Dissertation – Barriers to Renewable Energy Investment in the National Electricity Market

Abstract

The National Electricity Market (NEM) must roughly triple its variable renewable capacity by 2050 to follow the pathway set out in the Australian Energy Market Operator’s Integrated System Plan, yet committed investment has repeatedly lagged the required trajectory. This dissertation examines why capital is not flowing at the pace the transition demands. Adopting a qualitative-dominant mixed-methods design, it draws on 18 semi-structured interviews with developers, investors, financiers and network specialists, triangulated against secondary policy and market documents. Thematic analysis identifies six interacting barriers, of which policy and regulatory uncertainty, grid connection delays and transmission congestion were cited most frequently. The findings show that these barriers compound rather than operate in isolation, raising effective hurdle rates and deferring final investment decisions. While the Capacity Investment Scheme and transmission access reform address parts of the problem, participants regarded revenue certainty and connection risk as only partially resolved. The study offers evidence-based implications for Australian energy policy.

Introduction

The National Electricity Market (NEM), which links the eastern and southern states, is the principal arena for Australia’s electricity decarbonisation. The Australian Energy Market Operator’s Integrated System Plan (AEMO 2024) sets a step-change pathway in which variable renewable generation, firmed by storage and transmission, displaces the retiring coal fleet within two decades. Meeting that pathway requires sustained private investment at a scale and speed the market has not consistently delivered. The Australian Energy Regulator has observed that new commitments repeatedly lag the trajectory needed to retire thermal plant reliably (AER 2023), and industry monitoring points to a widening gap between the pipeline of proposed projects and the volume reaching financial close (Clean Energy Council 2024). International monitoring similarly finds that capital gravitates to jurisdictions that pair decarbonisation ambition with predictable revenue frameworks (IEA 2023).

This apparent paradox, an abundant project pipeline coexisting with hesitant capital commitment, motivates the present study. Although Australian governments have layered new instruments onto the market, including the Capacity Investment Scheme and reforms to transmission access, the persistence of the investment gap suggests that the barriers are structural and interacting rather than incidental. This dissertation therefore investigates how developers and investors themselves understand the obstacles to committing capital in the NEM. It is guided by three research questions:

1. What are the principal barriers that developers and investors perceive to committing capital to renewable generation in the NEM?
2. How do these barriers interact across financial, technical, regulatory and market-design dimensions to shape final investment decisions?
3. To what extent do current Australian policy mechanisms, notably the Capacity Investment Scheme and transmission access reform, mitigate these barriers?

The scope is deliberately confined to utility-scale wind, solar and storage within the NEM, and to the perspective of the investment decision maker rather than the system planner. Western Australia and the Northern Territory, which sit outside the NEM, are excluded.

Literature Review

Scholarship on renewable investment consistently frames the commitment decision as a problem of risk-adjusted return under uncertainty. Where cash flows are volatile and partly irreversible, investors apply higher hurdle rates and demand contracted revenue before releasing capital (Simshauser 2021). In an energy-only market such as the NEM, this logic is sharpened by the absence of a capacity payment, so that developers must recover fixed costs from wholesale and contract revenues alone.

A first body of work concerns revenue and market design. As variable renewable penetration rises, correlated output depresses prices in the very periods when generators produce, a dynamic widely described as value deflation or cannibalisation (Nelson, Pascoe & Calais 2021). Negative prices during high solar output further erode capture prices and complicate the merchant case (AER 2023). Moreover, the large-scale generation certificate revenue historically administered under the Renewable Energy Target is tapering as the target is met (Clean Energy Regulator 2023), removing a support that earlier projects could bank. International analysis reaches similar conclusions about the limits of energy-only pricing for financing low-carbon capacity (Newbery 2016).

A second theme is grid connection and transmission. The Integrated System Plan identifies large actionable transmission projects and Renewable Energy Zones as preconditions for orderly entry (AEMO 2024), yet connection processes, marginal loss factor revisions and generator performance standards impose cost and timing risk on individual projects (Wood & Dundas 2022). Delayed network augmentation can strand otherwise viable generation and lengthen development timelines.

A third theme is policy and regulatory uncertainty. Frequent changes to targets and schemes raise the perceived risk of stranded or devalued assets and reduce the tenor over which investors are willing to contract (Garnaut 2019; Productivity Commission 2023). The recently introduced Capacity Investment Scheme is designed to provide a revenue underwrite through contracts for difference (DCCEEW 2023), while transmission access reform seeks to sharpen locational signals (AEMC 2023).

Across these literatures, the barriers are usually examined in isolation and through quantitative modelling. Comparatively little qualitative evidence captures how practitioners weigh and combine these risks in a live Australian setting. This study addresses that gap by foregrounding the investor’s own account of the decision.

Methodology

This study adopts a qualitative-dominant mixed-methods design, in which semi-structured expert interviews form the primary evidence and secondary document analysis provides triangulation. The qualitative emphasis suits a research problem centred on the meaning and weighting that decision makers attach to competing risks, which is not readily captured by market data alone.

Eighteen participants were recruited through purposive and snowball sampling to span the investment chain: project developers, equity investors, debt financiers, network and connection specialists, and commercial advisers active in the NEM. Interviews of 45 to 60 minutes followed a common protocol covering perceived barriers, their interaction, and views on current policy. Interviews were recorded with consent, transcribed, and analysed thematically through a six-phase process of familiarisation, coding, theme development and review, supported by NVivo. Reported frequencies record the number of participants who raised a theme unprompted.

Secondary analysis drew on public documents including the Integrated System Plan (AEMO 2024), the Australian Energy Regulator’s market reporting (AER 2023), the Capacity Investment Scheme design paper (DCCEEW 2023) and investment commentary from the Clean Energy Finance Corporation (CEFC 2023) and the Australian Renewable Energy Agency (ARENA 2022). Figure 1 sets out the analytical framework linking barrier categories to the final investment decision.

Ethical clearance was obtained from the university’s Human Research Ethics Committee, and participants were de-identified using codes (P1 to P18). Trustworthiness was supported through triangulation, an audit trail and member checking of emerging themes. As a point-in-time study of a single jurisdiction, the findings are analytically rather than statistically generalisable.

Findings

Thematic analysis produced six barriers to investment, summarised by frequency in Table 1. Policy and regulatory uncertainty was near universal, raised by 17 of 18 participants, followed closely by grid connection and transmission concerns.

Table 2 decomposes the leading themes into their constituent sub-barriers and illustrates each with a representative participant concern.

Participants consistently described policy uncertainty as the primary amplifier of every other risk. Several noted that shifting targets and the evolving detail of the Capacity Investment Scheme made it difficult to fix a bankable revenue line (P4, P7). Connection risk was the most operationally immediate barrier: lengthening queues, rework to meet generator performance standards, and post-commitment revisions to marginal loss factors were described as capable of eroding an equity case after capital had been committed (P9). Transmission congestion and delayed actionable projects under the Integrated System Plan were seen as threatening to strand generation in constrained parts of the network (P2). Revenue and financing barriers, although ranked lower, were understood as the channel through which the others ultimately register, by raising the hurdle rate required for a positive final investment decision (P11).

Discussion

The findings support the study’s central proposition that barriers to renewable investment in the NEM compound rather than operate independently. In answer to the second research question, participants described a causal chain in which regulatory uncertainty widens risk premia, connection and transmission risk lengthen and de-risk timelines unpredictably, and revenue design determines whether the residual merchant exposure is financeable. The final investment decision is thus the product of interacting rather than additive risks, consistent with the conceptual framework in Figure 1.

The sensitivity that participants attached to connection variables can be illustrated with a simple worked example drawn from the interviews. For a 200 MW asset operating at a 30 per cent capacity factor, annual generation is 200 MW x 8,760 hours x 0.30 = 525,600 MWh. A post-commitment revision to the marginal loss factor from 0.95 to 0.88, within the range participants reported, reduces settled output by 525,600 MWh x (0.95 – 0.88) = 36,792 MWh. At an assumed capture price of A$45 per MWh, the annual revenue effect is 36,792 x 45 = A$1.66 million, recurring across the asset life. A change of this order, applied after financial close, explains why several participants treated loss-factor risk as a decisive rather than marginal consideration (P9).

In answer to the third research question, participants regarded current policy as partially, but not fully, responsive. The Capacity Investment Scheme was widely credited with addressing revenue certainty by underwriting a contracted floor (DCCEEW 2023), and was seen as the single most material intervention. However, several cautioned that scheme design detail and tender timing introduced their own uncertainty, and that a revenue underwrite does little to resolve connection and transmission risk. Transmission access reform (AEMC 2023) and the delivery of actionable Integrated System Plan projects (AEMO 2024) were considered necessary complements. The concessional finance and early-stage support provided by the Clean Energy Finance Corporation and the Australian Renewable Energy Agency were valued for de-risking novel technologies, but were not regarded as substitutes for a stable market framework (CEFC 2023; ARENA 2022). These findings echo warnings that transmission delivery, not headline ambition, is now the binding constraint on the transition (Wood & Dundas 2022).

Conclusion

This dissertation examined why private capital has not flowed into NEM renewable generation at the pace the Integrated System Plan requires. Drawing on 18 expert interviews and supporting policy analysis, it identified six interacting barriers, of which policy and regulatory uncertainty, grid connection and transmission congestion were the most frequently cited. The central contribution is to show, from the investor’s own perspective, that these barriers are mutually reinforcing: uncertainty in one domain raises the risk premium applied across all others, deferring or defeating the final investment decision.

For Australian policy, the implication is that revenue support and network reform must advance together. The Capacity Investment Scheme addresses the revenue leg of the problem but leaves connection and transmission risk substantially intact, and its benefits depend on stable and predictable implementation. Accelerating actionable transmission and stabilising the rules that govern connection would, on this evidence, do as much to unlock capital as further revenue underwriting.

The study is limited by its point-in-time, single-jurisdiction design and its modest sample, and its findings are analytically rather than statistically generalisable. Future research could test the relative weight of these barriers quantitatively, or track how investor sentiment responds as the Capacity Investment Scheme moves from design into delivery.

References

Australian Energy Market Commission (AEMC) 2023, Transmission access reform: final report, AEMC, Sydney.

Australian Energy Market Operator (AEMO) 2024, Integrated system plan for the National Electricity Market, AEMO, Melbourne.

Australian Energy Regulator (AER) 2023, State of the energy market 2023, AER, Melbourne.

Australian Renewable Energy Agency (ARENA) 2022, Investment priorities for the renewable energy pipeline, ARENA, Canberra.

Clean Energy Council 2024, Clean energy Australia report 2024, Clean Energy Council, Melbourne.

Clean Energy Finance Corporation (CEFC) 2023, Investment insights: mobilising capital for the energy transition, CEFC, Sydney.

Clean Energy Regulator 2023, Quarterly carbon market report: December quarter 2023, Clean Energy Regulator, Canberra.

Department of Climate Change, Energy, the Environment and Water (DCCEEW) 2023, Capacity Investment Scheme: design paper, Commonwealth of Australia, Canberra.

Garnaut, R 2019, Superpower: Australia’s low-carbon opportunity, La Trobe University Press, Melbourne.

International Energy Agency (IEA) 2023, World energy investment 2023, IEA, Paris.

Nelson, T, Pascoe, S & Calais, M 2021, ‘Efficient integration of variable renewable energy into the National Electricity Market’, Energy Policy, vol. 155, pp. 112-124.

Newbery, D 2016, ‘Towards a green energy economy? The EU energy union and market design’, Applied Energy, vol. 179, pp. 1321-1330.

Productivity Commission 2023, Investment in the energy transition, Productivity Commission, Canberra.

Simshauser, P 2021, ‘Renewable energy zones, network investment and the merchant risk frontier in the National Electricity Market’, The Energy Journal, vol. 42, pp. 45-72.

Wood, T & Dundas, G 2022, Go for net zero: transmission and the energy transition, Grattan Institute, Melbourne.