Who Do You Want to Provide Your Energy Services in the Future?

by Bob Shively, Enerdynamics President and Lead Instructor

“…our customers are the same people who dropped their landlines for cell phones, then switched wireless carriers to get the latest, greatest smart phones.  They cut their cable TV packages to the bare minimum and stopped renting DVDs from Blockbuster…”
~ Michael T. Burr, Editor-in-Chief of Public Utilities Fortnightly

In Enerdynamics’ seminar titled The Future of the Utility we explore scenarios on how
consumers may buy energy services in the future. Historically we think of buying our energy services from our local electric and gas utilities. That is, of course, if we even think about the commodity we buy as a service.

In some states, consumers have gained experience with energy retailers through deregulation of the commodity function, allowing service providers to sell gas or electricity directly to consumers[1]. Although consumers probably haven’t thought much about future energy services, many energy insiders envision a future world where energy services may become as diverse and numerous as services for your cell phone or multimedia delivered via your internet connection.

If this does occur, a key question is who will provide these services? Will utilities transform themselves into energy service providers, will new large energy retailers emerge, or will existing consumer-oriented companies move into the energy space? In our seminar, we ask the following question:

For electric services you might buy in the future, from whom do you want to buy them?

  • Your local electric utility
  • Apple
  • AT&T
  • Comcast
  • Ford
  • Google
  • An unregulated electric retailer
  • Someone else (who?)

Responses typically look like this:

Energy services provider poll answers

This suggests that utilities may fair best by finding ways to partner with consumer-oriented technology companies that are known and trusted by consumers. Who do you want to provide your future energy services? Share your thoughts in the comments section of this blog post!


[1] See “Will a Gulf in Energy Services Become the Next Digital Divide?” at http://blog.enerdynamics.com/2015/01/22/will-a-gulf-in-energy-services-become-the-next-digital-divide/

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New Technologies That May Drive Our Energy Future

by Bob Shively, Enerdynamics President and Lead Instructor

“Technology is no silver bullet, yet it’s an essential part of the de-carbonization equation.” ~ April Reese, Discovermagazine.com

In recent years, the energy industry has made significant strides in moving toward technology that helps reduce greenhouse gas emissions including developments in wind, solar, biofuels, and electric vehicles. But as Dan Arvizu, Director of the U.S. National Renewable Energy Lab, recently stated at the IEEE Power and Energy Society conference, the technology that got us to the gigawatt scale in clean energy will not get us to the terawatt scale. And this matters in a world that in 2014 consumed more than 20,000 terawatt-hours of electricity.

So what new technologies might help society get to terawatt-hours of clean energy? Much research is being done by highly skilled and intelligent people, and, as Arivizu noted, progress in the lab is absolutely phenomenal. It is impossible to know what might become the technology of the future, but here are some interesting ones to ponder:

Solar satellites
Solar arrays in space are not hampered by many of the realities of land-based solar. Space arrays can receive sunlight almost all hours of the year and can take advantage of intense solar rays. It’s estimated that a photovoltaic (PV) cell in space can deliver up to 40 times more energy that the same cell would generate on earth. But how does the energy get back to earth? The energy would be converted to either laser beams or microwaves, sent to a receiving terminal on earth, and then converted back to electricity. Various entrepreneurial companies have attempted to develop a successful space energy business model, and ideas continue to be batted around in the world of venture capital.

satellite photo courtesy of NREL

satellite photo courtesy of NREL

Thermonuclear fusion
The same process that heats the sun might be harnessed as a high-powered source of energy. Fusion reactions occur when nuclei from two fuel atoms fuse under high temperature, resulting in a heavier nucleus. As the atoms fuse, high amounts of energy are released. The technology has been held back by the difficulties of containing the fuel plasma and making the process efficient enough given the large energy input required to start the reaction. But researchers in various countries continue development of viable concepts.

Small modular nuclear reactors (SMR)
Nuclear power is carbon free, but it has been held back in some countries due to safety concerns and the high initial cost of constructing nuclear reactors typically over 1,000 MW in size. Development work is now proceeding in multiple countries to adapt the nuclear fission process to smaller generators that can be manufactured in a factory and shipped to location in modules on the order of 200 MW.  These units could be designed for passive safety, meaning the nuclear fission would automatically shut down if safety issues occurred. Smaller units are attractive since they can fit demand needs more precisely and can be more viable for utilities to purchase.

Photoelectrocatalytic (PEC) water splitting
Clean hydrogen fuel has been created for years using water-splitting processes.  The problem? Energy input into the process is too high to create a viable industry. But certain metal alloys with semiconductor properties are capable of absorbing sunlight to separate charges that can be used to split water. In the lab, it has been shown that these materials can convert sunlight to hydrogen fuel. Researchers are now working on extending the concept to a workable technology.

These are just a few of many interesting concepts in R&D. Others include advanced biofuels, ocean thermal energy conservation (OTEC), green buildings that generate more power than they consume, and new generation PV materials. Will any of them come to fruition? All could be long shots, but so were many of the technologies we now take for granted.

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Update on the Clean Power Plan – What Happens Now?

by Matthew Rose, Director EMI Consulting and Enerdynamics Instructor

On Aug. 3, 2015, the Environmental Protection Agency (EPA) revised and released its Clean Power Plan. The 1,560-page document lays out reduction targets for power plant carbon emissions. The Plan revision is based on soliciting and receiving extensive comments to the agency’s initial proposal (issued in Spring 2014)[1]. 

The final rules are slightly stronger in terms of emissions reductions than the draft proposal, targeting a 32% decline in carbon emissions over 2005 levels by 2030, instead of the 30% that was originally planned.

The core pieces of the regulation remain the same:

  • States are assigned individual emissions targets and are given flexibility in deciding how to meet them.
  • If a state refuses to file an emissions reduction plan — or it files an inadequate one — the EPA will assign a federal implementation plan (FIP) that will help the state get to its emissions targets.

It is important to note the Plan as currently configured is a policy directive and is based on a series of modeling forecasts. The 32 percent emissions decrease in the Plan is not an actual requirement. Rather it is a projection reflecting EPA’s modeling efforts using the current best information available. The Plan sets emission rates for 47 states that, based on current information, EPA projects should reduce emissions roughly 20 percent below 2012 levels by 2030 — or about 32 percent below 2005 levels. It is acknowledged that unforeseen changes in the market environment could affect the actual reduction results [2].

What Does The Plan Mean To The Industry?

The legalities and application of EPA’s Clean Power Plan will continue to play out over time. It is likely to receive formal legal challenges once it is published in the federal register, and there will be plenty of political noise. But unless blocked by the courts, it is unlikely that the Plan’s implementation will be blocked. There are more than 1,500 pages of rules and a number of supporting documents to guide the Plan’s execution. This all suggests an evolving process for states to fully understand and determine the best options moving forward.

The initial response from the electric utility industry is mixed. A number of utilities and their trade group, the Edison Electric Institute, have indicated the EPA has worked hard at addressing key issues. A list of utilities that have been complementary of the EPA and the Plan (without necessarily fully endorsing it) include: Pacific Gas and Electric, Xcel Energy, Public Service Electric and Gas, Dominion Resources, National Grid, and Los Angeles Department of Water and Power [3]. A number of states and utilities also have raised concerns and objection to the Plan.

At first glance, there is nothing glaring in the Plan that suggests any significant changes in terms of how utilities operate. With some exceptions, many industry companies have operated in the ‘spirit’ of reducing carbon emissions even as the Clean Power Plan was in revision.

To the extent that renewables and energy efficiency offer utilities a cost-effective strategy to comply with the rules, companies are likely to continue such efforts as part of their relevant state compliance plans. This reflects the fact that energy efficiency has been advanced as a policy providing benefits beyond just carbon reduction. Still, it will be interesting to follow the path of individual states in the months and years ahead.


[1] According to the EPA, the agency received more than 4 million public comments and conducted hundreds of stakeholder meetings (EPA, The Clean Power Plan, presentation from Joe Goffman, Senior Counsel at EPA, August 12, 2015).

[2] Alaska, Hawaii, Guam and Puerto Rico are excluded from the rule because they are non-contiguous. Vermont and Washington, D.C., are excluded because they don’t have power plants that would be considered under EPA’s framework.

[3] National Resources Defense Council, Power Companies Respond Positively to EPA’s Final Carbon Pollution Standards, Derek Murrow NRDC Blog, August 7, 2015.

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Southern Company/AGL Merger Reflects Trends in the Utility Business

by Bob Shively, Enerdynamics President and Lead Instructor

On August 24, 2015, Southern Company and AGL Resources announced a planned merger whereby AGL will become a new wholly owned subsidiary of Southern. The merger, if approved by regulators, will create the second largest U.S. gas and electric utility as measured by number of customers [1]. The merged company will have a ratebase of $50 billion. The merger is interesting as it reflects key trends in the utility business. 

Value in Consolidation
As we explored in a recent issue of Energy Insider [2], the electric business has been hit with flat load growth. This is a big issue for electric utilities whose earnings models are based on expanding investment in capital assets and growing sales. If you can’t increase top-side revenue through growing sales and/or higher rates based on capital investment, the only other way to maintain or grow earnings is to control expenses. 

We already have seen numerous utility mergers in recent years and expect this to continue as utilities attempt to achieve economies of scale through horizontal mergers. After all, do we really need over 3,000 electric utilities and more than 100 gas utilities in the United States? Mergers should reduce overhead as functions are consolidated and should foster innovation as new ideas are shared quickly between operating units.

Desire to Build Ratebase
Utilities also are working to find creative ways to build capital investment (called ratebase). The key is to find investments that regulators will find in the best interests of customers given that just about any investment in a flat-growth world will result in a rate increase unless it saves an equivalent amount in expenses. Florida Power and Light recently obtained approval to include up to $750 million of investment in gas reserves into its electric ratebase [3].

The argument is that with gas prices at historic lows, this is a way to lock in low gas prices for power generation for the long term. But, of course, it also provides a 10.5% rate of return for utility shareholders for the amount of the investment. Southern Company may or may not have similar ideas, but if they do, owning a company involved in the gas business is a good way to gain the institutional knowledge to make this work. And even absent a play on investing in gas resources, it is expected that gas pipelines, storage, and distribution systems will continue to expand capital investments as growth in the gas business is forecast to be more robust than in electricity.

The Ongoing Convergence Between Gas and Electricity
As has been frequently noted, gas is overtaking coal as the preeminent fuel for electric generation. Only three years ago, the Wall Street Journal featured an interview with the Southern Company CEO titled “Tom Fanning: The Natural Gas Skeptic” [4].  In the article, Fanning discussed the growth of gas but stressed the risks associated with future price volatility. Yet that same year, natural gas surpassed coal as the primary fuel used by Southern Company. Just two years later, the Wall Street Journal article covering the planned merger is titled “Power Giant Buys Into Gas Boom” [5]. In Southern Company’s 2014 Annual Report, the degree of the transition becomes obvious:

merger blog_chart
And while ownership of gas pipeline, storage, and distribution company assets doesn’t provide any direct benefits to Southern power plants due to open access rules, ownership certainly gives the ability to influence management decisions and to know exactly what is happening in the gas business.

So, should we expect to see more gas/electric mergers?  It’s very possible. As Southern has identified, there may well be solid value in reducing costs through consolidation, building ratebase through growth in the gas business, and in gaining the intimate industry knowledge that comes through owning and managing gas assets.


[1]  Interestingly, just after Southern’s announcement, the DC Public Service Commission rejected the proposed Exelon/Pepco merger.

[2] See Utilities Grapple with a “No Load Growth” Future at http://marketing.enerdynamics.com/Energy-Insider/2015/Q1Electricity.html

[3] http://www.utilitydive.com/news/florida-regulators-approve-fpl-request-to-boost-gas-drilling-investments/401001/

4] http://www.wsj.com/articles/SB10001424052702303448404577410473497091202

[5] See print version of the Wall Street Journal, dated August 25, 2015.

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Distribution Automation: The Hidden Revolution

by Bob Shively, Enerdynamics President and Lead Instructor

While electric storage, renewables, and the Clean Power Plan have received lots of press lately, a fourth revolutionary change has gone widely unnoticed. At the recent IEEE Power and Energy Society General Meeting, much talk was devoted to distribution automation.

And while it was often discussed by the engineers as simply the next step in modernizing the system, changes to the distribution grid truly are revolutionary.

A few years ago, talk of the Smart Grid was all the rage, and when visible change other than smart meter installations didn’t occur overnight, many decided it was just hype. Now, utilities are taking the lessons from numerous Smart Grid demonstration projects and are quietly modernizing their grids.

Here we see a very simple distribution circuit:

hidden revolution graphic

Prior to just a few years ago (and still in some areas of the grid) there would be no remote communication with the distribution substation or with the circuits beyond. Utilities would learn about an outage from customers calling in to complain. Then, the utility would send a crew to check the substation, then work its way down the line checking other components manually. If the problem occurred on the section of the circuit below the substation but above the switch, then the circuit would be switched manually to restore service to the customers on the bottom. This would likely take at least a few hours.  

Even on days without an outage, difficulties could occur. The voltage regulator near the end of the circuit, required to ensure sufficient voltage to the last customer, was set in a fixed position.  This means it could not respond to the actions of the customers, and often it would raise voltages higher than optimal simply to ensure this customer got voltage within the tariff requirements.

Today on an upgraded circuit, outages are reported automatically, crews can often be dispatched immediately to the location of the problem, and the grid may switch automatically to restore service to customers when possible.

Here is what has changed:

distribution automation chart

As you can see, grid capability has fundamentally changed. The result is reduced times for outage response (and in some cases, restoration of service automatically), reduced costs for maintaining voltages (utilities can often reduce peak demands by as much as 1%), and reduced maintenance costs through monitoring of conditions (for example, transformer oil can be changed as needed, not on a fixed schedule). 

As sensors, controllers, and monitoring equipment become even less costly, utilities will find more and more ways to efficiently upgrade their distribution systems. This will allow them to prepare for a rapidly approaching world where the distribution system is asked to do many unconventional things such as offer choices for power quality service levels, integrate numerous distributed energy resources, and protect against growing concerns about system security.  

This is a significant jump from the utility of yesteryear, yet today’s modern electric consumer is unlikely to notice a big difference. If you ask your next door neighbor what they think of the utility’s distribution automation program, you most likely will get a blank look!

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State of Maine Proposes Alternative to Net Metering of Rooftop Solar

by Bob Shively, Enerdynamics President and Lead Instructor

Suppose you decide to install a solar photovoltaic (PV) system on your home. Unless you decide to also put in a big battery system and maybe a backup generator, you will want to remain connected to your utility so that the utility provides power during the night hours, on cloudy days, and other times when your home usage exceeds the output of your PV system. And, during hours when your PV system output exceeds your usage, you will also want to sell power back into the utility distribution system. 

The key question for you and the utility is what price you should be paid for solar output. How utilities compensate customers for solar power is becoming one of the most contentious energy issues around the nation. So what are the options? 

  1. Net metering: Your solar output over the year is netted against your usage, in essence paying you the retail rate for solar power even if you generate the power at noon and use it at 6 p.m. or in the middle of the night.
  2. Avoided cost: You are charged the retail rate for all power you use and paid the wholesale avoided cost rate for all the power you generate. 
  3. Feed-in-tariff: You are charged the retail rate for all power you use and are paid a price based on some determined value of your solar output for all the power you generate.

In 43 states plus the District of Columbia, net metering is the current policy. But numerous utilities have asked their regulators to look at the issue, and many have suggested either eliminating net metering or continuing it with a significant monthly fixed charge added to solar customers’ bills. 

The State of Maine recently did a net value of solar (VOS) study that came up with a rate as high as $0.33/kWh, much higher than the retail rate of $0.13. A group of Maine legislators proposed an alternative to net metering that would create a centralized standard buyer agency, which would contract to buy the output of roof-top solar. Solar from commercial and industrial customers would be paid an amount set in a competitive reverse auction where customers proposing solar projects would bid against each other, while residential projects would be paid through a declining block methodology.[1]

The standard buyer would then resell the solar power in the competitive wholesale marketplace (selling all products including capacity, energy, renewable credits, etc.) and, by tracking the revenues received, will over time discover the true value of the solar power.  

Whether Maine’s proposition or some other idea will prove acceptable to the various stakeholders around the U.S. remains to be seen. But, if nothing else, Maine is providing an innovative idea to try to break the deadlock.


[1] For more details, see Maine lawmakers proposed groundbreaking way out of net metering wars, available at:http://www.utilitydive.com/news/maine-lawmakers-propose-groundbreaking-way-out-of-net-metering-wars/400074/

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Recent EPA Study Examines Fracking’s Potential Impacts on Water Supplies

by Christina Nagy-McKenna, Enerdynamics Instructor,
and Bob Shively, Enerdynamics President and Lead Instructor

On June 3, 2015, the U.S. Environmental Protection Agency (EPA) released its draft “Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources.” While it should be noted that the study’s results are still in draft form iStock_000033313732_Mediumand are not yet official agency policy, the study found no evidence that hydraulic fracturing or “fracking” has extensive effects on U.S. drinking water supplies.

Possible impacts of fracking include excessive water consumption and a risk of water contamination. Here’s a quick look at each and what the EPA study concluded:

Water consumption

Fracking is very water intensive, with the average well requiring 1.5 million gallons. This number jumps to 4 million gallons if only horizontal wells are factored into the equation. In its study, the EPA looked closely at how water moved throughout the fracking process. When water is acquired for fracking, it competes with other uses such as municipal water systems and farming. 

The EPA found that, depending on what part of the country the gas well is located, the water source may be surface water, ground water, or reused fracturing wastewater. In western states that have a more arid climate it is more likely the water used for fracking is from the surface and ground waters. In the East, producers usually use surface water. Reused water is found most often in Pennsylvania.

Producers need to be aware of the geologic conditions and climate in which they operate so as to avoid negatively impacting the drinking water. For example, if ground water is drawn down too aggressively, it can take more out of an aquifer than what it can naturally recharge. Also, using too much surface water may alter how a stream flows. In a few locales, competition for water resources may be important, but overall the impacts of water acquisition have not proven significant.

Water contamination

In looking at various stages of the fracking process, factors contributing to possible water contamination include:

  • chemicals that can spill and leech into the soil
  • wastewater if inadequately treated and discharged
  • the movement underground of fluids due to a production well

Controlling these potential hazards is important as the EPA found that between the years 2000 and 2013, close to 9.4 million people lived within a mile of a well that was being fracked. Also, drinking water sources for 6,800 public water systems serving 8.6 million people were also within a mile of a hydraulically fractured well during this time period. 

In preparing the report, the EPA did find some instances where impacts on drinking water occurred but said the number of instances is small relative to the number of fracked wells drilled in recent years. This led the EPA to state that it “did not find evidence that these mechanisms have led to widespread, systemic impacts on drinking water resources in the United States.”

Next steps

The EPA’s draft is out for public review and comment, and we expect many parties on both sides of the fracking debate will participate. Once the report is final, it should provide more knowledge to allow state agencies to develop effective regulation that allows fracking to continue while protecting water resources from potentially negative impacts.


“Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources,” United States Environmental Protection Agency, Office of Research and Development, Washington D.C., June 2015. 

 “EPA Blesses Fracking,” Silverstein, Ken, Fortnightly’s Spark, 2015.

 “EPA’s Fracking Finding May Prove a Boon for Industry,” Neuhauser, Alan, U.S. News and World Reports, June 5, 2015.

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