (such as solar PV panels and wind turbines), while highly dislocated funding markets, especially for bank loans and corporate debt, have raised funding costs. 2. An investment-grade off-taker was not essential to obtaining debt finance on reasonable terms. This finding is consistent with the growing trend towards merchant VRE. Between 2017 and 2019, 2.4GW of fully merchant VRE projects entered the NEM. Also during this period ten existing wind plants (with total 0.6GW capacity) ended up with merchant exposures following the expiry of their long-term power purchasing agreements. 3. What-if analysis of WACC impacts from: a. replacing the existing marginal loss factor regime with a compressed loss factor regime. Four-fifths of investors consider this change would decrease their WACCs, by 100-150 basis points per annum (p.a.), or 10-15 per cent of initial WACCs. b. replacing the existing regional pricing approach with nodal pricing and financial transmission rights. All investors consider this would increase their WACCs, in the order of 200 basis points p.a. (an increase of 20 per cent).
Implications for policy makers
These findings have the following policy implications: » Policy design should prioritise removing the largest barriers to entry, such as increasing network capacity in ways that minimise the risk to consumers of overbuilding. In this regard, ongoing efforts by the ESB to streamline and quicken regulatory investment tests, as part of the broader “actioning the ISP” work program, are appropriate and necessary. » There is a need to give market participants sufficient time before implementing fundamental reforms. This need is a pragmatic one, cognisant of the financing models used for generation projects, namely the predominant use of both longterm contracts and relatively shortterm debt. Fundamental reforms implemented too quickly or without the requisite design details fleshed out can trigger force majeure clauses in long-term contracts, and create refinancing and re-contracting risks for existing projects, increasing the risk of asset stranding and debt default.
In summary, big-picture policy reforms need to pragmatically consider the interaction between: » Real-world financing models, in particular the widespread use of hedging contracts and debt finance that are both shorter in duration than the useful lives of generation plant, which creates rollover and refinancing risks for generation projects, and » Economic theory in relation to providing efficient price signals to incentivise the right types of resources to be built at the right times in the right locations, albeit at the ‘cost’ of increased complexity and in turn higher cost of capital and barriers to entry, and reduced competition.
This article is based on a paper authored by Alan Rai and Tim Nelson, currently under peer review in an academic journal.
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NEGATIVE OIL PRICES = LOWER ELECTRICITY PRICES?
by Chris Gilbert, Senior Economic Advisor, Energy Networks Australia
Oil prices went negative for the first time in history during April, with May future contracts for US West Texas Intermediate crude oil falling to never-before seen lows, dragging down Brent crude futures with them. Here, we take a look at some of the wider energy implications of massively reduced oil prices.
Flatlining industrial demand, fuelled by the COVIDinduced US industry shut down, led to storage facilities reaching capacity and having nowhere to store oil.
In great news for hip pockets, this could eventually have the flow-on effect of reducing energy bills.
Liquefied Natural Gas (LNG) prices tend to follow Brent crude oil prices but with a lag of about three months. 1
If LNG exports from Australia fall in line with global LNG prices, use for domestic supply looks much more attractive. With more gas staying onshore; we might expect downward pressure on wholesale gas prices and a reduction in gas-powered electricity generation costs, that could lead to lower electricity generation costs.
The extent to which cheaper natural gas prices influence electricity wholesale prices largely depends on how often gas generators running on cheaper natural gas can displace other, now more expensive forms of generation in the wholesale electricity market. 2
Lower wholesale gas and electricity prices will mean lower bills for customers as long as these savings are passed through to retail prices.
DER impacted
The rapid descent in oil prices serves as an interesting example of how interlinked the energy market can be.
Falling wholesale electricity prices, from any oil price effects or simply lower demand could, for example, even influence the path of investment in Distributed Energy Resources (DER).
If lower oil prices do lead to a fall in wholesale electricity costs and end-use electricity tariffs, the value of electricity produced and consumed by solar PV will fall, making it less likely that households and businesses will invest in DER.
Non-essential spending – particularly on large capital items – is likely to dry up and limit investment in DER.
DER investment is down, but the ability to produce and install DER technologies is also likely to have fallen as well.
DER equipment could become relatively more difficult to access, with some borders closed and supply chains disrupted.
Additionally, qualified installation personnel may in some cases be unable to work due to COVID restrictions. However, more households are working from home and are benefiting in the short term from selfconsuming a higher proportion of electricity from their DER. Despite the incentive of better utilisation, working from home doesn’t seem to be a strong enough incentive to spur investments in DER, as new solar installations in March seem to have plummeted (though March installation data may still be trickling in).
DER take-up at risk?
While it’s clear DER uptake rates have fallen, the exact factors at play are opaque.
If the repercussions of COVID persist, it’s likely that the trajectory of DER uptake will be noticeably impacted.
The Australian Energy Market Operator (AEMO) produces a few different scenarios that attempt to model DER uptake in different economic, policy and technology conditions.
The ‘central’ scenario reflects current policy settings and technology trajectories, where the transition from fossil fuels to renewable generation is led mainly by market forces.
There are other upward and downward scenarios, for example the ‘step-change’ scenario, with aggressive decarbonisation targets and strong technology improvements, or the ‘slow change’ scenario, where economic conditions are challenging, investment is lower and living standards are protected over pursuing structural reform.
There’s no doubt that over the last couple of months there’s been a broad economic shift towards the ‘slow change’ scenario, but the scale and persistence of the shift remains to be seen.
We’ll have to wait until the dust settles before we have a better picture of how DER uptake is likely to track in the months and years ahead.
Figure 1. Monthly installations, installed solar PV capacity and average system size, January 2012 – March 2020 (Source: Clean Energy Regulator data, Australian Energy Council analysis).
SIGNS OF HOPE AS ARROW SANCTIONS SURAT GAS PROJECT
Arrow’s sanction decision follows the final investment decision (FID) for phase one of the SGP from its shareholders, PetroChina and Shell.
Arrow CEO, Cecile Wake, said, “The decisions by PetroChina, Shell and Arrow demonstrate commitment to and confidence in Queensland and the Australian market at a time of global economic turmoil from COVID-19 and against the backdrop of sustained low oil prices.
“This significant investment comes at a critical time and will cement Arrow’s position as a major producer of natural gas on the east coast,” Ms Wake said.
“The Surat Gas Project is the first large-scale CSG project in Australia to be underpinned by a significant infrastructure collaboration and gas sales agreement, together with a suite of supporting agreements, which have been put in place between Arrow and the Shell-operated QGC joint venture.
“This agreement enables the use of capacity in QGC’s existing gas and water processing, treatment and transportation infrastructure, reducing the impacts on landholders, communities and the environment and ensuring that more gas can be economically developed.”
Ms Wake said Arrow would this year commence construction of more than 600 phase one wells, and is on track to deliver first gas from the project in 2021. Over the full 27 year life of the Surat Gas Project, Arrow expects to develop around 5TCF of natural gas.
“An initial 200 construction jobs will be created during phase one, with an anticipated further 800 construction and operating roles over the life of the Surat Gas Project,” Ms Wake said.
“Arrow recognises the current uncertainty caused by COVID-19 and oil-price volatility, and will ensure that its development plans retain sufficient flexibility to manage these evolving challenges while bringing more gas to market.
“The decision to sanction phase one of the Surat Gas Project and commence construction this year is good for Queensland. It will mean more jobs, more opportunities for local companies and other economic benefits for regional Queensland, which has been home to Arrow for more than 20 years.”
Arrow currently operates five gas fields in the Surat and Bowen basins in southern and central Queensland, respectively, and produces the equivalent of more than 40 per cent of Queensland’s total domestic gas demand. In a welcome boost for the industry, Arrow Energy has sanctioned commencement of the first phase of its Surat Gas Project (SGP) in southern Queensland, with construction set to begin this year.
“This FID is the result of extensive collaboration between not just Arrow and the QGC joint venture, but also with landholders, communities and the State Government.
“In taking this investment decision, Arrow is enlivening those collaboration arrangements for the benefit of Arrow and its shareholders, the QGC joint venture and all Queenslanders,” Ms Wake said.
“Importantly there have been sustained efforts by Arrow, its landholders and local communities to jointly develop tailor-made ways of working on high-quality black soil with minimised impacts, which will be the foundation of positive co-existence into the future.
“We sincerely appreciate the efforts of all involved, including the State Government, to bring Arrow to this point, and we look forward to safely and successfully delivering the first phase of this exciting project.
“In these challenging COVID-19 times, Arrow remains committed to operating its business and executing this project safely and responsibly to protect the health and well-being of its people and all of the regional communities where we operate,” she said.
“The utilisation of QGC’s existing upstream pipelines and treatment facilities enables Arrow to significantly reduce development costs, making Surat Gas Project competitive and economically attractive,” said Maarten Wetselaar, Integrated Gas and New Energies Director at Shell.
Shell Australia Chairman, Tony Nunan, said “The Arrow joint venture partners’ decision not to build another two trains on Curtis Island provided the opportunity to create this alternative pathway to market for the resource. The approach we have taken to this investment is aligned with Shell’s focus on actively managing all operational and financial levers to deliver sustainable cash flow generation. It reflects our disciplined approach to capital spend, which takes a long-term view of the fundamentals of supply and demand.
“QGC has reached strong and stable production since its start up in December 2015, and Arrow has the strong technical capability to develop the Surat Basin fields innovatively and efficiently.
“QGC supplied 16 per cent of the demand in the Australian east coast domestic gas market in 2019 and celebrated its 500th LNG cargo. Gas from Arrow will provide more supply to both Australian domestic customers and export markets.”
Arrow, as the developer and operator of the Surat Gas Project, is currently seeking Expressions of Interest (EOI) for services to support operations and project activities related to the Surat Gas Project, including specialist road construction services and off-plot construction services.
Construction of the project will commence later this year, with first gas sales expected in 2021.
ARROW AT A GLANCE
Arrow Energy is an integrated coal seam gas (CSG) company that explores and develops gas fields, produces and sells CSG and generates electricity. The company has been safely and sustainably developing CSG since 2000 and supplying it commercially since 2004, currently producing the equivalent of more than 40 per cent of Queensland’s domestic gas demand from its five CSG fields in the Surat and Bowen basins. Arrow is working to meet the growing demand for cleaner burning fuels. Arrow is owned 50/50 by Shell and PetroChina (a subsidiary of China National Petroleum Corporation).
GLOBAL OIL MARKET CRASH: THE IMPLICATIONS FOR ENERGY AROUND THE WORLD
There have been many economic victims to COVID-19 around the world, and arguably one of the biggest has been the global oil market, which has crashed into negative territory for the first time in history. We spoke to Peter Kiernan, Lead Analyst for Energy at The Economist Intelligence Unit, about the price crash, and about some of the longer term implications for energy markets around the world.
With the massive drop in global oil prices, what are some of the downstream impacts you expect to see in energy industries around the world?
The current oil price crash is a function of both collapsed demand and oversupply, which makes this latest scenario a little unusual. The price crash of 2014 was mainly a supply story, the one before that, in 2008-09, was about demand. But this time we have demand collapsing because of COVID-19, while key exporters decided in early March to fight a battle over market share. This was a recipe for disaster for oil prices. As a result, refineries will have to cut runs in the face of collapsed demand, upstream operators will have to make drastic cuts to capital expenditure, and proposals for key infrastructure projects, such as LNG projects, will be put on hold (if not yet with an FID). If producers do not cut supply quickly enough, stocks will build rapidly and global storage capacity will be reached, forcing them to cut back on output. This is because the demand is not there to take barrels and no-one has anywhere to put them. However, this is quite disruptive to the industry, as shut-ins are costly for producers, while downstream players are affected as well, in refining, distribution, and storage.
What do you expect to happen with global LNG prices in response to COVID-19?
Natural gas prices have been falling, although they have already been weak, especially in the US, where natgas is trading at less than $2/MMBTU. Prices in Europe and Asia are under pressure as well. Oil-indexed LNG prices will fall, narrowing the difference with spot prices, thus there will be pressure on exporters, such as Australia. The impact of this is that proposed projects for liquefaction capacity expansion are likely to be delayed, especially where such projects are more expensive, such as Australia and Canada. Some mooted projects in the US will be taken off the board as well.
What do we need to see globally to see oil prices lifting again?
Because the contraction in demand is so severe, and could be as much as 20-25 million barrels per day, which is 20-25 per cent of total demand, it will take very severe supply cuts to lift prices sustainably above $40/bbl. For that to happen, demand will also have to recover, but this is unlikely until the second half of this year. Therefore OPEC exporters, Russia and others would need to collectively cut output, and this includes the US where doing so is difficult from a regulatory angle. Once storage capacity is reached, producers will have to shut-in production, which eventually will have a price impact. Even without a mandated cut, US output will contract this year as prices are too low for shale producers to continue growing output. Eventually the market will play its part if mandated cuts are not enough to restore balance between supply and demand, but there will be a lot of disruption along the way.
Will there be any winners in the energy industry as a result of COVID-19?
There are no winners, but some will lose more than others. In an environment of demand destruction, higher cost producers will suffer more, such as the US shale sector, Canada and Brazil, while lower cost producers, such as Saudi Arabia, can expect to weather the storm better. This is probably what the Saudis banked on in early March, but it is likely they did not appreciate the extent to which demand was going to collapse. Otherwise, oil producers that depend less on oil revenue for their economic health will not lose as much as those that are more dependent, although most in OPEC are in the latter category.
What changes to global energy demand do you expect to see as a result of COVID-19?
This is an unusual situation as the demand contraction has been caused by the necessary response to the devastating COVID-19 outbreak. Travel bans, stay at home orders, flight cancellations, lockdowns, shut downs of non-essential industries and disruption of supply chains have all been the norm. Oil prices have collapsed, and theoretically this is good for the consumer, but it matters little when economies are in lockdown and people can’t drive or fly, shops are closed or factories closed. It remains to be seen whether this will have a long-term impact on consumer habits in terms of fuel consumption, but it is worth noting that air quality has improved during this crisis in many cities, and this may not be forgotten when the world emerges from this global health crisis.
Do you think the crisis will cause importing countries to start to look at the security of these arrangements, and potentially renewable alternatives that could make them less reliant on imports?
While low prices are good for huge oil-importing economies, such as China, Japan, and several in South East Asia, they are still subject to the volatility of oil and gas price swings, and those that have the resources to do so will continue to make efforts to limit oil consumption growth (China and Japan). Importing economies may also use this opportunity of low oil prices to cut back on fuel subsidies, which many did last time. I think that exporters face a dilemma, in that the oil market seems to be in short-term turmoil while it faces a longer term existential crisis, and that is of peak demand. They will therefore need to inoculate their economies from over-dependence on fossil fuel exports, and diversify, which will make their economies more resilient in the long term.
What impact will the pandemic have on exploration and development in the energy industry around the world?
Upstream players will cut back on their capital expenditure budgets, and this means less spent on exploration and production for the foreseeable future. It will take some years before we see the effect of this, but clearly the majors, such as ExxonMobil, and others, such as the smaller shale players, have already made big cutback announcements for 2020, as you would expect given the sharp crash in oil prices. Eventually as oil prices recover this will change, but we must remember that this is the second price crash in five years, and the last price crash resulted in expenditure cutbacks as well. The US shale sector, for example, will find that the willingness of the financial sector to fund its activities will ease off, which has implications for shale’s future growth potential. Oil and gas majors may find that investments in other sectors, such as clean energy technologies, which offer lower but more stable returns, might be worth a bigger think.
September 2020
Deadline: 24 July 2020
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