Electricity Will Bypass Any Border Walls


by Bob Shively, Enerdynamics President and Lead Facilitator

In recent years, U.S. imports of electricity from Mexico have grown significantly, mostly through bilateral energy sales into California. As Mexico implemented its electricity market reform earlier this year, Mexican officials expressed a desire to foster enhanced cross-border trading with the U.S. to the north and with Central America to the south.

Now Mexico appears poised to become part of the California ISO (CAISO) Energy Imbalance Market (EIM), which would have generators in northern Baja California actively participating in the CAISO real-time energy market. And with future plans for integrating the Baja grid into the Mexico National System, this could further extend integration of the Western U.S. and Mexican markets.



What is the EIM?

The EIM is an organized market that allows participating generators across portions of eight western U.S. states to offer their units into the CAISO real-time energy market. This means that generators located within the service territories of Arizona Public Services, Nevada Energy, PacifiCorp, and Puget Sound Energy can now offer to ramp their generation up or down based on economic decisions made by the CAISO. In return, these generators are compensated through real-time energy payments as determined by the CAISO real-time energy price.

This market creates benefits including:

  • More efficient dispatch of units between regions since efficient units in one region are now available to handle real-time needs in other regions
  • More efficient dispatch of units within regions since dispatch is now done automatically based on economic generation offers
  • Reduced curtailment of renewable energy resources since unexpected variability in one region can be balanced by resources in other regions
  • Reduced need for regions to carry flexible reserves since the requirements for reserves can be shared between regions

CAISO’s analysis shows the EIM resulted in $26.16 million of net benefit in the 3rd quarter of 2016 and has resulted in a cumulative benefit of $114.35 million since market inception in November 2014. In the third quarter of 2016, the market also allowed an additional 33,094 MWh of renewable energy to be dispatched, resulting in a reduction of 14,164 metric tons of CO2 output compared to what it would have been if the market was not in place.

Mexico’s Participation in the EIM

In October, the CAISO and the Mexico ISO, El Centro Nacional de Control de Energía (CENACE), announced the initiation of a study to explore participation of the Baja California Norte grid in the EIM. Baja, which as of 2014 has about 600 MW of renewable generation (including geothermal energy sold in a bilateral contract to the City of Los Angeles) has the potential for significantly growing renewable generation. As referenced in a recent paper by ICF International, studies have suggested that Baja could develop as much as 10,000 MW of wind generation with additional geothermal and solar resources.

But with internal demand of only a few thousand MW on a typical day, northern Baja is unable to utilize its potential resources without an external means of balancing variable renewable supply. Meanwhile, California is moving forward with implementing its 50% renewables requirement, and imports from Baja may well be a low-cost renewable source. So, we have a potential low-cost supplier sitting next door to a buyer with significant needs and an existing market mechanism that can make it happen fairly easily. Given these factors, we can conclude that despite recent negative political rhetoric about cross-border trade with Mexico, U.S. and Mexican electricity markets are going to become increasingly integrated.




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Are Zero Marginal Costs Transforming the Energy Industry?

by Bob Shively, Enerdynamics President and Lead Facilitator

In his 2014 book The Zero Marginal Cost Society, futurist Jeremy Rifkin states his view that  “the emerging Internet of Things is speeding us to an era of nearly free goods and services.”[1]

Specifically, Rifkin describes how once initial capital costs are spent, more and more goods and services have almost no marginal cost[2] to produce. An example is the music industry where digital versions of songs, once recorded, have virtually zero marginal cost to provide copies to consumers. In a recent talk in Chicago, Rifkin described his views on how this applies to the energy industry. These were summarized as follows by the Energy Times[3]:

“The Third Industrial Revolution will see a decline in massive vertical power structures in favor of a horizontal, distributed model. Economies will move from a seller-buyer model to a provider-user model. More and more industries – just like the music and entertainment industries have already experienced – will make the shift to operating off of very low margins of very high traffic.

The same will hold true for energy companies. In this highly distributed model almost every community, no matter the size, will be generating it’s [sic] own power off of solar and wind. Energy will become amazingly cheap, and energy companies will make their money through partnerships with their customers and clients to manage those distributed networks.”

Certainly, the energy world is becoming familiar with the concept of low marginal costs.  Advances in the natural gas industry including horizontal drilling and hydraulic fracturing have resulted in a natural gas resource with very low marginal cost that has driven prices to sustained lows not seen since the early 2000s. And in both the generation and the utility distribution side of the business almost zero marginal cost renewable generation is roiling business practices built on the concept that both capital costs and variable costs could be spread across all customers in a “fair” manner determined by long-standing regulatory principles.


Rifkin suggests that utilities must be preparing for the Third Industrial Revolution by running two parallel business models. One focused on continuing to provide reliable service in today’s energy world primarily driven by fossil fuels, and one focused on transitioning the company to the future.  He suggests that utilities prepare for the future by setting “up partnerships with thousands and thousands of enterprises. You have to manage their energy flow on an on [sic] internet platform, helping them to mine the analytics of their big data and their energy flows.”[4]

Interestingly, this echoes the direction the State of New York is taking in the ongoing Reforming the Energy Visions (REV) proceeding where regulation will be reformed to move electric utilities to become distribution systems platforms[5]. Over time, New York envisions that utility revenues will become more and more driven by market-based earnings associated with network services. Below illustrates NY PSC’s vision for future utility earning sources.earning-sources-over-time

Transforming a company while also keeping the lights on in today’s world is not an easy task. Certainly some utilities will do better than others. A recent study by Lux Research[6] suggested that some of the utilities leading the way include the European utilities E.ON, Enel, Engie, and RWE plus the U.S. utilities SDG&E, Exelon, and Duke.


Of course, who wins and who loses in the coming new world remains to be seen. But what appears certain is that future energy companies will be as dramatically different from our traditional utilities as today’s mobile carriers are different from the Bell telephone companies of yesteryear.


[1] If you have 10 minutes, we recommend Rifkin’s video at https://www.youtube.com/watch?v=3xOK2aJ-0Js

[2] For an explanation of marginal costs, see http://www.investopedia.com/terms/m/marginalcostofproduction.asp?lgl=no-infinite

[3] Bold New Power Vision at Empowering Customers & Cities 2016, Steve Spaulding, The Energy Times, November 3, 2016, http://tdworld.com/energy-times/bold-new-power-vision-empowering-customers-cities-2016

[4] Utilities Must Partner with Thousands, the Energy Times, October 6, 2016, http://tdworld.com/news/utilities-must-partner-thousands-0?utm_rid=CPG04000000071983&utm_campaign=10742&utm_medium=email&elq2=60f97daa7c6f478e8e6af8489d0077d7

[5] See Enerdynamics blog, New York’s REV a New Model for the Electric Business Worldwide?  https://blog.enerdynamics.com/2016/04/21/new-yorks-rev-a-new-model-for-the-electric-business-worldwide/

[6] http://blog.luxresearchinc.com/blog/2016/07/leaders-and-laggards-in-the-race-to-create-the-utility-of-the-future/


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LNG Goes Off the Grid

by Christina Nagy-McKenna, Enerdynamics Instructor

Liquefied natural gas fueling station

This liquefied natural gas fueling station at INEEL was built by MVE, Inc. and provided to INEEL by Amoco LNG. As part of its liquefied natural gas R&D program, INEEL uses this skid-mounted LNG fueling station that can be moved to various locations to service its natural gas vehicles. (Photo credit: NREL)

Liquefied natural gas (LNG) may soon be available to customers who, due to infrastructure restraints, do not have the option to choose natural gas as a fuel source. ISO (International Organization of Standardization) containers that fit on rail cars, truck trailers, and container ships and can hold 10,000 gallons of LNG are the lynchpin to opening these new markets. The 40-foot by 8-foot containers hold the equivalent of 830 Mcf of natural gas, enough to meet the annual consumption of 13 American households[1], and they offer an alternative delivery system to the large tanker ships that have been used for many years.

Mainland, remote U.S. markets are the target for one project that utilizes ISO containers, while another company is focused on more distant markets in Alaska, Puerto Rico, the Bahamas, and the Caribbean. Each will offer new choices to customers as they manage their environmental and business goals.

In Port Allen, La., NuBlu Energy recently began construction on a small-scale LNG plant that will ship containerized LNG to U.S. markets that do not have access to natural gas pipeline infrastructure. While the company is currently focused on high-use, industrial, and power generation end-use customers, shipping LNG in ISO containers also could be useful to smaller companies that cannot afford the high cost of traditional gas pipeline infrastructure expansions. The first phase of NuBlu’s project will produce up to 30,000 gallons of LNG per day. The company plans to expand to 90,000 gallons per day with 120,000 gallons of on-site storage capacity.

William H. Martin, Inc., a USA waste services company, Waste Management of PA, fueling station

photo credit: NREL

Crowely Maritime entered the LNG market by purchasing Carib Energy LLP in 2013. Among its energy services, Carib LLP, now a Crowley subsidiary, offers containerized transportation of LNG to markets in Alaska, Puerto Rico, the Bahamas, and the Caribbean. Small-scale LNG deliveries in ISO containers has helped the company reach end users such as Molinos de Puerto Rico, the largest supplier of flour to Puerto Rico.  Using ISO containers, Crowley will transport LNG that it will purchase from Pivotal LNG to its shipping facility in Jacksonville, Fla. From there the containers will be loaded onto a ship and delivered to Puerto Rico where Crowley will oversee the delivery of the containers to the Molinas plant.

These are but two examples of the possible markets that containerized LNG will reach in future years. If the ISO distribution and LNG fuel technologies continue with their early joint success, remote end-use customers will eventually have more fuel choices like the many customers who are connected directly to the gas pipeline grid.

Footnotes and references

[1] 2009 Residential Consumption Survey, Table CE3.1, Household Site End-Use Consumption in the U.S., Totals and Averages, 2009, U.S. Energy Information Administration, January 11, 2013.

Containerized LNG Broadens Reach of Natural Gas to Off-grid Customers,” October 26, 2016, U.S. Energy Information Administration.

 “Crowley to Supply LNG to Alaskan Power Plant,” LNG World News, October 16, 2016.

Pivotal LNG, Crowley’s Carib Energy Reach Multi-Year Supply Agreement for Puerto Rico,” News and Media, August 31, 2016, Crowley Maritime Corporation website.

2009 Residential Consumption Survey, U.S. Energy Information Administration.


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Are E-Bay Style Transactions and Blockchains Ready to Transform Electricity Markets?

by Bob Shively, Enerdynamics President and Lead Instructor

Over the last 20 years, the electric industry has gradually transitioned how its consumers purchase electric services. Prior to the 1990s, all consumers bought bundled service from their monopoly local utility. Beginning with deregulation in the 90s, some regions unbundled supply from distribution to allow consumers to purchase electricity from third-party retail marketers; transmission and distribution remained the role of the monopoly utility.



Approximately 24% of U.S. consumer electric usage currently is acquired from retail marketers instead of the distribution utility. This figure has increased steadily and is likely to continue its growth given interest in Community Choice Aggregation in California and a successful ballot proposition in Nevada where voters supported implementation of customer choice. In other countries, this percentage ranges from 0% to 100% depending on regulatory and business models.

Both models assume that large central generators produce the bulk of supply that is then purchased by a central entity (either a utility or a retail marketer) for resale to end users. Retail electricity markets have continued transforming in some regions with the growth of distributed energy including combined heat and power (CHP), rooftop solar, and active economic demand response. But markets are still structured with the assumption that any distributed energy not used internally by a customer is sold back to a centralized entity.


Are Markets Ready for a New Paradigm of Peer-to-Peer Transactions?

From time to time, energy insiders have discussed whether an E-Bay model allowing customers with DER — sometimes called prosumers since they can both produce and consume electricity — could interact among themselves and bypass centralized market players. It’s comparable to how people sell unneeded used items on E-Bay or via Craigslist. Until now, technologies, markets, and regulatory rules have not allowed for such transactions. Even if one can figure out how to physically sell power to a neighbor (run a wire over the fence?) it’s likely they’ll receive a letter from the local utility instructing them to cease and desist from violating their monopoly franchise service territory.

But with regulators looking at new business models fostered by the growth of DER, pilot projects are now testing the possibility of enabling peer-to-peer transactions.

Unbundled peer2peer.png

Imagine that you install solar on your roof, but you and your other family members typically work during the day so no one is home. Rather than selling back to your utility, you might instead sell the supply directly to another consumer so they can avoid high time-of-use or demand charges and simply use the utility as an enabling network.

Enabling Technology is Here, We Just Need to Develop Regulatory and Business Models

The enabling technology is already available to make this happen including the PowerMatcher platform developed in Europe by the Flexipower Alliance Network and the Transactive Grid platform developed by the U.S. company LO3 energy. As the State of New York explores new business models in the NYREV process, Siemens AG and LO3 have announced that the Brooklyn Microgrid project will test local energy trading based on blockchain technology that is now being used to facilitate secure financial trading, but that has yet to be applied to retail energy.  Pilot projects such as the Brooklyn Microgrid and other efforts in Europe will begin to address the desirability of moving forward with new transactive business models. It will then be up to the regulators and industry participants to modify current structures to allow a new way of doing business to grow.

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Surviving the Winter Without Aliso Canyon: A Look at California’s Short- and Long-term Natural Gas Storage Future

by Christina Nagy-McKenna, Enerdynamics Instructor

California’s transition to a carbon-free resource mix for electricity generation may have just gotten a momentum boost from a most unlikely source: clean-burning natural gas.

Long at the forefront of the movement to use resources such as solar, wind, and hydro for electricity production, California – the state which as of 2025 will have no large-scale nuclear power plants and doesn’t use oil or coal – may sever its dependence on natural gas as a power generation fuel. This decision comes after last year’s leak at the Aliso Canyon gas storage field in Southern California. In place of traditional gas-fired electric generation, the state will focus on developing renewable energy projects, demand reduction, distributed generation, and energy storage.

On Oct. 23, 2015, employees of Southern California Gas Company discovered a leak at Aliso Canyon, the largest natural gas storage facility in California. Before the leak was finally plugged on Feb.18, 2016, it displaced thousands of nearby residents and became the largest methane leak in U.S. history[1]. The short-term implications of the leak may include curtailments, higher gas prices, and tighter balancing rules as California nears the winter heating season with Aliso Canyon still closed to storage injections. The long-term implications may be profound, and they may change the storage and energy production industries. Safety regulations will be strengthened and natural gas as a fuel for generation may be more quickly supplanted by renewables and energy storage.

Aliso Canyon SS 25 wellhead, December 17, 2015.
Note subsidence craters at center, apparently from the attempts to plug the leaking well [2].

Aliso Canyon plays an important role in ensuring that there is adequate natural gas available to Southern California customers during the peak winter season. It also serves many gas-fired power plants year round by providing an accessible source of gas for quick power plant dispatch. On a daily basis power plants belonging to Southern California Edison (SCE), Los Angeles Department of Water & Power (LADWP), San Diego Gas and Electric (SDG&E), and numerous smaller municipalities including the cities of Glendale, Burbank, Pasadena, Anaheim, and Vernon, all rely on Aliso Canyon to help balance their natural gas needs.

These power plants have no backup fuel as burning oil is rarely allowed in California. When combined, the inability to burn oil and coal, limited hydroelectricity due to four years of drought, and the closure of the San Onofre Nuclear Power Plant in 2012 that wiped 2,200 MW off the grid in Southern California left the region substantially dependent on natural gas. When Aliso Canyon sprang a leak that could not be plugged for four months, natural gas suddenly looked less safe and reliable.

Under order of Governor Jerry Brown, the California Energy Commission, the California Public Utility Commission (CPUC), LADWP, and the California Independent System Operator (CAISO) formulated a plan to shepherd Southern California through Summer 2016 with the intent to minimize gas and electric interruptions to all customers. The plan worked well with results including:

  • tighter balancing rules for non-core through stricter operational flow orders;
  • demand reduction;
  • closer coordination between the ISO and SoCalGas;
  • LADWP operated its system differently as it halted excess energy sales, economic dispatch, and physical hedging;
  • LADWP acquired a waiver to burn diesel if its gas was curtailed; and
  • Aliso Canyon was limited to 15 Bcf of inventory to be used only for system reliability issues per order of the CPUC.

For the winter, a recently released plan from the same regulatory agencies added additional measures to deal with the possibility that Aliso Canyon will remain unavailable this winter for anything other than system reliability issues. These measures include:

  • a gas demand response program;
  • extending the tighter balancing rules;
  • new balancing rules for core customers;
  • reducing down time on pipelines due to maintenance;
  • preparations to buy liquefied natural gas (LNG);
  • identification and solicitation of additional gas supplies;
  • monitoring gas usage of oil refineries; and
  • modifying the use of Aliso Canyon as appropriate if regulators change the restrictions currently in place.

In concurrence with this plan, the CPUC last week ordered SoCalGas to submit a proposal for a demand response program for natural gas that would be implemented on December 1, 2016.

What Else Can Be Expected This Winter?

The utility’s own hydraulic modeling shows that under normal weather conditions, without withdrawing gas from Aliso Canyon, it can meet customers’ daily demands by withdrawing gas from its remaining gas storage facilities. Under cold weather conditions, it appears that as long as all facilities remain operational, the utility will just barely meet customers’ delivery needs with very little cushion for contingencies. However, the utility will be unable to meet peak day demands without curtailing customers by approximately 0.3 Bcf.

The worst-case scenario would be an abnormally cold winter, no ability to use Aliso Canyon, and equipment malfunctions on either SoCalGas’ pipeline system or those of the interstate pipeline companies that serve Southern California that would limit supply deliveries. If there is not enough supply for the region, then natural gas and electricity prices are expected to rise. Higher natural gas prices will increase rates to customers for gas and electricity if electric generators use the spot market to round out their supplies.

In the longer term, the impact of the Aliso Canyon leak will be codified through more operational and safety regulations that are expected from California’s Division of Oil, Gas, and Geothermal Resources (DOGGR), which regulates gas wells, the CPUC, and also the California Legislature. SB 887, which calls for increased testing and reporting for storage owners, is already sitting on Governor Brown’s desk awaiting his signature.

Some of these new rules will impact storage owners’ operations this winter, but it is unknown at this time if and when the Governor will sign the bill into law. Natural gas will continue to play an important role as a heating fuel for most customers and as feedstock for large industrial end users. However, its role as a popular fuel for electricity generation in California seems to be coming to an end.

Source: Energy Information Administration

The colossal nature of the Aliso Canyon leak will continue to accelerate California’s development of renewable power generation, distributed generation, energy storage, energy conservation, and the move away from electricity generated from natural gas. The scale of the accident, including the thousands of people temporarily displaced from their homes, the record amount of methane released into the atmosphere, and the inability of the utility to plug the leak for four months was simply unprecedented and unsettling. In Northern California PG&E has announced it will shut down the Diablo Canyon Nuclear Power Plant in 2025. However none of the steps it will take to replace the 2,200-MW gap in capacity involves natural gas. Instead, the utility plans to work with customers to reduce energy usage and to use renewables, distributed generation, and other forms of energy storage.

Predicting the future is an inexact practice, but given the recent accident at Aliso Canyon, regulators and legislators seem determined to steer power generation in California away from natural gas and toward a cleaner, carbon-free future. While the short-term focus will be on regulations that make gas storage safer and strategies that ensure natural gas supplies and deliveries are adequate to serve customers in the coming winter, the long-term emphasis will be to develop energy projects that do not rely upon fossil fuels, to incent customers to use less resources, and to ramp up the usage of energy storage. Natural gas as a heating fuel will have its place, but natural gas-fired power plants will have a much more limited role in California’s future resource mix.

Footnotes and references:

[1] For an explanation of how the leak occurred, see our blog Gas Storage Safety, What is Next After Aliso Canyon?, https://blog.enerdynamics.com/2016/02/23/gas-storage-safety-what-is-next-after-aliso-canyon/

[2] Image By EARTHWORKS (Aliso Canyon leak well pad 4 Credit: Earthworks), [CC BY 2.0 (http://creativecommons.org/licenses/by/2.0)%5D, via Wikimedia Commons

Aliso Canyon Gas and Electricity Reliability Winter Action Plan, California Public Utilities Commission, California Energy Commission, California Independent System Operator and the Los Angeles Department of Water and Power, August 22, 2016.

Bade, Gavin, “After Diablo Canyon: PG&E CEO Tony Early on Renewables, DERs and California’s Energy Future,” Utility Dive, June 30, 2016.

Manzagol, Nilay, “California is Using More Renewables and Less Natural Gas in its Summer Electricity Mix,” September 6, 2016, US Energy Information Administration

Natural Gas Weekly Update, September 14, 2016, US Energy Information Administration

Southern California Daily Energy Report, September 21, 2016, US Energy Information Administration

Walton, Robert, “Facing Stricter Climate Goals, California Passes 4 Bills to Boost Energy Storage,” Utility Dive, September 2, 2016.


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Is the End of Baseload Generation a Reality?

by Bob Shively, Enerdynamics President and Lead Instructor

Since the mid-20th century, it’s been widely accepted wisdom: For electric utilities to economically serve customers they must build generating systems rooted in large baseload plants. But with the recent growth of renewables in various global markets, the need for large baseload plants is in question. Developments in markets such as Southern Australia and Northern California suggest that the concept of baseload generation may soon be considered a thing of the past.

Adding significant amounts of wind and solar to the electric grid results in a paradigm shift from traditional baseload generation. Now a significant amount of electric supply is not controllable and is variable in nature. The new resources share some interesting characteristics with typical baseload units and in other ways are the exact opposite.

From a cost standpoint, renewables share the baseload characteristic of low operating costs but higher upfront capital costs. This means that utilities prefer to take the output of renewable units whenever it is available. And given the operating restrictions on baseload units, system operators do not like to ramp the units much meaning that controllability of baseload units is low. This is similar to renewables (at least from the standpoint of the ability to ramp up, renewables can usually be ramped down by simply curtailing their power although this is not a popular alternative). But the key difference is variability. Traditional baseload units are expected to have similar output every hour (except during planned or forced maintenance outages), whereas renewables are a variable resource whose output depends on weather.

As renewables grow, system operators shift the focus on operating traditional units to serve all loads to operating them to serve the “net load’ – that portion of load not served by renewable resources. Forecasts for some scenarios suggest that eventually solar power may push net loads in some regions to below zero. To maintain system balance, operators in this case would either need to export power to another grid, have available storage options, have flexible loads willing to use more power, or curtail solar output.

So will renewables be the death of baseload? In 2015, Australian professor Mark Diesendorf raised eyebrows in the utility industry with his paper titled “Do We Need Base-load Power Stations?” The paper suggested that “base-load power stations are unnecessary to meet standard reliability criteria for the whole supply-demand system, such as loss-of-load probability or annual energy shortfall.” Diesendorf suggested that future dispatch curves may look like this:

Source: Energyscience.org [1]

In the last few months, it has become clear that Diesendorf’s thoughts are not just idle speculation. In May, the state of South Australia closed its last baseload unit, the 520 MW Northern coal unit. Now, the dispatch curve in the state shows large amounts of renewables supplemented with flexible gas generation:

Source: RenewEconomy [2]

In June the major utility in Northern California, Pacific Gas and Electric (PG&E), announced a settlement that will result in closing their 2,240 MW Diablo Canyon nuclear unit by 2025[3]. The settlement outlined PG&E’s plan to replace Diablo’s power with a mix of reduced loads through energy efficiency, flexible loads, storage, and renewable power. Once this occurs, one of the largest utilities in the U.S. will be operating without any traditional baseload units.

In most cases, major infrastructure such as electric grids take many decades to transition once new technologies are introduced[4]. Many regions will continue to use baseload units for years to come. But markets such as Southern Australia and Northern California show us that, in some cases, transitions happen more quickly than we expect. And yes, it is possible to run an electric system without baseload units.


[1] Available at: http://www.energyscience.org.au/BP16%20BaseLoad.pdf

[2] Giles Parkinson, Wind and solar power become the new “base load” power for South Australia, May 16, 2016, available at http://reneweconomy.com.au/2016/wind-and-solar-become-new-base-load-power-for-south-australia-99364

[3] See Joint Proposal for the Orderly Replacement of Diablo Canyon Power Plant with Energy Efficiency and Renewables, available at http://www.pge.com/includes/docs/pdfs/safety/dcpp/MJBA_Report.pdf

[4] See for instance this blog by Vaclav Smil: http://blogs.scientificamerican.com/the-curious-wavefunction/vaclav-smil-e2809cthe-great-hope-for-a-quick-and-sweeping-transition-to-renewable-energy-is-wishful-thinkinge2809d/

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Utility Business Acumen Series Helps Companies Navigate Changing Workforce

by John Ferrare, Enerdynamics CEO

Earlier this month Enerdynamics President Bob Shively wrote about the changing workforce that change-000058098154_mediumwill drive the energy industry’s future. Perhaps the most notable statistic: As much as 50% of utility employees will reach retirement age in the next five to 10 years.

Over the past several years, I’ve noticed increasing requests for business acumen curriculum. In fact, many clients have done extensive needs analyses for their companies and found utility business acumen training to be a primary training concern among employees.

In response to this phenomenon, Enerdynamics recently launched 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.

Remember that much of what we do can be customized for your company. Contact me at 866-765-5432 ext. 700 or jferrare@enerdynamics.com 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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