Transitioning to a Nodal Electricity Market

Transitioning to a Nodal Electricity Market

Published on July 27, 2022

The arrangements which currently govern the commercial operation of the electric power industry in the UK date back, in large part, to the time of privatisation in the very early 1990s.

Simple in conception, if complicated in practice, the main elements included in the final price to consumers is discovered by reference to the price of the unit of electricity that meets the last unit of demand-the so-called “marginal price”. This price is theoretically equal to the maximally efficient price from a competitive Dutch Auction where all participants are paid the price of the highest accepted offer.

Clearing the market at a single market-wide marginal price, with all the add-ons, is under fire. As a pricing model, its fitness for purpose is being critically questioned given that the current market marginal price is set by presently expensive natural gas.

Concerns first hit the headlines in the summer of 2021 when power prices in Spain, with that country’s extreme summer exposure to the importation of “gas priced” power, climbed to levels previously unseen. The recent invasion of Ukraine by Russia and the consequential mandatory and voluntary sanctions resultant from that has amplified the price pain across Europe. While generators have received excess rent, consumers have borne the brunt of the price rises, with no immediate end in sight.

In the UK, the market arrangements debate has taken on an urgency, with the National Grid ESO seeking to evaluate alternative methodologies that might offer a more efficient and economic price to end users.

The focus is on so-called “nodal pricing”. How does this alternative form of trading arrangement work and what might it mean for the significant overlay of spot and contract markets that flourish around current methodologies?

Independent expert and long-time power markets practitioner, John Woodley, joined Energex consultant, Ulrich Arnheiter in a Q and A, with questions being posed by Energex co-founder, Colin Bryce, who was closely involved in trading electricity markets in the UK at their inception post-privatisation.

Q & A

Q: (Colin)– Let me start Ulrich by asking you what is the problem with the current methodology?

A: (Ulrich) The difficulty with the current system derives primarily from the need to address a couple of key characteristics of the commodity itself-firstly the fact that electricity will flow through the path of least resistance and not necessarily where efficient commerce would like to direct it and secondly, the fact that the demand for power and the supply of it is far from geographically contiguous. The result is that further costs must be layered upon the consumer to deal with these inefficiencies along with further environmental taxes and the need for a higher capacity reserve to be maintained to guarantee stability in an otherwise potentially unstable network of supply.

To give an example, during the electricity demand collapse of the Covid 19 pandemic the discrepancy between wholesale and realised end consumer prices widened as system operators struggled to cost-effectively balance their networks and system balancing costs rose sharply. In the GB power market system balancing costs are largely determined by the system operator accepting bids and offers from trading entities to change their level of generation or demand. If demand collapses the gap between geographically dispersed clusters of generation and demand will widen and force the system operator to accept more costly bids and offers in the balancing market to ensure the stability of the network. All this happens within an hour (post gate closure) prior to real-time before other costly ancillary services measures take place closer to real-time such as frequency response of generation units. These costly system balancing and network management requirements are more severe in a network where generation is concentrated in specific regions and less severe in a network with more regionally distributed generation assets. That’s why creating incentives to create less regionally concentrated clusters of generation is important.

Q: (Colin) So Ulrich, who is proposing what in the UK?

A: (Ulrich) Back in December of last year, Ofgem issued a public tender for “Design Options for Nodal Pricing in GB” and then in March of this year, the National Grid proposed locational pricing to avoid excessive costs. In April, the government’s British Energy Security Strategy pointed to consultation in respect of changes to the 2024 CfD auction to “incentivise renewables to locate and operate in a way that minimises overall system costs” and then the same report announced a comprehensive Review of Electricity Market Arrangements (REMA) which was published this July and includes a strong focus on locational pricing issues.

The current system is costly and is not designed for net zero emissions. These high costs are a function of the required balancing mechanism and ancillary services costs. The REMA points out that the current wholesale market trading arrangements which influence those costs were designed for a power system consisting of mainly large fossil-fuelled power generation units connected to a centralized transmission network rather than the distributed power system which is more reflective of low carbon generation.

Q: (Colin) John, we appreciate the opportunity to pick your brains as someone who has been involved in the implementation of Nodal markets in the USA and who has directly traded in these markets. Firstly, can you tell us why the current trading arrangements are inefficient?

A: (John) A national electric market with a single wholesale price is folly. The electric grid is too complex. Many generators and loads are connected to each other by multiple of lines and power, as Ulrich said, flows through multiple combinations of these lines between generator and load. It is common for the grid operator to reduce the output of a high-efficiency plant and replace it with power from a less efficient generator simply to ensure that transmission lines are not overloaded. Injecting power at the wrong location can cause grid costs and emissions to rise. Conversely, connecting a load at the right place can cause grid costs and emissions to go down. The only way to recognise this is to derive the price of power at several nodes in the grid individually. Specifically, this means those injecting power at points that cause overall grid operating costs to rise should be allocated those costs. Hence, the possibility of negative electric prices at certain nodes.

Q: (Colin) So John you didn’t hold back by declaring “a national electric market with a single wholesale price is folly.” Can you explain that in more detail?

A: (John) It’s possible and often happens that a generator delivers power to the grid, but at an inopportune location. At that location, the injection of power causes the operators of the grid to have to reduce power from a low-cost (efficient) resource to a higher-cost (inefficient) resource to preserve grid stability. Economic efficiency demands that the cost of that change be allocated to the cause. Nodal pricing facilitates that. A single grid-wide market price absolutely does not. This occurs in normal grid operations all the time and absent nodal prices, the cost is socialised through a uniformly allocated charge, often called “uplift”.

Q: (Colin) Given that, can you explain how nodal pricing would work in practice?

A: (John) An electric grid typically has thousands of nodes and the grid requires tuning every few seconds. And every node must be individually balanced because inflows and outflows are constrained. It is no coincidence that electric markets were the last “natural monopoly” to be deregulated. A nodal market clears on ex-post prices at each node and load (or generation) are billed (or paid) on a weighted average summed across short time increments. This methodology is now the norm across most US electric markets and those are the most efficient and liquid in the world. The main benefit is that the inequitable tax (the so-called “uplift”) resulting from the hidden inefficiencies of constrained grid dispatch is removed and costs are allocated directly to the associated causes.

Europe has long resisted nodal pricing which is strange since one of the oldest European markets, the Nordic Nord Pool, explicitly acknowledged the need to operate sub-grids, in what would be called a zonal market. This worked in the Nordic case consequent on the dominance of large and flexible hydro resources in that system whereas, in more disaggregated markets, only a node by node approach will suffice.

Q: (Colin) You will be aware that multiple existing contracts are serving the existing trading arrangements, generators and consumers. Would a move to a nodal market not result in contractual chaos consequent on there being a huge number of nodes, many of limited size and effect?

A: (John) It is not as tricky as it sounds! At the outset, several closely connected nodes are chosen which are generally representative of a large localised load centre in the existing market. This becomes a market “hub” where most liquidity concentrates. As in all commodity markets, the advice is “hedge the waves first and then the ripples.” Major moves in the overall environment are mostly fully captured in the traded hub markets.

But electricity is a second-by-second balancing act. Gas can get by with hours of storage in the pipes, oils with barrels by the million in flexibly dispatchable tankers. Electricity is local and must be matched second by second. The day ahead market clears by the hour for the next day based on participants’ bids for power or offers to supply. The grid operator then examines and accepts/rejects based on the maximisation of the economy in light of the physical constraints. Participants who have bids/offers accepted are committed and are, as such, exposed to real-time ex-post prices should they deviate. Deviations are reviewed by the regulator to ensure against market manipulation. A virtual market effectively overlays the day ahead market where day ahead can be bought or sold naked to be settled at real-time outturn price, again with regulatory scrutiny for outsized positions. Those players involved in this activity need to understand that to motivate more load or less generation at a node, prices can trade into negative territory (for the right reasons as opposed to currently where they represent price distortions). As such, nodal markets exhibit volatility to the downside as well as to the upside, the latter being more regularly seen in marginal price markets, to the detriment of consumers.

So, to answer your question on the possibility of contractual chaos, bear in mind that in markets that are already operating under nodal pricing, provision is made for the overlay of contracts known as Financial Transmission Rights (FTRs) and Auction Revenue Rights (ARRs). FTRs financially settle based on the price difference between a pair of nodes. Existing participants are granted FTRs based upon the differences between their node and the market node to insulate historical volumes against nodal price differences. Any change a generator or load consumer makes in response to local node price will create a benefit, but the FTR pays out as if they had not made the change. So FTRs are very similar to swaps and represent a hedge against being unable to access the revenue from physical delivery to a higher-priced node in circumstances where a player’s local node offers a lesser return. Regular FTR auctions are held by the grid operator where participants can fine-tune and speculators can add liquidity.

Q: (Colin) It seems clear that a nodal system should find a purer, if perhaps more volatile, price and that, consequently, the cost burden for ancillary services/ use of system /uplift etc can be minimised via these price signals. What of trade ability?

A: (John) Liquidity tends to develop in nodal markets at key larger nodes so liquidity gets concentrated rather than dispersed across all the minor locations. The PJM market on the East Coast of the USA is a nodal market and the PJM Western Hub is probably the most liquid power market anywhere in the world.

Summary: (Colin) Thank you both for your time. Despite the difficulties associated with the present market arrangements and the allegation that they have been “gamed” since Day 1, it seems that leading energy companies are set to oppose reforms, as revealed by Emily Gosden in the Times newspaper in April of this year. She quoted one senior energy source as saying that the proposals for nodal pricing constituted “hideously complicated reforms”. Yet they work well elsewhere, lowering costs through the impact of more pure price signals and the enhanced hedge ability consequent on these changes.

Perhaps the alternative is to build significantly more network links, with the consequent above-ground environmental issues that ensue. With this genie out of the bottle and the prospect of long-term fuel cost pressure and the distribution of renewable power generation detached from the location of load, there is a certain inevitability that change is coming.

And it is to transition issues that we will return to in a future article.