'Too much to bear': the strict new regulations imposed on NT solar
As more private solar developments apply to connect to the NT grid, are the new regulations enacted on the industry (called generator performance standards) necessary to ensure the power system remains secure and reliable, or do they represent onerous restrictions that lock out solar and favour existing gas assets? It depends on who you ask
All over the world, renewable energy is generating jobs and lowering power prices. But it’s also posing challenges to outdated electricity grids that were originally designed to be powered by coal or gas. The NT is no exception.
The NT's network provider Power and Water Corporation predicts significant growth for solar PV in the Territory with over 120 MW of new solar generation applying to connect to the Darwin-Katherine grid. Enabling third-party private renewable energy generators to sell their energy on the NT grids requires rewriting generator technical requirements that had been largely written for a power system with a generation fleet dominated by gas-fired synchronous generators.
On 29 February 2020, the NT’s Utilities Commission made its final decision in relation to new Generator Performance Standards (GPS) applying to all generators exceeding 2 MW, as proposed by Power and Water.
But many of the Territory's solar developers have argued that the new GPS represents strict conditions - including in regards to forecasting (accurate predictions 30 minutes ahead on a rolling 5-minute basis), strict ramping requirements and the need for battery storage - that make projects unviable by adding up to 30 percent to their costs.
Industry submissions to draft versions of the GPS reflected strong objections
- In its submission, Assure Energy stated "the costs of complying with the capacity forecasting accuracy requirements are too much to bear for a project like ours (fully committed, power purchase agreement executed and construction underway). We estimate the costs to be in excess of $10m. The financial imposition of the proposed GPS as it currently stands is not acceptable to us and would impact our ability to make future investment in the Northern Territory due to the uncertainty of such an investment."
- In its submission, ENI calculated that for its 45 MW solar farm portfolio in the NT, "the upfront cost of complying with the GPS provisions would likely be over (45 ÷ 25 x 10 x 1.15 =) $20M, which excludes the recurring cost of remediating ongoing BESS [Battery Energy Storage Systems] degradation."
- ENI also described the proposed GPS as anti-competitive in favour of incumbent generators. "It imposes a forecasting obligation on renewable energy plants that has no equivalent on conventional plants. When conventional plants do not meet their forecast (via unplanned outages - which has happened 98 times in the 2017-18 year as stated in the Draft Decision), they are able to call upon shared spinning reserve / C-FCAS, which all generators (including renewable generators) have to fund for them. Inversely, when a renewable generator does not meet its forecast it must spend tens of millions of dollars in batteries (in our case) or suffer up to 80% pre-contingent curtailment (loss of revenue) going forward."
- In its submission, NT Solar Future stated the GPS "introduces significant barriers to new market entrants. We have determined that these barriers will drive up complexity and costs significantly, making the NT unattractive for investment and/or driving up energy prices for consumers".
- In its submission, the government-owned energy retailer Jacana Energy explained that it had sought to keep power prices low by contracting 45 MW of solar from private developers. However, the application of these new standards "may increase grid connection costs and potentially result in increased costs being passed through to customers".
The Utilities Commission response:
In their final decision, the Utilities Commission acknowledged the following concerns of the NT solar industry:
- the cost of complying with the automatic access standard proposed for a number of technical requirements, in particular the forecast accuracy proposed in NTC clause 3.5.17, threatens the commercial viability of new solar generation projects
- the forecast accuracy requirement prevents the adoption of other more efficient measures, such as central batteries shared by a number of generators
- the forecast accuracy requirement is difficult to meet for generators developed behind the meter and operating with a zero-export connection agreement
- renewable generators may be constrained to provide frequency control services suffering lost revenue from energy sales.
They hoped that the industry might be satisfied with a provision that allows for generators to negotiate alternate performance standards "if they can demonstrate that adopting those standards does not adversely affect power system security or the quality of supply to Territory electricity consumers, such as a central battery if it makes commercial sense to do so".
"A very dangerous precedent"
In its submission, ENI noted: "it is not the job of Generator Performance Standards to ensure a power system has adequate supply of capacity, energy or storage going forward. If a shortfall of capacity, for example, presents itself in the DKIS [Darwin-Katherine Interconnected System], it is the proper task of government policy to provide the right market or structural incentives to fix. Using technical regulations to solve perceived failures or shortcomings of commercial or market arrangements sets a very dangerous precedent."
In their final decision, the Utilities Commission made a pointed criticism of the Territory Government: "the Territory Government has been contemplating further electricity market reforms for a number of years that, if committed to and implemented prior to this point, may have alleviated at least some of the issues now being faced by the industry”. In regards to a potential reliability standard ("which is necessary to ensure there is an independent, objective way to determine whether the combination of generating units is sufficient to meet the desired standard for customers"), the Commission "is not aware of any progress made in relation to this matter".
On a single forecast system and centralised battery storage
In their submissions, several NT solar companies described the proposals as "inefficient" and argued for aggregated forecasting and central battery storage.
In its submission, ENI states that "under this proposal, individual generators are strongly incentivised to co-locate the required BESS systems on their own facilities and reserve them exclusively to provide forecasting services, in order to hedge against the extreme risk of pre-contingent curtailment. This' 'turns off' all the other services this infrastructure could provide the power system if centrally controlled (including at night) and enabled to instead firm up aggregate forecast error (the sum of all forecast error on the power system including all solar farms, together with behind the meter (rooftop) forecast error). This is a highly inefficient outcome."
In its submission, Assure Energy pointed out that in the proposed standards:
- Each generator is focussed only on its own firm offer. This will result in times where one plant has a BESS charging and another plant has a BESS discharging. Individual batteries responding differently on the same network is clearly inefficient
- The regime is trying to make individual generators incredibly accurate. This is not realistic as there will be times when a plant does not meet its forecast (e.g. through plant failures or forecasting failures) so a problem would still exist in the proposed GPS. Such an occurrence would require a system response but each generator is tasked with meeting its own forecast rather than helping with a system response. A separate system response is therefore likely to be required under the proposed GPS. We question if a single integrated system response alone would be more efficient than trying to make generators individually achieve very high levels of forecast accuracy.
Submissions also pointed at a failure to address forecasting for the grid’s 50 MW of behind-the-meter rooftop solar.
In its submission, NT Solar Futures stated: "The proposed GPS does not address any of the urgent issues of uncontrolled household and commercial behind the meter solar generation and its effect on system security. The rapidly increasing amount of daytime solar generation when injecting at low demand periods, may push the existing gas turbine generators on the system below their minimum stable operating points. This may well risk a System Black event on the DKIS within the next 12 months."
Additionally, ENI points out that for the $20M they will have to spend to comply with the GPS, "the same amount spent on BESS facilities spread around the Darwin ring main would buy the same 36 MW / 18 MWh facility". Their arguments for this included that central battery storage would provide:
- spinning reserve ("allowing the existing generation fleet to run fewer operating hours overall at much greater thermal efficiency and reliability")
- black start services
- voltage and frequency contingency support services following a line outage on the single circuit transmission line between Channel Island and Katherine ("battery systems located at the ENI solar farms would instead be 'behind' these outages and therefore useless in this event")
- a systems-view approach to voltage, frequency and synthetic inertia support services
- all these power system services for 24 hours per day (unlike a solar farm battery which is "necessarily unutilized outside of daylight hours")
ENI believed the economic benefits to electricity consumers from all these additional features would add up to many millions of dollars per year.
The Utilities Commission response:
"As there is no central battery (or other alternative solutions such as a centrally controlled distributed battery solution) currently in the Darwin-Katherine system, the commission cannot rely on this for the automatic standard in this Final Decision, nor can the commission compel a party to build a central battery or compel other proposed alternatives such as upgrades to existing generation plant. Given the lead times to construct, connect and test a battery, even a commitment to build a central battery by a public or private party as soon as possible would not address the immediate issues for at least the next two years. The Commission considers that serious reliability and security issues would arise in the Darwin-Katherine system in a much shorter timeframe than that in the absence of new GPS requirements."
On a competitive ancillary services market
In their submissions, several NT solar companies also argued for an ancillary services market. Jacana Energy argued such a market would ensure "lower-cost outcomes for customers".
The Utilities Commission response:
"Another on-going issue is the current approach to providing and paying for ancillary services in the Territory whereby the many services that make up ancillary services, such as voltage control, frequency control and black start services, are provided by TGen as a 'bundled' service at a set price. The lack of a competitive ancillary services market whereby other parties can be paid for providing at least some of these services, means that the provision of a centralised battery solution by a private party would be less profitable than if provided by TGen and may not eventuate."
Again, the Commission had strong words for the Territory Government. "Notably, the unbundling and eventual competitive procurement of ancillary services was discussed in the Territory Government’s Consultation Notes on the Northern Territory Electricity Market Consultation Draft Functional Specification, also in early 2019. Again, the Commission is not aware of any progress made in relation to this matter. The Commission notes that if the Territory Government was to progress these ancillary services reforms they could assist in delivering more efficient negotiated alternatives to meet the GPS requirements."