Updates Made to Most Popular Online Energy Industry Courses

When you purchase or site license any of Enerdynamics’ online courses you are able to access, without additional fees, the periodic updates made to these courses. Enerdynamics recently updated its two most popular online courses: Gas Industry Overview and Electric Industry Overview (including Canadian and Global versions). These updates are important as the industry evolves rapidly. Within just a few short years, energy industry data including customer, economic, and even regulatory information can change dramatically. These are the type of updates now found in both courses.

If you have site licensed either course and are running the files on your LMS, Enerdynamics already has or will contact you soon with download information for the new files. If you purchased subscriptions that run on Enerdynamics’ LMS, any new starts to either course will refer to the updated version. Those employees who already started a course prior to the update will continue with the existing course.

Gas Industry Overview and Electric Industry Overview present comprehensive introductions to each industry and are ideal for new employees or those who need a better “big picture” understanding of the industry.

For a demo of Electric Industry Overview, click here or on the image below:

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For a demo of Gas Industry Overview, click here or on the image below:

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For more information on these updates or how to make these courses available to your employees, contact John Ferrare at jferrare@enerdynamics.com or 866-765-5432 ext. 700.

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A Typical Day at an ISO (Independent System Operator)

by Bob Shively, Enerdynamics President and Lead Facilitator

To prepare for an operating day, the independent system operator (ISO) must schedule units one day ahead of time to kansas_city_2_lprovide supply across the upcoming 24 hours. This is handled by the day-ahead scheduling process. Units are scheduled hourly, meaning that units will receive 24 schedules – one for each hour of the following day. The schedule tells the unit what services it is expected to provide and the amount of megawatts (MW) associated with each scheduled service.

For instance, for a given hour a unit with a capacity of 200 MW might have 150 MW scheduled to provide energy and 50 MW scheduled as spinning reserves. This tells the unit operator that for the given hour, it is expected to provide 150 MW of energy and must be prepared to ramp up an additional 50 MW if called on by the ISO.

Day-ahead Scheduling

The day-ahead process works as follows:

  • At a specified time in the morning, unit scheduling coordinators submit an offer to the ISO. This offer includes services the unit is willing to provide at a given price as well as various operational characteristics such as start-time, ramp capability, willingness to be started and then stopped, and minimum and maximum run times.
  • Simultaneously, load-serving entities (LSEs) submit hourly bids for buying energy to supply loads. Although LSEs sometimes state an unwillingness to buy energy above a certain price level, in most cases LSEs simply state a forecast load plus a willingness to pay whatever the price is to receive supply.
  • The ISO inputs expected system conditions including transmission availability and then runs optimization software to determine the least-cost dispatch available to serve the required loads given the various generation offers.
  • By the early afternoon, the ISO sends out schedules to each unit that was selected in the optimization process and notifies other generators that they have not been scheduled. The ISO also notifies all LSEs of the amount of load scheduled to be served. The optimization model creates day-ahead energy prices for each location on the grid and zonal prices for ancillary services. The energy prices are called locational marginal prices, or LMPs, and reflect the actual marginal cost of serving load at each location.
  • Since day-ahead schedules are considered firm, units are paid the LMP for their scheduled output, and loads are charged the LMP for their scheduled deliveries regardless of what actually happens in real time.
    day-ahead scheduling

Real-time Operations

A separate group at the ISO runs the system to ensure that supply and demand are kept in balance in real time during the operating day. This process works as follows:

  • The real-time operators have various units available to ramp up or down given the resources selected in the day-ahead scheduling process.
  • As the supply-demand balance fluctuates, the ISO ramps units as needed based on the offers accepted in the day-ahead. A real-time LMP is determined based on the price for marginal units used in ramping.
  • After the hour, the ISO calculates each unit’s actual output compared to the output scheduled in day-ahead. The real-time LMP is applied to any deviation from scheduled, and each unit is paid or charged (depending on whether the unit generated more or less than scheduled) based on the LMP at that unit’s location.
  • Similarly the ISO compares each LSE’s schedule at specific grid locations to the LSE’s actual usage. Again, the deviation from day-ahead schedule is either charged or paid depending on whether the LSE used more or less than scheduled.

Real-time operations

Want to learn more about ISOs and how they operate? ISO Market Basics, an online course by Enerdynamics, gives a thorough overview of how ISO markets work, how services (capacity, energy, operating reserves, and financial transmission rights) are bought and sold in an ISO, the role of ISOs and various market participants, and the various types of electric markets available to market participants.

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What is the Least-cost Source of Electricity in Your Community?

by Bob Shively, Enerdynamics President and Lead Instructor

Average Costs Across the U.S.

In our June 2016 blog post titled Economics, Not Policy Mandates, Drive the Growth of Renewables we described how the price of utility-scale wind and solar projects was becoming competitive with traditional forms of generation. The discussion was centered on data developed in 2015. Costs for renewables are decreasing so rapidly that an update using more recent numbers shows even more dramatic results. Stunningly, wind and utility-scale solar PV are now the two lowest-cost generation sources.

Levelized Gen Costs 2016

Source: Lazard’s Levelized Cost of Energy Analysis – Version 10.0, December 2016

Costs in Your Community

The University of Texas at Austin recently performed a related study titled New U.S. Power Costs: by County, with Environmental Externalities that takes into account generation costs similar to those shown above, but it also considered additional externalities. The complete list of factors considered include:

  • Power plant costs including operating plus capital costs
  • Fuel costs
  • Environmental and health costs including air quality and greenhouse gases
  • Infrastructure costs including transmission and distribution, rail, and gas pipelines
  • Integration costs for renewables and distributed energy resources
  • Opportunities for energy efficiency
  • Government financial support for electricity

The University of Texas study analyzed the lowest-cost form of generation by county across the U.S.:

lowest cost generation map.png

Source: Natural gas and wind are the lowest-cost generation technologies for much of the U.S., new UT Austin research shows, December 8, 2016

Here we see the dominance of wind in the Midwest, solar in sunny regions of the West, and natural gas combined-cycle turbines in much of the rest of the country. Interestingly, in a smaller number of counties nuclear power is the low-cost resource.

How Costs Affect U.S. Generation Mix

Not surprisingly, planned generation additions and retirements are reflective of cost data. 

Summer capacity additions.png

Source:  EIA website as of March 2017

Given that generation decisions are made at the local and state levels, it seems logical to conclude that regardless of federal policies the movement to gas and renewable generation will continue.



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Corporate Purchasers Are As Important as Utilities in Renewables Growth

by Bob Shively, Enerdynamics President and Lead Facilitator 

In recent years, new wind and solar electric generating capacity has outpaced all other sources of power. In 2016, the two renewables sources grew by more than 20,000 MW compared to the next largest source, natural gas, which grew by about 7,000 MW.

net changes in U.S. Summer Gen Capacity.jpg

Source:  Based on data from the EIA website

Much of this capacity has been built under power purchase agreements (PPAs) with utilities either because the utility needs the power to fulfill a state-mandated renewable portfolio standard or, increasingly, because renewable power has become the low-cost supply choice when the utility performs its periodic Integrated Resource Planning (IRP) process. But another key factor leading to the growth of renewables is growth of corporate end-use buyers who sign PPAs with renewable developers.

Indeed some analysts have suggested that corporate buyers have become as important as utilities. The Business Renewables Center tracks publicly announced corporate renewable deals and is showing  4,810 MW of new corporate-funded renewable capacity over the last two years.

corporate renewable deals.jpg

Source: Rocky Mountain Institute

Buyers include many well-known companies including Amazon, Apple, Dow Chemical, Google, Microsoft, and Walmart. Google announced that in 2017 they expect to buy enough renewable energy to account for 100% of their usage[1], (which is about equivalent to the energy usage by the city of San Francisco!).

Why Do Corporate Buyers Sign PPAs to Buy Renewables?

Corporate buyers are signing renewable deals for two key reasons. One is that a growing number of corporations have adopted corporate sustainability goals and/or believe that buying clean power enhances their marketplace image. But in many cases, corporate buyers are committing their dollars because they believe it is the best way to lock in reasonably priced power supply over the long-term.

As quoted in a recent Utility Dive article[2], Google’s director of energy and sustainability said: “We are not doing this because it will make us feel good.  These are economic decisions that are also good for the world.”

I’ve heard similar sentiment from the corporate energy buyer for Walmart who said when he goes to the Walmart board for approval for his plans, he doesn’t even mention sustainability; he simply sells renewables deals based on what is the most economic source of energy supply for Walmart. The key is that by signing fixed-price long-term PPAs, corporations are reducing their risk of future electricity price increases.

How Does a Corporate PPA Work?

In competitive retail markets where end users are allowed to buy directly from generators, it is easy to see how a company like Google can lock in fixed power prices through a PPA since the power they buy can be directly used by their end-use facilities[3].

corporate PPA

Source: Google whitepaper[4]

To make things work in a market where the utility is responsible for supplying power to end-use consumers is a bit more complex as demonstrated by the above graphic.

  1. Google buys energy bundled with renewable energy credits (RECs) from a renewable project in a long-term fixed price PPA. The PPA gives Google the rights to all MWh generated plus all RECs associated with the MWh.
  2. As energy is generated, Google resells the MWh into the wholesale market place. The revenue that Google receives varies depending on the market price of electricity. In some cases it will be higher than what Google paid to the renewable developer; in others is will be lower.
  3. Google buys energy supply for its data center from the local utility and pays the regulated utility supply rate. While the cost of the utility supply rate may not exactly match up with the revenues Google receives from selling power in the wholesale market in Step 2, there should be a decent correlation between the two prices since the utility also buys power from the market.
  4. Google applies the RECs to its consumption to verify that its use of electric supply is backed by renewable generation.

While the renewable PPA isn’t a perfect price hedge relative to the cost of utility supply, it is expected to be a reasonable hedge against utility rate movements. And Google gets one other significant benefit — the output from the renewable project does not have to match up in time with consumption by the data center since the utility grid is being used to “store” power when generation and usage doesn’t match.

What is the Future of Corporate Renewables Purchases?  

The Rocky Mountain Institute estimates that over 60,000 MW of new renewables will be needed by 2025 to meet corporate clean power goals. Sixty-five key companies have created a set of Corporate Buyer’s Principles that are intended to guide utilities and regulators in setting rules that allow for ease in signing long-term PPAs.  Signatories include most of the companies already mentioned here plus other well-known companies including Target, Gap, GM, Kellogg’s, Hilton, Starbucks, and McDonald’s. By all indications, corporate support for renewable projects will continue to grow even if U.S. government policy does not support renewables.


[1] See ‘We’re set to reach 100% renewable energy — and it’s just the beginning’ at    https://blog.google/topics/environment/100-percent-renewable-energy/

[2] See ‘Mutual needs, mutual challenges: How corporate PPAs are remaking the renewables sector’ at http://www.utilitydive.com/news/mutual-needs-mutual-challenges-how-corporate-ppas-are-remaking-the-renewa/425551/

[3] There is still an issue associated with the locational value of power if the generator is not located at the same point on the grid as the consumer, but we will explore that issue in a future blog.

[4] See  ‘Achieving Our 100% Renewable Energy Purchasing Goal and Going Beyond’ at  https://static.googleusercontent.com/media/www.google.com/en//green/pdf/achieving-100-renewable-energy-purchasing-goal.pdf

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Will Low Natural Gas Prices Continue?

by Bob Shively, Enerdynamics President and Lead Facilitator 

In 2016, annual average natural gas prices in the U.S. were the lowest since 1999.

Ave annual HHub natural gas spot price.png

Source: EIA website


Interestingly, this occurred even with a slight drop in production and slight increases in both demand and exports.

US dry gas production and demand.png

Source: EIA website

While prices rose a good bit in December due to cool weather, warmer temperatures have pushed prices right back down in recent weeks:


Source: EIA website

Low natural gas prices have had significant impacts on the energy marketplace:

  • For the first time ever, electricity generation by natural gas power plants in 2016 was the largest source of generation in the U.S. surpassing coal which has been the leader since the mid-1900s.
  • The cost of power generation by gas has fallen to unprecedented low levels. Combined with growing low-cost renewable and solar power in some markets, numerous coal units and even some nuclear units have closed or been scheduled for closure.
  • Many independent power products (IPPs) are now questioning whether they can attain enough market revenues to stay in business
  • Exports of LNG are now economic as cargos priced at an index to Henry Hub are competitive in world markets.
  • Industrial gas demand in the U.S. is at the highest level since the year 2000.
  • And both natural gas and electricity consumers have benefited by low utility bills.

Given these factors can we expect that gas prices will continue to stay low, or will prices creep back up? A quick Google search of the phrase ‘2017 gas price forecast’ leads to sites with titles like “Outlook ’17: U.S. natural gas prices could soar” and “Will natural gas go on another run in 2017?”

Natural gas prices are set by the market based on the forces of supply and demand, plus market expectations for the future. So what are the expectations?

  • Demand plus exports is forecast to be flat: According to the EIA February 2017 Short-term Energy Outlook, the level of demand plus exports in 2017 is expected to grow about 1% compared to 2016.


It should be noted that this assumes that electric power generation will fall a bit, primarily because the EIA has forecast a significant gas price increase to $3.54, which makes gas generation less competitive with coal.

  • Supply is forecast to increase slightly: According to the EIA Short-term Energy Outlook, supply is forecast to increase by about 2% due to increasing U.S. gas production.

US Gas Supply.png

And indeed, we have seen natural gas rigs actively drilling for gas increase by 50% compared to this time last year, which would indicate that more supply is on the way.  Meanwhile, natural gas in storage is about 4% above the 5-year average.

  • The natural gas futures market is less optimistic on price than the EIA.

    NYMEX HH 2017 Futures Prices.png

The natural gas futures market, which indicates the current price available today to lock in a purchase or sale of supply in future months, suggests an average 2017 price of $3.03.  This is more in line with forecasts from the IMF and the World Bank, which forecasts U.S. gas prices of $3.00/MMBtu for 2017.

  • Weather doesn’t look promising to help gas prices in the near term: According to weather forecast maps from NOAA, winter may already be close to over with forecasts for both the next month and the next three months showing temperatures higher than normal for most of the country.



So what can we expect for gas prices in 2017?

With production still strong, heating demand looking low for the rest of this winter, and gas in storage above the five-year average, it doesn’t look optimistic for significant gas price spikes. Much will depend on power plant demand for natural gas, and producers are hoping for a hot summer. Absent that, we would expect gas prices to remain at historic lows. Others disagree and think there is potential for a price run-up. That is the fun of the gas markets — no one knows what will happen until it does!

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Electrification May Be Key to Saving Utilities and the Environment

by Bob Shively, Enerdynamics President and Lead Instructor

These are uncertain times for electric utilities. With flat load growth, increasing Straight open road to upcoming 2017 at idyllic sunsetdistributed energy, shrinking value for many large centralized power plants, and discussion around changing business models, electric utility shareholders are left wondering from where future earnings growth will come. Meanwhile, despite the current administration in Washington, utilities in many regions are feeling increasing pressure to reduce environmental impacts.

Historically, utilities have grown earnings by investing in capital facilities as loads grew. Large fossil fuel power plants were a favored source of investment. Customers were generally on board since growing loads meant costs were spread over more sales and rates did not go up much.  However, load growth now appears uncertain. As recently stated by Jim Rogers, the former CEO of Duke Energy:

“I think the demand for electricity is going to be anemic, at best. Perhaps more likely than not, the demand for electricity will actually decline.”

Without demand growth, the path for utility investment seems restricted to system upgrades.  Unfortunately, investment without load growth inevitably leads to rate increases. But, there may be a new path to load growth that will help utilities find a new wave of growth while also benefiting the environment. 

Jim Avery, Chief Development Officer at San Diego Gas & Electric, believes electric vehicles (EVs) are the solution. Says Avery: “Think I’m worried about growth? I’m worried about how the hell do I serve all of that.” 

The potential for load growth and environmental benefits was covered in a recent whitepaper from the Brattle Group, titled Electrification – Emerging Opportunities for Utility Growth. In the executive summary, the authors write that under the current prevailing paradigm, utilities struggle with weak sales and growing distributed generation (DG) while projections show that emissions of greenhouse gases (GHG) will continue to exceed what is needed to meet long-term GHG reduction goals. But the authors suggest that with electrification of the transportation and heating sectors coupled with a significant reduction in GHG outputs from electric generation, a different paradigm can be achieved that offers a strong future to electric utilities. Under this scenario, electric utility sales could nearly double by 2050 while energy sector GHG emissions would decrease by 70%. 

To make this happen, the authors suggest that electric utilities could strive to shift loads to electricity from fossil fuels. The benefits could be achieved by addressing two key sectors:

  1. Transport
  • Light duty vehicles including passenger vehicles such as the cars we all drive
  • Commercial light trucks
  • Freight trucks

For this sector, current liquid fossil fuels would be replaced with battery electric vehicles.

  1. Residential and commercial loads:
  • Water heating
  • Space heating
  • Cooking

Here, current demand fueled by natural gas, propane, and fuel oil would gradually be replaced by heat pumps, electric water heaters, and electric ranges. 

The result according to the Brattle Group could be a 96% growth in electric load coupled with a 72% decrease in U.S. energy-related GHG emissions.


How can utilities move toward this more positive future? Brattle Group suggests the following:

  • Regulatory outreach to communicate the potential benefits and to overcome barriers
  • Infrastructure deployment to build vehicle charging facilities
  • Rate reform to remove barriers to electricification and to account for the characteristics of the new end-use technologies
  • Program development including pilot projects and financial incentives to promote adoption
  • Resource planning including enhanced load shape forecasting and analysis of cost trajectories and adoption rates

While utilities currently struggle with the risks of slow load growth and potential competition from distributed resources, the Brattle Group presents a vision of an alternate future that could prove lucrative for utility investors. 

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Can Carbon Capture and Storage Do for Coal What President Trump Can’t?

by Bob Shively, Enerdynamics President and Lead Instructor

A key promise of Trump’s presidential campaign was revitalization of the coal industry to Smoking power plantmaintain coal-related jobs in the U.S. But as we pointed out in our Energy Insider article  “The Election Is Over: What’s In Store for the Energy Industry Under the Next Administration?”, it is unlikely that administration policies will do much to help a coal industry reeling from low natural gas prices combined with local and international energy policies designed to reduce greenhouse gas (GHG) emissions.

Indeed, since the inauguration, U.S. utilities have announced planned closures of the largest coal unit in the West and two large coal units in the Midwest[1]. And China, with its current fleet of more than 50% of the world’s coal capacity and more under construction, seems to be serious about reducing coal emissions[2].

But perhaps for the longer term, the coal industry saw a hint of light at the beginning of 2017 with the completion of the Petra Nova carbon capture plant southwest of Houston, Texas. Unlike other recent carbon capture generation units, the Petra Nova plant was completed essentially on time and on budget. The unit will capture 90% of the carbon dioxide (CO2, which is a key GHG) emitted from 240 MW of generation and will then pump the carbon through a pipeline for injection into a nearby oil field. The injection of the carbon will help producers capture more oil by stimulating flows, and the producers will pay Petra Nova for the CO2, thus creating a revenue stream for the power plant owners.

What is carbon capture and storage?

Carbon capture and storage (CCS) is the process of removing carbon from a fossil fuel stream, either pre- or post-combustion, and then storing the carbon in a location where it cannot leak into the atmosphere. If CCS can become feasible and economic, it can greatly prolong the use of fossil fuels in power generation since their GHG emissions would be significantly reduced. While CCS works in laboratories and demonstration projects, it has yet to be demonstrated in wide-scale commercial operation. Initial projects have struggled to get the technology to work well and to get projects built and running without wildly exceeding estimated costs.

So, the coal industry is celebrating as the new Petra Nova project comes online on time and on budget. This project is jointly owned by NRG and JX Nippon Oil and Gas, and it was installed on NRG’s existing WA Parrish generation station. In the new CCS plant, the exhaust waste from the electric generating station is run through a vessel containing a solvent called amine. Amine captures the CO2. The amine/CO2 mixture is then removed from the stream, the CO2 is separated by heating, and then pumped into a pipeline. The pipeline delivers the CO2 to a nearby oil field for use in a common process called enhanced oil recovery, which stimulates oil production. Since the process will result in oil production that was otherwise not possible, NRG estimates that at an oil price of at least $50/barrel, the process will prove economic[3].

Here’s a visual representation of how the process works as reported by U.S. News and illustrated by NRG:

source: http://www.usnews.com/news/articles/2014/09/17/carbon-captures-moment-in-the-sun

Does CCS have the opportunity to significantly reduce GHG emissions?

The role CCS plays as a widespread tool in reducing GHG emissions will depend on proving that the technology will work well in the field and in bringing down costs. Initial installations of any technology are always expensive. NRG estimates they can bring down costs for the next installation by 15%, but this likely isn’t enough to lead to many installations; costs will have to come down more substantially.

A recent study by the International Energy Agency, however, suggested that about a third of China’s existing 900 MW fleet of coal units could meet basic criteria for being suitable for a retrofit[4].  So although applications for CCS must still be proven, there is the possibility that use of CCS could become widespread through retrofits on existing coal plants.  In addition many in the industry believe that CCS may be a solution for reducing GHG emissions from natural gas units that provide needed flexibility to grids with large amounts of renewable power. Given these factors, there is strong industry interest in developing the technology, and initial projects will be closely watched to help determine whether CCS can become a part of our future.


[1] See ‘Utilities vote to close 2,250 MW Navajo plant, largest coal generator in western US’ at http://www.utilitydive.com/news/utilities-vote-to-close-2250-mw-navajo-plant-largest-coal-generator-in-we/436222/ and ‘DPL settlement to close two power plants, shift to green energy’ at http://www.bizjournals.com/dayton/news/2017/01/31/dpl-settlement-to-close-two-power-plants-shift-to.html

[2] See ‘China’s war on coal continues – the country just cancelled 104 new coal plants’ at  http://www.vox.com/energy-and-environment/2017/1/17/14294906/china-cancels-coal-plants

[3] For more detail on how the process works, see the video available at https://www.youtube.com/watch?v=GGnGZ6pLzLU

[4] See ‘The potential for carbon capture and storage in China’ at https://www.iea.org/newsroom/news/2017/january/the-potential-for-carbon-capture-and-storage-in-china.html

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