by Phil Davis, Schneider Electric
Demand response continues to teach lessons about customer interaction.
Successful implementation requires robust communications with customers, both human and machine, which must be founded on sound data analysis.
As utilities and regulators chart the way to greater efficiency and more renewable energy, the lessons of demand response continue to speak loudly and clearly.
A new look at demand response is in order.
The Department of Energy (DOE) defines demand response as changes in electric usage by end-use customers from their normal consumption patterns in response to changes in the price of electricity over time or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when grid reliability is threatened.
The Energy Policy Act of 2005 declares that demand response in all its forms shall be the policy of the United States, with its use encouraged and barriers removed.
Great words, but what is demand response really?
Electrons obey the laws of physics.
They travel the path of least resistance on their way to ground.
Our job is to get them to do a little work along the way without wreaking havoc, which electrons like to do.
Demand response is how we do that. Everything about an intentional electron’s journey is shaped by someone’s desire to modify that journey.
Those goals are determined by the vast community of electron users: customers.
In that sense, everything a utility does is demand response.
Now is the time to integrate demand response lessons into operations.
This will help meet the societal and stakeholder expectations of the utility of the future.
History of Demand Response
We marvel at smart phones and forget the iPhone first appeared in 2007, 35 years or so after the first cell phone.
The roots of demand response similarly stretch back decades to interruptible and time-of-use rates.
Demand-side management programs such as energy audits, efficiency rebates and similar also date back to the 1970s.
The first real changes came in the 1990s:
- Bulk power deregulated and launched the initial active wholesale markets.
- Independent power generators outpaced utilities in unit construction for the first time.
- Energy trading started as an efficient mechanism to bring deregulated power to market.<
- The first interval meters were developed and enabled the advent of time-of-use measurement.
The 2000s saw the following advances
- Retail deregulation spread, and retail energy marketers emerged.
- Integrated utilities split into distinct generation, transmission and distribution areas.
- Green energy markets appeared.
- Independent system operators (ISOs) took on the role of markets and created auctions and other mechanisms for bidding and clearing increasing diverse power products, including demand response.
- Third-party aggregators were born and initially targeted large commercial and industrial loads and aggregated them into portfolios of interest to the ISOs for hedging and risk management functions.
Since 2007, these broad functions have become more granular and more sophisticated.
Aggregators also serve as program managers in outsourcing demand response programs for distribution utilities, similar to the role played by project management firms in the 1970s.
Now, most states have renewable and efficiency standards, and demand response is a leading tool to integrate those activities and maintain grid reliability.
Today there is a form of demand response analogous to every form of generation.
And we start to hear the term smart grid a lot.
Impact of Customer-side Energy Efficiency
On the customer side, energy efficiency has matured to the point that there is a per capita decline in consumption despite an explosion in energy-using devices.
Load growth is tied more to population growth and shifts, and it is moderating to levels well below relatively recent predictions.
Large energy users have learned to use demand response techniques to avoid demand charges and frequently call internal demand response events independently of external programs.
This leads to the first significant challenge: utility revenue.
If many major energy users learn to manipulate energy patterns to minimize utility revenue (lower their own costs), how do utilities and regulators ensure continued financial stability in a critical industry?
Already, several utilities are seeing revenue pressure but lack tools available to nonregulated businesses to adapt.
The answer is to use demand response lessons to redefine smart grid away from technology more to business process.
Smart grid should be defined as the energy supplier plus the energy user.
This requires a collaborative model between utilities and their customers.
Potential Answer No. 1: Integrated Demand Response
Integrated demand response is one approach.
Already there are buildings with sophisticated modeling tools to shape energy demand along predetermined strategies.
This lowers energy consumption and demand.
This capability offers a potential answer to the revenue challenge.
Not every building has a management team with energy specialists.
Can utilities play that role, sponsoring the installation, maintenance and evolution of energy-aware systems that meet the needs of customers and suppliers?
That leads directly to many questions:
1. Does it make sense for a utility to subsidize a district program of building energy management around a stressed substation, for example, rather than investing a larger amount to upgrade delivery infrastructure?
2. What is the right technology and the path to technology evolution?
3. What are the legal and regulatory implications?
The technology answer is easy.
Led by open standards such as OpenADR 2.0, available equipment can and does make this grid relationship possible.
There even are methods of demand management that can identify and manage customer assets to provide frequency support and other regulation services.
The larger question is how to integrate the control room-to-customer path and how to create a customer relationship around this that delivers value and replaces revenue lost to efficiency.
Potential Answer No. 2: Microgrids
Another approach might be microgrids. Typical definitions include an islanding capability, local generation and organized control. Plus, someone has to pay for them.
Consider the core competencies of utilities; no other industry has the same deep understanding of large-asset finance or a cultural path to make that happen.
No other industry understands the real-time management, maintenance and balancing of diverse and distributed energy assets.
No industry responds better under crisis.
Microgrids are a key strategy to meet many energy challenges.
Using them to manage local renewable generation to meet requirements might be a better choice than massive wind and solar farms in some cases.
Smart inverter technology can work with the large grid to provide proper flow direction under variable circumstance.
They can reduce the challenge of electric vehicle charging to bite-size pieces, as well as manage them for storage and emergency conditions.
To make that work requires smart meters, operating centers with advanced distribution management systems (ADMS) and expert staff-all attributes of today’s utilities.
Under certain conditions, thousands of small, variable energy assets can be managed mathematically to follow an AGC signal.
This enhances rather than detracts from traditional utility processes.
Potential Answer No. 3: Grid-side Optimization
The grid has much to offer if we can release its potential.
The use of dynamic line rating systems removes the static rating barrier, increasing power delivery over existing lines.
This fits perfectly with wind generation.
When the wind blows, turbine blades rotate, but transmission lines also cool down and can accept more power.
Perhaps the use of this technology can allow greater renewables delivery without additional construction.
Pilots here and in Europe have shown 30 to 50 percent increases in line capacity over static limits.
Back in the control room, exactly what is this ADMS that is appearing in growing numbers of utilities?
In simplest form, it replaces several historically independent systems-geographic information system, outage management system, distribution management system, etc.-and provides a platform to react to new data flows from smart grid implementations.
A top ADMS system also can dispatch and monitor millions of points, and suddenly, the integration of sophisticated demand response programs and microgrid management isn’t so farfetched.
A well-designed ADMS can arbitrage between new assets and technologies and bring revenue streams and customer benefits far beyond today’s traditional approaches.
Finally, or perhaps first, there is the human side.
The industry needs a continuous improvement process that integrates supply and demand-side activities.
ISO 50001 and the DOE’s Superior Energy Performance programs provide examples of this process in action.
Identify, plan, act, measure, evaluate, modify are steps in a continuous loop of improvement and an area where utilities have strengths to offer.
Center to Customer
All of these steps lead to a fully integrated smart grid.
From control centers to customers, there is a flow of activity that is seamless with no artificial boundaries, such as meters, to stand in the way of efficiency and progress.
Renewable standards and efficiency goals often are defined as percents of a total.
There are two ways to increase percent: Increase the numerator or decrease the denominator.
To date, our response has been to do more with more.
It’s time for the integrated smart grid to help us do more with less.
Volt-VAR control fed by smart grid data offers an example.
Data points provide information on power at various points on the grid.
Volt-VAR control adjusts send out so it closely meets standards requirements.
This drops the need for generation 2 to 6 percent.
When that power comes from nonrenewables, the denominator is reduced.
De facto, this reduces the denominator automatically and raises the portion of renewable energy in use without having invested anything in new generation.
Utility of the Future
The utility of the future won’t look so different from the utility of today.
Generation, transmission and distribution remain, as do control rooms, customer service and customers.
What changes are the attitudes, processes and relationships of suppliers and customers, perhaps in ways similar to a smart phone ecosystem.
We don’t ride horses to work anymore, but most of us still commute.
We don’t mail letters, but we still write to one another.
We don’t use cash, but we still buy products.
What does your utility of the future look like?
Phil Davis is senior manager of smart grid solutions at Schneider Electric.
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