Wholesale Power Pricing Basics - Episode 110

As more corporations are using Power Purchase Agreements (PPAs) or Virtual Power Purchase Agreements (VPPAs) to procure renewable energy, these contracts are exposing companies to the risks and variabilities of the wholesale power market.

In this episode, Paul zeroes in on how the pricing of power in wholesale markets works so that we can start to understand, and manage, those risks.

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Transcript

This is Eight Minute Climate Fix – a podcast helping you understand the energy and climate challenge in just a few minutes – I’m your host, Paul Schuster

The power market is complex. Most of us will never need to worry about the thousands of details that make up the price on our utility bill – but for an increasing number of corporations, meeting renewable energy commitments means getting much deeper into how the power market, and specifically the WHOLESALE power market, works.

I won’t be able to dissect all of the nuances of the wholesale market, but, in eight minutes today, I’m hoping that I can cover how the power pricing model in wholesale markets work, and the risks that companies may be exposing themselves to when negotiating PPAs, VPPAs or other contracts that participate in this wholesale market.

Eight minutes – it’s how long it takes the sun’s rays to hit earth, or, about how long my kids enjoyed being back in school this week! I’m kidding – they were grumpy from the moment that 6 AM alarm kicked off. Mom and Dad, though ….

Let’s get it on!

The price that you see on your electricity bill is what is called the retail rate for power. It includes not only the cost to generate the power in the first place, but also the utility charges around transmitting and distributing that power to your home or business.

Now, there are a lot of retail considerations that factor into how those prices are calculated. Things like the amount of investment capital that regulators allow utilities to recover through rates or incentive programs like EV or Energy Efficiency rates.

Those are all on the RETAIL side of the ledger. They are adders or modifiers to the core cost of power, which the utility or retail electric provider that you use has to go out and buy.

Now, prior to 1978, utilities would have owned the majority of the vertical value chain to deliver power – everything from the power plant to the transmission lines to the utility poles and the individual house meters.

In 1978, The Public Utility Regulatory Policies Act (or PURPA) came into effect, which opened up the opportunity for third parties to build generation and sell their power to utilities on the wholesale market. Utilities were more than welcome to build and operate their own plants – but PURPA now created competition where the lowest cost option would need to be used – putting a major kink in what HAD been monolithic monopolies prior to that.

PURPA supercharged the need for a wholesale market for power, and it’s probably not surprising that as we’ve become more sophisticated with how the market works, it’s become a LOT more complicated, too.

Even in just the basic pricing of power, to begin with. One of the really unique challenges to power is that it has to be consumed AS it’s being generated – there isn’t a lot of storage on the grid, yet, to where we can inventory excess supply and save it for a rainy day.

Technically, that means grid operators ramp generation up and down all of the time in order to adapt to changing demand conditions. And they primarily do that by sending price signals to generators to get them to react in certain ways. Demand spikes and we need more power quickly? - well, then, increase the price of power in the short term so that more generators will come online and produce more electricity. Or vice versa.

So, first thing to understand is that power prices are always changing. And if we had PERFECT forecasting, we could simply set a different price at every second or minute or so and expect the market to respond properly. 

But, we don’t have perfect foresight, so we actually use a few different increments of time to price power – combining all of them to both finalize the actual cost to the energy provider as well as provide economic ways to hedge the risks around inaccurate forecasts.

For instance, we have something called a day ahead rate where the power needs for the next day are modelled out based on expected weather, major events, etc. and the grid operator seeks bids on what generators are able to provide, and at what price, for each HOUR of the subsequent day. 

This is a forecast. A day ahead, hour by hour forecast of prices based on expected demand and supply conditions. It’s one that we know will be wrong but we’re all hoping it’s relatively close to what the reality is likely to be tomorrow.

When we talk about power purchase agreements or virtual PPAs that utilities or even, increasingly, large corporations are signing – it was often based on this day ahead rate.

But that may not be the ACTUAL price of power. See, once tomorrow arrives and demand starts to fluctuate, real time conditions are likely to be different than that forecast. And the pricing that SHOULD have been used may be different than the pricing that was designated in that day-ahead rate. The difference between the two, between day-ahead and real-time is something called the DART spread – literally an acronym for Day Ahead Real Time.

Those PPAs that I talked about earlier? Hopefully those companies are taking into account their exposure to that DART spread – ‘cause it’s not nothing. Understanding and managing that risk MAY be important …

DART handles a bit of the temporal, time variability – the power grid also encompasses huge geographic footprints where a LOCATIONAL variability needs to be considered as well. 

Smaller grids can sometimes get away with calculating a singular clearing price for electricity across the entire grid network. That’s a pool program and is basically the model that the UK uses for their wholesale market. Essentially power generators bid in on a daily basis and the grid operator accepts the lowest bids, adding up capacity until they meet expected power demand – and whatever that marginal price was where supply met demand – THAT is the price that EVERYONE gets, regardless of location or generator type.

In the US, we do things a bit differently, as we have developed an interconnected series of nodes. Each node is where power is either generated or transformed or consumed – so places like power plants or distribution points.

And there’s a different demand profile at each node – as well as a different supply profile. The grid operators can adjust the price signal at each node to incentivize either increasing supply or decreasing supply to meet demand – something called Locational Marginal Pricing - LMP. This can be a lot more complicated than the power stack model that the UK uses, but it has a lot of benefits, too – for one thing, it can better signal to individual generators to take certain actions while also protecting consumers from price mismatches that could cascade throughout the entirety of the grid.

One thing to note is that LMP is not the same thing as time of use rates. You may have heard of how time of use rates are being tested and utilized in different markets to incentivize consumer activity at different parts of the day – for instance by offering lower rates to run your dishwasher at night or EV rates that are aligned with off-peak charging hours in order to keep all of those Teslas from plugging in at the same time. Sounds a bit similar to LMP as they both change rates at different times of the day.

TOU rates, though, are incentive based toward the CONSUMER – looking to incentivize the demand behavior. And they are a fixed rate – regardless of actual supply or demand conditions at the time, the TOU rate is a RETAIL rate that has been established to drive consumer behaviour. 

And while Locational marginal pricing CAN influence demand, it’s a WHOLESALE pricing mechanism that is reactive to the actual conditions on the grid. It’s designed to balance the grid, not, necessarily, to get more people to buy EVs.

Now, because LMPs are calculated at each node, there is an element of locational risk that needs to be considered within wholesale market contracts, as well. This is called basis risk and is the risk that the price at the node where a contract is settled may be different than the price where the power is being generated or consumed. 

More corporations than ever are looking to meet renewable energy commitments by purchasing power on the wholesale market – but that doesn’t mean it’s a one-to-one match with what there are paying on their retail bills. There’s the temporal risk around the day-ahead vs. real-time variability. There’s the locational, basis risk of where the PPA contract is being settled at versus where the power is being consumed. There’s even a retail rate vs. wholesale rate risk because retail rates may be FIXED … while the wholesale contract may be vary.

Understanding those risks is vital to a well-structured renewable energy contract. Too often, corporations are willing to sign these big deals without a full analysis of these risks – assuming that this is the quote, unquote “cost of sustainability”. But it doesn’t need to be. It just needs to be understood, modelled and prepared for just like any other financial transaction that the company takes on.

I’m Paul Schuster – and this has been your eight minutes.