Deregulated electricity markets don’t support a viable energy transition

In the early 1990s, deregulating electricity generation seemed like a good idea.  Led by the UK, many markets rushed to dismantle their vertically integrated electric utilities with the goal of creating competition to benefit their customers, the electricity using public.   The view was that utilities had become fat and lazy and since they were mostly able to pass on their costs through a regulated pricing system, they didn’t do their best to keep prices low.  Competition would remove the fat.

Fast forward 30 years or so and much of the world has followed this path.  There is a large relatively integrated European electricity market, the UK continues to operate its market and there are multiple states in the United States that operate this way.  But is it working – and of more importance – is this the right path to support the transition to a low carbon energy system?

To fully answer this question is a subject that requires a much longer discussion than is possible in a blog post.  We will address some of the issues and explain why we believe large scale market redesign is required.  For another excellent perspective we strongly recommend the book “Shorting the Grid” by Meredith Angwin that clearly explains how the current US deregulated model is failing the customer while reducing the reliability of the electric grid.  Read it – please.

The original concept was sensible.  Create competition in the electricity market to force electricity generation companies to become more efficient (In most cases transmission and distribution were not deregulated).  It seemed to work in telecom.  Why wouldn’t it work in electricity generation?  And at the beginning it did work.  Government owned electricity companies were sold off and broken up.  New generating companies competed with existing companies and yes, the result was improved operations of the existing generation fleet.

The markets were mostly created as energy markets, where generators competed on marginal cost of production (variable operating and fuel costs) in basically real time markets to sell electricity.  All that mattered was the price of electricity at any given moment.  This was happening at about the same time as gas was ascending to be a major player in electricity generation both in the US and in the UK.  Each generator would bid into the market at its marginal cost.  The market would accept bids at the lowest cost available and continue to accept higher prices until the demand was met.  The market price was the energy cost of the last generator who bid, and all participants received this price (the clearing price).  When demand was high, the last bid accepted was usually gas generation which has the highest marginal cost of production and this price seemed to be enough to keep the other players with lower marginal costs but higher fixed costs content. 

Then three things happened that started to change the equation.

First, at least in North America, the price of gas fell dramatically so that the only technology actually making money were gas generators.  Their marginal cost had become very low given the low cost of gas and other forms of generation could no longer survive at that price.  Hence the current situation where nuclear plants are closing before their end of life as they struggle to compete at very low gas prices.  The US government has just launched a $6 Billion program to help save these plants.  Market supporters may say – who cares?  The market is the market.  If gas plants are the lowest cost, then just run gas plants.  And yes, that is certainly an option if a single source electricity system based on 100% gas is deemed acceptable.  But if the objectives of the system are broadened to include diversity of generation for security purposes or to mitigate the risk of volatile fuel prices (yes, gas prices can and do go up), or to lower carbon emissions, then change is required.

Second, having an energy market only made it impossible to build new capacity.  Since everyone was operating on marginal cost, there was no possibility to recover full costs – which is needed to support new plant investment.  The solution was to create capacity markets.  Payments would be made for capacity based on a bidding process so that low-cost capacity would be added to the system.  Once again, in most jurisdictions, gas came to the rescue.  The cost structure of a gas plant is just right for this type of market.  The capital to build a plant is relatively low.  Once the capacity is paid for, you only operate the plant when the energy is needed, at an energy cost that covers the marginal costs (which is primarily based on the cost of fuel).

The issue with this market structure is that gas generators were always price makers, and all other technologies were price takers.  In other words, the business of electricity generation for all other technologies became a competition with gas.  While these technologies made or lost money based on this competition, gas generators were always whole, no matter the price of gas.  In effect, gas generation is pretty much a risk-free business in this market structure.  Consumers are happy as long as gas prices are low – but will be very unhappy when prices rise.

Next, countries committed to decarbonization goals and started to support adding low carbon electricity, primarily intermittent variable solar and wind power on the system.  To get these to work, subsidy was required both for price and to ensure the market takes the output of these resources when they produce, when the sun is shining and the wind blows.

To keep this story short, this structure made it near impossible for any other technology than gas or subsidized renewables to be built.  Other projects were just too risky, especially those technologies like nuclear power where the bulk of the cost of energy is based on their capital investment.  Even though a nuclear project is projected to be economic, once built, the price of the alternatives may change in the future so that the plant becomes unprofitable.  Or in other words, no matter how successful and low cost the project, the risk of having to compete with daily changes in gas prices would be unmanageable.  The solution was once again to contract outside of the market.  Power purchase agreements, contracts for difference (Hinkley Point C) and other approaches were developed to support these types of projects.  The result, more complexity, and complexity tends to increase costs.  That is why we see the Sizewell C project in the UK moving to a Regulated Asset Base (RAB) model, to simplify the project structure and keep costs lower.  (We will talk about this model in a future post.)

The reality is that data from the US DOE Energy Information Administration (EIA) show that customers do not benefit from these market structures.  2020 data shows that customers in deregulated states pay on average about 23% more for electricity than those in regulated ones.  And while most states remain regulated (about 32 to 19), when you consider the actual amount of generation under both regimes, it is much closer to half of US generation is deregulated and half regulated.

Back to the point of this post.  If you want to ensure grid stability, the markets need to change.  If you want to encourage diversity of generation, the markets need to change.  But most of all, a completely new structure has to be developed because the low carbon options (wind, solar, nuclear, hydro) have relatively high fixed costs and near zero marginal costs making an energy cost based market unworkable. For these forms of generation, a market structure based on recovering fixed costs is required. 

If we really want to work towards net zero carbon emissions, now is the time to re-imagine how we are going to generate electricity and pay for it.  One thing is certain.  The existing deregulated model in place in many jurisdictions will not take us where we need to go and the longer we take to accept that, the longer it will be to reach our carbon goals.