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  • Written by Mike Sandiford, Chair of Geology & Redmond Barry Distinguished Professor, University of Melbourne

In the third in my series on the crisis besetting the National Electricity Market (NEM) in eastern Australia ( see Part 1 & Part 2), I look at some evidence for how the market itself has played a role and specifically market power issues.

The recent troubles in our electricity market are well documented. As described in my earlier pieces in this series, two elements have focused the attention of our political masters and industry groups.

The first is the question of security, highlighted most dramatically by recent “black outs” in South Australia.

The second is the question of price, with both wholesale and contract market prices having risen dramatically across most regions in recent times but nowhere quite as dramatically as in Queensland (note that retail prices have also been rising as highlighted by the recent Grattan report).

While a tightening of the demand-supply balance in Queensland in response to an additional ~800 megawatt load from the massive CSG field developments and LNG export processing facilities partly explains the rise in wholesale or pool prices there, it is far from the full explanation.

Lurking in the details are issues to do with the very functioning of the market, and the exercise of market power by large generators who have, and continue to, exploit monopoly rents.

As described in the earlier posts, the NEM market is designed to signal changes in the balance of demand and supply via spot prices. But how much the spot prices respond is very dependant on the level of competition.

Recent experience of market participants flouting the spirit of the rules shines a light on competition issues and highlights a rather obvious, if somewhat trite, reality. That is, the benefits of competitive markets can only flow if markets are competitive.

The exercise of market power has been a perennial issue in the NEM. It is the role of the Australian Energy Market Commission (AEMC) to set the rules that allow for safe operation of the electricity network, and efficient operation of the market. It is the job of the Australian Energy Regulator (AER) to do the enforcing, while AEMO operates the market.

The AEMC periodically adjusts rules so as to minimise the impact of perceived or real anti-competitive behaviour. It did so most recently in December 2015 with the Bidding in Good Faith rule amendment because, to quote:

… The Commission considers that the current rules do not set adequate boundaries on the ability of some participants to influence price outcomes to the detriment of others. This is not reflective of an efficient market.

The statement “ability … to influence price outcomes” is key. It expresses AEMC’s concern that some participants have sufficient market power to extract so-called monopoly rents.

To understand why the particular rule amendment was introduced, we need to go back to the two important intervals on which the market operates, the dispatch interval and the trading interval.

The dispatch interval is where the physics of the power system meets the economics of the market.

The necessity to balance generation and demand in real time, requires a dispatch pool with an objective of serving the demand at minimum system-cost. Functionally, our energy market operates by pooling offers from generators and allocating dispatch for each five minute interval in order of increasing offer price.

A generator offer specifies the price at which a given quantity of electricity will be supplied into a given trading interval, if needed. The dispatch price is set by the last (highest-price) offer needed to meet the dispatch interval demand. All generation dispatched receives the same dispatch price, regardless of the offer price. Offers at prices above the dispatch price are not needed and so receive nought.

The theory is that, in a perfectly competitive energy-only market, generators will offer the majority of their capacity at their short run marginal cost, like that shown below for Victorian generators.

image Short run marginal cost of Victorian generators, stacked from left to right in merit order of increasing marginal cost. The x-axis shows the cumulative nameplate capacity of the lowest cost power plants in megawatts. Because renewables such as wind have zero fuel cost they stack on the left side of the merit curve. Contrawise, gas and diesel generators stack on the right. Image by Dylan McConnell.

In practice, individual generators apportion their capacity into a range of different price bands. They are then allowed to rebid the capacity into different price bands at short notice as part of the mechanism for making rapid adjustments to unforeseen circumstances that periodically arise in the normal course of events. AEMC’s Bidding in Good Faith rule amendment requires a justification for any late rebidding within 15 minutes of the start of the relevant dispatch interval.

As a deregulated market, optimal bidding is insured primarily by the discipline of competitive forces. It goes without saying, that without adequate competition, there can be no such insurance.

The other key interval is the half-hour trading interval or settlement period, across which dispatch prices are averaged to obtain a settlement or spot price, so called because it is the period on which financial payments are settled.

Since demand normally varies only slightly across a given half hour trading interval there should be little difference in the dispatch prices across the six corresponding dispatch intervals and the settlement price, especially when averaged over many trading intervals. In an efficient market with generators offering the bulk of their capacity at near their short run cost, this trading interval averaging should not materially affect the financial outcomes of the market. A necessary, though not necessarily sufficient, signal of the efficient operation of our market will be independence of dispatch prices or revenues on dispatch interval.

As shown below, January 2016 provides an illustrative case. It shows the dispatch prices for each dispatch interval averaged across the month. The narrow range of variation across each of the four regional markets that define the mainland part of the NEM, meets the expectation of a well-behaved market.

image Average prices for each of the 5 minute dispatch intervals that make up the half hour settlement price for January, 2016. Prices are relatively constant across all intervals as expected in a well-behaved market, trading in an interval of about $10-15 per megawatt hour, for all four regional markets that define the mainland part of the NEM. Note the period is the month following the Bidding in Good Faith rule amendment by the AEMC in December 2015, The good behaviour of the QLD1 market contrasts strongly with the same periods in the previous and following years as shown in the following diagrams.

There is no compelling theoretical or practical reason for the exercise of a half-hour trading interval, it being something of a historical artefact. However many of the operators of our large generators seem to love it (as witnessed by submissions to a proposed rule change that would dispense the trading interval).

Why so? The cynic would say because the current arrangements have afforded a convenient guise to engage in profiteering. For example, by rebidding capacity into higher price bands late in a trading interval, settlement prices can be raised, materially distorting the market because other participants do not have time enough to respond. While such a creative compliance would in theory only impact un-contracted customers trading directly on the wholesale market, any resulting price increase will eventually pass through to the contract markets thereby affecting all customers.

Does it happen? Well the AEMC certainly thought so, enough at least to amend the Bidding in Good Faith Rule in December 2015.

The AEMC was particularly concerned that such practices were impacting market outcomes in Queensland. The smoking gun lies deeply buried in the details of the offers and rebids. But the pointers are quite apparent, as shown in the figure below which covers the month of January in 2015, prior to the AEMC’s rule amendment. Rather than average price, it shows the wholesale revenue by the 5-minute dispatch interval (the two are strongly coupled and their graphs are identical twins). The striking feature is the asymmetry in Queensland (QLD1) revenue distribution, increasing very substantially across the last two dispatch intervals, compared with the earlier intervals. A crude estimate of the excess revenue generated by the anomalous, or inefficient, market behaviour is given by the sum of the differences between the dispatch interval prices and the lowest average dispatch interval price for the period. As noted on the right, in QLD1 it amounted to some 30% of total market value, or ~ $200 million for the month.

image Notional wholesale markets revenues for 5 minute dispatch intervals for January, 2015. The figures on the right correspond to the total market revenue for the month, and (marked with a +) the anomalous revenue given by the sum of the differences between the dispatch prices and the lowest average dispatch price. The latter is a guide to distortion that can be attributed to noncompetitive market forces - about $200 million, or 30%, for QLD1 in this case.

Given the magnitude of the anomaly the AEMC’s interest in a rule change is hardly surprising. To quote from their rule determination:

… the price volatility that arises from deliberately late rebidding … [is] … estimated to have added around eight dollars per megawatt hour to the price of caps in Queensland in the final quarter of 2014, and around seven dollars per megawatt hour in the first quarter of 2015. Across the market, this represents additional expenditure of approximately $170 million.

The AEMC noted also that

… While it is not guaranteed that the changes to the rules will put an immediate stop to the conduct of concern, they are a proportionate response to the issue, and ought to make it easier for the AER compared to the current arrangements to take enforcement action in respect of deliberately late rebidding. At the same time, they should not prevent rebidding in legitimate pursuit of commercial interests.

Did it do so? The AEMC and AER may well have been well pleased to see the initial response to its new rule determination in data such as for January 2016 shown above. However I suspect they will be concerned by the figure below, for January 2017. Essentially it is the mirror image of the January 2015 scenario, seemingly implying QLD1 generators are now initially bidding in capacity into elevated price bands in the early dispatch intervals. Conceivably, they may be rebidd capacity down to more normal values later in the trading interval, though that is moot since whatever the strategy it is achieving an identical outcome to 2015. Even if entirely within the rules, it would seem not in the spirit. The substantive result would appear to be situation normal in Queensland, with a $225 million monopoly rent extraction at the expense of electricity customers for this past January accompanying unprecedented spot price rises.

image Notional wholesale markets revenues for 5 minute dispatch intervals for January, 2017. It is notable that it is almost the mirror image of January 2015 shown above, an example of creative compliance by QLD1 generators following AMEC’s Bidding in Good Faith rule amendment of December 2015. Note also the almost doubling of January revenues since 2015.

There is such a lot to be said about this, and hopefully it will be. It is but one, easily illustrated example of the exercise of market power. There are others, as for example described in the notes below. From the perspective of this discussion it is illustrative of significant deficiencies in the current operation of the NEM. Those deficiencies are exacerbating our current energy crisis. A concentration of market power is adding materially to costs especially, but not only, in Queensland.

It is worth noting that the half-hour settlement period is currently under review by AEMC and will likely be scrapped against the wishes of most established operators, or so it would seem judging from their submissions to the review. (As Dylan McConnell has shown, the current rules also seriously disadvantage the economics of a number of emerging technologies such as battery storage, hindering innovation that would serve much needed competitive discipline into the market.)

Whatever is decided by AEMC, the underlying issue of market power cannot be addressed by tinkering with the rules. And it is only getting worse as old power stations such as Northern in South Australia and Hazelwood in Victoria are closed. In the wake of such closures lies an even more concentrated market. For example, following closure of Northern, AGL’s proportion of registered capacity in South Australia increased 4% points, from 35% to 39%, improving its relative market power by more than 10%.

image Percentage of registered generation capacity by participant in South Australia (top) and Victoria (bottom), both before and after the closure of the Northern (NPS) and Hazelwood (HPS) Power Stations, respectively. Note that Hazelwood is still operational at the time of writing, but is scheduled to close at end of this month (March, 2017). In both instances AGL’s relative market power has, or will be, substantially improved by these closures, by over 10% in relative market power terms. This increases the likelihood of AGL being a necessary or pivotal supplier, as it’s was in July 7th in the first of the South Australian energy crises of last year as described briefly in note [1]. Only the biggest seven participants in each state are shown.

With AGL in a position of great market power following the closure of Northern, it played its hand ruthlessly across July 2016, during the first of the South Australian energy crises as summarised here and described in more detail here (see Note [1]). With the closure of Hazelwood in a few weeks, AGL will again be the beneficiary of increased market share in Victoria, to a similar margin as it was in South Australia. That will increase the likelihood of AGL being a necessary or pivotal supplier in future high demand events in Victoria. How AGL responds will be a key to how steeply prices rise in Victoria and neighbouring states.

Like with any industry, our electricity generators have shown adeptness at exploiting the opportunities availed by the market rules. In so doing they have contributed to the price outcomes that are helping provoke our current energy crisis. One could only wish they turned such “innovation” to helping drive our energy system to a place we need it to be, that is secure, affordable and with much, much lower emissions. To be so guided, our market rules will have to be radically reshaped to be more aligned to the national interest, explicitly including all three elements of our energy trilemma, and ensuring adequate levels of competition allow the benefits of the deregulated market flow to all participants.

Sadly, as our energy crisis has unfolded, partly in response to the need to address its emissions intensity, emissions have begun to rise again. Just by how much we do not know, as I will discuss in the next piece in this series.

Notes

[1] In our analysis of the July 7th event in South Australia, we analysed the extent to which AGL bid capacity to high price bands (typically the market cap price) for the Torrens Island A Power Station. We also looked at the proportion of capacity that was available below and above $300/MWh. In aggregate, Torrens Island A offered its entire capacity to the market at less than $300/MWh 96.5% of time in 2015. For the remaining 3.5% of the year (or about 300 hours) some capacity was pushed into high price bands. Our analysis shows a correlation between periods of high scheduled demand and Torrens Island A’s bidding of capacity into high price bands. The proportion of time when some capacity was priced above $300/MWh is clearly skewed to times of high scheduled demand. In 2015, for the top 10% of scheduled demand periods, the amount of time some capacity was bid into these high price bands was 16.7%. For the top 1% of scheduled demand periods it increased to 35%. On July 7th 2016, it is clear is that Torrens Island had bid an unusually high volume of capacity at the market price cap, at a time it was needed to ensure supply as a pivotal supplier, consistent with exercising market power. While there is nothing in the rules to prevent this, the lack of appropriate competitive discipline means significant market distortion accumulated.

Authors: Mike Sandiford, Chair of Geology & Redmond Barry Distinguished Professor, University of Melbourne

Read more http://theconversation.com/the-anatomy-of-an-energy-crisis-a-pictorial-guide-part-3-73693

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