Australia: Allocating and managing grid connection risk

A consultation by the Clean Energy Council (CEC) in December 2021 has revealed that developers find the process of connecting to the Australian electricity grid and the technical requirements for doing so are the most significant challenges when developing clean energy projects in Australia. The second and third most challenging factors are also related to grid connection risk.

In line with what is happening in the solar space and our experiences in the renewables sector, it is unsurprising that grid risk presents the greatest challenge for developing clean energy projects in Australia.

The grid dilemma

The Australian electricity grid is long and thin. There is a real challenge in transitioning from synchronous to inverter-based generation, in the numbers required, to meet state and federal renewable energy targets.

Projects are being curtailed and delayed in connecting to the grid, including well-known solar projects in the West Murray, based around the so-called 'rhombus of regret'. These projects have faced significant issues connecting to the grid.

Among the projects in which we act for, or our clients are involved, we have seen the following issues:

• more than a years' delay in achieving export at full capacity caused by issues relating to model approval on a fragile grid. This included a contractor having to redevelop its model during the connection phase to suit new software requirements for the model to be validated
• a late change in reactive power support from the use of capacitor banks to STATCOMs due to a change in the interpretation of grid rules by a regulator
• despite achieving mechanical completion months ahead of schedule, the project was delayed by over a year in gaining full connection to the grid. This resulted in bond calls and injunction proceedings.

In the last few years, raw material and inverter costs (such as steel, polysilicon and copper) have all increased in multiples. Currently, supply chain costs related to grid connection are escalating significantly. In addition, changes in the scope of reactive support late in a project's construction phase are necessary due to grid limitations. However, this is impacting significantly on completion costs.

Contractors are struggling to maintain pricing during the bid phase. They are even less willing to hold a lump sum price for reactive support from the bid until the project is connected to the grid. This translates into risks to internal rates of return (IRR) and profit margins on projects.

Grid risk is now a bankability issue, increasing the cost of capital and, therefore, the viability of projects. Worst of all, grid connection risk is creating significant workflows for lawyers.

Contracts cannot manage all grid risks

Contracts excel at allocating risks between parties. Good contracts clearly state what the risks are, who is responsible for different risks and on what terms. However, allocating risks only limits the amount of risk a party bears and still leaves the risks within the project. While contracts seek to reduce risks through KPI and incentive provisions, these largely remain secondary considerations.

If relied on alone, simple allocations of connection risk in a contract can produce poor outcomes for projects. Below are some examples based on cases we have worked on:

• traditionally, if the approval of a generator model created by a contractor is delayed, the contractor will be liable to pay delay damages reflecting the revenue they would have otherwise earned. However, delay damages are commonly capped at around 10 per cent of the contract sum. In one case, the long connection delays meant that the contractor had to pay delay damages up to the delay cap. The principal could terminate the contract at that point. However, no other party could feasibly complete the build in the absence of the contractor's manufacturing capacity and intellectual property rights and have the model approved. Inevitably, a project 'reset' will occur at the principal's cost or the principal will need to use other grounds under the contract to pressure the contractor to complete on time
• usually, the principal takes on the time and cost risk for changes in law. However, this is typically limited to laws, rules and regulations with mandatory applications. Against this, determining the acceptability of generator models and the operation of the National Electricity Rules (NER) relies significantly on interpreting rules. Experts are renowned for not agreeing on how rules should be interpreted and it is common for disagreements and views to change once a project is underway. This is because interpretations are not strictly laws. However, they can have this effect when they are the views of those granting approval to connect or to progress beyond hold points. Not only do different interpretations of rules lead to delays, but they can also lead to different technological solutions being required (such as reactive support) to what was originally envisaged. This results in provisional sum overruns or variations at the late stages of the project.

Parties often don't turn their mind to other unintended outcomes from delayed connection to the electricity grid. For example:

• completion is more difficult to achieve if a plant has been in operation for extended periods
• a plant operating for periods longer than its intended design life may not be insurable.

What grid risks can parties try to manage?

If contracts are limited in their ability to sensibly allocate connection risks, can the parties manage those risks themselves?

Regulatory risk

Regulatory risk commonly refers to the risk that laws and regulations (including their interpretation) change. Developers (and contractors) are generally 'terms takers' in relation to regulatory risk and in practice, they have little ability to minimise the effect of these risks.

In relation to regulatory risk, the parties can:

• seek to engage early, understand the rules, observe practices and trends on other projects and listen to guidance
• create a nuanced contractual allocation of risk which attempts to benchmark the regulatory requirements when the contract commences
• hope.

While the parties can attempt to forecast changes in law and anticipate the attitudes towards interpretation from when financial close is achieved, they are limited in their ability to reduce the effects of any such changes.

Grid stability

Energy regulators have an overarching obligation to ensure the electricity grid's power system is stable. This imperative takes precedence over developers seeking their own stability in terms of development timing and technology requirements.

Ensuring grid stability often results in protracted model approval processes, the introduction of new or expanded reactive power support and staggered connection limits. The time and cost impacts of ensuring connection is generally allocated between the parties.

While the parties can attempt to forecast the changing nature of the grid and 'future proof' their projects, this is at the cost of the project and inconsistent with tender processes and efforts to achieve target IRRs.

Cost increases

While contracts can set the price of certain products, the parties are generally 'price takers' in relation to volatile global price movements.

In reaction to this, it has become common for the cost of reactive equipment to be provisional sums and to use broader price indexes on commodities, such as those mentioned above, in contracts.

Who is responsible for reducing grid risk?

No one person can reduce grid risk. However, key stakeholders all have a role to play.

For developers and contractors:

• benchmarking expected grid conditions at the end of a development will likely become more detailed and nuanced. Given recent project disruptions, simply stating a connection date and requiring the contractor to perform all works to ensure connection to the grid by that date is unlikely to work. Instead, parties should:
  • agree assumptions around the stability of the grid and the technology required to manage that stability when connection is to occur
  • agree on what NER, Connection Agreement requirements and Generator Performance Standards are to be met by which parties (including at subcontractor levels)
  • ensure access standards are negotiated before contract execution and build the price and program around those.
• parties need to model how long the grid connection process should take based on agreed forecasts and agree on the time and cost relief if the process is extended. The number of expected connection hold points and the anticipated duration of each hold point should be expressly stated
• interpretation risk needs to be contemplated in a contract's change of law provisions. The rules are, and will always be, in states of flux. Views on how those rules are to be interpreted will inevitably change during the connection process. Consequently, benchmarking 'norms' and the extent tolerances will be allowed will reduce the incidences of disputes
• in practice, completion dates based on best-case connection scenarios and delay damages regimes based on 100 per cent foregone generation values quickly lead contractors to meet contractual caps on delay damages and no longer be incentivised to complete. The risk of delayed completion then moves to the principal, who is unlikely to be best placed to manage this risk. Instead, programs and delay damage rates need to be built around:
  • realistic dates for completion based on assumptions that borderline or marginal grids will be difficult to connect to at completion
  • a delay regime that provides for a rate of accruing delay damages which will, in all reasonably foreseeable cases, exceed the worst-case scenario for connection timing
  • incentive and penalty regimes that reward and respond proportionately to achieving and failing to meet completion targets.

For regulators:

• creating regulatory certainty is key. On all too many projects, parties remain 'surprised', rightly or wrongly, at what regulators expect for grid connection during the course of the projects
• understand the impact that changes in rules and requirements can have on projects and to be circumspect and measured in changing rules and interpretations mid-development. To achieve this, regulators can:
  • place the onus of justifying rule changes on itself
  • require robust regulatory impact statements
  • introduce materiality thresholds.
• strive for complete regulatory stability. The Australian Energy Market Operator, the Australian Energy Market Commission and various working groups are working towards measures to anticipate connections and expected grid conditions over time. This will allow developers and contractors to build in appropriate time periods and technologies in anticipation of what will be required in the future.

For government:

• investment in the electricity grid is key. This is to reduce grid connection risk by stabilising grids with connection available well within their margins. It is promising to see direct investment in grid infrastructure and the creation of Renewable Energy Zones and Offshore Energy Zones being pursued at state and federal level and by both major parties
• timing is critical if state and federal renewable energy targets are to be met. For example while the UK has just announced significantly increased renewable energy targets, developers are being advised that there is a six to ten year wait for connection due to grid constraints. PWC recently suggested that connection times in Australia are increasing from 2018 lows. Sophisticated reactive power support by developers can only do so much to overcome the current capacity limitations seen across so many locations in Australia.

This publication does not deal with every important topic or change in law and is not intended to be relied upon as a substitute for legal or other advice that may be relevant to the reader's specific circumstances. If you have found this publication of interest and would like to know more or wish to obtain legal advice relevant to your circumstances please contact one of the named individuals listed.