The debate surrounding net energy metering (NEM) and the appropriate way to reform this policy is under scrutiny in many U.S. states. This is highly warranted since NEM policies do indeed need reforming because NEM often results in subsidies to private (rooftop) solar owners and leasing companies. These subsidies are then “paid for” by non-NEM customers (customers without private rooftop solar installations). The fundamental source of the NEM subsidy is the failure of NEM customers (customers with private rooftop solar installations) to pay fully for the grid services that they use 24/7. These subsidies are well-documented and underpin much of the regulatory reform efforts underway across the United States.[1]

In a recent Brookings paper, “Rooftop solar: Net metering is a net benefit,” Mark Muro and Devashree Saha contend that net metering is a net benefit for non-NEM customers.[2] I fundamentally disagree with their findings, and argue that NEM is not a net benefit; it is, in fact, a tariff that much of the time results in a subsidy to NEM customers and a cost shift onto non-NEM customers. As Executive Director of the Institute for Electric Innovation, a non-lobbying organization focused on trends in the electric power industry, I have followed this debate and written about it for several years.

Much of the talk about NEM focuses too often on the “value” of the energy that is sold back to the grid by a NEM customer. In reality, the amount of energy sold back to the grid is relatively small. The real issue is the failure of NEM customers to pay fully for the grid services that they use while connected to the grid 24/7, as shown in Figure 1.[3] Customers need to constantly use the grid to balance supply and demand throughout the day, and the cost of these grid services can be sizeable. In fact, for a typical residential customer in the United States with an average electricity bill of $110 per month, the actual cost of grid services can range from $45 to $70 per month–however, the customer doesn’t see that charge.[4] That means, in the extreme, if a customer’s energy use “nets” to zero in a given month because the customer’s private solar system produced exactly what the customer consumed, that customer would pay $0 even though that customer is connected to the local electric company’s distribution grid and is utilizing grid services on a continuous around-the-clock basis.[5]

Although exactly netting to zero energy in a month is highly unlikely, this example demonstrates the point that the customer would pay nothing, despite using grid services at a cost ranging from $45 to $70 per month. Over the course of one year, this customer could receive a subsidy resulting from NEM of between $540 and $840. Over the life of a private rooftop solar system, which ranges from 20 to 25 years, this is a significant subsidy resulting from NEM.

Granted, this is an extreme example, and most NEM customers will pay for some portion of grid services. However, the fundamental source of the NEM subsidy is the failure of NEM customers to pay fully for the grid services that they use 24/7, and the cost of these services can be quite substantial. When a NEM customer doesn’t pay for the grid, the cost is shifted onto non-NEM customers.[6] It is a zero-sum game; plain and simple. This is the elephant in the room.

This issue was directly addressed by Austin Energy when the company implemented a “buy-sell” arrangement for the private rooftop solar customers in its service territory. The rationale for the buy-sell approach is that the customer buys all of the energy that is consumed on-site through the electric company’s retail tariff and sells all of the energy produced by their private rooftop solar system at the electric company’s avoided cost. This addresses the “elephant in the room” because, by buying all energy consumed at the retail tariff, the customer does pay for grid services that are largely captured through the retail tariff. It is an unfortunate fact that under ratemaking practices today in the United States, the majority of fixed costs (i.e., grid and other costs) are captured through a volumetric charge.

Hence, I fundamentally disagree with the Muro/Saha paper–NEM does need to be reformed. NEM is not a net benefit; it is a tariff that the much of the time results in a cost shift onto non-NEM customers. One of the first studies to quantify the magnitude of the NEM subsidy was conducted by Energy+Environmental Economics (E3) for the California Public Utilities Commission (CPUC) in 2013. There was no mention of this analysis for the CPUC in the Muro/Saha paper. The E3 study estimated that NEM would result in a cost shift of $1.1 billion annually by 2020 from NEM to non-NEM customers if current NEM policies were not reformed in California.[7] A cost shift of this magnitude–paid for by non-NEM customers–was unacceptable to California regulators. As a result, California regulators set to work to reform rates in their state; many other states followed suit and conducted similar investigations of the magnitude of the NEM subsidy.

In reviewing NEM studies, Muro and Saha chose to focus on a handful of studies that show that net metering results in a benefit to all customers. In this small group of NEM studies, they included a study that E3 conducted for the Nevada Public Utilities Commission (PUC) in 2014–perhaps the most well-known and cited of the five studies included in the Muro/Saha paper. Very soon after the E3 Nevada study was published, the cost assumptions for the base-case scenario which showed a net benefit of $36 million to non-NEM customers (assuming $100 per MWh for utility-scale solar) were found to be incorrect, completely reversing the conclusion. The $36 million benefit associated with NEM for private rooftop solar turned into a $222 million cost to non-NEM customers when utility-scale solar was priced at $80 per MWh.[8] Today, based on the two most recent utility-scale contracts approved by the Nevada PUC, utility-scale solar has an average lifetime (i.e., levelized) cost of $50 per MWh, meaning that the NEM cost shift would be far greater today. In February 2016, the Nevada PUC stated that “the E3 study is already outdated and irrelevant to the discussion of costs and benefits of NEM in Nevada…”[9] Hence, because the E3 study for the Nevada PUC that the Muro/Saha paper included has been declared outdated and irrelevant to the discussion and because costs for utility-scale solar have declined significantly, that study does not show that NEM provides a net benefit.

No doubt there is an intense debate underway about NEM for private rooftop solar, and much has changed in the past two years in terms of both NEM policies and the growth of private solar projects:

• First, several state regulatory commissions now recognize that the NEM cost shift is both real and sizeable and that all customers who use the grid, including NEM customers, need to pay for the cost of the grid. As a result, many electric companies have proposed and state regulatory commissions have approved increases in monthly fixed charges over the past few years; this partially addresses the issue of NEM customers paying for the cost of the grid services that they use.
• Second and related, getting the pricing right for distributed energy resources of all types is important because we expect those resources to grow significantly in the future. Work is underway in this area and it is one focus of the New York Reforming the Energy Vision proceeding; but there is still much to be done.

By focusing on a select group of studies that show that NEM benefits all customers (as stated by the authors); by excluding the E3 study for the CPUC which was fundamental to the NEM cost shift debate; and by not providing an update on the NEM debate today, I believe that the Muro/Saha paper is misleading.

In the second part of their paper, Muro and Saha suggest some helpful regulatory reforms such as moving toward rate designs that “can meet the needs of a distributed resource future” and moving “toward performance-based rate-making (PBR).” Some electric companies have already implemented PBR or some type of formula rate and PBR is under discussion in several states.[10] Lawrence Berkeley National Labs is looking closely at this and related issues in its Future Electric Utility Regulation series of reports currently underway.[11]

Mura and Saha also suggest decoupling as a way forward–I disagree. In my view, decoupling is a not solution for private rooftop solar. Revenue decoupling is currently used to true-up revenues that would otherwise be lost due to declining electricity sales resulting from electric company investments in energy efficiency (EE). Decoupling explicitly shifts costs from participating EE customers to non-participating EE customers causing the same cost-shifting problem that is created by NEM. However, a fundamental difference is that the magnitude of the cost shifting onto non-NEM customers is on a much larger scale than the cost shifting due to EE. A recent study revealed that decoupling rate adjustments for EE are quite small–about two to three percent of the retail rate.^[12] In contrast, as described earlier in this paper, a NEM customer could shift a significant cost onto non-NEM customers (and the NEM cost shifting is essentially invisible to customers, which is one reason that NEM customers do not believe they are subsidized).[13]

Finally, Muro and Saha suggest that electric companies should invest in a more digital and distributed power grid. In fact, electric companies across the United States are doing just that. In 2015, electric companies invested $20 billion in the distribution system alone and this is expected to continue. Over the past five to six years, electric companies invested in the deployment of nearly 65 million digital smart meters to about 50 percent of U.S. households. In addition, electric companies are investing in thousands of devices to make the power grid smarter and more state-aware. Today, in states such as California, Hawaii, and Arizona, electric companies are investing to enable and integrate the distributed energy resources that are growing exponentially. And, in some states–where regulation allows–electric companies are offering rooftop solar or solar subscriptions to their customers.

No doubt, the electric power industry is undergoing a period of profound transformation–our power generation resource mix is getting cleaner and more distributed; the energy grid is becoming more digital; and customers have different expectations.[14]

Collaboration, good public policy, and appropriate regulatory policies are critical to a successful transformation of the power sector. In the context of this paper, this means reforming NEM so that private rooftop solar customers who use the energy grid pay for the grid. One straightforward approach is to require NEM customers to pay a higher monthly fixed charge thereby reducing the cost shift.[15] Ultimately the challenge is to make the transition of the electric power industry–including the significant growth in private rooftop solar and other distributed energy resources–affordable to all customers.

Lisa Wood is a nonresident senior fellow in the Energy Security and Climate Initiative at Brookings. She is also the executive director of the Institute for Electric Innovation and vice president of The Edison Foundation whose members include electric companies and technology companies.

       

On September 17, the Energy Security and Climate Initiative (ESCI) at Brookings hosted IEI Executive Director and ESCI Nonresident Senior Fellow Lisa Wood, editor of this publication, for a discussion of the evolving electric power industry and future trends. Brookings Institution Trustee and former CEO of Duke Energy Jim Rogers moderated the discussion.

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As Brookings described in an earlier commentary, while it is certainly true that there is a confluence of trends threatening the existing the utility business model, several key developments and challenges demonstrate that a more flexible distribution grid is already emerging with utilities at the center.

First, the power grid in the United States is evolving to meet three critical needs:

1. To integrate new energy resources.
2. To provide customer solutions.
3. To serve as an optimized and efficient platform for energy services and technologies.

Much of what we are talking about regarding innovations and change in the power sector – more distributed resources, more customer engagement and a smarter system that manages two way power and information flows – takes place on the electric distribution grid or distribution system. Thus, in a future that involves more variable generation and more distributed energy resources (such as distributed generation, demand response, energy efficiency and storage) a “flexible distribution grid” is critical. Across the United States, investments in grid technologies, digitization, data analytics, system monitoring, etc. are well underway to enhance the operational efficiency of the distribution grid (and distributed services) and to integrate new energy resources.

In fact, of the expected $100 billion in annual capital expenditures by the investor-owned utilities in the power sector over the next few years, more is going to the distribution system and less to generation. This alone signals the critical importance of the distribution system going forward. As Ted Craver, CEO of Edison International, recently stated: “We’re investing a lot in increasing the capabilities of that grid, of that wires system, of that network. That’s really where we investing the vast majority of our capital…and we wouldn’t do that if we didn’t think that that was actually essential to make all these other things work.”

One example of these capital expenditures is the deployment of smart meters. To-date, the electric utility industry has deployed over 50 million smart meters representing about 43 percent of U.S. households. We view smart meters as the building blocks to integrating new resources into the grid and providing new customer services and solutions (such as smart pricing, outage/restoration management, bill alerts, etc.). Thirty of the largest utilities in the United States have fully deployed smart meters to their residential customers.

Second, a multi-year integrated grid vision is critical for resource optimization.

This isn’t just about IT (information technology) and OT (operations technology) system integration or connecting legacy assets and systems to new ones. It is also about a vision to ensure that future electric distribution grid processes, customer interfaces, and services can be scaled. Scale is what creates efficiencies and cost savings.

Third, the states are leading the policy and regulatory discussion shaping the future of the electric distribution grid.

California, New York and Hawaii are the furthest along. In Hawaii, with a goal of 70 percent clean energy by 2030 for the HECO companies, the focus is on integrating distributed energy resources into the distribution grid. In California, as a result of a wide range of regulations, laws, and policies, the distribution grid is evolving into a network platform and will need to have the capability to integrate about 15 gigawatts of distributed energy resources by 2025. New York state has embarked on a comprehensive, market based plan which includes the Reforming the Energy Vision (REV) regulatory proceeding. The first part of REV involves a “collaborative process to examine the role of distribution utilities in enabling market-based deployment of distributed energy resources.” As a senior New York state official remarked to us, “New York wants to create a platform for third parties to innovate around needs of customers, with the utility getting paid for integrating something onto that platform. We need to figure out how to create markets to get innovation and capture value, and create a business that builds out capital from the customer, not the rate base.” Interestingly, New York is one of the states that has yet to make a significant investment in smart meters for its electricity customers.

Fourth, a critical element for realizing the future flexible and more distributed power grid is getting the pricing right.

A key element is understanding the complete value chain for all parties of distributed energy resources, including both demand-side resources such as energy efficiency and demand response as well as supply-side resources such as solar, storage, combined heat and power and other resources. Getting pricing right is, in part, what New York, California and others are trying to do. This is important because distributed energy resources and large scale renewable resources are increasing exponentially in the United States and are becoming a critical part of the 21st century power grid. For example, in 2010 the United States had just over 2,000 megawatts of solar capacity. In 2014, we expect to have over 14,000 megawatts of solar capacity with much of that growth in solar photovoltaics – a mix of large scale solar, community solar, and rooftop solar.

Fifth, the development of a flexible distribution grid will not be possible without technology and innovation.

Utilities and technology companies are, more than ever, joining forces to deploy an “intelligent, resilient, modern and digital grid.” However, more research and development funds to focus on energy technologies that will make a difference are absolutely critical. The Advanced Research Projects Agency – Energy (ARPA-E) is a key institution working in this area, but its budget of $289 million is a drop in the bucket relative to the Department of Energy’s total budget of $24.8 BILLION! Conversations between ARPA-E and the utilities have escalated with a recognition that technology and innovation are key drivers of business opportunities. While most grid-related projects supported by ARPA-E to-date have focused on transmission, the agency is turning increasingly to distribution – and addressing how a given technology works with other parts of the overall system.

In sum, the “flexible and evolving distribution grid” concept – harnessing the integration of new energy resources, customer solutions and grid efficiency and optimization – points to a central enabling role for utilities as grid builders, operators, and service providers. Many actors – not just in the utility industry – concur on this vital role for utilities. Jim Hughes, CEO of First Solar, Inc., recently stated that utilities need to position themselves as “trying to enable customer choice and innovation… and provide reliability.” And, Thomas Werner, CEO of SunPower, Corp., declared that “the idea that you’re going to eliminate the need for the grid or go off the grid is ridiculous.” Larry Ellison, the former CEO of Oracle, has often referred to the electric utility industry as the best plug-and-play industry in the world. Bob Rowe, president and CEO of NorthWestern Energy sees it this way: “The U.S. power grid, for most customers and most applications, is amazingly ‘plug and play’ in a way that is still aspirational in the IT world.” The challenge is figuring out the institutional, regulatory, and competitive frameworks that will lead to a flexible distribution grid platform that interconnects and enables all of the emerging energy technologies and services that customers want.

       

On September 19, the Energy Security Initiative (ESI) at Brookings hosted a discussion on renewable energy in Germany and Japan. This event served as the launch of ESI’s new policy brief, “Transforming the Electricity Portfolio: Lessons from Germany and Japan in Deploying Renewable Energy.” Report authors John Banks, a nonresident senior fellow with ESI, and Charles Ebinger, ESI’s director, joined ESI Nonresident Senior Fellow and Public Policy Consulting Principal Ron Binz in a panel discussion on the findings of the study. Lisa Wood, the executive director for the Institute for Electric Innovation and a nonresident senior fellow at ESI, moderated.

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Editor’s note: This piece originally appeared in the Institute for Electric Innovation (IEI)’s magazine
The Edge
. Lisa Wood, a nonresident senior fellow with the Energy Security Initiative, is the executive director for IEI and vice president of The Edison Foundation.

The integration of distributed resources and renewable energy is well underway. Distributed generation (DG) resources, such as rooftop solar systems, are growing and comprise a larger share of the energy resources on the nation’s power grid. As the costs of DG decline, it is critical that these resources are priced appropriately and that the subsidies that support DG are transparent to all parties—customers, regulators, legislators, solar providers, and DG advocates.

The Institute for Electric Innovation’s (IEI’s) recent issue brief, “Net Energy Metering: Subsidy Issues and Regulatory Solutions,” illustrates the subsidy created by current net energy metering (NEM) practices based on a typical residential customer in Southern California with a rooftop solar photovoltaic (PV) system. The results show that the size of the NEM subsidy in California today is overly generous and not transparent; most of the NEM subsidies go to affluent households (and are largely paid by less affluent households through their electric bills); and when a customer chooses to lease—rather than own—rooftop solar, most of the NEM subsidy is transferred to the leasing company. These are unintended consequences and need to be modified.

When a DG customer produces onsite energy, this reduces the amount of energy the customer purchases from the local utility. The customer avoids paying the portion of the energy rate that is designed to recover that customer’s share of the utility’s fixed costs for grid services. Hence, the source of the NEM subsidy is that DG customers do not fully pay for the grid services that they use. In addition, this NEM subsidy is mostly paid by non-DG customers. While the IEI issue brief looks specifically at the size of the NEM subsidy using California as an example, the lessons learned can be applied to other states with NEM policies.

Undo the Unintended Consequences

The legitimate purpose of a subsidy is to provide an incentive to pursue a desirable public policy. Subsidies should not be overly generous; the amount of the subsidy should be transparent; and the recipient of the subsidy should be clearly identified. The issue brief demonstrates that the current NEM approach in California fails all three tests.

DG customers who lease rooftop solar or enter into power purchase agreements (PPAs) with solar leasing companies accounted for about 75 percent of all new residential rooftop solar PV in California in 2013. Unfortunately, these customers receive only a small fraction of the NEM subsidy; the bulk of the subsidy goes to rooftop solar leasing companies.

According to the issue brief, the NEM subsidy alone is more than $20,000 for a 4-kilowatt (KW) rooftop solar PV facility that costs about $14,500 in California. This far exceeds what is necessary to incent rooftop solar PV. Combining both the NEM subsidy in California and the federal tax credit of roughly $4,300 (about 30 percent of the purchase cost), when a DG customer purchases rooftop solar, that customer receives more than $24,000 in subsidies for that rooftop solar PV facility.

It is important not just to understand the magnitude of the subsidy, but also to clearly identify the subsidy recipients. When a customer leases that same 4-KW rooftop solar PV facility, the entire federal tax credit of roughly $4,300 goes to the leasing company, and the NEM subsidy is distributed between the customer and the solar leasing company. Of the $24,000 in combined subsidies, the solar leasing company receives more than $17,000 (from both the NEM subsidy and the federal tax credit) and the customer receives about $7,000 (from the NEM subsidy).

Regulatory tools are available today, and in use in some jurisdictions, to reduce the unintended and excessive NEM subsidies to both customers and solar leasing companies, while also reducing the cost shifting onto non-DG customers.

• A “buy-sell” approach where DG customers purchase all of the power they use onsite at the utility’s retail rate and sell all of the solar power produced onsite at the utility’s avoided costs could eliminate the NEM subsidy and the cost shifting. However, the subsidy and cost shifting would be eliminated only if the prices paid for the solar energy produced by the DG facility were truly equal to the utility’s avoided costs.

• The issue brief provides estimates of how much the NEM subsidy would be reduced by using available regulatory tools, such as increasing the monthly customer charge (coupled with replacing the tiered-rate structure in California with a single energy rate) or implementing a buy-sell approach for DG customers.

The time to change net metering is now, and regulatory tools are available to do so. In fact, several states across the United States are now considering “value of rooftop solar” (VOS) approaches to DG; the VOS approach is a version of the buy-sell approach.

The VOS approach has two parts. First, the DG customer purchases all of the energy he or she consumes onsite from the utility at the utility’s retail rate. This ensures that the DG customer fully pays for the grid services he or she utilizes. Second, the utility purchases all of the solar energy produced onsite by the DG facility at the VOS rate (which hopefully represents the utility’s avoided costs). As indicated earlier, the subsidy and cost shifting are eliminated only if the prices paid for the solar energy produced by the DG facility are truly equal to the utility’s avoided costs.

Both the components of avoided costs and how to value each of them are highly controversial issues. In terms of the components of avoided costs, most would agree that avoided costs include: energy costs; transmission and distribution energy losses; and generating capacity costs. However, controversy typically arises over how to compute avoided transmission and distribution capacity costs and whether avoided environmental costs are appropriate to include. The components of avoided costs, the value of each cost component, and using consistent valuation approaches are equally important for a fair analysis.

VOS may be one approach for addressing the unintended consequences associated with NEM. However, the devil is in the details. To date, many of the proposed VOS approaches have resulted in simply swapping the NEM subsidy for the VOS subsidy. If the goal is to make progress toward pricing solar right, creating a new set of subsidies under VOS is not the answer.

       

VALUE OF THE GRID TO DG CUSTOMERS

Some advocates of distributed generation (DG) claim that the DG customer derives no benefit from being connected to the host utility’s distribution system. While it is easy to say that a DG customer is “free from the grid,” that is simply not true – even for a DG customer (or a micro- grid) that produces the exact amount of energy that it consumes in any given day or other time interval.

This paper describes how a DG customer (or a micro grid) that is connected to the host utility distribution system 24/7 utilizes grid services on a continuous, ongoing basis. The point is to recognize the value of these grid services and to develop a methodology for the DG customer to pay for using the services. The utility cost of providing grid services consists of at least four components – the typical fixed costs associated with: (i) transmission, (ii) distribution, (iii) generation capacity, and (iv) the costs of ancillary and balancing services that the grid provides throughout the day for the DG customer.

       

EXECUTIVE SUMMARY

The U.S. power system is the backbone of
the country’s economy. Yet, with growing
stress on the aging existing electricity grid,
increasing integration of information technology
with the power sector infrastructure, and an
imperative to reduce the environmental impact
of power generation, the system faces an unprecedented
range of economic, environmental, and
security-related challenges. The situation has
given rise to increased interest in the potential
for Distributed Power Systems (DPS): a combination
of distributed sources of power production,
and distributed energy storage. This study
examines the economic, environmental, and energy
security case for DPS. It finds that increased
penetration of DPS has the potential to make a
significant positive contribution to the US power
system. It also finds a strong case for DPS as a resource
for the defensive and offensive operations
of the U.S. military.

In general, the economics of DPS are still unproven:
using a traditional cost-comparison model,
our analysis shows that most DPS technologies
are currently uncompetitive when compared
with central station fossil-fuel generation. However,
in certain regions of the country, some DPS
technologies are already cost competitive with
large-scale fossil-fuel generation. These include
internal combustion engines with combined heat
and power; large-scale solar photovoltaic; and
medium and community-scale wind generation.
The economic analysis also shows that a moderate
price on carbon of $30 would increase the
competitiveness of some renewable energy DPS
applications. Moreover, many DPS technologies,
such as solar photovoltaic, are realizing rapid declines
in unit costs that are likely to continue with
sustained research, development and deployment
of such systems. Economic analysis and extensive
outreach to power sector stakeholders show that
the benefits of DPS are location and time-specific,
and that DPS is more valuable in areas with high
levels of system congestion or peak demand and
no excess capacity.

There is also widespread agreement among power
sector stakeholders that existing economic models
do not capture the full range of potential benefits
that DPS can provide. These include improved efficiency
of the distribution system, reduced strain
on the grid during peak demand period, greater
reliability, environmental and land-use benefits,
possible job creation, the harnessing of untapped
energy resources, and other region-specific benefits.
They also include the security value of DPS,
both as a means of decreasing the vulnerability
of the civilian grid to disruption and attack, and
as a resource for the defensive and offensive operations
of the U.S. military. In addition, many
stakeholders see that there is insufficient information
on the full spectrum of costs and benefits of
DPS.

Federal and state policy makers have an opportunity
to better capture the economic, environmental, and energy security benefits of DPS
through the implementation of policies that correct
market failures, provide incentives, remove
barriers, and promote the exchange of information
and education. To realize the full potential
of DPS, the federal government should: set broad
energy policies that account for the externalities
of carbon dioxide and other emissions; promote
sustained technology research and development;
conduct research on the impact of DPS penetration
on both reliability and security; support
DPS-related knowledge sharing and awareness;
and use procurement both in the civilian and
military sectors to increase DPS competitiveness
through increased scale. The U.S. military has a
particularly compelling incentive to adopt DPS,
which can help it meet its renewable energy and
energy efficiency goals; improve the security of
power delivery to bases at home and abroad; and
provide advantages for expeditionary activities in
theater. The military should consider distributed
generation and microgrids as an essential part of
its electricity generation strategy, and should develop
and deploy DPS technologies that increase
the efficiency of personnel in theater.

State governments should take a lead in DPS-specific
policy making. They should use policy tools
that differentiate between DPS systems according
to size. For small-scale customer generation, state
regulators and energy planners should encourage
net metering, reduce technical and non-technical
barriers to interconnection, and implement pricing
mechanisms that accurately value the power
produced from DPS. For larger systems that sell
power into wholesale markets, state policy makers
should adopt limited financial incentives aimed at
increasing the competitiveness of DPS over time.
Stakeholders agree that storage and combined
heat and power (CHP) have particular potential
for improving the efficiency and economics of the
U.S. power sector and, therefore, should be priorities
for targeted policy support.

The increased penetration of DPS has the potential
to make a significant positive contribution to
the U.S. power system and to the energy needs of
the U.S. military. As policy makers strive to meet
the challenges of the power sector in the 21st century
in an economic and environmentally responsible
way, this paper provides them with a set of
options for realizing that potential.

       

On September 11, the Brookings Institution’s Energy Security Initiative and Metropolitan Policy Program hosted a discussion on the challenges of modernizing the electricity grid. Federal Energy Regulatory Commission Chairman Jon Wellinghoff delivered a keynote address on the federal perspective. Following the chairman’s remarks, Charles Ebinger, senior fellow and director of the Energy Security Initiative, moderated a panel discussion on the governance issues in the electric transmission sector. Lynne Kiesling, senior lecturer at Northwestern University, moderated a panel discussion on the technological implementation and regulatory reforms necessary for the development of a national smart grid.

After each panel, participants took audience questions.