This piece was originally published in the January/February 2020 issue of electroindustry.
Doug Staker, Vice President of Utility Business Development, Enel X
Mr. Staker is a pioneer in the world of smart grid technologies, with a focus on smart metering and intelligent energy storage.
Today’s electric power industry is migrating through various elements of change. The integration of renewable power at a scale that competes with traditional generation is impressive. Endorsed by renewable supporters and condemned by businessas-usual promoters, the reality is that a simple principle of physics is at play: economic gravity.
Wind and solar power generation are growing globally. There are a variety of reasons, but a fundamental element is that they produce a lower Levelized Cost of Energy (LCOE) than their fossil fuel and nuclear counterparts. A key component is that their fuel costs—the wind and sun—are free. In calculating LCOE, one needs to include both capital and operating costs in the equation. Wind and solar power are now at an LCOE that is competitive with natural gas and hassurpassed coal in the past few years.
How the Grid Works
Energy generation is only one part of the energy delivery system, which also includes transmission, distribution, and load. A vital aspect of the power grid is that it is a perfect “just-in-time” delivery system. Supply has to match demand; otherwise, the grid delivers voltage and frequency outside of the standard operational limits. These components are subject to two elements, time and location. Generation must follow and match load to keep the grid stable. Transmission and distribution systems need to be sized to meet peak demand. With the introduction of distributed energy resources, like solar, storage, and combined heat and power (CHP) systems, new market entrants can participate in the rules of economic gravity, where gravity pulls the economy in a direction that leans heavily toward lower costs when selecting resources.
In the United States, utilities are subject to State and Federal oversight. That means we have 50 jurisdictions that influence how the commodity of energy is priced and delivered. In the late 1990s and early 2000s, new utility markets emerged in some regions of the country. New England, New York, the mid-Atlantic states, Texas, the Midwest, Southwest, and California restructured and formed new markets. Vertically integrated utilities were disaggregated in these regions. Generation was developed to be a competitive resource. Utilities retained transmission ownership, but the ownership is controlled and regulated by an independent group known as a regional transmission organization (RTO) or independent system operator (ISO). The utilities are paid via various tariff schemes developed by the Federal Energy Regulatory Commission (FERC).
Since most ISOs depend on energy transmitting across state lines, FERC becomes the regulator for these markets for generation and transmission.
In restructured markets, utilities today are fundamentally in charge of the local distribution system. The pricing and control of generation and transmission are managed by the ISO that develops both day-ahead and day-of-pricing models that reflect current conditions.
These energy markets follow the rules of supply and demand and are subject to the laws of economic gravity—low costs win. Generators bid in both markets and are rewarded with participation as their price is accepted based on the amount of the resources needed to meet demand. The ISO accepts bids based on price (lowest price first, etc.) until enough megawatts are secured to meet the forecast demand for two different time periods: day-ahead and real-time.
Day-ahead offers are bid 24 hours ahead, and they are cleared based on price and the number of megawatts. The day-ahead pricing is cleared and published at 4 a.m. for the next day that will begin at midnight. There are 21 hours of notification before the pricing begins. In the real-time market, they forecast the shortage or imbalance in the system due to the variance between the day-ahead forecast and the 90 minute view of the current usage. It is very dynamic and can create price spikes that entice entrants to jump in and solve the shortage.
The transmission system is like a freeway: there are physical restrictions that limit the number of electrons (cars) that can flow. The ISO knows the limit of each line, and another generator is then selected past
the point of congestion, which adds an element of locational benefit into the pricing equation. These elements follow the principles of economic gravity which are influenced by time of day and location; location-based, low-priced wins.
In order to develop a full digitalization of the energy delivery system, the next frontier to establish is the distribution system. Along with the load it serves, the distribution system is the least automated and least understood component of the energy delivery system. To make things even more problematic, the distribution system is still managed with monthly metrics.
With the growth in distributed generation, we now have a changed model where energy can flow in both directions, and load can be managed to reduce congestion or to lower the need for peaking power. Market participants are pushing to have the ability to sell excess generation into the wholesale market, via the distribution system, and participate under the rules of economic gravity. Time and location have just as much value in the distribution system. There are also those who would like to develop local markets where excess solar energy could be sold to a neighbor via a market transaction.
Today where retail markets are restructured, distribution utilities get to charge for their service to deliver energy purchased from third-party resellers or energy marketers. The distribution utility charges for delivery of the energy. Energy is defined as the “supply” or the “commodity.” So, in the restructured market, we have “supply” and “delivery” charges.
In the restructured retail energy markets, customers can buy their “supply” in the day-ahead market. They select an energy retailer that offers a variety of pricing models, but the two most popular are fixed (flat- rate) or hourly pricing based on the wholesale day- ahead market. The day-ahead model is known as an “indexed price.”
For commercial customers, supply is measured as energy or kilowatt hours. Think of it as mileage. It measures the number of electrons delivered over a billing period, but it doesn’t answer the question of the rate or speed of energy use. The rate at which energy is measured is known as “demand.” Customers are billed for “peak demand” which is the fastest average speed that the electrons were delivered to the customer. In most cases, demand is measured every 15 minutes. A meter keeps track of the peak demand measured during the billing period.
As an energy retailer develops pricing to end users, they buy energy in the day-ahead market and pay for the aggregation of all of their customers’ peak annual demand, which is known as their installed capacity (ICAP). This is measured for each load at the peak hour of the year. To keep the billing simple, the retailers transform the ICAP charge into an energy charge (cents/kWh) along with their margin. As highlighted earlier, end users can choose to buy hourly energy or at a fixed rate. Retailers like to tell end users that a flat rate allows the energy manager to ensure budget certainty and eliminate any risk in the market.
Index pricing for energy supply is another example of economic gravity. Generators compete to sell their supply into a competitive market, and the laws of supply and demand prevail. So, as we develop the new frontier of the distribution system, why wouldn’t we investigate how to develop variable delivery (e.g., hourly or real-time) pricing based upon market conditions in the distribution system? As we develop more distributed resources, especially solar and storage, we can better match supply with demand based on real-time pricing. Real-time distribution pricing can also reflect the laws of supply and demand locally and help support lower costs.
Continuing to build to meet the peak in a distribution system will result in continued growth in system costs. New methods in how regulators allow utilities to develop the distribution system have resulted in the development of non-wires alternatives (NWAs). New performance-based regulations for utilities encourage third parties to offer load-modifying resources to help eliminate the need at peak.
Case Study in New York
To develop pricing signals to help influence load modification, under the direction of the New York Public Service Commission, Enel X and Con Edison have developed a variation of what is known as a standby rate. Instead of having a monthly demand charge, we have a daily demand charge with a second demand component that is priced higher during the four hours of the network peak. In the residential districts of the outer boroughs that have the most potential of hosting rooftop solar, we have distribution system peaks that occur along with the residential peak (7 p.m. to 11 p.m.). Solar photovoltaic production occurs mainly between 10 a.m. and 2 p.m.
The ability to store and time shift this energy into the evening hours allows for the reduction of grid stress during peak hours and helps reduce the capital needed to support peak loading. Con Edison is incented by regulators to implement NWAs, as they get to keep 30 percent of the economic benefit derived in the benefit cost analysis study that the NWA-provider delivers. Instead of deploying more capital that has a lower utilization factor, Con Edison is rewarded with improving system utilization and saving money.
While the conversion from monthly demand charges to daily demand charges is a step in the right direction, the next phase is to move to hourly pricing for distribution charges. This market-based pricing scenario allows market participants to more easily stack the values across the energy delivery system. The market participants will help reduce the operating costs of the grid, benefiting all ratepayers. It will add competition to the distribution market and help solidify the principles of economic gravity. This will help to more cost-effectively integrate more variable supply from renewable resources and make the goals set out around clean energy a reality.
This new market-based pricing will allow for the evolution of the distribution utilities into a distribution system operator that can use market-based metrics to organize how the grid operates based upon the physics of economic gravity. That will help ensure that prices will be competitive and value maximized. ei