A Look at Japan’s Post-disaster Grid Resilience

Introduction by Bob Shively, Enerdynamics President and Lead Facilitator
Presentation by Dan Bihn, Enerdynamics Facilitator

Sure everyone wants a more resilient electric grid. Especially after a recent natural disaster that caused long outages. But few consumers want to pay the increased rates that go along with utility-financed grid “hardening.” For example, when JCP&L proposed a 4.5 % rate increase following Hurricane Irene and Superstorm Sandy, a city councilman from Vernon, N.J., gave a typical response in public comments: “I don’t think the customers, who are supposed to be served, should be paying for what was essentially their [the utility’s] lack of management and poor planning.”[1]

As we develop new technologies and as utilities and regulators consider new business models, it is fair to ask if there’s a better way than utility spending to improve grid resiliency. Enerdynamics’ facilitator Dan Bihn recently visited Japan, which has a long history of natural disasters and is currently undergoing implementation of retail electricity deregulation. Bihn discovered that grid-connected electric vehicles (EVs), smart homes, meaningful electric pricing driven by competitive electric retail companies, and business opportunities may be resulting in a new model for how to create and pay for grid resiliency. Based on his findings, following is a SlideShare presentation by Bihn titled Japan’s Disaster Resilient Smart Energy Economy.


[1] Vernon councilman Dan Kadish quoted in the New Jersey Herald: http://www.njherald.com/story/21311355/jcpl-cites-sandy-in-seeking-rate-increase#
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A New Workforce Will Drive Energy’s Future

by Bob Shively, Enerdynamics President and Lead Facilitator

Not too long ago, utility workers were overwhelmingly male and white, and they tended to stay at theportrait-of-confident-multiracial-business-team same utility for decades of employment. Now studies show that in most utilities, as much as 50% of the workforce will reach retirement age in the next five to 10 years. 

UtilityDive’s ‘The State of the Electric Utility 2016 Survey‘ asked over 500 utility executives what the three most pressing challenges are for their utility. The most prevalent response, at 43% of respondents, was “aging workforce.” The expected turnover in employees will come at the same time that the utility industry is grappling with a likely transition to new technologies, new expectations from customers and regulators, competition from technology giants like Google and Apple, and a need to develop new business models. 

The composition of the workforce is also changing when it comes to gender and race:



I recently observed this while teaching a seminar of new engineers at a utility in the Southwest. Out of 20 new employees, only two were white males, and over half the attendees were female. 

Secondly, expectations for how workers will work are significantly changing. In a recent paper titled ‘Transitioning to Workforce 2020‘ tech company Cisco outlined changing employee expectations:

Cisco went on to suggest that traditional organizations will need to reform significantly by “letting go of some immediate control in order to keep the globalizing organization in better balance over the long run.” According to Cisco, necessary activities will include some or all of the following:

  • Synthesizing diverse viewpoints – more dialogue and compromise
  • Recalibrating timing and processes – allowing workgroups to work at their own pace with their own tools
  • Reforming existing policies – restructuring and disruption of current policies
  • Integrating new values – valuing creativity and innovation as much as efficiency and productivity
  • Shifting key relationships – lateral relationships replacing vertical with cross-functional groups
  • Concentrating attention on opportunities – maintaining focus through unforeseen conditions and market complexity
  • Engaging new and different stakeholders – reaching out to more partners, customers, governments, and communities
  • Allocating resources – flexible approaches to deal with fast-changing, hard-to-predict business conditions

Clearly the needed changes will be doubly hard for utilities given the imperative to maintain careful processes to ensure safety and reliability, and given the overwhelming influence of regulation in the industry. Utility leaders and managers must prepare themselves for what may be the biggest challenge of their careers.

One way Enerdynamics is helping current and prospective clients navigate a changing workforce is through its “Utility Business Acumen Series,” which assists companies in meeting their evolving training needs. On our website at www.enerdynamics.com/utility you will find options for both utilities and companies providing services to utilities, since each sector must have a thorough understanding of the utility business.

Once you choose the appropriate sector, you are a click away from a variety of appropriate training options. First you’ll see examples of programs we’ve put together for other clients. And below that you will find the various products (online courses, live seminars, and books) that may be useful in providing quality business acumen training to your employees. Much of what we do can be customized for your company. Contact us at 866-765-5432 ext. 700 or by email if you’d like to discuss your specific needs, learn how we’ve worked with other companies with similar needs, and get details on the customized training program we can build to meet such needs.




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Mexico’s Electricity Market Reforms Create New Opportunities

by Bob Shively, Enerdynamics President and Lead Facilitator

In a recent blog post we compared the current deregulation of Mexico’s gas market to the 1990s in the United States. But unlike the U.S., which phased gas and electricity restructuring, Mexico is restructuring its gas and electricity markets at the same time.  Mexico finalized laws for comprehensive electricity market reform with the Electric Industry Act in 2014, and at the beginning of this year the competitive wholesale market kicked off.

Prior to regulatory reforms, Mexico’s electricity was provided by the vertically integrated monopoly Comisión Federal de Electricidad (CFE) under limited oversight from the federal Secretaría de Energía de México (SENER).  In 2002, Independent Power Producers (IPPs) were allowed to build generation but could only sell to CFE.  Also in this time frame, industrial customers were allowed to acquire supply through self-supply from closely related generation entities.

Market Structure Prior to Reform

market structure prior to reform.png

Source: Regional Address to the CAISO Stakeholder Symposium, Electricity Reform in Mexico, presented by Jeff Pavlovic, SENER, October 22, 2015

The structure resulted in multiple concerns including:

  • Average rates 25% higher than in the U.S.
  • Extensive use of government subsidies to keep rates low; without subsidies rates would have been over 70% higher than in the U.S.
  • Lack of incentive for investment in clean power or in new transmission projects
  • Limited transparency in setting pricing and making investment decisions

With the objectives of reducing costs and rates, fostering more clean energy, and spreading benefits among multiple stakeholders, a new market structure has emerged. Policy makers believe it will provide incentives for value creation and efficient operation, result in decision-making through competitive processes, provide open-access and non-discriminatory use of the electric system, and offer transparency.

The New Market Structure


Source: Regional Address to the CAISO Stakeholder Symposium, Electricity Reform in Mexico, presented by Jeff Pavlovic, SENER, October 22, 2015

The new electric market reforms have ushered in new market players and a new market structure.

Market Players

  • Existing CFE generation will be split into multiple subsidiary companies.
  • Existing and new IPPs will be allowed to participate directly in the market.
  • Clean energy power producers will be incented to develop projects by new clean portfolio requirements and the trading of Clean Energy Certificates.
  • A new Independent System Operator (ISO) named Centro Nacional de Control de Energía has been created to run day-ahead and real-time markets, operate the electric system, provide open access to the electric system, and to ensure interconnection requests are fulfilled.
  • A new regulatory agency Comisión Reguladora de Energía (CRE) has been created to set transmission and distribution rates and tariff rules, grant generation permits, and oversee regulatory aspects of the new market.

New Market Structure Overview

  • Long- and medium-term bilateral transactions will be facilitated by power auctions run by CENACE.
  • CENACE will run centralized day-ahead and real-time markets using price offers and optimized energy/ancillary services processes similar to U.S. ISO markets with nodal pricing (with the difference that all price offers must be cost-based).
  • CENACE will administer a yearly capacity market.
  • CENACE will facilitate a yearly and monthly Financial Transmission Rights market.
  • CENACE will administer a yearly Clean Energy Certificates market for retailers to fulfill clean energy portfolio requirements set by CRE.
  • CFE will continue to own the transmission and distribution system.
  • Small commercial and residential customers will continue to buy their supply from CFE under cost-of-service-based tariffs.
  • Larger consumers can choose to buy regulated supply from CFE or can purchase unregulated supply from marketers or generators.

The Market Has Begun

The market has kicked off.  CENACE has been running the spot markets since January 1.  The following graphic from the U.S. Energy Information Administration shows results for the first six months of 2016:

Source: EIA Today in Energy, July 5, 2016

The initial long-term auction for energy, capacity, and Clean Energy Certificates was held in March with CFE as the only buyer. A second auction is planned for this fall with multiple buyers. Other aspects such as FTR auctions, the CENACE-administered capacity auction, medium-term auctions for energy, and the CENACE-administered clean energy market will be implemented over the next two years. And Mexico has ambitious plans to become a key international player in electricity markets with connections to the U.S. and Central America. Indeed, Mexico has indicated an interest in direct participation in the California ISO (CAISO) real-time Energy Imbalance Market (EIM). There certainly will be numerous interesting developments to discuss in future blog posts as Mexico’s new electric market evolves.



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Can Wyoming Reinvigorate the Coal Industry?

by Bob Shively, Enerdynamics President and Lead Facilitator

Open Pit Coal Mine

Texas and Wyoming are perhaps the two states most associated with fossil
fuels production – Texas with its oil and natural gas, and Wyoming with its coal. Concerns about global warming, evolution of new low-cost natural gas and renewable electric generation, and growth of electric vehicles are putting pressure on economies dependent on fossil fuels.

Texas has been able to hedge its energy bets by developing a robust renewables industry, leading the Wall Street Journal to recently pen a front-page article titled “Texas’ Latest Gusher: Wind and Sun”[1]. Meanwhile in Wyoming, numerous renewable projects are in development stages including a 3,000-MW wind project by the Power Company of America. However, Wyoming has struggled to rapidly grow renewable energy production. Barriers include Wyoming’s remote location, lack of transmission to carry power to loads in other states, and, in some cases, lukewarm political support by a state where the coal economy is estimated to make up 14% of state GDP and 11% of state government revenues[2]. 


Source: EIA

Opportunities to Market Coal in the U.S. Appear to be Declining

Since its peak in 2008, Wyoming coal production has fallen by almost 20%. 


Source: EIA

The fall in production is not due to lack of supply in Wyoming, because reserves and productive capability remain robust. Instead it is driven by lack of demand as the U.S. generation fleet transitions from a dominance of coal to rapid growth in natural gas and renewable capacity.


Wyoming Attempts to Buoy Coal’s Future

Given the importance of coal production to Wyoming’s economy, the trends are not promising. Coal producers in Wyoming have attempted to develop export markets to sell coal to Asia but have been hampered by environmentalists’ opposition to developing West Coast ports to allow more exports as well as the costs of shipping coal far distances[3]. Wyoming Governor Matt Mead is focused on the issue and realizes that without addressing coal’s environmental barriers, the future will continue to look bleak. 

In April of this year, Gov. Mead, state officials, and utility executives broke ground on a new $21 million research center in Gillette, Wyo., next to the Dry Fork coal power station. The center will provide a real-life laboratory for scientists to design and test technologies that remove carbon emissions for the plant’s emission stream.  Participating scientists will be buoyed by the opportunity to win a $10 million prize offered by the XPrize Foundation and awarded to the team that can best achieve two goals: 1) remove the greatest amount of carbon from the stream; and 2) turn the carbon into a product with the largest commercial value[4]. The governor also recently signed a cooperation agreement with the Japan Coal Energy Center, a consortium of 120 companies, for research associated with clean-coal technologies[5].

According to the governor, the hope is to find a game-changing technological breakthrough that will again make coal a favored fuel. It won’t be easy, as other research associated with removing carbon emissions has resulted in technologies that work in laboratories but have yet to prove economic in power plant applications. Time will tell whether coal can continue to support Wyoming’s economy or whether Wyoming should look to Texas’ example of finding new ways to grow a more prosperous energy future.  


[1] Wall Street Journal, August 29, 2016

[2] See: The Impact of the Coal Economy on Wyoming, available at  http://www.uwyo.edu/cee/_files/docs/wia_coal_full-report.pdf

[3] See for example: Think Progress,The Plan to Revive Big Coals Fortunes Isn’t Panning Out,   https://thinkprogress.org/the-plan-to-revive-big-coals-fortunes-isn-t-panning-out-cc6300b1e715#.r2wbuq62r

[4] For more details, see: The Casper Star Tribune, Wyoming, hoping to save coal, breaks ground on a new test center,  http://trib.com/business/energy/wyoming-hoping-to-save-coal-breaks-ground-on-new-test/article_53e3cadb-502e-5429-9c7f-5cc7c1fa15f4.html

[5] See:  The Seattle Times, Wyoming Partners with Japanese Companies seeking coal, http://www.seattletimes.com/business/wyoming-partners-with-japanese-companies-seeking-coal/

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What Services Can Distributed Energy Resources (DER) Provide to the Grid? Part II

by Bob Shively, Enerdynamics President and Lead Facilitator

Our last blog post discussed the transformation from an electric grid driven by centralized generation to a grid powered by distributed energy resources (DER). For this transformation to successfully occur, industry insiders must understand the many services that DER must provide if and when it becomes a primary energy resource. 

DER services tableAs shown in the table above, these services can be divided into energy-related services and network-related services. Last week we looked at what each energy-related service entails. We continue this week by outlining each network-related service.

Network-related Services

  • Voltage control: In addition to providing real power (kW) to match consumer loads, electrical systems must provide reactive power (vars) to match the consumption of reactive power by electrical lines and by certain types of loads (electric motors, fluorescent lights for instance). Reactive power historically has been provided by central generators and/or by devices on the distribution system such as capacitor banks. Voltage control is the ability to provide vars to the system as needed.  
  • System support during disturbances: A disturbance on a distribution circuit often results in voltage dips below normal levels. These dips may be temporary in nature. DERs are often set to isolate themselves from the grid when low voltage occurs. But this makes the problem worse as sources of supply are removed from the system. DERs designed to ride through low voltage can provide a benefit of helping keep the system voltage from dropping to the point that the circuit automatically takes itself out of service and causing a blackout.
  • Power quality: Distribution utilities strive to deliver electricity with high power quality meaning that voltages and currents follow a consistent pattern. But various consumer devices can result in localized impacts on the power on a specific distribution circuit, including variation in voltage magnitudes, voltage dips and spikes, or variations in wave shapes. DER can be beneficial or harmful to power quality depending on the design of DER inverters and on operational practices.
  • Energy loss reduction: Power that is delivered from a generator to a load results in losses along the transmission and distribution system. Energy loss reduction is production of energy at or near the consumer that provides a reduction in system losses. 
  • Mitigation of constraints: The lowest cost source of supply cannot always be used due to lack of transmission capacity to deliver the supply to loads. Production of energy at or near the consumer can provide resources that can be used to mitigate constraints on the transmission system.
  • New T&D capacity deferral: Growth of loads can result in the need to upgrade transmission and distribution facilities.  These upgrades can sometimes be costly.  Production of energy at or near the consumer can provide supply that does not require T&D capacity for delivery to the consumer. If located in the right spot, DERs can be used as an asset to avoid or delay having invest in system upgrades.

Attracting these services from DER will require significant changes to current regulatory and business arrangements; both the utilities that operate the networks and the owners of DER must be incented to take advantage of the services that distributed resources can provide, and owners must be paid appropriately for the benefits that DER assets bring to the system. We will explore these issues in future articles.

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What Services Can Distributed Energy Resources (DER) Provide to the Grid?

by Bob Shively, Enerdynamics President and Lead FacilitatorRooftop Solar Panels on Factory Roof

Some key regions around the world – New York, California, and Germany among others – are amidst a major transformation from an electric grid driven by centralized generation to a grid powered by distributed energy resources (DER). New York is currently revising its method of regulating electric utilities to foster use of DER when they are more economic than traditional generation resources. As Audrey Zibelman, Chair of the New York Public Services Commission, wrote recently in IEEE Power and Energy Magazine:

“It is time to recognize that the demand side of the grid can be a more-valuable resource than we could have imagined 30 years ago. Rooftop solar, energy storage (from household batteries to electric vehicles), smart energy management technology, and the aggregation of demand are all areas where demand, rather than generation, can become the state’s primary energy resource.”[1]

As this transformation is occurring, it is important for those in the energy industry to understand the services that DER must provide if they are to become a primary energy resource. It takes much more than just kilowatt-hours to run a grid reliably. As shown in the table below, necessary services can be divided into energy-related services and network-related services[2].

DER services table

Below is a closer look at energy-related services and what they entail. Next week we’ll continue with a deeper look at network-related services.

Energy-related Services

  • Energy (kWh): Load-serving entities (LSEs) must ensure that sufficient kilowatt-hours (kWh) of supply are provided to the grid to match their customers’ loads plus system losses. Energy acquired by LSEs may be purchased forward (for a period in the future beyond tomorrow), day-ahead (for delivery tomorrow), hour-ahead (for delivery in the next operating hour), or in real-time (for immediate delivery). Depending on the type of DER, energy can be made contractually available for some or all of these timeframes. 
  • Firm capacity (kW): System operators must ensure that enough supply capacity is available to provide energy upon request during future timeframes. Capacity planning occurs over long-term periods (three or more years) as well as seasonally and monthly, and capacity is planned to meet the forecast peak demand during that time period plus a reserve margin. DER that can reliably provide energy during the peak can provide capacity services.
  • Fast ramp capacity (kW): In regions with significant variable renewable resources (wind and solar) system operators must ensure capacity to provide kWh upon request during a specified period with the capability to move from one level of output to another level of output quickly (measured in kW or MW per minute). DER with the capability of ramping quickly can provide fast ramp capacity.
  • Operating reserves: Going in to each operating hour, the system operator must have available sufficient capacity to provide kWh as needed to balance the system during an operating hour. This reserve capacity is needed to respond to both normal supply and demand fluctuations and fluctuations due to contingencies such as unexpected loss of generation or transmission.  Various operating reserves are required including regulating reserves, spinning reserves, non-spinning reserves, and supplemental reserves. Certain DERs can provide some or all of these services.
  • Black start: System operators must have availability of units that can start-up to put energy on the grid without first drawing power from the grid.  This is necessary to recover from grid outages. Certain DERs can provide this service.

Next week we’ll continue with a breakdown of network-related services.


[1] Audrey Zibelman, REVing Up the Energy Vision in New York, IEEE Power and Energy, Volume 14, Number 3, May/June 2016

[2] This table has been adapted from figure 3 in the article by Ignacio J. Pérez-Arriaga, The Transmission of the Future, IEEE Power and Energy, Volume 14, Number 4, July/August 2016. 

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Halting Fugitive Methane Emissions Is Key to Attaining Natural Gas’ Environmental Benefits

by Bob Shively, Enerdynamics President and Lead Instructor

Natural gas has recently replaced coal-fired generation as the dominant form of generation in the U.S. From the standpoint of power plant emissions of greenhouse gases (GHG) this is good news. On average, gas-fired generation emits less than 50% of the amount of GHG emitted by the equivalent output of coal generation.

history of generation

In fact, GHG emissions from the power sector in the U.S. declined by 13% in the decade ending 2014. Once data becomes available for 2015 the decline will be even more dramatic given the ongoing switch to gas generation.

emissions graph.jpg

But, there is a catch to this seemingly good news.  Uncombusted methane (methane typically makes up over 90% of natural gas carried in a pipeline) is a much more potent GHG than the carbon dioxide released when natural gas combusts. 


The U.S. Environmental Protection Agency (EPA) has determined that methane has a Global Warming Potential (GWP) that is 28 to 36 times greater than the equivalent amount of carbon dioxide. Given that, even though much less methane is released, it still made up 11% of the U.S. human-caused GHG release in 2014[1].  This means that natural gas that is released during production or during its journey through the gas system prior to its combustion at the power plant is negating some of the benefits of converting coal to gas generation.   

Methane losses through the gas delivery system are called fugitive emissions. According to the Environmental Defense Fund (EDF) recent data suggests fugitive emissions are significantly higher than previously thought. In fact, EDF states that 2013 fugitive gas emissions have over a 20-year period “the same climate impact as over 200 coal-fired power plants”[2].

As EDF points out, “the lost gas is worth $1.4 billion at 2015 prices,” meaning that gas producers and pipeline companies have an interest in solving the problem that goes beyond being good environmental citizens. The good news is that fugitive emissions are a solvable problem once the source of emissions can be identified. 

A couple of years ago, an environmental scientist told me about his work in a gas field in Wyoming where he and his colleagues could not understand a new high concentration of methane that their instruments were measuring. Then one evening, he fell into conversation with someone who worked at a gathering pipeline company who told him that they had recently changed their procedures resulting in frequent purposeful blow-out of their pipelines. (For those not familiar with the term, blow-out means releasing gas into the air in order to clear the line for maintenance or other planned procedures.) His rapid calculations showed that the unexplained source of methane was now explained and could be addressed through new pipeline operating procedures.

methane map                   Source: NASA/JPL-Caltech/University of Michigan

Since then, scientists from various organizations have become active in identifying unexpected concentrations of methane and then identifying their causes. The photo above shows a concentration of methane in the Four Corners areas of Colorado and New Mexico (see the red/orange on the map) that is reportedly the size of Delaware. Researchers from NASA’s Jet Propulsion Laboratory and the California Institute of Technology spent the last two years identifying the sources of the methane by using low-flying aircraft with spectrometers. They recently published their findings in the Proceedings of the National Academy of Sciences. The research team discovered 250 sources of methane in the region ranging from gas wells, storage tanks, pipelines, and processing plant. 

But interestingly, two-thirds of the emissions came from only 25 sources. Asset operators in the region have already taken action. The result is that gas companies increase production and emissions are reduced. So it’s now feasible to find fugitive emissions and, in many cases, fix them through relatively minor actions. A key outstanding question is whether the industry will do so voluntarily or whether government regulations are required.


[1] See EPA, Overview of Greenhouse Gases, https://www.epa.gov/ghgemissions/overview-greenhouse-gases

[2] See EDF, David Lyon, EPA Draft Says Oil & Gas Methane Emissions Are 27 Percent Higher than Earlier Estimates, http://blogs.edf.org/energyexchange/2016/02/23/epa-draft-says-oil-gas-methane-emissions-are-twenty-seven-percent-higher-than-earlier-estimates/










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