Optimizing, Balancing and Pricing Power Supply and Demand in ERCOT
On February 21st I posted a summary online of the policies and physical workings of the electricity market in Texas managed by ERCOT. The purpose was to allow non-energy folks to understand the basics of a very complex industry and where shortcomings may have occurred across the state. During our power outages. A lot of thoughtful people on FB and LinkedIn provided positive feedback on the first summary, and some suggested I might attempt to explain power pricing in a follow-up. So here goes. For those in the industry who read this, I again welcome all suggestions, clarifications and edits. I want to get this right – but keep it simple enough for a layperson.
Executive Summary (also known as the impatient reader paragraph) to explain high prices
ERCOT’s competitive electric market relies on an “energy only” model. ERCOT operates a power exchange similar to a stock exchange where power is bought and sold, but the exchange is limited to power purchases and sales in the Texas ERCOT region. Like a stock exchange, assurances of payment are required real time or on short notice. Thus, money must be on hand at all times when prices are volatile. The volatility from Uri was unprecedented and caused shortages of money.
Power plants offer power for sale into the market every 15 minutes, 24/7, and the lowest priced offers are chosen to run. Higher priced offers do not run (unless extreme scarcity requires it). The model relies on adequate supplies to meet all demand. When supplies run low and demand grows closer to exceeding supply, an automated pricing system on ERCOT’s power exchange takes over pricing to incentivize power plants to run. The high prices also signal to big industrial users to reduce consumption or shut down (sometimes being paid to turn off) to keep the electricity grid stable. That automated system ramps up from normal prices of $30 to a $9000+ per MWh price.
Past weather events lasted a few hours; the February event lasted days at these price levels. The extreme weather caused shortages in supply that forced all sellers of power to purchase more at extremely high prices to meet demand. Those sellers had agreed to sales at normal (low) prices, so sellers were financially upside down on those quantities of power. Defaults have already occurred, and more are expected.
There are many nuances to this explanation, but a severe shortage of supply and record demand for electricity resulted in high prices that could not be recovered immediately from customers.
The longer, slightly more complicated version
Current market and future expectations – my take
Texas enjoys the finest electric market model in the world, despite the severe event of February. Many countries dispatch people to Texas to learn how our competitive electric model works and how it came to be. I have met with power professionals from Mexico, Australia, New Zealand, Japan, Canada, and the UK. They are fascinated by it, and most wish they could export it to their country. Other U.S. states also wish they had the political will to enact such a sweeping reform. Instead, their somewhat competitive markets include utilities continuing to compete for sales of electricity. Imagine forming a company and trying to unseat an entrenched, incumbent, monopoly utility with huge political clout. Those markets have not yielded the benefits of the Texas model.
To level set this discussion, I need to clear the air. In my opinion, and many share this view, the market structure did not directly cause the outages. Every form of electric company – wires companies, municipal utilities, cooperatives – suffered losses of energy supply as a result of the weather conditions and other factors. Regulations – words on paper – produce no power and afford no warmth to the atmosphere to rectify the outages. Regulations, however, set boundaries for behavior that are important to the market, and a review of the pricing model is expected so that longer term issues do not arise. Solutions to reliability will lie with infrastructure upgrades, improved communications, and a handful of approvals to ensure fuel supplies maintain power. Solutions to financial challenges will partly be met through infrastructure upgrades and partly through modifications to the pricing model.
History explains a lot about today’s market
Senate Bill 7 in 1999 required the separation of monopoly utilities (now Oncor, CenterPoint and AEP) into three entities – a fully regulated monopoly “wires and poles” company, a generation company, and a retail services provider. The generation and retail services would no longer be monopolies; they would compete for business. The only fully regulated component of the market is the transmission and distribution wires, and those are best analogized as the highways for electrons to reach homes and businesses. For SB7 to pass, municipal and cooperative utilities were carved out and allowed to remain monopolies. Entities like Austin Energy, Pedernales Electric Cooperative, and CPS San Antonio continue as monopolies.
In this new market, power plant developers and newly formed retail electric providers (REP) could compete for electricity sales in the competitive areas. Oncor, CenterPoint and AEP were forbidden to buy or sell power – they only transmitted (bulk power on big wires) and distributed (retail power on the smaller wires behind your homes) power for the competitive entities. Power plant developers flocked to Texas in the early 2000s, and I recall hearing that something like $20 billion in new power plants was added in the first few years alone. Old, less efficient plants were retired and replaced by newer, cleaner ones.
In 2005 Senate Bill 20 was passed to eliminate electrical bottlenecks on the transmission grid that prevented wind energy from running. That legislation ultimately caused the expansion of transmission lines to the farthest reaches of the state for wind power development. The PUCT was tasked with the details and spent the next 2-3 years formulating a plan that became known as the CREZ (competitive renewable energy zones). CREZ authorized the construction of wires to accommodate 18,000 MWs of additional renewable energy to move from mostly West Texas to heavily populated areas to the east (and also enabled Gulf Coast wind farms). The CREZ wires were completed by 2019-20, and wind turbines have already filled those wires. That’s an amazing amount of energy and capital added in Texas. Consider that 1 MW of wind generation costs at least $1.5M; that’s $27-38 billion in new wind farm development. The transmission lines cost approximately $8 billion, and that regulated cost was added to every consumer’s monthly bill. Although the $8B is a huge number, electric consumption in this state is gargantuan. The thinking by (again) a lot of smart people is that the transmission lines are a 40+ year investment, and the cheap energy moved on the wires would more than offset the $8B. I haven’t run the math, but I suspect that power prices have declined significantly from wind energy to support that thinking. Lower energy prices are good for consumers of all kinds, but the decline has been hard on other power generation resources that must pay for fuel. That brings us to the pricing model.
Developing a pricing model - background
Natural gas supply was deregulated in 1984 by the Federal Energy Regulatory Commission, and artificially inflated gas prices dropped like a stone. Telephone services were deregulated in the early 80s (anyone remember signing up for MCI and Sprint to make a “long distance call”?) and caused the price of phone service to drop. These experiences also shaped the Texas model.
Competitive forces drive the ERCOT power generation market. When the market was formulated two decades ago, our electric founders did not want government to dictate the types of power plants to be built. The 1990s saw big price increases for electricity as a result of expensive power plant additions including nuclear and coal plants. These plants were added by local monopoly utilities (HL&P, TXU, CPL, WTU) after review and approval by the PUCT. Consumers were angry with rising costs and demanded change.
Note how radically different the old utility model is compared to a competitive model. Prior to 1999 (but after 1976 when the PUCT was first formed), each utility would evaluate its power needs, decide on what type of plant to build, and propose that plan to the PUCT for approval. Utilities profit from making a capital investment. A natural tension existed between utility (spend as much as possible) and regulatory authority (contain cost as much as possible). The PUCT held rate cases as required by law to essentially litigate the findings. Tens of entities would submit comments, challenges and supporting briefs. Fortunately for Texas, the large industrial base across the state would counterbalance the political power of large utilities to achieve compromises in what would be approved. This balance of interests contained costs for all ratepayers. Many other states lack that industrial influence, and utilities wield the most political clout of any enterprise. Virginia has a recent and well publicized problem with this.
Thus, the competitive market was structured to allow a private company to decide the type of power plant to build. If a private company puts money at risk to build a power plant, that company should decide what it wants to build. Economics, market signals, environmental regulations and other external forces would shape the ERCOT power market for years to come. That hands-off model exists today. Government has almost no hand in the types of plants to be built in ERCOT. Approvals for building power plants are limited to environmental impacts (air emissions, water consumption for cooling, ground contamination, etc…) and an electrical study by ERCOT to ensure that a new plant is interconnected in an appropriate way and location. Thus, wind and solar farms could be built with little more than an ERCOT interconnection approval. Light-handed regulation spurred the incredible expansion of wind energy over the last 15 years.
This background is important to understand how the pricing model was formed and modified. Tens of billions have been spent by power developers on all forms of power generation. The current market model has done its job to attract capital and development of power plants. Reserves of power generation – the amount of power on call during peak times in excess of demand – is sufficient today, but that assumes only a normal number of “trips” by plants. Additional generation would certainly help, but the expansion and hardening of fuel supply channels will be necessary. Assurances of returns on investment will need to be shored up by state officials.
Developing a pricing model – how it works
ERCOT’s pricing model was created by renowned economists, regulatory leaders, and some of the best minds in the energy business from around the world. In a sentence, the model is designed to allow power plant operators to offer power for sale at a price agreeable to them, make available their power at all times (cannot withhold power from plants), but stand the risk of not running at all when other power plants have offered power at a cheaper price. This concept took a while for me to grasp. Let me explain. There is no requirement that a power plant offer power for a regulated or preordained price. Power operators decide the price at which they will sell. Except for extremely high demand periods (V-Day most notably), more power is produced and offered into the market than ERCOT needs. The power plants chosen to run every 15 minutes, 24 hours per day, are those that are the most economical (that is, they offer the lowest price). Thus, a power plant operator is not deciding how much it can make. Rather, the operator must offer a price low enough to ensure the plant runs at all but high enough to cover costs and make a profit. If the plant doesn’t run, it earns nothing. Zip. Now here’s the part that once confused me. If an operator offers a low price and ERCOT chooses that plant to run, then you will earn the highest price offered and accepted for that 15-minute period. The counterintuitive purpose for this is to not penalize power plants for offering power at a low price.
Here’s a simple example. Five plants offer 1MW of power each at different prices. Wind at $0, Solar at $0, Nuclear at $5, Coal at $10, and a gas-fired plant at $20. ERCOT determines total demand for that power interval will require only 4 units of power. Under the economic dispatch model, ERCOT instructs all but the gas-fired plants to run. The gas unit receives no payments, but the other four power plants are each paid $10, the highest price offered (by the coal plant in this example) and accepted to run by ERCOT.
ERCOT’s market structure is called energy only. No payments are made to generators for simply owning a plant. The generator is paid to run and produce power, not to own. This is in contrast with power markets in other regions with a capacity payment which compensates generation owners for owning and making ready a plant. ERCOT does not have this type of payment.
Let’s look at relative economics to understand some of the public posturing on power generation and pricing. Imagine operating an existing wind farm in ERCOT and the competitive advantage you would enjoy. Every 15 minutes you can offer power with no fuel cost, so an extremely low price can be offered every 15 minutes. In fact, wind farms can offer at or below a price of $0. Why? Two reasons. One, the wind farm operator will receive the highest accepted offer price. Two, because the federal government provides a “production tax credit” for wind farms. Thus, for every MW of power produced by a wind turbine, a tax credit is produced on the order of $23 per MWh ($35 after-tax equivalent). Thus, the wind farm owner collects the tax credit plus the price of power every 15 minutes as long as it runs. In ERCOT, wind farms run as long as the wind blows. This is good for lowering the price of energy.
To be clear, I am not passing judgment on tax credits. Most industries, including the petroleum sector, enjoy tax credits for various investments and behaviors. All I am pointing out here is the disparity in pricing between wind energy and other forms. Solar power receives an investment tax credit, a benefit for constructing the asset. Although this credit makes economically possible the construction of some solar farms, the tax credit does not apply to the production of power.
One other economic reality in the ERCOT market is what happens if you fail to run after being accepted to run. Wind and solar have no negative economic consequences for failing to deliver power. Because they are reliant on wind and sun to operate, they are called intermittent resources. ERCOT does not penalize them for failure to run. Dispatchable plants (commonly called thermal units including nuke, coal and gas) must run for the entire time they are called to run. If dispatchable plants trip off for any reason, that plant operator must pay for replacement power of a like quantity. In peak hours when prices are high, you can see how expensive that trip could be.
You can see now how thermal (nuke-coal-gas) power generation is economically disadvantaged when compared to renewable resources. I point this out to highlight the challenges we will face in ERCOT to attract more dispatchable thermal plants. The one type of power plant ERCOT could add is a peaking plant which can start quickly, operate reliably, and produce a lot of power. These types of units are usually gas-fired and seldom run. They are essentially jet engines similar to those hanging on the wing of an aircraft. These same engines are combined with a steam turbine to create what is commonly called a combined cycle plant. The steam turbine is usually driven by the waste heat from the jet engine to produce more power. These combined cycle plants are very efficient and produce power at a much lower cost than a jet engine alone (called simple cycle). Thus, the peaking power plant (simple cycle plant) does not run very often due to high fuel cost. This presents a big challenge in ERCOT. If you don’t run, you don’t earn. Peaking units must earn all of their money in peak hours. How do we create enough incentive to develop more peaking units, or how do we restructure pricing to offer the right incentive for all power plant additions without creating a punitive price?
Let’s dive into another layer of complexity. Not only does ERCOT administer the flow of power across most of Texas, but it also operates the power exchange where power is bought and sold 24 hours each day. ERCOT closely follows supply and demand to ensure they stay balanced. We heard a lot about this already since V-Day. If supply and demand converge (that is, demand increases and power supplies do not increase proportionally), there are carefully crafted rules for ERCOT to follow. When power supply reserves drop to a certain level, then ERCOT declares an energy emergency alert (EEA) at the first level, then the second, then finally the third level when the system is critical. These EEA events also trigger the power exchange to automatically take over the pricing of power. Again, this process is already built into the systems and largely automated because of the need for fast action and the huge number of transactions taking place.
The automation that is triggered drives prices much higher to signal to power generators that all available power supplies should be made ready to operate. When I say much higher, the prices escalate from perhaps $50 to well over $1000. The EEA 3 event means that prices are pegged at $9000 for energy sales, and that price can go higher based on price adders that can create a much higher total price. It also signals to large consumers (think oil refineries, steel smelters, and other industrial businesses) that they should reduce or eliminate usage to avoid high prices. Some of these large businesses are paid to lower or cut usage in times of scarcity of supply (called emergency reserve service or ERS). These sophisticated businesses not only avoid high-cost energy but also get paid to stop consuming power. This is an efficient tool for ERCOT and other power regions to manage the power grid in times of high demand, limited supply, or other emergencies. Thus, this dramatic price increase usually prevents shortages and begins a return to normal pricing in a short period of time.
Putting the love back in Valentine’s Day
Unfortunately, we experienced a weather event that didn’t cooperate with historical norms. Overlaying the ERCOT pricing model with the conditions we experienced starting Valentine’s Day, you can see how the automated peak pricing model caused extreme stress on market participants. Past extreme events lasted only a few hours. The February event lasted days. Despite hundreds of experienced people developing and tweaking this model over 20 years, almost nobody anticipated an extreme winter weather event like this. Texas builds everything to endure blistering heat. Extreme cold coupled with precipitation and spread across the entire state for days was not expected. Well, it is now.
Further market components and complexities
I have greatly simplified the market design to make it understandable. Other features that add to its complexity and functionality include:
· Other power products – “Ancillary services” are offered into ERCOT to keep the lights on. Quick start (a quick starting power plant to add power), responsive reserves (units run in the background in case additional power is needed), regulation up and down and other features are offered for value.
· Reliability must run – Called RMR contracts, ERCOT evaluates the grid and determines if any units are essential for continual service. If so, then a contract is signed with that power plant to run when called upon by ERCOT. These types of contracts are not favored because consumers pay RMR costs regardless of whether the plant runs.
· Real time vs day ahead power prices – Power can be sold a day in advance or on the same day it is delivered.
· Bilateral contract arrangements – Buyers and sellers of power can contract between themselves to establish prices and terms. These contracts account for a huge amount of the power sales. This is how REPs are able to sell power to residential customers and others at fixed prices, regardless of what happens at pea times. The power prices are set for longer terms.
· Financial transactions vs physical – Hedging is common for the reason stated above. This can be done through a liquid exchange like the ICE platform where parties can find one another to manage power pricing for a variety of consumers. Financial derivatives are used to convert, for example, a daily variable power price to a monthly fixed price. Physical transactions are purchases of delivered power.
· ERCOT “uplift” – If a market participant (like Brazos) defaults and does not pay its bill, that bill must be paid on the power exchange. This assurance of payment is necessary to give all market participants confidence in buying and selling on the exchange. ERCOT has no resources to cover these costs, so the amount in default is shared among remaining market participants (generators, REPs, traders) in proportion to their activity level. So these default costs are shared among the rest of us.
Solutions
We must all wait to see what lawmakers plan to do but here are some of the possibilities for their consideration. The cost-benefit analyses of each of these would need to be run, but these are ideas worth considering.
· Study the price cap for changes – The $9000 cap has its advantages and disadvantages. Not only does this price need a review, but the duration of its application also merits a look. Does a capacity market make sense? Does a revision to the penalty for plants tripping make sense?
· Secure fuel supply – Freezing coal, frozen gas lines, frozen gas wells – these all need to be discussed to determine what, if anything, can be done to secure supply under extreme conditions. Does it make sense to create a Texas “strategic petroleum reserve” of its own strictly for power production needs? One lesson learned in the legislative hearings is that every industry is deeply dependent on electricity.
· More ERS – ERCOT can review the limited amount of emergency reserve service that is offered and determine if the program should be expanded. This would further reduce demand at peak times.
· Adequate rewards for power plant development – Ensuring that dispatchable power plant development continues is paramount in a growing state. Adequate rewards for power sales are one component, but the industry should also evaluate adequacy of fuel, pipelines, storage assets, water availability, and other components.
· Deepen responsive load reductions – Most businesses and homes in ERCOT have smart meters, and millions of them can be switched on and off remotely. An investment in smart systems to allow more businesses and even homes to respond to peak demand would “flatten the curve” of power demand.