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



[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:

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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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The Home of the Future: A Profit Center for Residents?

by Bob Shively, Enerdynamics President and Lead Instructor

As the Electric Power Research Institute (EPRI) states in its report titled The Integrated Grid:

“The role and operation of the U.S. electric power system are undergoing profound changes driven by the spread of distributed energy resources (DER).”

Such changes will enable the residential energy consumer to become a “prosumer,” who is both a provider and a consumer of grid services. Enerdynamics’ latest infographic, the House of the Future, shows elements that will likely be integrated into new homes and retrofit into existing homes. (Click on infographic to print and/or download a PDF version.)


Future homes will use energy-efficient technologies that reduce overall energy usage. These include:

  • highly efficient appliances and lighting
  • a super-insulated shell and energy-efficient windows
  • geothermal heating and cooling that use thermal energy from the earth to efficiently heat and cool a home
  • a smart thermostat that keeps a home at an optimum temperature
  • a home combined heat and power (CHP) system that generates electricity and provides heat for hot water and/or space heating

While a single home will likely not include all of these elements, a mix of just some of them will significantly minimize the amount of energy required to meet desired lifestyle demands.

Once one’s needs to buy energy services from the grid are reduced, the next investment may be in technologies that lower energy costs (or even make them go negative so that homeowners are making money!). This may be achieved by shifting electric demand to times when power is the cheapest and/or by selling electricity back to the grid. This is what turns a consumer into a prosumer. Technologies that facilitate this change include:

  • smart appliances; adaptive lighting; a smart thermostat; a controllable water heater; and an electric vehicle with a battery — all of these allow consumers to time shift their electric usage
  • The previously mentioned CHP system, which provides capacity and electricity
  • A solar array that can also provide capacity and electricity
  • A home battery that can provide capacity, electricity, and regulation services and may also allow the homeowner to time-shift use of power bought from the grid or generated by a CHP system or solar array

Those who take advantage of these technologies’ benefits will want to remain connected to the distribution utility to get the economic benefit of selling these services. This requires a smart meter and a smart inverter that converts the power generated or the electricity discharged from batteries to the level of power quality needed for the distribution system.

All these components won’t run and optimize themselves alone, so a home energy management system (HEMS) is required to manage it all. HEMS users will simply use the convenient home energy app provided by their energy services provider (Google, Facebook, cable/internet provider, electric utility or energy retailer?) to set preferences and the system will then run itself.  Such efforts should result in a reduced energy bill at the end of every month.

Sound futuristic? All of these technologies are available today. But to fully integrate them as described above there must be changes to the electric utility model as well as innovative service providers who pull it all together. In some states around the U.S. and countries around the world, this future is not too far away.

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A Quick Look at Services Bought and Sold in an ISO

by Enerdynamics staff

Many who are new to the electric industry share a common question about Independent System Operators (ISOs): What type of services are bought and sold in an ISO?

 A thorough and easy-to-follow answer to this question is contained in the following video clip taken from Enerdynamics’ new online course titled ISO Market Basics. Just click on the following image to begin the video:


Want more insight into how ISOs function? ISO Market Basics, Enerdynamics’ newest full-length online course, is appropriate for those with little or no experience in ISO markets. The course looks at:

  • The role of ISOs and various market participants
  • The various types of electric markets available to market participants
  • The services that are traded in electric markets
  • How the ISO markets work

The course comprises 11 modules that include practical examples and exercises to help learners understand how markets are used in real life by various market participants. For more information or to buy a subscription, click here.

Enerdynamics offers discounts on bulk subscriptions and site licenses. Contact us at 866-765-5432 or for special pricing on bulk orders.

If you specifically are seeking to learn how the Midcontinent Independent System Operator (MISO) functions, we also have ISO Market Basics — MISO version available.

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Why Would a Commercial or Industrial Electric Customer Want a Battery?

by Bob Shively, Enerdynamics President and Lead Instructor

In a recent two-part series of blog posts, we looked at reasons a residential electric consumer would want a home battery. We concluded that in almost all cases, home battery systems don’t currently make sense for residential consumers other than as a threat to energy collagekeep utilities from creating overly punitive rate designs for those customers installing solar. But we mentioned that batteries may indeed make sense for commercial customers. So let’s explore why…

Walmart Wants Batteries to Manage Utility Bills

In a recent webinar[1], Walmart Director of Energy David Ozment described Walmart’s Vision 2020 energy procurement goals. By 2020 Walmart plans to increase procurement of renewables by 600% over 2010 and to accelerate efficiency so that the energy intensity of its buildings is decreased by 20% over the same time period. As Ozment described, Walmart is on the path to procuring 100% renewable electricity. But as Ozment also noted, this is an economic decision not a “feel good” or marketing strategy. Each project has to make economic sense.

Walmart plan for RE

A piece of this strategy includes using batteries to improve project economics. Walmart began pilot projects in 2013 with small 15-30 kW batteries that are charged at night and discharged during the day. This year, Walmart will pilot larger 200 kW batteries that are designed to be charged by roof-top solar systems. Its pilot partner is, interestingly, Solar City/ Tesla.

The smaller batteries have been used to time shift purchased power to take advantage of Time-of-Use (TOU) rates and to shave overall facility peak demand.  The larger batteries will be used to manage solar output so that it can be used at the time that will best reduce Walmart’s utility bills either through time shifting or peak shaving.  The larger batteries offer much more flexibility to manage bills since they can store an amount of power equal to a typical demand for a Walmart store.

Walmart is Using Batteries to Give Utilities What Utilities Want

Note the key point here – Walmart does not plan to use batteries to disconnect from the utility but simply to manage its utility costs by giving the utility what the utility rate structure tells Walmart it wants: power use at night rather than during the day, and lower monthly peak demands. Down the road, sophisticated commercial and industrial (C&I) customers in certain markets may also be able to increase the economics of batteries through participation in capacity and/or ancillary services markets.

Not too far in the future, it is likely that batteries will become a key asset for C&I customers to manage electricity procurement costs. Successful utilities will recognize this and devise rates and services that reward customers for using their assets to benefit the overall distribution grid.


[1] See:  “Not Taking No for an Answer” available at

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