The future growth of Australia’s renewable energy industry is in question, with a lack of available transmission lines, grid bottlenecks and uncertainty affecting the sector. These issues are likely to directly impact the financial viability of many large-scale developments. Over 4.5 GW of renewable energy projects are now positioned to be deployed into Australia’s power grid, with many more ‘in the pipeline” being actively considered. Our view is that renewable energy developers will almost certainly experience connection delays; this risk factor is certainly important, as many utility scale projects might be abandoned before a shovel hits the ground.
It’s a classic case of the “chicken and the egg’’ - which came first? With many existing interconnection points being allocated, there are many developers speculating on where and how quickly the grid will be extended to absorb newly-generated power.
The crux of the problem is a lack of connection infrastructure in Australia, resulting from its long and skinny transmission network. While coal power stations and the Snowy hydro scheme are well-served by existing transmission lines, it’s a very different story for the increasingly active Australian renewable energy sector, with many new solar and windfarms springing up all over the country. While developers are focused on achieving development in areas featuring good resources, strong radiation levels for solar projects and strong, consistent winds for windfarms are needed to deliver efficient and predictable revenues. To date, there has been a more limited focus, either on the available existing or the planned new interconnections to the grid.
The situation is particularly acute for new projects in north-west Victoria, far west and central New South Wales and Northern Queensland; no solar plant, wind farm or other form of renewable energy, in an area of Australia where the transmission lines are not sufficient to carry the load, can run at 100% of capacity.
So what does this mean for projects which have practically completed construction and have conducted the required internal stress and commissioning tests to ensure the generation system performs as designed and intended? Many power generators are finding that they are unable to complete the essential final testing and commissioning tests which are required, following interconnection to the grid by the Australian Electricity Market Operator (AEMO). This is because AEMO is required to approve all final checks which are required for full certification before 1) developers will accept transfer of risk of loss from their contractor parties and 2) before licensed export is permitted.
This means that many renewable energy projects which are essentially fully constructed and practically completed and should contractually move into full commercial operations still remain in limbo. The lack of an available export transmission network means that the projects are physically and commercially frustrated, pending the deployment of the grid.
Let’s use a drainage pipe analogy; only so much water can pass through a pipe of a particular size before something has to give. The lack of transmission options means AEMO is curtailing the amount of power that many renewable projects can feed into the grid.
For example, a large asset may be able to generate 400 megawatts, but AEMO is placing export controls on power generators, limiting the level of output that they are allowed to achieve. The projected revenue of a power facility is obviously inextricably linked to the available output; in addition to creating uncertainty around the scheduled date of generation output, the limitaion of permitted level of permitted output is creating challenges with generators’ financial modelling and contractual commitments. There is also a lack of uniformity or transparency in setting the caps which is making project delivery increasingly uncertain.
Until a project is tested at full capacity and certified as meeting all requirements to enter full commercial operations, its status for insurance is impacted. Without being able to undertake full performance testing due to Marginal Loss Factors (MLF) curtailment, they are unable to have their facilities signed-off by AEMO as the regulated grid operator.
While this clearly creates significant challenges for predicting revenue generation, it also means that construction project risks often require insurance extensions resulting from the delayed testing, handover and transition to commercial operations. Construction insurers are often reluctant to agree to extend policies (for a premium) as they see their rates and covers being aligned to the physical works activities and not completed risk, albeit that the project is not operational.
A further consideration is how the Defects Liability Period (DLP), which would normally commence after the project goes operational, is affected by a delay in the issuance of the final taking over certificate. Construction insurers often have limitations on the overall construction period they may cover, including defects periods commonly up to 24 months; a long additional delay to the issuance of the Taking Over Certificate can cause them to breach their internal guidelines for maximum construction periods. They are also likely to feel strongly that the initial construction rate is not appropriate for completed facilities, where contractor parties have often all but left the facility having completed their work. This is leading to a stand-off between developers/owners and contractors as to who will solve the impasse. Adding to the difficulties is that not all construction insurers also provide competitively-priced operational phase policies.
When new projects are being developed, contractors are seeking to ensure that any financial delays due to AEMO curtailment liabilities are being considered as Force Majeure events by the contractors, leaving owners to take the full risk in the event of a delay over which they have no control.
There are several examples which demonstrate the problems with the current system. For instance, power giant AGL currently has a project in Queensland generating at 25% of its capacity during the day and 50% at night because of constraints on the grid.1 This is costing the company $100 million in issues around Price Purchasing Agreements – other companies have contracted them to supply power from this plant and where that isn’t being met, financial penalties abound.
It’s a classic case of technology and business moving faster than infrastructure. Developers, particularly those entering into contractual obligations, need to know how to plan ahead for this eventuality. In the framing and negotiation of contracts, they need to be aware of how the issues might play out and consider wisely in their forecasting and contingent modelling.
John Rae is Renewable Energy Leader, Australasia at Willis Towers Watson. John.Rae@willistowerswatson.com
