Gigabytes of bandwidth and acres of digital newsprint may well be devoted to arguing the ultimate reasons behind yet another blackout – albeit only partial – in South Australia yesterday evening:

In this analysis I’ll stick to the immediate causes apparent so far in the market data.

Whilst prices did of course spike to $13,000-$14,000/MWh for over 2 hours, including the duration of the load shedding (when the spot price is automatically set to the Market Price Cap), this post will focus on the supply / demand balance we saw yesterday. This, rather than bidding behaviour or other factors, was the key driver of both the load shedding and the extreme prices.

I’ll start with an analysis of the demand and supply situation around the time of the load shedding, then some observations on how the day evolved.

Extreme heat drove SA demand to very high levels

Adelaide endured a maximum temperature of over 42 degrees and some inland locations saw readings exceeding 46 degrees. This pushed scheduled demand well above this summer’s previous highs, approaching 3,100 MW, seen here along with dispatch price and (local) generation availability over the period 12:00pm – 10:00pm AEST in this screenshot from ez2view’s Time Series Data Viewer tool:

This demand level corresponds to AEMO’s “P10” maximum half hourly demand forecast for South Australia in the most recent National Electricity Forecasting Report – meaning a forecast expected to be exceeded only one year in ten.

Demand last exceeded this level in January 2014 (and reached levels over 3,300 MW in 2009 and 2011), however AEMO’s forecasts have predicted declining maximum demands due to assumptions of increasing PV penetration, energy efficiency, and changes in South Australia’s economy.

An observation from this chart is that it shows a demand drop of about 300 MW during the load shedding period compared to the 100 MW figure quoted in AEMO’s media release – the reasons for the difference are unclear.

South Australian Supply

The green line on the chart above shows available generation in South Australia on Wednesday afternoon / evening. Three features are immediately obvious:

The line moves around substantially (isn’t generation capacity more or less fixed?);

more or less fixed?); It declines through the afternoon peak whilst demand is climbing (why?); and

through the afternoon peak whilst demand is climbing (why?); and There is a large gap between local generation capacity and demand throughout the afternoon peak (what fills this gap?)

The answer to the first two questions is that “available generation” reflects maximum output that can be physically produced given real time wind and temperature conditions. With a large fleet of wind generators in South Australia, falling wind speeds on a hot, still summer afternoon meant less maximum output from those windfarms. To a lesser extent, very high temperatures also degrade the maximum output capability of most forms of generation, particularly gas turbines, and a smaller part of the decline is due to this effect.

The gap between local supply and demand is met from the two interconnectors linking SA to Victoria and the rest of the NEM – the Heywood AC interconnection capable of securely flowing around 600 MW into SA, and the Murraylink DC interconnector, which has nominal capacity of 220 MW.

The following chart breaks down the contributions of thermal generation (gas and liquid fuel fired), interconnector imports, and windfarms to South Australian supply yesterday:

This highlights the output from wind generation falling away into the afternoon and the increasing contribution from local thermal generation. Combined interconnector imports were relatively constant through the afternoon.

So why the load shedding?

The quick answer is that by 6pm AEST (6:30pm Adelaide daylight saving time), all online, available local generation sources in South Australia, wind and thermal, were producing their maximum available output for the conditions. More interconnector imports were needed to fill the increasing demand-to-generation gap shown in the earlier chart, and – on the Murraylink interconnector – had exceeded levels consistent with keeping the power system in a secure state. We can see this in the following snapshot from ez2view showing the South Australian region for dispatch interval 18:05 (the five minute period 18:00 – 18:05).

I’ve enlarged the icon showing target flows (197 MW) on Murraylink and, in the very small font underneath, limits on these flows – the relevant one is the left hand import limit of 78 MW, which is being exceeded by over 100 MW. In fact this situation of Murraylink flows exceeding limits had pertained for about 30 minutes preceding this snapshot.

These limits do not reflect the physical interconnector capacity (220 MW) but are the output of system constraints designed to keep the power system in a secure operating state. Outside the bounds of these constraints, a single contingency such as a line or generator trip, could possibly result in damage to equipment, risks to safety, and in the worst case a widespread blackout. Broadly, AEMO has an obligation to return the power system to a secure operating state within 30 minutes.

The only reason flows on the Murraylink interconnector would have exceeded the relevant import limit in the first place is that no further generation supply was available for dispatch in South Australia at this time – AEMO’s dispatch process will fully utilise all available generation resources before scheduling such constraint violations.

With demand continuing to rise, no further local generation able to be dispatched, and interconnector flows beyond secure levels, AEMO instructed SA Power Networks – the local distributor for South Australia – to begin rolling load shedding.

Generation Analysis – Why did supply fall short?

I’ve prepared the following table comparing actual generator outputs at 6pm AEST yesterday – a fair reflection of their maximum capability at the time of load shedding – with the nominal summer capacities of each power station in South Australia, broken into Thermal and Wind groups, as well as nominal interconnector capacities (but note the comments above on the impact of constraints):

Notes to the table indicate where specific thermal stations had output materially below capacity due to unit outages.

Thermal stations as a group produced to about 89% of their nominal summer capacity. The largest outages being one unit (120 MW) at Torrens Island Power Station and the Port Lincoln Gas Turbines (56MW) being offline, the latter reportedly due to transmission issues.

The other, long term, outage noted above – and not counted towards nominal capacity for yesterday – is the withdrawal of one unit at the Pelican Point gas fired power station from regular service since March 2015. This unit is not available for immediate dispatch – according to this AEMO document:

“ENGIE has advised that half of the Pelican Point Power Station capacity (239 MW) can be assumed to remain out of service …, and that the full power station capacity could be made available within three months, subject to the commercial viability of returning the unit to service”

Update Thurs 9 Feb:

This afternoon we have seen AEMO issue a Direction to a South Australian market participant following declaration of a Lack of Reserve 2 (LOR2) event, and from 15:55 AEST generation at Pelican Point ramping up to around 320 MW, which would be consistent with startup of the “withdrawn” unit. Furthermore comments attributed to AEMO in this media article imply that with early enough notice on the day, startup of this unit might have been achievable on Wednesday – contrary to the statement above.

As an inherently variable supply source, the nominal capacity of wind generation is less relevant than the proportion of that capacity that can be “conservatively” assumed to be available at times of peak demand. AEMO use an assumption of 9.4% in their system reliability studies, and at 5.7% yesterday, wind output was about 55MW lower than this level.

As noted earlier, flows on the Murraylink interconnector were within physical capacity, but in excess of constraint limits.

Overall, this analysis indicates overall available supply capable of supporting demands up to about 3,000 MW under the conditions ruling yesterday. Hence as demand approached the 3,100 MW level, AEMO ordered planned load shedding to reduce demand and thus maintain secure system operation.

What could be seen earlier in the day?

Yesterday’s events caught many by surprise (certainly this observer, exhibit A being I produced a quick post mid-afternoon on Wednesday focussing on the outlook for Thursday 9 Feb and ignoring the outlook for the rest of Wednesday afternoon). Those events were a very unpleasant surprise for South Australians left without power during the peak of the late afternoon heat.

Full discussion of “who should have done what, when?” is not appropriate for this early post, I’ll just use the extent of the demand surprise lurking in AEMO’s on-the-day predispatch forecasts to illustrate the difficulties in predicting even the short term future of the market.

This chart, based on ez2view’s Forecast Convergence tool shows how AEMO’s predispatch forecasts evolved through the day – to partly reduce clutter not all these forecasts, which are updated half hourly, are shown:

Actual demands continued to climb well above successive predispatch forecasts, which never came close to keeping up. Even the forecasts produced relatively late in the afternoon did not show demand approaching the 3,000 MW level discussed above.

For a second, numerical view of this data, we can use the Forecast Convergence tool’s “Grid” view:

Each column on this is for a specific half hour of the day. Each row represents a forecast of half hourly demands out for the balance of the day (latest forecast at the top), with actual values showing on the diagonal. Reading the chart up each column shows how the forecasts for that half hour evolved over the day.

Summary and Conclusions

South Australia effectively “ran out” of secure power supplies due to extreme heat pushing demand to levels beyond that supportable, given wind and system conditions on the day

Rolling controlled load shedding over a period of ~1 hour was used as the last option to keep system supply and demand balanced in a secure operating state

The performance of those generators available on the day, including windfarms, and interconnections, was probably generally consistent with pre-summer planning assumptions

Even on-the-day forecasts struggled to envisage the size of the demand peak ultimately reached, However, given the limitations on supply available at the time, more accurate on the day forecasts may not have changed the ultimate outcome.

Update 9 Feb

The increased output seen on Thursday afternoon from Pelican Point and statements attributed to AEMO may possibly mean that this station’s second unit could, with sufficient notice, have been brought back into service by Wednesday afternoon had the need been more clearly foreseen earlier – although what lead time would have been necessary is uncertain.. This may – stress may – have obviated the need for load shedding.