You bought a BESS. Hurray!

Time for a post of truly epic proportions to help you decide what to do with it – specifically, how to recover all that money you spent on it and justify all that time you spent fighting with your local network business to connect the damn thing. Hi DNSPs, you have a PR problem FYI.

Before we continue, I’d like to emphasise that nothing in this post should be taken as direct financial or legal advice. You already knew that, but I thought I’d remind you.

You head on down to the BESS value super store to pick up some products. After having your sausage sizzle, you’ve popped energy and FCAS in your shopping trolley. Great start. They’re taking up a lot of space in there! But there’s room for network tariff management, which you now know is very important because you read this post, so you pop that in the trolley too.

As you near the middle aisle, you hear other shoppers murmuring about some products you’ve never heard of – RERT, PDRS, CIS, PPAs, Caps. You were planning on skipping the middle aisle because you don’t need a jetski or a new hat, but this sounds like something different. You sidle over to see if there isn’t something to fill that weird front section of the trolley that you never know what to do with.

Kind of like the middle aisle at Aldi, this post is a grab bag of ways to increase the revenue from your NEM-based BESS portfolio in ways that may or may not work for you. None will be the central pillar of your business case, but some could provide a great boost for the right project in the right place.

RERT

Referred to by some as the gateway drug for energy flexibility, RERT is your on-ramp to full-blown market participation.

Contrary to popular belief, people in the energy industry do know what proper drugs are (“Can I interest you in a bump?” was a legit question someone asked me at All-Energy 2024), but for some reason they get there via RERT.

What is it?

Formally the Reliability and Emergency Reserve Trader but informally known as AEMO’s “Oh, sh*t” button, RERT is an emergency trigger AEMO can pull when the electricity market fails to deliver a reliable power system. Put another way, it enables AEMO to procure electricity reserves from outside the market when the market itself has failed to incentivise enough capacity to be available for dispatch. RERT is traditionally provided by C&I energy users, either by ramping load down or switching to a form of backup supply (e.g. generator or BESS), although Aggreko went ham with an unorthodox method a few years ago, 110MW worth of diesel generators in the middle of Victoria (didn’t last long).

The NEM dispatch model – specifically, its system of forecasts and scarcity prices – is generally pretty good at ensuring there is sufficient in-market capacity available to meet grid demand, plus a reserve margin to cover any unexpected events. So, RERT reserves tend only to be activated in times of significant system stress, e.g. a very hot afternoon on a summer weekday when two large coal units are offline, wind output is low, and a significant transmission line is constrained. Activation of RERT reserves is AEMO’s attempt to stave off the worst-case scenario: involuntary load shedding.

How is RERT procured?

AEMO is constantly peering into its reliability forecast machine to look for (ways to make people’s lives suck and) periods when available supply will not be sufficient to meet demand (following the Reliability Standard). If a gap is identified, AEMO will issue a market notice indicating that a Lack of Reserve (LOR) exists for the specified period. This notice is intended to prompt a market response – a lack of reserve indicates the potential for higher prices, which incentivises in-market capacity to be available. In most cases the market responds – updated forecasts now show that participants will be available during that period, and the LOR notice is cancelled. But sometimes the reliability shortfall persists, indicating that AEMO needs to take action by procuring RERT.

There are a few different types of RERT. Each is procured in a different way, with different payment arrangements and different obligations around availability. These requirements are set out nicely by AEMO in the following table:

In recent memory, AEMO has tended to use the short notice RERT framework the most. Most parties with RERT capacity to offer will do so via an aggregator, but some of the very big players contract with AEMO directly.

To offer your capacity as RERT reserve, you need to satisfy AEMO’s “out of market” provisions. Easily one of the greyest areas of the NEM’s regulatory framework, the policy intent is that you can only offer reserves as RERT if that capacity doesn’t otherwise participate in the electricity market. As a principle this makes sense – you don’t want in-market capacity pulling out of the market to chase RERT revenue – but in practice it’s tricky to draw a clear line. There’s a lot more detail than we care to cover in this post, but if you’re looking to sign up for RERT it’s important to look at these provisions closely.

Any technical requirements?

Not really. Pretty much all you need is the ability to reduce demand and/or export to the grid, and a market-facing meter to measure the response.

Should you put RERT in the trolley?

Here’s what’s good about RERT:

Low barrier to entry. RERT is your home brand flexibility product.
Low compliance burden. Compared to participation in the energy and FCAS markets, the RERT compliance rules are a breeze.
Can be lucrative for just a few hours’ work.

And here’s the bad:

No year-to-year revenue certainty. Maybe AEMO will procure RERT this summer, maybe it won’t. The only one who really knows is AEMO.
No guarantee of dispatch, and therefore no guarantee of payment for short-notice RERT, the most procured form of RERT.
The “out of market” provisions. If you’re a BESS operator doing daily electricity price arbitrage, it’s a little hard to argue that your capacity isn’t “in market”.

With the cons described above, you’d be a fool to choose RERT over the full stack of year-round, market-based revenues available to you as an unscheduled BESS operator.

Most sensible businesses look at RERT as a nice little money-maker when it comes around but certainly wouldn’t include it in a revenue forecast or investment business case.

The only circumstance where you might consider RERT participation is if you’ve got a new BESS energised and your market registration has been delayed.

[There is also the circumstance where AEMO is so stressed out about system reliability that they throw the out of market provisions out the window and contract with anyone, but that’s against the rules so they wouldn’t do it, right? RIGHT?]

The future of RERT

RERT has saved the day on a number of occasions. The alternative – widespread blackouts – has significant social and political consequences. But, RERT is expensive, and the pool of potential providers is somewhat limited. While it’s generally acknowledged that we need RERT, policymakers have been trying to lure flexible capacity in the NEM instead of sitting on the outside chasing RERT revenue every now and then, with the idea being that this will deliver higher levels of efficiency, transparency and reliability.

Who pays for RERT?

As is the case with pretty much every other cost in the NEM, Australian consumers do.

But not every consumer pays the same amount. AEMO allocates the cost based on each retailer’s share of total regional energy consumption during the period RERT was activated. This means that the retailers whose customers were drawing more electricity during the critical grid event will pay a larger share of the costs than the retailers whose customers were incentivised to reduce demand during that period, for example.

Capacity Investment Scheme (CIS)

Some people might be offended by the suggestion that the CIS is a “middle aisle of Aldi” product, but if you’re a small-scale demand-side player, it’s appropriate. The CIS is a federal scheme designed to de-risk large-scale renewable and dispatchable capacity projects through long-term underwriting contracts. Projects are selected through a series of tenders for each NEM region, run roughly every six months. CIS contracts provide two-way price protection through:

a price floor, which provides a minimum guaranteed revenue for the project operator, and
a price ceiling, above which revenue is paid back to the government.

Can unscheduled BESS get a CIS contract?

Small BESS assets such as <5MW standalone BESS and BESS co-located with C&I customer load are technically capable of providing the “dispatchable capacity” governments are looking for. But that doesn’t mean they’ve been able to participate in the tenders. Ineligible for CIS, maybe smaller BESS should have a TRANS?

Is this thing on? Taps mic C’mon, love this crowd.

The only tender to allow these sorts of assets to put a bid forward was the second tender run in NSW, which required that any such capacity be registered (and thereby scheduled) through the wholesale demand response mechanism (WDRM). The demand flexibility aggregator Enel X was awarded a contract for 95 MW of capacity, all of which will be in the WDRM. All CIS tenders since have prohibited participation by small flexibility assets, including if scheduled through the WDRM.

In a positive development, the federal government recently sought feedback on ways to enable unscheduled, aggregated resources to bid for CIS underwriting support. The proposal was to extend most of the existing CIS requirements to aggregated proponents, including:

the minimum 30MW bid size
the requirement to set up a special purpose vehicle (to separate CIS-associated revenue from other business revenue)
the 2-hour minimum duration obligation
the revenue floor/ceiling payment structure.

The CIS also requires successful proponents to be scheduled. The consultation paper proposes that proponents of aggregated resources would only be eligible for CIS underwriting if they commit to registering in the “scheduled lite” mechanism, due to commence May 2027.

It may be difficult for portfolios of aggregated resources to satisfy some of these requirements and to compete fairly against grid-scale resources in the same tender, particularly if the portfolio involves customer load.

The government is hoping to allow aggregated resources to bid in the next round of tenders in late 2025, so we can expect a decision on these matters soon.

What happens when CIS tendering finishes in 2027?

A panel of sensible thinkers is reviewing the NEM’s investment framework, and in particular what happens when CIS tenders finish up in 2027. Can spot prices alone drive the levels of investment we need to deliver a reliable, renewables system? The Panel thinks not. Its draft report recommends a mechanism of investment support that involves the creation of new financial products designed around the reliability services the grid will need - specifically firming, shaping and bulk energy.

Unfortunately, the Panel’s focus has been almost exclusively on large-scale capacity. There’s a long list of reasons why governments should be supporting demand-side capacity over supply-side solutions. While there are still many details to finalise, there is a real risk that the mechanism’s design will favour large-scale proponents, who will empty the shelves and leave demand-side proponents with a lighter trolley.

NSW Peak Demand Reduction Scheme (PDRS)

This NSW Government program was launched in 2022 to deliver peak demand reductions in NSW. Legislated out to 2050, it sets a target for peak demand reductions each year, which is apportioned amongst all electricity retailers in NSW. Retailers must create or purchase enough peak reduction certificates (PRCs) to cover their share of the annual target.

One PRC represents 0.1kW of peak demand reduction delivered between 2:30pm-8:30pm in summer (specifically 1 Nov to 31 Mar). PRCs are tradeable and retailers face a financial penalty if they fail to surrender sufficient PRCs to meet their target. Consequently, PRCs have a financial value that can be realised when sold to a retailer or third-party trader.

PRCs are created through the delivery of eligible PDRS activities. Current activities include things like the installation of more efficient pool pumps, refrigerated cabinets and heat pump water heaters. In 2024, two BESS activities were introduced, providing support for the installation of a battery (BESS1 activity - in a dramatic rug pull, the NSW Government decided to terminate this activity given the support provided by the federal government’s Cheaper Home Batteries scheme.) and connecting it to a VPP (BESS2 activity). The battery must be between 2-28kWh, must be co-located with solar, and it must be a small customer site (i.e. think residential and small business).

So, nothing in it for C&I BESS?

In short, no. But it’s an active policy issue.

The NSW Government has been trying to introduce a C&I PDRS activity for several years now. Its first attempt – the wholesale annual response method (“WARM”) activity – proposed to require participants to be registered in the wholesale demand response mechanism (WDRM, explained in this post) to create PRCs. But the proposal never left the design phase due some unresolved policy issues and the uncertainty surrounding the WDRM’s future. Now that the AEMC has determined that the WDRM is a mechanism worth retaining, it’s possible that the WARM activity will get picked back up.

Other options proposed include a C&I version of the BESS1 activity, providing a fixed number of PRCs per kW of C&I BESS capacity. The NSW Government seems committed to developing something for the C&I sector, so maybe you’ll see a PDRS product on the shelf next time you visit the BESS value super store.

PPAs

When you borrow money/sell shares to fund a Project that hasn’t yet been built (i.e. to get the money to build it), you get better terms if you have some evidence that people will pay you for its output. This often comes in the form of a PPA (Power Purchase Agreement).

This has been the case for virtually all renewable generation and some of the batteries built since the NEM came into being.

Banks love it if those people help you build out a case for your credit-worthiness. If you’ve ever heard the term ‘bankable counterparty’ thrown around in discussions about this topic, this is what they mean.

PPAs often relate to the wholesale market, but their value can sometimes incorporate other markets too. They always involved a Generator and a Buyer of some description ([Corporate] Customer, [Energy] Retailer, or another [Independent] Trader).

For the Buyer - PPAs present an opportunity for protection against market volatility without having to buy expensive products from the contract market.

For the Generator - Most large utility-scale Projects have historically required a PPA in order to reach Financial Close, because revenue is completely at risk without one. If you want to get money out of a bank without putting your house on the line, you’ll normally need one.

The structure and term of these agreements varies depending on the Projects and the parties involved. We referenced some common structures in this post back in March.

PPAs warrant a post of their own, but here’s a quick rundown of the different types and terms you may have heard:

Corporate PPA - A Buyer (normally a Customer) signs a contract with a Generator for the power produced by the Project. The Project must be market-facing (through one of the means described here). The Generator’s output profile is matched with the Customer’s consumption profile, with any gaps filled using certificates. The Customer’s Retailer is normally involved, with the ongoing reconciliation managed through a process known as sleeving. No wizards in this story.
On-site PPA - These also normally feature Customers, and the Projects are co-located with their load. They will sign a contract with the Generator to purchase the power that comes out of the Project (typically solar, BESS, or both) at an agreed rate. These are incredibly common, and have accompanied most no-upfront-capex commercial solar deals done in Australia over the years. The Project need not be market-facing in this arrangement.
Tolling agreement - these take two forms, Physical and Virtual.

One party (Buyer) signs a contract for the output from one or many Projects (normally grouped by State but sometimes blended across the NEM).
Physical tolls -

Buyer assumes responsibility for controlling each Project and dispatching them as they see fit. All market revenue (including FCAS) goes to the Buyer.
The Generator receives a fixed payment in return, and must make sure the project continues to operate within agreed uptime metrics.
The Generator’s yield is normally lower, but with lower risk because the Buyer is doing more work.
They can be a good option if the toll rate is sufficient to get the Projects funded.
100% of Project output is normally contracted to the Buyer.

Virtual tolls -

Generator retains responsibility for controlling and dispatching each Project.
All market revenue (including FCAS) from the Project initially goes to the Generator, and the Buyer settles with them separately.
Yield for the Generator is normally higher than with a Physical toll, but with more obligations and risk.
They can be a good option if the Generator does not want to contract out 100% of their Project output and is technically sophisticated to enough to dispatch their Projects.

They’ll normally contract out the minimum required to satisfy lenders and leave the remainder exposed, using equity partners to fund it.

This is generally seen as a good way to balance downside risk whilst retaining access to some upside from the market.
The Calala BESS is a good recent example of this structure for a utility-scale project, and Engie’s recent announcement with AGL is the first of undoubtedly many more to come in the growing DER era.
Generators cannot get away with some form of software to automate dispatch of their Projects here. You can try, but it ain’t happening.

There’s nothing preventing an owner of Unscheduled BESS from securing PPAs using one of the above models. Their complexity is likely to increase over time as Buyers seek to manage their market exposure with exotic shaped products.

We see some sik Virtual Tolls in the market’s future as batteries become more prominent. This is a major reason for Hachiko’s existence. Dealing with the complexity of Virtual PPAs with a large distributed portfolio is not a simple task, so it’s a good thing you have us.

Stick ‘em in the trolley, you absolute weapons.

Caps

Caps protect market-facing entities from its famous volatility. They are like the condoms of the wholesale market, but not as cheap. They’re an insurance product, traded on the ASX.

What is their purpose?

They are called $300 caps because they cap the buyer’s exposure to wholesale market prices at $300. This isn’t a charitable act, of course. The cap itself has value, and sellers sell them for this reason. When volatility is (or is expected to be) high, caps are expensive.

Who are the buyers?

Normally retailers, out-and-out traders, or someone else who has some reason for being exposed to wholesale market volatility. I don’t know man, you get some weirdos out there.

Who are the sellers?

People with access to generation that can be used to back the obligations created by the sale of a cap, or just out-and-out day trader cowboys (incredibly risky).

How do they work?

Sold according to region, MW volume, and time period, caps provide the buyer with the right to receive all wholesale market revenue above $300 for the chosen region and time period, according to the cap’s associated MW volume. This is a purely financial transaction.

Cap transaction (one-off)

*Contrary to popular belief, it isn’t CAP.*

During cap cover period (every trading interval)

*$X is the wholesale energy settlement price.*

The Seller must do this throughout the cap cover period, even if they don’t receive their equivalent green line from the market. Things can get hairy (oops I have no hair) dicey (oops I don’t really play board games) shitty (I shit, just like you) quickly if you don’t have market revenue coming in to help back your cap obligations.

Why do it?

Selling caps enables you to create some revenue certainty for a portion of your portfolio (capitalising on others’ fear of volatility) or even make extra money alongside normal wholesale market revenues (if you can arbitrage the caps). This is not for the faint of heart, though. You need:

Trading capability
Access to clearing
Access to someone with a Financial Services Licence
Price forecasting capability
Effective and reliable automation for dispatch of your portfolio

When organisations become sophisticated enough to do it, trading caps is an excellent way to increase the value of your portfolio. As a rough rule of thumb, revenue can increase by >40%, but this is heavily dependent on how much volatility the market expects at various points in time.

However, don’t just chuck them in the trolley willy nilly. Huge companies (really huge) have faced very bad times after selling caps, due to major market events combined with generator downtime that left them looking desperately under the sofa cushions for spare cash.

That’s it!

Wow, what a shopping trip! How full is your trolley? Are you excited? Don’t forget to leave it in the designated area in the car park. Don’t be one of those people.

Shopping the stack: alternative sources of revenue for non-scheduled BESS