Independent Review into the Future Security of the National Electricity Market Blueprint for the Future, Jun 2017

3.4 Generator Reliability Obligation

Regions with a very high proportion of VRE can present challenges for system reliability. A number of submissions to the Review¹⁹⁷ highlighted that, going forward, there will be a need for more dispatchable capacity to be brought forward to the market to complement an increasing proportion of VRE generators like wind and solar photovoltaic.

The Panel recommends the adoption of a new Generator Reliability Obligation. This will consist of new obligations for VRE generators connecting to the NEM, to ensure reliability is maintained. As part of this measure, the market bodies should undertake regional reliability assessments to determine the minimum dispatchable capacity required for each region to maintain system security and reliability. How much dispatchable generation is required in any region of the NEM depends on a number of factors. Considerations should include:

Total VRE generation as a proportion of dispatchable generation.

Strength of the network.

Extent of variation in VRE generation.

Interconnections with other NEM regions.

The load profile.

Wholesale and contract market considerations.

Expected future trends.

In regions where dispatchable capacity approaches the determined minimum acceptable level, new generation projects should be obliged to also bring forward new (i.e. not contracting existing) dispatchable capacity to that region. This obligation should be expressed in terms of a percentage of the new VRE generator's nameplate capacity, able to be dispatched for a required time period. The new capacity should not need to be located onsite, and could utilise economies of scale. Multiple VRE projects could pair with one new large-scale battery or gas-fired generation project, for example.

If technology cost reductions or policies such as more ambitious state and territory based renewable energy targets lead to very high levels of VRE in a particular region, the Generator Reliability Obligation would ensure that adequate dispatchable generation is also brought into the market to maintain reliability.

The Generator Reliability Obligation could also assist in maintaining liquid contract markets in regions by maintaining a level of dispatchable capacity. Implications for the financial markets should be considered when undertaking a regional reliability assessment.

Box 3.3 – Falling costs of technology

The Panel notes that, even since the Review started, utility scale batteries, wind and solar photovoltaic have declined in cost substantially more than expected.

Origin Energy Limited has agreed to buy all of the power generated by the Stockyard Hill Wind Farm and the associated Renewable Energy Certificates for a power purchase agreement (PPA) of below $60/MWh.¹⁹⁸

AGL recently outlined its estimates for the cost of different fuels. AGL considers that a new wind farm supported by gas peaking generation (through the ‘firming cost’) to now be cheaper than new CCGT at a $8/GJ price. A new solar farm supported by gas peaking generation would also be cheaper than new CCGT at a gas price of $12/GJ (see Figure 3.11).¹⁹⁹

Figure 3.11: Implied cost of new generation²⁰⁰

Recommendation 3.3

To complement the orderly transition policy package, by mid-2018 the Australian Energy Market Commission and the Australian Energy Market Operator should develop and implement a Generator Reliability Obligation.

The Generator Reliability Obligation should include undertaking a forward looking regional reliability assessment, taking into account emerging system needs, to inform requirements on new generators to ensure adequate dispatchable capacity is present in each region.

3.5 Additional reliability measures

The orderly transition policy package and Generator Reliability Obligation discussed above, if implemented and committed to in full, will improve the investment environment, lead to more efficient market outcomes and give confidence that the reliability of the NEM will be maintained through the energy transition. The measures discussed below represent additional reforms that may be warranted to address more specific issues that could arise in the future and have implications for reliability. The Panel recommends market bodies investigate the appropriateness of these measures in relation to existing arrangements.

Out of market strategic reserve

Consideration should be given to the suitability and desirability of an out of market Strategic Reserve mechanism. This could involve equipping AEMO with the power to contract for a targeted level of capacity that would be held in reserve outside the market. If implemented, this policy should be designed as an enhancement or replacement to the existing reliability safety net measure, the Reliability and Emergency Reserve Trader (RERT) mechanism (see Box 3.4), to avoid adding additional complexity and uncertainty for the electricity sector.

Box 3.4 – Reliability and Emergency Reserve Trader mechanism

The primary tool to ensure reliability under the existing framework is the Reliability and Emergency Reserve Trader (RERT) mechanism. The RERT allows the market operator to contract for additional electricity generation reserves, where there is a projected shortfall. The reserves that the market operator contracts with cannot otherwise be available to be bid into the market, and participants are only paid if their contract is executed. From November 2017 onwards, the maximum length of time that the market operator can enter into a RERT contract is 10 weeks ahead of a projected shortfall. Prior to recent revision the maximum contract timeframe was nine months.

Changes to the RERT may be warranted. The relatively short timeframe at which reserves can be contracted prevents AEMO taking steps to address identified capacity shortfalls well ahead of time. This reportedly places the market operator in a sub-optimal negotiating position when trying to negotiate with potential participants.

In addition, because the RERT only pays participants once a contract is executed, it does not currently provide sufficient incentives to encourage the participation of distributed demand response aggregation services. This shortcoming is a key reason changes to the RERT may be warranted. Making better use of demand response in the NEM represents a low cost and as yet under-developed opportunity to maintain reliability.

To avoid interventions crowding out private sector investment or creating other perverse outcomes, there would need to be a clear and transparent set of criteria under which the reserve could be called upon. For example, AEMO may only intervene in cases where the reliability standard is forecast to be breached.

Ramp rates

South Australia is at the forefront of managing the impacts of a high penetration of VRE generation. The Panel understands that AEMO has recommended a series of actions to be implemented in South Australia to address current challenges presented by VRE generators, independent of this Review. The Panel considers these reforms adequate for addressing South Australia’s immediate concerns and recommends the measures be further assessed for their suitability in other NEM regions.

Among these new measures is a requirement for active power control facilities to be fitted to all VRE generators. This measure is understood to require VRE generators to control their rate of change of active power (ramp rates), among other things. This may require that VRE generators curtail their power output at times to ensure they meet limitations on power output rates of change. This measure has the potential to provide additional incentives for VRE to install energy storage or partner with other storage companies as a way to capture the potentially lost value of curtailed power output. AEMO should monitor the effectiveness of this new requirement and assess its application more broadly.

Day-ahead markets

The ability for both AEMO and NEM participants to contribute to short-term reliability could be enhanced through greater forward transparency of supply conditions. While the NEM already has mechanisms that provide forward transparency, another approach that is used in other countries is a ‘day-ahead market’, as discussed in Box 3.5.

Box 3.5 – Case study – international experience on day-ahead markets

Internationally, day-ahead markets are widespread. They exist in most European power markets, including in Germany, Great Britain and NordPool; many are part of an integrated European
day-ahead market called the Price Coupling of Regions.²⁰¹ There are also day-ahead markets in the majority of North American power markets, including in the PJM Interconnection, the Electric Reliability Council of Texas (ERCOT) and the California Independent System Operator (CAISO).

In these markets, bids to trade volumes of electricity for each interval in a day are submitted, and financially committed to, the prior day. From the bids a schedule is developed which commits certain generating units to run for given intervals, and instructs how much they must generate (‘dispatch’). In developing the schedule, the generation portfolio is optimised based on constraints that reflect expected real-time conditions. The day-ahead market is followed by a real-time ‘balancing’ market where supply is dispatched to balance residual demand, including based on updated constraints. While participation is usually voluntary, typically a high proportion of electricity trading volumes is settled in day-ahead markets.

In contrast to this ‘two settlement’ system, the NEM uses a ‘single settlement’ approach, with no firm day-ahead market. All electricity trades are settled in the real-time market. There is a
pre-dispatch process that has similarities to a day-ahead market, but it is not financially binding: up until the start of the relevant five-minute dispatch interval, generators are allowed to resubmit bids (‘rebid’) to shift volumes between price bands nominated in the original bid.²⁰² The accuracy and validity of the pre-dispatch process depends on factors such as demand forecasts, wind and solar forecasts, changes to constraints, unplanned outages, and the level of rebidding.²⁰³ Aside from rebidding, the same factors also affect the accuracy and validity of scheduling in day-ahead markets.

A key function of day-ahead markets in European and North American power markets is for more efficient coordination of electricity transactions with neighbouring power markets; though this is not relevant to the NEM, as it does not connect to any other power markets. Another beneficial feature of day-ahead markets is their ability to coordinate with fuel markets. In the United States, day-ahead markets assist gas-fired generators in procuring and transporting their gas supplies (referred to as ‘gas-electric coordination’). The windows for bidding into these day-ahead markets are synchronised with the windows for procuring gas supply.

More broadly, day-ahead markets may be a more efficient means for the market operator to manage reliability than a pre-dispatch process, to the extent that a pre-dispatch process may be subject to strategic capacity withholding or disorderly bids. However, there is also recognition of the efficiency benefits from the flexibility of securing unit commitment closer to real-time (as occurs in a single settlement system), and in some existing day-ahead markets there is consideration of moving the gate closure closer to real-time. The forward nature of day-ahead markets also enables generators and loads to hedge against exposure to pricing and scheduling risks, and in doing so, can reduce price volatility in the real-time market. The financial markets in the NEM provide a similar function, but in a less transparent way.

Importantly, day-ahead markets are also recognised to better facilitate demand-side participation compared to real-time markets. A recent assessment of a day-ahead market for the New Zealand Energy Market noted potential efficiency benefits in this regard.²⁰⁴

For the NEM, any further consideration of a day-ahead market would require detailed cost-benefit analysis, including in relation to the nature of changes to the existing real-time and contract markets, impacts on market participants, and the implementation costs. Introducing a day-ahead market would be a significant reform. Other reforms are more urgent, as discussed elsewhere in this chapter. For further consideration, the Panel recommends that AEMO and the AEMC should work closely with market participants to consider the possible benefits of a day-ahead market in the NEM.

Recommendation 3.4

By mid-2018, the Australian Energy Market Operator and the Australian Energy Market Commission should assess:

The need for a Strategic Reserve to act as a safety net in exceptional circumstances as an enhancement or replacement to the existing Reliability and Emergency Reserve Trader mechanism.

The effectiveness of the new licensing arrangements being developed for generators in South Australia and whether they should be applied in other National Electricity Market regions.

The suitability of a ‘day-ahead’ market to assist in maintaining system reliability.