Utility Investments in Emerging Technologies May Transform the Traditional Grid

by Bob Shively, Enerdynamics President and Lead Instructor

Utilities are often criticized for being too conservative and living in the past rather than466470105 (2) innovating to meet the future. With recent controversies over solar net metering, opposition to energy efficiency programs in some states, and opposition to the EPA’s Clean Air program, it would be easy to assume that utilities are determined to use lobbying clout to craft regulatory rules that will keep them comfortable in their historic way of doing business. But industry observers who believe this may be missing the true story.

Utility Dive recently surveyed over 400 utility executives for the State of the Electric Utility 2015 survey (available for download here).

Included in the study’s finding is the following:

Top three emerging technologies survey
It is illuminating to note that the three central generation technologies (natural gas peaking units, environmental upgrades, and carbon capture and storage) are at the bottom of this list. Meanwhile, renewables and “future grid” technologies such as storage, energy efficiency, demand response, and microgrids are popular. If utility executives indeed act on their convictions, we may see a more rapid transformation of our traditional centralized grid than many observers have envisioned.

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The Future for Utilities: More Efficiency and Less Fossil Fuels

by Bob Shively, Enerdynamics President and Lead Instructor

Enerdynamics recently released an update of its Electricity Flow infographic (click on infographic to enlarge):

2013 electricity flow infographic v3

This graphic is based on data from the Energy Information Administration and shows the input fuels, conversion losses, transmission and distribution losses, and end-use consumption through the electricity delivery chain. It is an easy way to quickly view how we in the U.S. create electricity and how we use it.

What’s interesting is to compare this 2013 data (the most recent available) to the data from five years ago, just before the recession hit.  Here are the three trends that jumped out at us when comparing 2008 to 2013 data:

1. Electric demand is flat even with increasing economic activity

electric use vs GDP

Despite a 9% increase in U.S. gross domestic product (GDP) since 2008, electricity use has not increased. This is primarily due to improvements in energy efficiency. Many people intuitively believe flat demand is due to a decrease in industrial activity and a shift in our economy to services. But in fact, industrial use has declined by 3% over the five years while the U.S. Industrial Production Index increased by 2.5%.

2. Coal-fired generation is being replaced with natural gas and renewables

change in output since 2008

Over the five-year period, the fuel used to generate electricity has changed dramatically.  Coal use declined by 20% while natural gas and renewable use increased by 24% and 31%, respectively. This trend is likely to continue as numerous coal units have recently been or are soon to be retired and as new environmental regulations make it less economical to utilize coal-fired generation.

3. A transition to a post-fossil fuel world may be beginning

fossil fuels used to generate electricity

The amount of fossil fuel energy used to generate electricity has declined by 9% while total electric output has been flat. This likely is the beginning of a long-term transition away from fossil fuels. The trend will be furthered over the next few years by increasing development of renewable projects and the opening of multiple new nuclear units in the U.S. Certainly there is still an open question of how far we can go in generating electricity from non-fossil fuels, but it is clear that a movement in that direction in underway.

As these three trends indicate, we are in the midst of a dramatic transformation in our nation’s electricity consumption and generation.

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Why Are Energy Prices Still Rising in New England?

by Christina Nagy-McKenna, Enerdynamics Instructor

In his inauguration speech on January 8, 2015, Massachusetts Gov. Charlie Baker said the following related to energy in his state:

“But as we begin the new year, families and businesses across New England are being hit with unprecedented increases in their energy and electric bills. At exactly the same time energy prices across the rest of the country are falling. This increase is being driven in large part by inadequate delivery systems, the result of poor planning and coordination.”[1]

NE natural gas supply system

Source: U.S. Energy Information Administration

High natural gas prices in the Northeast are not new or unexpected. Algonquin City Gate prices into Boston and Transco Zone 6 New York prices are consistently among the highest in the U.S. market. In 2014, 2 Bcf/d of new capacity was added to the Northeast, but most of it was not destined to help New England. Last year’s polar vortex breakdowns that blasted the Northeast in arctic temperatures exposed New England’s extreme vulnerability as natural gas spot prices climbed as high as $78/MMBtu.[2]

A graphical display of what happens during a polar vortex breakdown is shown below, with a normal vortex on the left and one that has broken down on the right. As the Northeast struggled to cope with the unexpectedly frigid weather from the two polar vortices that struck last winter, New England’s natural gas and electricity prices soared.

polar vortex breakdown

 Image Credit: NASA Earth Observatory

The underlying problem for the New England market is fairly basic: inadequate pipeline capacity. However, the problem is compounded because it leads to price spikes during peak demand for both natural gas customers and electric generators who are increasingly depending on natural gas to fuel their power plants.

Due to geological constraints, there is no locally available gas storage that would help smooth out peak demand. New England imports LNG, however, competition for LNG is global so it is often more expensive than U.S. natural gas. While imported LNG can help ease peak demand shortages, it cannot reduce overall energy costs. The solution to this myriad of issues is complicated and involves spending money to expand the current pipeline infrastructure.

Algonquin Gas Transmission and Tennessee Gas Pipeline, the largest suppliers of natural gas to the region, have already announced plans to increase pipeline capacity by 4.1 Bcf/d by the end of 2018.[3]

Pressure from the demand side will continue as New England must either replace 3,400 MW of coal, oil, and nuclear generation that will be retired by the end of 2018 or find some way to reduce its demand by that amount.[4] Natural gas-fired generation has grown in the meantime as New England replaced some of its older, fossil-fuel plants with cleaner-burning natural gas-fired plants. The graph below from ISO NE shows the rapid growth of natural gas-fired generation from 2000 to 2013 and its forecasted growth by 2020.

system capacity by fuel typeSource: ISO-NE

The growth of natural gas-fired generation in New England only puts more pressure on the constrained gas infrastructure. When spot natural gas market prices spike, it means generators also pay more for their gas, and then end-use customers pay more for their electricity. Thus, we have circled back to the problem as outlined by the new governor: Consumers in New England are paying more for energy than those in other parts of the country. The solution to build more pipeline infrastructure may not be particularly edgy, complex, or technologically exciting, but it will lead to a solution.

 Footnotes and other resources: 

[1] Text of Charlie Baker’s Inauguration Speech, January 8, 2015, The Boston Globe.

[2] Algonquin City Gate (Boston) natural gas spot price on January 23, 2014, SNL.

[3] Today in Energy: 32% of Natural Gas Pipeline Capacity into the Northeast Could be Bidirectional by 2017, December 2, 2014, U.S. Energy Information Administration

[4] Resource Mix, ISO New England, http://www.iso-ne.com

Polar Vortex Review: Natural Gas Perspectives, Adams, Briana and ICF International, 2014.

What is the ‘Polar Vortex’ Sweeping Across the U.S., and How Did it Form? The Journal.ie, January 4, 2014.

Natural Gas Weekly Update, January 28, 2015, U.S. Energy Information Administration.

Short-Term Energy Outlook, January 13, 2015, U.S. Energy Information Administration

Today in Energy: December Natural Gas Prices Spike in Boston, December 3, 2013.

Today in Energy: New England Sport Natural Gas Prices Hit Record Levels This Winter, February 21, 2014.

Today in Energy: Boston, New York City Winter Natural Gas Prices Expected to Remain High, November 24, 2014.

Today in Energy: New England Generation Fuel Mix Changes Likely as Vermont Yankee Nuclear Plant Retires, February 2, 2015.

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New Models Emerging as Potential Future of the Electric Distribution System, Part II

by Bob Shively, Enerdynamics President and Lead Instructor

Last week we looked at the Distribution System Platform Provider or DSPP, one of two new models emerging as electric utilities and their regulators work to redefine the future of the electric distribution utility.Electric distribution

This week let’s look at a second model, the Distribution System Operator or DSO.

The DSO presents perhaps an even more radical concept. This model has been proposed by former FERC chairman Jon Wellinghoff as well as authors at the CalTech Resnick Institute[1]. The DSO would break up the distribution business in a similar way that the bulk grid in many U.S. regions was disaggregated through the creation of Independent System Operators (ISOs). These ISOs became responsible for generation dispatch, transmission system operations and planning, and facilitation of wholesale markets.

The DSO would provide the same function for distributed resource dispatch, distribution system operations and planning, and facilitation of distributed markets. Like ISOs, the DSO would be an unbiased entity without ties to any market participant. To facilitate active retail markets, the DSO would bid aggregated distributed resources into competitive ISO wholesale markets in competition with centralized generators. While no states have yet moved forward with the DSO model, it is in the informal discussion stage at some commissions. 


Of course, in the utility business significant change doesn’t happen overnight. But we can be watching states such as California, Hawaii, Massachusetts, Minnesota, and New York to get an idea of where the future of the distribution utility may be headed.


[1]  See http://www.fortnightly.com/fortnightly/2014/08/rooftop-parity

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New Models Emerging as Potential Future of the Electric Distribution System, Part I

by Bob Shively, Enerdynamics President and Lead Instructor

“Many of the current disrupters have the potential to fundamentally change the distribution system: smart grid sensors coupled to new data-crunching resources, distributed generation, distributed storage, automated demand response, smart appliances, electric vehicles, and more.”[1]

As technologies associated with electric distribution and customer energy usage rapidly evolve, electric utilities and their regulators are working diligently to redefine the future of the electric distribution utility.

One possibility is to try to evolve existing models through the use of incentive regulation and integrated resource planning traditionally used for generation and transmission planning. States such as California and Hawaii are moving down this road through recent regulatory initiatives.

But others believe that in a marketplace characterized by competition and innovation, depending on regulatory proceedings and utility-planning processes will stifle growth. Two other models have evolved in an attempt to create an environment where competitive forces can drive change. These models are called the Distribution System Platform Provider or DSPP and the Distribution System Operator or DSO. This article focuses on the DSPP model, but next week we’ll examine the particulars of the DSO model.

The DSPP is being developed in New York’s Reforming the Energy Vision proceeding designed to radically restructure the role of the electric utility and the way that regulation is implemented[2]. Under New York’s vision, the regulated electric distribution company would:

  • coordinate customer distributed resource activities to optimize use of energy efficiency, demand response, distributed generation, and microgrids
  • provide a platform for third-party providers to offer services to customers

The DSPP would own and operate all distribution utility assets and the New York Public Service Commission would oversee the utility through outcome-based incentive regulation. Here’s a visual of what that might look like:

Read more about how New York is forging a path for the DSPP model in Utility Dive’s article “Is New York the future of the utility industry?

Next week we’ll look at the more radical Distribution System Operator or DSO model and who is advocating it.


[1] Energy Experts Unplugged…Volume 6 available at http://americaspowerplan.com/energy-experts-unplugged-volume-6/

[2] See http://www3.dps.ny.gov/W/PSCWeb.nsf/All/26BE8A93967E604785257CC40066B91A?OpenDocument

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Will a Gulf in Energy Services Become the Next Digital Divide?

by Bob Shively, Enerdynamics President and Lead Instructor

Concerns over the Digital Divide are widespread. As described by Internet World Stats:

“The Digital Divide, or the digital split, is a social issue referring to the differing amount ofiStock_000016130151_Large information between those who have access to the Internet (especially broadband access) and those who do not have access.”[1]

Similarly, significant attention has been paid to the lack of access to reliable grid power in certain regions of the world. [2] But here in the United States, another divide may be coming — the gulf between energy services available in competitive retail markets as compared to utility services available in markets where the utility company is the only retail provider.

There was a time when phone service — local, long distance, and hardware — was provided by the Bell Service monopoly, colloquially known as “Ma Bell.” Imagine if today’s smart phones, texting, apps, and other services we depend on were all delivered by just one regulated monopoly company. Would such choices and “extras” even exist? Now look at this map showing where competitive electric retail services are open to customers in the United States and Canada:

To all of you living in blue areas on the map, will you soon feel like a 20th century Ma Bell customer surrounded by states and provinces with 21st century technology and services?

But, you might argue, electricity is electricity and all that matters is price and basic reliability, right? Wrong. Already electric retailers in some states are offering various interesting services to entice and better serve customers. Examples include:

  • Direct Energy offers various rewards programs to their customers
  • Comcast and NRG’s Energy Plus retailers are concluding a test program in Pittsburgh that bundles services such as cable TV, electricity, and home automation with perks like free HBO or Showtime and free gift cards for signing up
  • NRG offers eVgo, which provides various electric vehicle charging services to residential and business customers
  • Numerous retailers in the Northeast offer demand-response related programs
  • Green Mountain Energy offers various renewable programs including solar installation, buy-back of excess solar generation, and solar community projects with bill credits

Over the next decade, the potential for more sophisticated services is likely to explode. We have started to see this as both utilities and retailers are creating services around Google’s Nest thermostat. Soon our homes will be inhabited by the “Internet of Things,” meaning that almost all our device and appliances will be connected.

According to the website DataFloq.com the number of smart devices on the planet will increase from two billion in 2006 to 200 billion by 2020. This is equivalent to 26 smart devices for every person on the planet![3]

Electricity’s future may lie in smart devices each bidding to buy power from a competitive marketplace only when the form of power one desires is available. That might be low-priced power, green power, or some other product related to what one personally values. And it is likely that the future will offer ways to increase efficiency that will result in many new ways of using electricity with little impact on one’s total monthly bill.

Of course, utilities can offer such services, too. But with no profit motivation, the often stifling effect of regulation, and the lack of competition to drive innovation, it is hard to imagine how utilities will keep pace. Perhaps the utilities will find a way to open their systems to third-party service providers without giving up the supply function, but this seems much harder than simply having open retail competition.

So the question remains, will we soon see a new push for retail competition, or will we simply become a country with a wide gulf in energy service availability?


[1] The Digital Divide, ICT and the 50×15 Initiative, http://www.internetworldstats.com/links10.htm

[2] Modern Energy for All, http://www.worldenergyoutlook.org/resources/energydevelopment/

[3] See https://datafloq.com/read/internet-of-things-will-make-our-world-smart-infographic/302

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Shale Gas Roils Gas Markets

by Bob Shively, Enerdynamics President and Lead Instructor

If there’s one thing certain about natural gas markets it’s that they are always subject to change. In the last decade, the shift in the U.S. supply-and-demand mix with the influx of screen_marketsshale gas has been widely discussed. But less discussed is how the locational change in gas production is fundamentally altering the gas marketplace. Let’s explore this transformation and some of its key impacts.

As noted in a recent Reuters article[1], Henry Hub trading volumes on the Intercontinental Exchange (ICE) have shrunk by 70% in the last five years while trading in regional hubs has grown significantly. Notable changes include:

  • Trading in the Dominion South Hub, the largest hub in the Marcellus shale gas region, is now almost double the Henry Hub volume. This reflects changes in gas production.
  • Gulf of Mexico production has shrunk from 20% to 4% of U.S. production.
  • Production in the Marcellus region has risen to 20% of U.S. production and is expected to continue its growth this winter.

As is expected, such shifts are causing fundamental changes to the gas marketplace:

  • Gas flows are dramatically evolving. The mid-Atlantic and Northeast states were traditionally fed mainly by Gulf supply with additional supplies from Canada. This winter, production from the Marcellus region is expected to be sufficient to serve all of Pennsylvania, West Virginia, New York, New Jersey, Delaware, Maryland, and Virginia demand.
  • Gas prices in the mid-Atlantic and Northeast states have dropped dramatically and are likely to remain low except during very high-demand days when pipeline capacity is insufficient. The long suffering consumers in these regions may suddenly become favored.
  • For many regions, it no longer makes sense to price or hedge off Henry Hub since prices are being driven by local production relative to local demand. Perhaps Henry Hub will no longer be viewed as the continental pricing point.
  • Gas pipeline construction is racing ahead to move gas from the Marcellus region to other markets, including moving gas south to Henry Hub and the Southeast. Henry Hub appears poised for another gas price battle between supplies from the Marcellus, Permian, Anadarko, Barnett, and Gulf regions. In the short term, prices may fall well below the recent $4 averages.
  • Low prices will boost ongoing demand growth with additional gas-fired power generation, large industrial facilities, and LNG export projects.

What does this mean for the longer term? One scenario is that producers — hit by low gas prices and maybe also low oil prices — will dramatically cut back drilling and exploration. Then, later in the decade just as all the new demand projects come on line, production could drop and lead to a significant price increase. This would be similar to the numerous boom-bust cycles I have seen in my 30 years in the energy business. Whether shale production will make it different this time remains to be seen.


[1] See Henry Hub, King of U.S. Natural Gas Trade, Losing Crown to Marcellus, September 25, 2014.

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