Will States, Cities, and Corporations Negate Trump’s Decision to Quit Paris Agreement?

by Bob Shively, Enerdynamics President and Lead Facilitator

President Trump’s June 1 announcement that the U.S. will pull out of the Paris Climate change and American flag in two directions on road sign. Withdrawal of climatic agreement.Agreement on climate change action[1] was greeted by predictable comments from the agreement’s supporters and opponents. But more meaningful was the reaction of various entities who will have much to say about what happens with America’s actual future emissions. Within days, states, cities, counties, universities, non-governmental organizations, and businesses stepped forward to pledge to work together to see the U.S. meet its goals with or without support from Washington.

Under the terms of the agreement, the U.S.’ exit would not be effective until November 2020, although the government could in the meantime simply not participate in any efforts to achieve its commitments.

What is the Paris Agreement?

It is an agreement negotiated under the United Nations Framework Convention on Climate Change (UNFCC), signed by 195 countries. (Of the countries who are part of the UNFCC only Nicaragua and Syria failed to sign.) The aim is to: a) hold down the increase in global average temperature to well below 2°C and to pursue efforts to limit it to less than 1.5°C above pre-industrial levels; b) increase the world’s ability to adapt to climate changes; and c) enable finance flows to facilitate a pathway toward low greenhouse gas emissions and climate-resilient development.
Under the accord, each country sets out voluntary goals for reductions in greenhouse gas emissions (called the Nationally Determined Contribution or NDC) and, in some cases, for financial aid to help poorer countries cope with climate change. The U.S. under President Obama pledged to cut U.S. greenhouse gas emissions 26-28% below 2005 levels by 2025 as well as provide $3 billion in aid.
The agreement included no enforcement mechanism, meaning it is up to each signatory to voluntarily meet its pledges.

As of June 19, nine states, 194 cities and counties, 306 universities, and more than 1,000 businesses had signed “We are Still In,” a statement confirming their commitment to support action to meet the U.S.’ contribution. Included in the statement:

In the absence of leadership from Washington, states, cities, colleges and universities, businesses and investors, representing a sizeable percentage of the U.S. economy will pursue ambitious climate goals, working together to take forceful action and to ensure that the U.S. remains a global leader in reducing emissions.

It is imperative that the world know that in the U.S., the actors that will provide the leadership necessary to meet our Paris commitment are found in city halls, state capitals, colleges and universities, investors and businesses. Together, we will remain actively engaged with the international community as part of the global effort to hold warming to well below 2℃ and to accelerate the transition to a clean energy economy that will benefit our security, prosperity, and health.”

Significant actions have already begun. The states have come together in the U.S. Climate Alliance. Cities formed the Mayors National Climate Action Agenda. And corporations have already become the largest buyers of renewable  power in the U.S. Earlier this month, California Governor Jerry Brown recently met with Chinese President Xi Jingping to discuss direct cooperation between China and California on climate change initiatives.

Paris Agreement map.png

Source: National Geographic, compiled by Riley D. Champine


The entities signing “We Are Still In” are not small players – they make up key energy users including states such as California and New York; cities such as Baltimore, Boston, Houston, Los Angeles, New York, Phoenix, and San Francisco; and corporations such as Adidas, Amazon, Apple, Facebook, Google, Microsoft, Nike, Target, and Walmart. According to the Rocky Mountain Institute, the cities and states who signed as of June 5 had a combined Gross Domestic Product (GDP) of $6.2 trillion and a population of 120 million, while the companies had a combined revenue of $1.4 trillion. This suggests that these entities make up about 10% of the world’s economy.

As of the last year that data is available (2015) the EPA states that the U.S. has reduced greenhouse gas emissions 11.5% below 2005 levels driven largely by energy efficiency and the shift from coal-fired electric generation to natural gas and renewable electricity. This has occurred without mandates at the federal level. So can state and local governments combined with the actions of market-based corporations continue the downward trend?

Amy Meyers Jaffe, executive director for energy and sustainability at the University of California, Davis thinks so. States Meyers Jaffe: “I personally think the market itself will deliver what we committed to without much intervention. There are very few states that aren’t going in the direction of energy efficiency and renewables.”[2]

I am inclined to concur. With renewable power now the cheapest electric source available in much of the U.S. (with natural gas being cheapest in most of the areas where renewables don’t rule) state utility commissions will likely drive utilities toward these sources in regulated states, and power markets will drive the shift in competitive states. The last key factor will be emissions in the transportation sector. If current efforts to develop competitive electric vehicles are successful, it seems likely that even without support from Washington the U.S. will meet its Paris Agreement goals.


[1] Under the terms of the agreement, the U.S.’ exit would not be effective until November 2020, although the government could in the meantime simply not participate in any efforts to achieve its commitments.

[2] https://www.scientificamerican.com/article/governors-pledge-climate-action-in-face-of-possible-paris-withdrawal/


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What Do Growing LNG Exports Mean for the U.S.?

by Bob Shively, Enerdynamics President and Lead Facilitator

In our latest blog post on LNG we explained what LNG is and how it is produced.  We then noted that LNG exports by the U.S. have grown substantially in the last year:

LNG exports


Now let’s explore what growing LNG exports may mean for U.S. and global natural gas markets.

U.S. LNG Export Capacity Will Increase Almost Seven-fold by 2020

The growth of exports in 2016 and early 2017 are just the start. With construction of additional export capacity ongoing at six different facilities, the U.S. is poised to have the world’s third largest LNG export capacity by 2020 (following Qatar and Australia). By the end of 2019, the U.S. is expected to have capacity of 68 million tons per annum (MTPA), which is equivalent to 3.1 trillion cubic feet (Tcf) of gas. By way of comparison, the U.S. consumed about 27.5 Tcf in 2016, meaning that if the export capacity were fully used (it won’t be) demand for gas would increase by more than 10%. And a second wave of export capacity projects is expected later, perhaps after 2025.

U.S. LNG Export Capacity
Source: EIA


U.S. LNG Exports Are Expected to Equal 11% of U.S. Production by 2025

According to EIA estimates, the U.S. will become a net exporter of natural gas next year.  Growth in LNG exports, coupled with growing pipeline exports, will flip the U.S. from its traditional role as a net importer to being a net gas exporter.

U.S. LNG is Shaking Up World Natural Gas Markets

Historically, most LNG has been traded under long-term contracts tying a specific liquefaction source to a specific destination with no flexibility to redirect supplies to markets offering a better return. In the last 10 years, the percent of LNG traded in shorter-term contracts (less than 2 years in duration) has increased from about 10% to close to 30% with more contracts allowing destination flexibility.

Pricing historically has been indexed to oil prices, but in recent years there has been some movement to instead price LNG relative to gas market hub prices in the destination marketplace. Also in this time, numerous countries have added the capability to receive LNG – the number of LNG-consuming countries has grown from 17 a decade ago to 39.  The development of off-shore floating storage and regasification units (FSRU) has allowed smaller markets to join the LNG marketplace, and the number of participating countries is expected to grow.

In the next few years, large volumes of U.S. LNG will enter the market with no destination limitations and with price indexed to Henry Hub, not oil.  This likely will have significant impacts as more and more LNG is traded in spot markets with the capability to chase the highest return and potentially land at a price significantly lower than supplies indexed to oil. Two potential impacts are prices around the world converging (which we are already seeing), and the potential for natural gas to price other fuels such as coal and oil out of the market, as we have already seen in the U.S.  A secondary benefit will be cleaner energy production as natural gas displaces more polluting fuels.

monthly average regional gas prices.png

Source:  International Gas Union (IGU) 2017 World LNG Report


The Impact of LNG Exports on U.S. Gas Markets Appears Small

U.S. producers expect to benefit from LNG growth. New markets are now available for their supplies, and there is the possibility that export profits could be higher than sales of gas at home. Meanwhile, consumers in the U.S. may be wondering what is in it for them.  While LNG exports certainly don’t help U.S. consumers, most analysts seem to agree that they won’t hurt customers all that much either. Clearly an increase in export demand has the potential to cause prices to rise. But most observers believe that the U.S. has ample supply to cover both consumer demand and exports while keeping prices at moderate levels.

A 2015 study performed for the U.S. Department of Energy concluded that “most of any U.S. LNG exports would be made possible by increased extraction rather than the diversion of natural gas supplies.” The key is for production to continue to increase. If producers find it difficult to produce low-cost shale gas supplies due to technical, political, or environmental reasons, then our conclusions could change quickly. So as with most things associated with natural gas, it will be important to keep a watchful eye on the market fundamentals.

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How the LNG Delivery System Works and What LNG Means for the U.S.

by Bob Shively, Enerdynamics President and Lead Facilitator

The winter of 2016/2017 was the first winter season with liquefied natural gas (LNG) exports from the continental U.S. Historically the U.S. exported small amounts of LNG from a facility in Alaska, but the first LNG exports from the Lower 48 began in February 2016 with a shipment from Louisiana’s Sabine Pass facility. Exports continued through the year and dramatically increased beginning in November. Countries receiving U.S. LNG supplies in the first year included China, India, Japan, Jordan, Kuwait, Mexico, Portugal, Spain, and Turkey.

LNG exports

Going forward through the remainder of the decade, export capacity is expected to continually increase with the completion of multiple projects. By 2020 export capacity will reach 8.6 Bcf/d, which if fully utilized would roughly be equivalent to 12% of the average annual demand of U.S. gas consumers.

In the Part Two of this two-part article, we will explore how LNG demand is expected to grow and how it may impact gas markets. But first, we will go back to the basics and review what LNG is and how it is produced.

What LNG is

In its natural state at atmospheric pressure and normal temperatures, natural gas is in gaseous form. It is most commonly transported via pipeline as it is too voluminous to be transported by truck or ship in quantities that are meaningful for most consumption.  But when natural gas is cooled below approximately -260 degrees Fahrenheit (-162 degrees Celsius) it becomes liquid and its volume is reduced by a factor of about 610.  The resulting liquid is called liquefied natural gas or LNG. Because its volume has been reduced dramatically, LNG can often be economically transported via ship or truck, and it can also be stored in above-ground tanks for use as gas distribution peaking supplies.


How LNG is Produced and Delivered

LNG Delivery System by Enerdynamics

(For a downloadable version of the above graphic, visit Enerdynamics’ website.)

Natural gas is produced from underground reservoirs, brought to the surface, and processed to remove impurities and valuable natural gas liquids (NGLs). To make LNG, natural gas from the production field is first processed and then cooled in a liquefaction plant. The LNG is stored at atmospheric pressure in double-walled cryogenic tanks that keep the gas cooled in a liquid state until a tanker is available.



LNG is then shipped in an LNG tanker, which is a double-hulled ship specially designed to keep the natural gas cool. Tankers move the LNG from the production area to a regasification terminal near the point of consumption. In most cases, regasification takes place at a terminal although in some cases this process occurs aboard the tanker (if the tanker is a regasification vessel).

If regasified on board the vessel, the gas is then put directly into an undersea pipeline that connects to the onshore pipeline grid. When not regasified on board, the LNG is off-loaded from the tanker into a storage tank similar to those used at the liquefaction plant.  When the gas is needed, it is taken from storage and sent through a regasification plant where it is warmed in a carefully controlled environment so that the LNG reverts to a gaseous state, and the pressure is increased to match the pressure of the pipeline it is entering. Finally, the gas is put into the pipeline where it is commingled with other gas supplies and delivered to consumers.

Why does LNG matter?

With the development of new LNG export facilities, there is the potential the U.S. could become the world’s largest exporter of natural gas by 2030. This could prove to be an economic boom to U.S. gas producers, but it also may put pressure on the environment and the price paid by U.S. gas consumers. Now that you understand how LNG is produced and delivered, our next blog post will more thoroughly explore the future of U.S. LNG exports.

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Energy Books to Read This Summer

by Bob Shively, Enerdynamics President and Lead Facilitator

Books to read concept on blackboard with empty paper sheet

Ready for summer and want to catch up on your energy reading?  Want some good books to give you an in-depth view of the current energy industry and how rapidly it is changing? Here, in no particular order, are current books we recommend:

  1. The Quest: Energy, Security, and the Remaking of the Modern World, by Daniel Yergin

    Yergin originally came to fame with his Pulitzer Prize winning book The Prize, which chronicled the history of the oil industry through the 1991 Gulf War. His follow-up book expands to consider the whole energy industry with coverage of oil and gas since 1991 plus electricity, climate, renewables, and the road to the future.  If you want to get a big-picture history of the energy industry in 717 pages, there is no better source than The Quest.

  2. America’s Utilities, Past Present and Future, by Leonard S., Andrew S. and Robert C. Hyman

    If you want a better understanding of electric utilities, then turn to the latest edition of America’s Utilities. Originally written by long-term utility industry expert Leonard Hyman, the latest edition has been updated to include the recent evolution of the electric industry. Here you can learn the principles behind how utilities run their business, the history of utilities, how they are regulated, and what the future may hold.

  3. The Grid: The Fraying Wires Between Americans and Our Energy Future, by Gretchen Bakke

    This is one we haven’t read yet, but we have heard Bakke interviewed and as a cultural anthropologist she carries an interesting perspective on our grid. Not sure I’d agree with the “Fraying Wires” subtitle, but from what readers have told me, the book does a good job of discussing our electric grid from a holistic viewpoint including technology, legal, regulatory, and environmental perspectives in a language anyone can understand.

  4. Reinventing Fire: Bold Business Solutions for the New Energy Era, by Amory B. Lovins and Rocky Mountain Institute

    Way back when I was a young engineer at Pacific Gas and Electric, the story went that company executives would hide in their offices when Amory Lovins was known to be the in the building. Why? He was a vociferous advocate for what then was considered a radical concept — demand side management. Now demand side management has become mainstream, but Lovins is still pushing corporations and governments around the world to continue an energy transformation from fossil fuels to clean energy. Reinventing Fire lays out a clear and compelling roadmap for how the transition can be effectively implemented. There is perhaps no better view of the future of the energy industry.

  5. Powering Forward: What Everyone Should Know About America’s Energy Revolution, by Bill Ritter

    The former governor of Colorado and current director of the Center for New Energy Economy at Colorado State University lays out his vision for our energy transition from a policy viewpoint. Perhaps most compelling is Ritters’ vision that the transformation will occur at the state and local levels regardless of what is occurring in Washington.

  6. Understanding Today’s Natural Gas Business and Understanding Today’s Electricity Business, by Bob Shively and John Ferrare

    We can’t let a list of good energy books go out without including our companion industry primers! These books are written in straightforward, easy-to-understand language and are loaded with interesting charts and illustrations to help readers digest energy industry concepts and terms quickly and easily.

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Storage Changing Paradigms in Electric System Design and Operations

by Bob Shively, Enerdynamics President and Lead Facilitator


“Building networks to accommodate peak demand – or lulls in supply – requires overbuilding of infrastructure that leads to extra costs and system inefficiencies.”
Sam Wilkinson, IHS [1]


As we explored in last week’s blog, the gas system has optimized the mix of pipeline capacity, storage, and customer demand management to reduce the costs of building expensive infrastructure.

While the electric grid has utilized demand side management to reduce peak capacity needs, it until recently only had one cost-effective form of storage — pumped hydro — which is only available in limited geographic regions. (As of 2015, the U.S. had 156 pumped hydro plants that made up 2% of the peak summer capacity.) Hence almost all fluctuations in demand are met by adjusting supply through power plant dispatch.  The result is significant power plant capacity that sits idle much of the year.

However, recent advances and falling costs in electric storage technologies, especially lithium ion batteries, suggest that a new paradigm of optimized storage throughout the grid may rapidly change principles of electric system design and operations.

“Similar to the rise of wind and solar generation in the last 15 years, we are now starting to see exponential growth in the deployment of battery-based energy storage systems, thanks in part to a rapid decline in pricing for lithium-ion batteries.” [2]


Cost declines in lithium ion batteries
    Source:  Bloomberg New Energy Finance

The potential for cost-effective electric storage is coming none too soon — the system that once had to accommodate fluctuations in demand now needs to also accommodate lulls in supply as more renewables with variable output are connected to the grid. This is true on the bulk power system as indicated by the now famous California duck curve as well as on specific distribution circuits as demonstrated by the Hawaii “Loch Ness Monster” curve.

duck curve

loch ness curve

Fortunately, the modular nature of batteries allows for the possibility of placing storage on the grid where it is most beneficial, ranging from centralized renewable generators all the way to behind the customer meter. Making distributed storage most useful will require communications systems that allow storage to be operated as part of the greater distribution and/or transmission system. Again, developments in battery technologies are being accompanied by rapid expansion of digital communications networks throughout the distribution grid all the way to the customer meter.

storage deployment across grid

Source: EIA Today in Energy  

Many utilities are now implementing various storage projects to develop the knowledge that will result in growing use of developing storage technology. We will look forward to watching the evolution of the electric grid as cost effective storage allows new forms of optimal design and operations.


Want to learn more about how electric systems work?  Look into Enerdynamics’ Electric Systems Fundamentals seminar available online or live. And if you want to learn more about energy storage, contact us about Enerdynamics’ live seminar Energy Storage: Applications, Technologies, and Economics.


[1] From Reaching peak performance: What the electric power sector can learn from society’s other vital networks, Sam Wilkinson, available at https://cdn2.hubspot.net/hubfs/2810531/Collateral/AES%20ES%20White%20Paper%20-%20IHS-Markit%20The%20New%20Energy%20Network.pdf

[2] Ibid, p. 3

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Storage in Design of Gas and Electric Systems

by Bob Shively, Enerdynamics President and Lead Facilitator

“Building networks to accommodate peak demand — or lulls in supply — requires overbuilding of infrastructure that leads to extra costs and system inefficiencies.” ~ Sam Wilkinson, IHS [1]

A key to efficient design of gas networks is the interplay between pipeline capacity that can deliver supply into a region and storage that can supplement supply when flowing pipeline gas is insufficient to meet demand.

As costs for certain electric storage technologies decline, designers and operators of electric systems are beginning to envision a future where electricity storage will be used to significantly improve the efficiency of electric networks in a similar way. Let’s explore the principles behind use of storage to improve system efficiency and look at how storage is used in gas systems. Next week we will discuss how it may be increasingly used in electric systems.

As described by Sam Wilkinson in the IHS whitepaper Reaching Peak Performance, networks are commonly designed to ensure that supply can meet demand even during periods of unusually high demand and or lulls in supply (although this is not always true — failure to build for peak demand is why we end up sitting on the freeway during rush hour or can’t text on our phones during a popular sporting event). Of course, building for peak demand is expensive. The result is that consumers must pay for facilities that sit idle much of the time.

An example of this from the electric world: the California ISO has a typical annual peak load exceeding 46,000 MW while the typical average annual load is more like 22,000 MW. To ensure the peak can be met, the California system maintains about 55,000 MW of capacity plus transmission to import power from out of state. This means that almost half of the system is underutilized during numerous hours of the year. Indeed, looking at the load duration curve for California shows us that the last 15,000 MW of supply is needed for less than 10% of the hours of the year.

Hourly demand in the California ISO for typical summer week

CAISO demand

California load duration curveCAISO load duration curve

Similar disparities exist for gas supply and demand. A typical annual average gas demand in California for “normal” weather is around 6 Bcf/d. This rises to about 7 Bcf/d for a year that includes a cold winter (lots of heating load) and a low hydro year (lots of gas power plant demand). Yet the highest daily sendout recorded in recent years was 8 Bcf/d in the summer and 11 Bcf/d in the winter.

How Gas Operators Use Storage to Meet Peak Demand

Absent storage, the gas companies in California would need to build over 11 Bcf/d of pipeline capacity into the state to ensure ability to meet the peak. And a similar effort would be required to match capacity and peak demand for each local transmission line and each distribution feeder serving a neighborhood. But luckily natural gas can be stored — in the pipeline itself, in underground reservoirs, and in above-ground tanks.  This gives operators the flexibility to pack extra gas into pipelines prior to expected cold days and to draw from underground storage when flowing supplies are insufficient to meet demand.

gas storage slide

California also uses utility regulations that require large industrial and power plant customers to accept curtailment of supply on peak demand days unless the customer wants to pay extra for firm service. Thus, on peak days, there can be a demand response as utilities notify large customers they must curtail gas use. This means that portions of the gas system do not have to be sized to cover these customers on extreme days.

The result of mixing and matching pipeline supply capacity, underground storage capacity, storage in the pipe, and demand response is that California has reliably run its gas system with the approximately 8 Bcf/d of pipeline capacity and 4.5 Bcf/d of storage capacity. This is significantly more efficient than building enough pipeline capacity to cover peak needs.

Historically, the electric industry has built supply capacity to cover peak needs, plus an additional 15% reserve margin for ensuring reliability. In next week’s blog, we’ll explore how storage and demand response may change the paradigm for electricity, allowing the industry to attain some of the system efficiencies gas has achieved.

Want to learn more about how gas systems work?  Look into Enerdynamics’ Gas Systems Fundamentals live seminar.


[1] From Reaching peak performance: What the electric power sector can learn from society’s other vital networks, Sam Wilkinson, available at https://cdn2.hubspot.net/hubfs/2810531/Collateral/AES%20ES%20White%20Paper%20-%20IHS-Markit%20The%20New%20Energy%20Network.pdf

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Demand Side Management Key to California’s Changing Grid

by Bob Shively, Enerdynamics President and Lead Facilitator

The role of demand side management (DSM) programs traditionally has been three-fold:
Eco Time or washing

  1. reduce overall usage through energy efficiency (EE) efforts (for example, weatherization or more efficient light bulbs)
  2. reduce usage at times of system peak or system shortages (for example, direct load-control switches on air conditioners or hot water heaters that allow interruption by the utility)
  3. shift demand from peak periods to off-peak periods (for example, ice storage systems for building cooling)

The overriding purpose of such DSM programs has been to offer an alternative to building costly new power plants. But as the grid changes with the rise of renewable and distributed energy resources (DER), the role of DSM itself is positioned for dramatic change.

With California’s renewable goal of 50% by 2030, grid issues are extreme. To determine how DSM might best help support the grid, the Lawrence Berkeley Lab recently worked with consulting firms E3 and Nexant along with various market participants to perform the study 2025 California Demand Response Potential Study – Charting California’s Demand Response Future. Over a two-year period, the team used customer-specific data to evaluate end-use and technology capabilities while focusing on two questions:

  1. What types of demand response services can meet California’s future grid needs?
  2. What is the expected resource base size and cost for demand response services?

A key part of the study was to move away from just thinking about traditional types of DSM and to ask what specific services does the grid need to best utilize DSM resources. The study identified four demand response (DR) service types that will be most helpful:

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The shed service is similar to traditional load management programs where load such as air conditioners or hot water heaters are curtailed during peak times.


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The shift service is similar to traditional peak demand shifting, except that in the future grid it is expected that it will be necessary to shift load into the middle of the day to utilize the significant solar generation that will come onto the grid.


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The shape service accomplishes the same load movement as shed or shift, but instead a service where the load is moved only when needed, the shape service results in permanent changes in load shapes.


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The shimmy service moves loads up or down quickly in response to specific system needs, possibly in time increments as small as every 5 minutes or even less.

To summarize the time frames in which each service would interact with the grid:


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Likely end-use technologies included in California programs are:

  • electric vehicles (EVs)
  • behind-the-meter batteries
  • air conditioning and HVAC systems
  • pool pumps
  • commercial lighting
  • commercial refrigeration
  • large industrial processes
  • agricultural pumping
  • data center loads
  • wastewater treatment and pumping

The study’s medium demand response scenario for California found that the current time-of-use (TOU) rates and critical peak pricing (CPP) programs provide 1 GW of shed and 2 GW of shift. New programs could provide up to 10 to 20 GWh of daily shift, 2 to 10 GW of cost-effective shed, and 300 MW of load-following or regulation shimmy. So clearly there is significant potential here.

What is needed to make this happen?

The study cover letter from the California Public Utilities Commission (CPUC) suggests that key steps include:

  • Investing in the integration of demand response into wholesale markets where it can be dispatched consistent with locational marginal prices
  • Enabling a new generation of demand response aggregators capable of delivering tailored options that work for customers with unique needs
  • Committing to default TOU rates for all customers
  • Committing to a greater differentiation of incentives based on relative locational value (meaning that DSM provided at one location might be paid more than the same DSM provided at a less valuable location)

As the grid continues to evolve, it will be necessary to reformulate traditional DSM programs to get the most potential from available flexible customer loads. Our expectation is that load resources will be increasingly important in allowing grids to integrate large amounts of renewables at the least cost possible.

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