Update on Energy Storage

by Bob Shively, Enerdynamics President and Lead Facilitator

Earlier this year on Energy Currents we explored how storage is changing paradigms in electricity system design and operations. Given that storage use is evolving rapidly, it is worth a bit more discussion on some key current issues involving energy storage.

storage deployment across gridSource: EIA Today in Energy


Technology Development

While hydro-pumped storage still dominates the overall electrical storage capacity in the U.S. (and other markets worldwide), rechargeable batteries are the quickest growing source.

Energy storage deployments in US

Source: U.S. Energy Storage Monitor: Q3 2017 Executive Summary, Energy Storage Associate and GTM Research


Rechargeable battery types include lead-acid, nickel-metal-hydride (NiMH), litium-ion (Li-ion), sodium sulphur (NaS), and vanadium redox flow (VRB). Li-ion and VRB types have seen significant performance improvements and cost reductions in recent years. Currently Li-ion batteries make up close to 95% of new installations, with VRB accounting for most of the rest according to the U.S. Energy Storage Monitor.

Li-ion installations are popular because the battery performance is acceptable, costs are relatively low compared to other battery technologies, and the technology is readily available in the market. An example of a recent use are three large-scale projects in Southern California that were built quickly in response to the Aliso Canyon Gas Storage facility leak. The facility was shut down thus eliminating a source of gas supply for gas-fired power plants that were required to maintain the electric grid in Southern California. In response, the California Public Utilities Commission (CPUC) approved construction of up to 100 MW of electricity storage in the Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E) service territories.  The result was multiple projects[1] all completed by January of this year including:

  • SCE’s Alta Gas Pomano Energy Facility (20 MW/ 80 MWh) built by Greensmith Energy using Li-ion batteries from Samsung SDI
  • SCE’s Mira Loma Battery Storage Facility (20 MW/ 80 MWh) built by Tesla using Li-ion batteries from Tesla/Panasonic
  • SDG&E’s Escondido Substation (30 MW/ 120 MWh) built by AES also using Li-ion batteries from Samsung SDI

The projects have shown that battery facilities can substitute for gas-fired generation units as a grid resource  Indeed, California is now debating the economics of batteries combined with distributed energy resources versus construction of a new gas -fired combustion turbine power plant in Oxnard.

Regulatory and Market Issues Are Holding Back Battery Storage Development

How rapidly battery storage grows will depend not only on technology development but also regulatory developments. At both the federal level (FERC) and state level (state commissions) issues must be addressed including:

  • Who should own storage assets (third parties, regulated transmission owners, regulated distribution companies, and/or end-use customers)
  • How markets should evolve to compensate storage owners for the services they provide the grid (capacity, storage, traditional ancillary services, new flexibility-based ancillary services, energy, T&D deferral, power quality, etc.)
  • How retail rate structures should evolve to recognize behind-the-meter storage
  • How compensation for distributed energy resources such as net-metering affect energy storage
  • How tariffs at the wholesale and retail level can create a level playing field for the various technologies that might compete to provide grid services including battery storage, other forms of storage, demand response, central power plants, and transmission or market expansion to wider geographic regions

As the technology develops rapidly, it may be regulatory and market issues rather than technology developments that hold back storage. We will continue to watch these as things progress.


[1] For a list of all projects, see Greentech Media,  Tesla, Greensmith, AES Deploy Aliso Canyon Battery Storage in Record Time


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Energy Prices Aren’t Always Predictable, Part II – the Natural Gas Version

by Bob Shively, Enerdynamics President and Lead Facilitator

Last week I wrote about how many in the electricity industry were surprised by price behavior during the solar eclipse.  This week, let’s look at another unique event – Hurricane Harvey hitting the Gulf gas production basin. This is an interesting event for those in the gas industry because it is the first major storm to hit the Gulf in the “shale gas era.”

Harvey made landfall late on Friday, Aug. 25between Port Aransas and Port O’Connor, Texas. It was the strongest hurricane to impact Texas since 1961 and the first category 4 storm to make landfall in the U.S. since 2004. Harvey’s impact on gas production and pipelines was significant as numerous producers shut down wells plus multiple pipelines were damaged and unable to deliver supply out of the Gulf Basin. In the past, severe storms in the Gulf immediately caused significant price spikes. But not in 2016!

HH prices and hurricanes

Indeed, looking at Henry Hub cash prices for the days around when Harvey made landfall show that markets gave a big shrug.

HH cash price

Clearly anyone basing their gas pricing decisions on what used to happen during big storms in the Gulf would be wildly wrong.

Why Gas Prices Behave Different Now

While Gulf production was recently as much as a quarter of U.S. production, it now makes up a much smaller percentage.

Gulf gas production
   Source: EIA


Other regions with plentiful production such as the Appalachians and the Rockies were happy to make up for any lost Gulf production missing in the demand centers of the Northeast and the Midwest. Meanwhile in the Gulf, demand was way down as power plants and industrial facilities went off line due to storm damage to their facilities and/or electric lines. And multiple gas pipelines and storage fields (that were in injection season, creating more demand) had to curtail operations. The result? Supply that was available in the Gulf was trapped without demand, which Resulted in falling prices, not rising prices. 

What We Can Conclude

The U.S., which used to have a strong need for Gulf supply, now has many other places to get natural gas. This means that we have a much more resilient gas system compared to 10 years ago, and opportunities for big price spikes are significantly lower.

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Energy Prices Aren’t Always Predictable

by Bob Shively, Enerdynamics President and Lead Facilitator

Not an energy trader? You might be grateful for that. Predicting price behavior is seemingly harder and harder. History would tell us that in regions with high penetrations of renewables, an event that reduces renewable output should result in higher electricity prices.  And based on the past, we all think that a major storm in the Gulf should cause natural gas prices to spike. If you think this all makes sense, it is worth taking a deeper look at prices during these two recent events.

The Solar Eclipse in California

California is becoming more and more dependent on solar power.  Here is a typical summer day for the California ISO:

CA renewables         Source: CAISO Renewables Watch, August 22, 2017


As discussed in last week’s blog, the large bulge in renewables is due to plentiful solar power. But as also discussed last week, renewable output predictably declined during the eclipse:

Aug 21 vs Aug 22


Now let’s look at price behaviors:

CAISO SP15 prices 8.21.17


In the day ahead, buyers assumed prices would rise during the hour starting at 10 a.m., as the sun became obscured and solar power dropped. This was based on the maximum eclipse occurring around 10:15 a.m. The result was a day-ahead price of $52/MWh, which likely signals that gas-peaking units were successful in the day-ahead price auction.  What happened in real-time? Prices began dropping during the height of the eclipse!  And then as the sun started coming back, prices fell below zero.

To get a full picture, we also need to look at the load curve:

CAISO loads

Here we see total loads (the purple line) and net loads (the orange line). Net loads are total load minus renewable output, which represents the amount that must be served by traditional forms of generation or by imports. Notice that net loads were low during the early hours of the eclipse (9 and 10) but then climbed in hour 11. Why were net loads low during the height of the eclipse? Partially because the eclipse cooled the air, meaning that air conditioning loads dropped. Some have also speculated that numerous people were outside observing during this time rather than using electrical devices in their homes and businesses, so load also dropped due to consumer behavior. 

So now we;ve explained why real-time prices moderated during hour 10. But we still haven’t explained why prices fell during hour 11, when the net load was rising as people quit looking at the sun and headed back indoors. To understand this, let’s look at one more graph:


Here we see the value of the of the Western Energy Imbalance Market (EIM).  As net loads grew, California was able to buy cheap import power, which instead of driving prices up drove them down.  This, coupled with gas plants that couldn’t get off-line fast enough, resulted in prices falling dramatically.

And now you see how hard it is to predict price behavior during unusual events. Next week we will delve into the issue of natural gas prices during Tropical Storm Harvey.

Want to learn more about how electric wholesale prices are set and how markets behave? Enerdynamics offers both live and online Wholesale Power Markets seminars.  See www. enerdynamics.com for more details.

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The Solar Eclipse Showed Us How Power Grids Effectively Handle Renewables

by Bob Shively, Enerdynamics President and Lead Facilitator

In the weeks leading up to the Aug. 21 solar eclipse, numerous articles appeared questioning whether U.S. power grids could handle the expected loss of solar power.  This map from the Energy Information Administration (EIA) shows the path of the eclipse across a map of utility-scale solar generation:

eclipse path

 Source:  EIA Today in Energy, August 7, 2017


At least 10 states were expected to see significant impacts:

PV capacity affected by eclipse

Source:  EIA Today in Energy, August 7, 2017


The results of Monday’s test indicate that the grid was more than ready to handle the event: No negative operational effects were noted. Said Eric Schmitt, CAISO vice president of operations: “We didn’t have any major challenges on the system, even minor challenges. We are very pleased about how smoothly it went … All the resources performed the way they were supposed to perform, our planning was excellent (and) the market performed well.”[1] 

Let’s take a look at how California managed the loss of solar power.  

Normal Operations vs. Eclipse Operations

The following graphs show California ISO (CAISO) renewable output for the day of the eclipse compared to the day prior:

Aug 21 vs Aug 22.png


For hour 1100, when the eclipse was at maximum, solar power on Aug. 21 was at 3,613 MW compared to 8,599 MW for the same hour the next day.  Note that this only reflects utility-scale solar power, as additional impacts from rooftop solar are hidden by the fact that the CAISO sees loss of distributed solar as additional load. (California is estimated to have 1,300 MW of rooftop solar, so we might guess an additional 500 to 700 MW was lost during the height of the eclipse.)

How CAISO Handled the Loss of Solar Power   

By looking at a series of hourly charts of generation sources comparing output on Aug. 21 and Aug. 22, we can see how the CAISO compensated for reduced solar output:

Hour 1000

Hour 1100

Hour 1200

Hour 1300


The charts reveal a few key points:

  • California got lucky in that it was windier than normal during the eclipse, contributing extra wind power just when it was needed.
  • To compensate for the loss of solar during the eclipse, CAISO imported more power from outside the state, used more hydro, and used more gas generation.
  • As solar power ramped back up as the eclipse waned, the CAISO first used the flexibility in hydro power and reducing imports to absorb the increasing solar power, then reduced gas output.
  • Although not visible in these charts, it is also possible there was some purposeful demand response that reduced load during the eclipse (in addition to the natural reduction in cooling loads). For example, Nest offered its customers a special Solar Eclipse Rush Hour program that used their Nest thermostats to precool their homes, and then reduce cooling loads during the eclipse.  


System Operator Tools Allow Variable Resources to be Managed

We can conclude that the multiple tools helped make the eclipse a non-event as far as the California grid was concerned. These included diversity of renewable technologies, ability to draw on power from other regions through geographical diversity, availability of fast ramp assets including hydro power and natural gas generation, and demand response. Now this was a little easier because CAISO knew the event was coming and could plan for it. Indeed, IEEE Specturm reported that CAISO held extra reserves of 800 to 1,000 MW, whereas they would normally hold about 350 MW during this time period.  But, by studying the eclipse, we can get a vision of the future of the power grid, when variable resources will not negatively impact reliability because the system operators will know how to use their various tools to keep things running smoothly.


[1] “Grid runs smoothly in California during the eclipse”, The San Diego Union-Tribune, Wednesday, August 23, 2017



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U.S. Becomes a Net Natural Gas Exporter

by Bob Shively, Enerdynamics President and Lead Facilitator

The U.S. has traditionally been a natural gas importer that depends on pipeline supplies from Canada, and, to a lesser extent, amounts of gas via LNG tanker.

US gas imports vs exports

Source: Data from EIA website

But in recent years the shale gas boom has resulted in increasing pipeline flows into Mexico and Canada, and, beginning late last year, growth in LNG exports. As of mid-2017, the EIA projects that the U.S. will become a net exporter of natural gas.

US natural gas net trade

Source: EIA Short-term Energy Outlook, August 2017


Net Exports Are Expected to Grow in Three Ways

This fundamental shift is expected to intensify in the coming years:

  1. Pipeline imports from Canada are expected to continually decline as lower-priced gas supplies from the Appalachian Basin continue to displace use of Canadian supplies in the Midwest and Northeast. Meanwhile exports are expected to continually grow into eastern Canada as U.S. supplies can undercut pricing from Western Canada.

    US exports and imports to and from Canada
         Source: Data from EIA website

  2. Pipeline imports to Mexico are growing rapidly along with growing construction of cross-border pipelines into Mexico.

    US exports to Mexico
         Source: Data from EIA website

    Pipeline capacity into Mexico, which has grown more than threefold since 2010, is expected to again almost double by 2019.

  3. As LNG export projects currently under construction come online, LNG exports are expected to grow significantly.

US LNG export capacity

              Source: EIA Short-term Energy Outlook, August 2017

The EIA Short-term Energy Outlook for August 2017 forecasts 2018 exports of almost
4,000 Bcf.  To give you a sense of magnitude, this equals more than 80% of forecast residential demand or almost 50% of industrial demand. So, there is no doubt that exports are becoming significant.

Impacts on U.S Consumers Are Uncertain

Clearly the growth in exports will be a benefit to gas producers who will see markets expand. Classic economics tell us that as demand grows, prices must increase. But interestingly, given the current belief in robust gas supplies, the forward gas price does not reflect such an expectation:nymex-ng-futures.jpg

NYMEX natural gas futures prices as of August 10, 2017

Studies on the pricing impact of exports are varied. A 2015 study performed for the U.S. Department of Energy concluded that “in every case, greater LNG exports raise domestic prices and lower prices internationally.”[1] But a 2012 NERA study suggested that the increases would be small due to market factors: 

“Natural gas price changes attributable to LNG exports remain in a relatively narrow range across the entire range of scenarios. Natural gas price increases at the time LNG exports could begin range from zero to $0.33 (2010$/Mcf). The largest price increases that would be observed after 5 more years of potentially growing exports could range from $0.22 to $1.11 (2010$/Mcf).”[2] 

Industrial consumers in the U.S. are not convinced. The Industrial Energy Consumers of America (IECA)  group recently sent a letter to Secretary of Energy Rick Perry expressing concerns that growing exports will negatively impact U.S. manufacturing. Others have suggested that while overall price levels may not go up much, price volatility will grow significantly, thus subjecting U.S. consumers to severe price risk.

Many factors will impact future prices of gas including growth of gas-fired power generation (perhaps following by declines in use for power generation if renewables continue to grow), growth in industrial demand, levels of exports, amounts of domestic production, and global natural gas price levels. After many years of historically low natural gas prices in the U.S., we must carefully watch developments in the coming years.


[1] U.S. DOE, The Macroeconomic Impact of Increasing U.S. LNG Exports, p. 8, available at https://energy.gov/sites/prod/files/2015/12/f27/20151113_macro_impact_of_lng_exports_0.pdf

[2] NERA Economic Consulting, Macroeconomic Impacts of LNG Exports from the United States, p. 2, available at https://energy.gov/sites/prod/files/2013/04/f0/nera_lng_report.pdf

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ISO Markets Continue to Expand, Part II

by Bob Shively, Enerdynamics President and Lead Facilitator

Last week’s Energy Currents article discussed how organized competitive markets run by an Independent System Operator (ISO) are winning out over less-competitive unorganized markets centered around vertically integrated utilities, bilateral trading, and transmission wheeling services. We looked at how organized markets have grown in North America over the last five years and how they are poised for even more growth in the near future.

So, continuing this discussion, why the movement to organized markets?

It is all about saving money and integrating renewables. The bigger the scheduling footprint, the easier it is to maintain adequate reserves and quickly respond to contingencies. And the bigger the footprint, the easier it is to access flexible resources to respond to too little or too much renewable generation in any specific region at a specific point in time.

Before organized markets, a system operator wanting to call on a resource in another region had to make a phone call and typically had to agree to take power from that resource for a minimum of two hours. Under the western EIM, the cheapest units are dispatched automatically for periods as short as five minutes. It is not hard to see the advantage. A study for the Mountain West Transmission Group suggested that in 2016 they could have saved $88 million in production costs by participating in a regional market. This graphic from the study indicates many of the benefits:

Brattle Group graphicSource:  Brattle Group, “Production Cost Savings Offered by Regional Transmission and a Regional Market in the Mountain West Transmission Group Footprint”


One final question: Will all of North America become an organized market?

The last key holdouts are certain regions of the U.S. Pacific Northwest dominated by Bonneville Power Administration (BPA), provincial utilities in Canada, and the southeast U.S. It is likely that the entities in the northwest will soon feel pressure to join the growing western organized markets, especially given the ongoing growth of renewables in the region.

Powerex, which covers the bulk of load in British Columbia, is already committed to the EIM, so most of western Canada will soon be tied to an organized market. So as far Canadian holdouts go, that leaves Sasketchewan and Manitoba, which historically had limited participation in cross-border trading; Quebec; and more isolated northeast provinces. With Quebec pushing for more transmission lines into ISO-NE, deeper integration may come in the future.

Meanwhile, it is perhaps the southeast U.S. that will take the longest to see benefits from joining an organized market. But within the decade, it appears likely that most, if not all, of North American will be part of organized wholesale electric markets. By then, we’ll be talking about organized markets on the distribution system!


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ISO Markets Continue to Expand, Part I

by Bob Shively, Enerdynamics President and Lead Facilitator

For the last 20 years, it appeared North America was locked into two paradigms on wholesale market design:

  • Less competitive unorganized markets centered around vertically integrated utilities, bilateral trading, and transmission wheeling services
  • Organized competitive markets run by an Independent System Operator (ISO)[1]

It’s becoming increasingly clear that organized competitive markets are the winning paradigm. Some regions such as the U.S. Southeast and Canadian provinces dominated by vertically integrated utilities are still holding out, but large markets continue to join or are on the verge of joining ISOs. And as use of renewable generation grows and dependence on baseload units fades, the benefits of ISO participation are becoming clear.

This week we’ll look at the recent history of organized market growth and the short-term future of such growth. We’ll continue the discussion next week with a look at why organized markets are winning out and what the long-term future may hold for North America’s organized market structure.


North American regions with organized ISO Markets as of 2017

2017 ISOs N America.png



Organized markets have grown substantially in the last five years

In the last five years, we have seen the following:

  • 2013 – Ten transmission companies from the south, including various Entergy utilities and CLECO, joined the Midcontinent ISO (MISO).  This added territory across parts of the states of Arkansas, Louisiana, Missouri, Mississippi, and Texas to the ISO that formally operated solely in the mid-west.
  • 2014 – The Western Energy Imbalance Market (EIM) was launched by PacifiCorp becoming a participant in the California ISO (CAISO) real-time market.   This meant that generation assets across parts of seven western states became available for real-time cost-based dispatch.  Subsequently, Arizona Public Service, NV Energy, and Puget Sound joined. Seven more entities including Powerex in British Columbia plan to join between now and 2020, and part of the Mexican grid in northern Baja California is studying participation as well.
  • 2015 – The Southwest Power Pool (SPP) added the Upper Great Plains region including parts of Iowa, Montana, Minnesota, Nebraska, North Dakota, and South Dakota.  Much of this system was previously operated by the Western Area Power Administration and this expansion marked the first time a federal power agency had joined an ISO.
  • 2016 – Mexico implemented electricity reform including creation of Centro Nacional de Control de Energía (CENACE), a country-wide ISO running day-ahead and real-time markets.

Organized markets are poised to grow significantly more in the near future

It doesn’t appear that growth in organized markets will slow anytime soon. PacifiCorp and CAISO are working toward PacifiCorp becoming a full member of CAISO. If it comes to fruition, it appears that other utilities may soon follow. Efforts continue to develop CAISO into a full western regional electric market. And recently, the Mountain West Transmission Group, comprising eight utilities and two WAPA divisions, announced a non-binding letter of intent to hold detailed discussions with SPP. SPP reportedly was selected after consideration of CAISO or PJM as possible partners. The entities could join as soon as 2019.

WAPA map.pngSource:  WAPA website


Next week we’ll continue this look at ISO expansion and answer two key questions:

  1. Why the movement to organized markets? 
  2. Will all of North America become an organized market?


[1] In this blog we are using the term ISO as a synonym to a Regional Transmission Organizatoin or RTO

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