Interview with Evan Pittman of Comverge
Associate Director, Corporate Strategy
How long have you worked at Comverge?
One year. Coming out of business school, I was looking for opportunities where I could help bridge the gap between wholesale and retail electricity markets—to help get price and scarcity signals more effectively to end-use customers to drive a more efficient electricity grid. Comverge offered the perfect opportunity with its mix of direct load control and price-based demand response offerings for residential and small commercial customers.
What is your role at Comverge?
I sit in our corporate strategy group, where my role has three distinct components. The first is staying on top of industry trends and participating in internal meetings with our product management, sales, and executive teams to ensure that our strategy, development priorities, and messaging in the marketplace are in line with the needs of our customers. The second is supporting our clients and prospects as we collaborate on tailoring our solutions to meet their specific opportunities. Finally, I spend a good deal of time on regulatory and market development matters, with a particular focus of late on the Texas and New York markets.
How long have you been involved in demand side activities?
I began my career seven years ago in The Brattle Group’s electricity consulting practice. I wasn’t exclusively focused on demand-side issues there, but I worked on several projects related to time-varying rate design, utility energy efficiency programs, and demand response in wholesale capacity markets. Between Brattle and Comverge, I spent two years in graduate school at the University of Chicago’s Booth School of Business where I co-chaired the student Energy Group, worked with a home energy efficiency finance startup, and stayed closely engaged in the energy scene around Chicago.
What challenges have you faced as a DR professional within your organization and within the industry?
The biggest challenge with DR, like other distributed energy resources, is capturing its full value in what has become a very fragmented industry. DR used to be viewed as an emergency resource with little more than a reliability benefit. Today, it can be many things—a planned part of the capacity mix, a means to avoid high energy prices, a tool to integrate intermittent renewables, or an alternative to investing in new distribution infrastructure, just to name a few. But across much of the US, the industry is structured such that one entity might be responsible for managing the distribution system, another for operating the wholesale markets and bulk transmission system, and yet another for driving the retail relationship with the customer.
It can be an enormous challenge to negotiate with each of these entities to unlock all of the potential benefits of DR. ISO rules (e.g. outdated telemetry requirements for ancillary service resources or a lack of access to energy markets for third party DR aggregators) can make it impossible to capture certain wholesale benefits. Distribution utilities may not have accurate estimates of their locational cost to serve, and even when they do, may not have the right regulatory incentives to compensate third parties who invest to reduce that cost to serve. Finally, retailers may not be confident they will hold a customer for long enough to invest and may be settled by ISOs on hourly profiles (as opposed to interval meter data), which prevents them from realizing any energy benefits.
Until the right policies are in place (especially at the ISO and utility levels) to reward DR for all of the value streams it creates, we’ll continue to miss out on cost-effective opportunities to invest in DR—opportunities that would lower the total cost of delivered electricity and yield other behind-the-meter benefits for customers.
What changes have you seen in the industry as it relates to DR and EE over the last few years?
In some respects, I’ve seen encouraging progress in addressing the challenges I just described. In particular, reforms are brewing in a number of states that provide a clearer path for distribution utilities to compensate third parties when they create value on the utility’s network. I’m most familiar with New York’s Reforming the Energy Vision (REV) initiative, in which the Commission has already taken a number of proactive steps in this direction, including: (1) asking utilities to identify specific opportunities for distributed energy resources to defer or eliminate the need for traditional distribution infrastructure investment, (2) ordering the adoption of “bring your own device” DR tariffs state-wide, and (3) proposing ratemaking reforms that will reward utilities for making efficient decisions, even if it means foregoing the deployment of their own capital. Great progress is being made in California, Massachusetts, and several other states as well.
However, there are a lot of changes underway and potentially looming. Whether it be changes to ISO programs, the impact of which are yet to be seen, or the outcome of the DC Circuit Court’s EPSA ruling. The latter drew into question FERC’s jurisdiction over DR in wholesale markets, which is certainly a threat to realizing any value whatsoever from the wholesale markets.
What do you expect to be the biggest challenge with implementing DR in the next decade?
I see a massive movement forming to restructure retail pricing in the industry, which will present both challenges and opportunities. There’s been discussion of mass-market time-varying retail rates, demand charges, and other tariff designs that are more closely tied to cost for decades with little in the way of wide scale adoption. But I think the vast proliferation of distributed energy resources—including controllable loads like Wi-Fi-enabled appliances and electric vehicles—will force the issue at last for two reasons.
First, since DERs are largely out of the utility’s or grid operator’s control, customers themselves will need to be incentivized to make grid-optimal decisions. Rates tied to costs will make those DER configurations that minimize grid costs most lucrative. For example, customers exposed to time-varying energy pricing might orient their solar panels such that their maximum output is better aligned with system peak or might install thermostats that balance their comfort preferences against real-time prices.
Second, concerns around fairness and cross-subsidization will drive rate reform. For example, distribution utilities and their regulators won’t allow DER owners to skirt their share of the cost of the delivery infrastructure just by minimizing their net energy consumption. We’ll see a move toward demand charges or other pricing models that ensure all the delivery infrastructure costs don’t get lumped into kWh-based rates that non-DER owners might foot disproportionately.
A world of time-varying rates and demand charges raises questions for utilities and DR vendors alike. When will utilities seek direct control of dispatchable DERs as opposed to relying on price signals to incentivize efficient operation? As tariffs become more complex, to what extent will utilities provide tools and equipment to customers to help manage their energy consumption? As mass-market DR vendors, we’ll need to ask ourselves who our customers will be in 10 years. Will we sell primarily to utilities or will we be providing services to end-use customers who are fully incentivized through their tariff to optimize their energy use?
What advice or guidance would you give to young professionals who are considering a career in demand response and smart grid?
Join us. This is an incredibly dynamic industry and you never stop learning. As you first start out, look for a position that will give you broad exposure to all parts of the electricity industry, not just the demand side. There’s a steep learning curve, and getting the big picture as quickly as possible helps. Also, be forewarned… once you’ve spent more than a few years in this industry, you’ll probably never leave it!
How long have you worked at Comverge?
One year. Coming out of business school, I was looking for opportunities where I could help bridge the gap between wholesale and retail electricity markets—to help get price and scarcity signals more effectively to end-use customers to drive a more efficient electricity grid. Comverge offered the perfect opportunity with its mix of direct load control and price-based demand response offerings for residential and small commercial customers.
What is your role at Comverge?
I sit in our corporate strategy group, where my role has three distinct components. The first is staying on top of industry trends and participating in internal meetings with our product management, sales, and executive teams to ensure that our strategy, development priorities, and messaging in the marketplace are in line with the needs of our customers. The second is supporting our clients and prospects as we collaborate on tailoring our solutions to meet their specific opportunities. Finally, I spend a good deal of time on regulatory and market development matters, with a particular focus of late on the Texas and New York markets.
How long have you been involved in demand side activities?
I began my career seven years ago in The Brattle Group’s electricity consulting practice. I wasn’t exclusively focused on demand-side issues there, but I worked on several projects related to time-varying rate design, utility energy efficiency programs, and demand response in wholesale capacity markets. Between Brattle and Comverge, I spent two years in graduate school at the University of Chicago’s Booth School of Business where I co-chaired the student Energy Group, worked with a home energy efficiency finance startup, and stayed closely engaged in the energy scene around Chicago.
What challenges have you faced as a DR professional within your organization and within the industry?
The biggest challenge with DR, like other distributed energy resources, is capturing its full value in what has become a very fragmented industry. DR used to be viewed as an emergency resource with little more than a reliability benefit. Today, it can be many things—a planned part of the capacity mix, a means to avoid high energy prices, a tool to integrate intermittent renewables, or an alternative to investing in new distribution infrastructure, just to name a few. But across much of the US, the industry is structured such that one entity might be responsible for managing the distribution system, another for operating the wholesale markets and bulk transmission system, and yet another for driving the retail relationship with the customer.
It can be an enormous challenge to negotiate with each of these entities to unlock all of the potential benefits of DR. ISO rules (e.g. outdated telemetry requirements for ancillary service resources or a lack of access to energy markets for third party DR aggregators) can make it impossible to capture certain wholesale benefits. Distribution utilities may not have accurate estimates of their locational cost to serve, and even when they do, may not have the right regulatory incentives to compensate third parties who invest to reduce that cost to serve. Finally, retailers may not be confident they will hold a customer for long enough to invest and may be settled by ISOs on hourly profiles (as opposed to interval meter data), which prevents them from realizing any energy benefits.
Until the right policies are in place (especially at the ISO and utility levels) to reward DR for all of the value streams it creates, we’ll continue to miss out on cost-effective opportunities to invest in DR—opportunities that would lower the total cost of delivered electricity and yield other behind-the-meter benefits for customers.
What changes have you seen in the industry as it relates to DR and EE over the last few years?
In some respects, I’ve seen encouraging progress in addressing the challenges I just described. In particular, reforms are brewing in a number of states that provide a clearer path for distribution utilities to compensate third parties when they create value on the utility’s network. I’m most familiar with New York’s Reforming the Energy Vision (REV) initiative, in which the Commission has already taken a number of proactive steps in this direction, including: (1) asking utilities to identify specific opportunities for distributed energy resources to defer or eliminate the need for traditional distribution infrastructure investment, (2) ordering the adoption of “bring your own device” DR tariffs state-wide, and (3) proposing ratemaking reforms that will reward utilities for making efficient decisions, even if it means foregoing the deployment of their own capital. Great progress is being made in California, Massachusetts, and several other states as well.
However, there are a lot of changes underway and potentially looming. Whether it be changes to ISO programs, the impact of which are yet to be seen, or the outcome of the DC Circuit Court’s EPSA ruling. The latter drew into question FERC’s jurisdiction over DR in wholesale markets, which is certainly a threat to realizing any value whatsoever from the wholesale markets.
What do you expect to be the biggest challenge with implementing DR in the next decade?
I see a massive movement forming to restructure retail pricing in the industry, which will present both challenges and opportunities. There’s been discussion of mass-market time-varying retail rates, demand charges, and other tariff designs that are more closely tied to cost for decades with little in the way of wide scale adoption. But I think the vast proliferation of distributed energy resources—including controllable loads like Wi-Fi-enabled appliances and electric vehicles—will force the issue at last for two reasons.
First, since DERs are largely out of the utility’s or grid operator’s control, customers themselves will need to be incentivized to make grid-optimal decisions. Rates tied to costs will make those DER configurations that minimize grid costs most lucrative. For example, customers exposed to time-varying energy pricing might orient their solar panels such that their maximum output is better aligned with system peak or might install thermostats that balance their comfort preferences against real-time prices.
Second, concerns around fairness and cross-subsidization will drive rate reform. For example, distribution utilities and their regulators won’t allow DER owners to skirt their share of the cost of the delivery infrastructure just by minimizing their net energy consumption. We’ll see a move toward demand charges or other pricing models that ensure all the delivery infrastructure costs don’t get lumped into kWh-based rates that non-DER owners might foot disproportionately.
A world of time-varying rates and demand charges raises questions for utilities and DR vendors alike. When will utilities seek direct control of dispatchable DERs as opposed to relying on price signals to incentivize efficient operation? As tariffs become more complex, to what extent will utilities provide tools and equipment to customers to help manage their energy consumption? As mass-market DR vendors, we’ll need to ask ourselves who our customers will be in 10 years. Will we sell primarily to utilities or will we be providing services to end-use customers who are fully incentivized through their tariff to optimize their energy use?
What advice or guidance would you give to young professionals who are considering a career in demand response and smart grid?
Join us. This is an incredibly dynamic industry and you never stop learning. As you first start out, look for a position that will give you broad exposure to all parts of the electricity industry, not just the demand side. There’s a steep learning curve, and getting the big picture as quickly as possible helps. Also, be forewarned… once you’ve spent more than a few years in this industry, you’ll probably never leave it!
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Periodic updates on news & events related to demand response and smart grid.