This is part 1 of a two-part blog articulating the view of Jonathan O’Sullivan of the Eirgrid Group, which has TSO responsibilities for the systems of Ireland and Northern Ireland. The view encompasses how the industry evolved to its current state, and where it needs to go from here to satisfy the goals and needs of electricity customers and society. Part 1 offers an original view on what customers really want, while Part 2 offers a thoughtful perspective on how Eirgrid plans to provide it.
The Physics and Economics of AC Power Systems
Electricity is a relatively new invention, with the large-scale roll-out of three-phase alternating current power systems occurring in 1896. The seminal event that sealed the decade-long battle between the Thomas Edison–inspired direct current (DC) and the Westinghouse-backed Tesla alternating current (AC) was the powering of the World Fair in 1901 in Buffalo, New York, by high voltage machinery 120 km away in Niagara Falls. From that point on, the large conglomerates of Westinghouse and General Electric agreed to roll out three-phase AC technology. Since then, there has been an estimated $140 trillion worth of investment in this technology worldwide.
From an economic perspective, the businessman Samuel Insull (a former pupil of Thomas Edison) in 1896 recognised that there were large economies of scale in three-phase power systems and strenuously argued (successfully) for monopoly utilities with regulatory oversight. This became the dominant model that powered the roll-out of three-phase electricity across the globe. Essentially, the model was for regulated utilities to build assets which increased their asset base on which they got a reasonable rate of return. The source of the monies to pay for these allowed monies would come from the consumers, who were to be charged on a unit price basis with a standing charge. The model of a unit price with standing charge is still prevalent today in users’ bills worldwide.
By the 1970s, the benefits of economies of scale had largely come to an end, and some of the issues created by these monopolies were beginning to outweigh the benefits. In the deregulation of utilities in the late 1980s and early 1990s, energy was considered a commodity, and a better outcome for consumers would be brought by competitive markets. To this extent, all market designs—whether pool or bilateral, gross pool, zonal or nodal—are all based on determining the marginal cost for energy or energy balancing. The implicit, but never stated, assumption is that energy is a good proxy for the utility of the value provided to the consumer: the more energy used by a consumer, the more value the consumer is supposed to have received from the utility. However, if energy is not a good proxy for value, the market will not efficiently meet the needs of individual customers or of society at large.
Why Energy Markets Appeared to Work When First Introduced
When markets were first introduced, they relied on the marginal price of energy being sufficient to cover the variable costs of the generator (usually a combined-cycle gas turbine). As long as each generating unit was a little more efficient than the last one and there was super normal profit on every MW generated, this was more than sufficient to make an investment decision. In addition, the capital cost of the combined-cycle gas turbine was a small part of the overall lifetime operational cost. Being slightly more efficient than the last unit was a long-term insurance policy to enable an investment where the return would be over 15 to 20 years.
There was also a need to meet grid code standards. While never explicitly stated, building new synchronous combined-cycle gas turbines that met grid code standards ensured that there was sufficient portfolio capability to meet a range of possible issues on the power system. These included generator trippings, fault current during an event to trip protection, and synchronizing torque to bind generators to the same speed. Fundamentally, these capabilities ensured that the resilience of the power system—its reliability and stability—was a by-product of investing in combined-cycle gas turbines; the energy market with energy as a proxy for customer utility appeared to work. The only slight concern was for providing operating reserves and adequacy margins. In this regard, the economic theory considered these services as provided in some way at the opportunity cost of energy. Ancillary service and capacity market designs generally reflected this opportunity cost in some way.
In short, the energy market as proxy for the utility of consumers’ value, combined with basic grid codes, ensured that affordable energy for citizens could be delivered while ensuring that what I refer to as the resilience of the power system could be maintained across a range of possible issues that could arise.
Why Change If Energy Markets Have Worked Since the Late 1980s?
With the advent of large-scale renewable generation, there are fundamental changes to financial and technical characteristics of power systems. First, the investment requirement moves from one that is predominantly paying for operating costs to one that covers capital. In a market dominated by the marginal price of energy, as more low-marginal-priced variable-output generators enter the market, the energy price will trend down and become more volatile. This will not be able to support the capital investment required to meet the renewable energy transformation.
In addition, the resilience expected by society from electricity systems changes. The exact changes are specific to each individual power system; however, generally, as more renewable generation (variable, non-synchronous solar and wind) comes onto the system, it will displace fossil-fuelled synchronous generation, and this changes the stability and reliability characteristics as follows:
- Electromagnetism is reduced, thereby inducing a range of instabilities and reactive power control issues
- The source of traditional operating reserves needs to change away from conventional plant to new technologies
- Uncertainty increases compared to that of a fossil fuel plant, as there are forecast differences for different energy sources, and also differences in the range of services that meet this resilience need
Therefore, the existing energy markets cannot in themselves support the necessary financial change required to make the renewable transformation that public policy wants. Nor, even if they could, would the power system with large-scale deployment of renewables be sufficiently reliable to meet the expectations of the consumer.
In short, with the advent of large-scale renewable generation the energy market does not meet the long-term utility of the consumer or the need of society as expressed in public policy objectives.
How and Why Might We Change the Market?
In seeking to change the market, there is an interesting anecdote from when Thomas Edison heard that Samuel Insull had decided on a unit price of energy and a standing charge bill structure to the consumer. He is alleged to have said, “But I am selling light, and next year I will have a more efficient light bulb!” Back in 1896, Thomas Edison was effectively questioning the sanity of using energy to value the utility that was being obtained by customers. He was easily able to get hundreds of dollars per year for lighting Pearl Street, and yet with positive advances in technology the bill structure over time would see his profit eroded.
Which got me thinking, “What is it that the consumer really wants from electricity?” I certainly never think about electricity when I am home, but I use it ever second of every day. What am I going to cook, what am I going to watch on TV? I have an alarm clock to wake me up, I have a refrigerator and freezer. I also have an implicit expectation that the electricity is guaranteed to work when I want it to, even if I change how I use it radically, unless there is an exceptional issue—big storms, a major outage in the area. But these interruptions to service are rare and need to be for very short periods of time.
So, really, I want electricity to make my life easier. This means I need affordable electricity and a guarantee that it works when I want it to. This guarantee is what I call the resilience of power systems (certainly in a world where off grid is a negligible proportion—a reasonable assumption until at least 2050 in Europe).
Why Have We Never Before Really Paid for Resilience? And Why Start Now?
Traditionally, synchronous generators (generally combined-cycle gas turbines) have been the new investment of choice. This meant that more and more electromagnetism, and certainty, was being added to the system with every new generator. Despite the fact that old ones were retiring, this did not fundamentally alter the fact that there was excess electromagnetism and certainty. Operating reserves and resource adequacy came as by-products of part loading generators designed to operate at full load. The remuneration mechanisms for these services were based on commodity principles and effectively priced in some way as the lost opportunity cost. The values for operating reserve provision were generally small (less than 2% of revenue) and generally only seen as upside for the equity investor.
But in the world of high renewables, there is a range of technical scarcities that arise that need to be solved if the consumer’s utility is to be maintained. The operating reserves and adequacy will need to be replaced with new technologies such as storage and demand-side management, which are not built to provide energy as combined-cycle gas turbines were. But it also critical that projected technical scarcities in electromagnetism and certainty do not lead to impacts on consumer utility. These have been the basis of the success of AC power systems since their inception and have never been considered scarce before. But in a world of high renewables, this changes.
In part 2 of this blog post the author discusses how Eirgrid plans to provide grid reliability in a high-renewables world.