Con Edison New York – Transitioning to a Distributed Services Platform Provider

by Bob Shively, Enerdynamics President and Lead Facilitator

As low load growth, increasing renewable generation, closing of traditional baseload fossil fuel plants, growth of distributed resources, and decreasing cost of storage have all become a reality, energy utilities are forced to rethink business models that have worked well for many years. In Energy Currents, we are exploring various utilities’ responses to the changing energy business. In today’s blog, we explore the New York utility Con Edison.

Case study 2 graphic 1aSource: Con Edison Annual Report 2016


These include Consolidated Edison Company of NY (CECONY), which delivers electricity, natural gas, and steam to more than 3 million customers in New York City and Westchester County; Orange and Rockland Utilities (O&R), which together with its subsidiary, Rockland Electric Company, delivers electricity and natural gas to more than 300,000 customers primarily located in southeastern New York State and northern New Jersey; Con Edison Clean Energy Businesses, which develops, owns, and operates renewable and energy infrastructure projects and provides energy-related products and services to wholesale and retail customers in 13 states; and Con Edison Transmission, which through its subsidiaries invests in electric and gas transmission projects.


Case study 2 graphic 1
Source: Con Edison

The majority of Con Ed’s earnings come from its utilities, and this is expected to continue:

Case study 2 graphic 3

Source: Con Edison presentation of Wolfe Utilities and Power Conference, September 27, 2017

The utilities primarily own electric transmission and distribution facilities, gas distribution facilities, and a district steam system. The only electric generation owned by the utilities is a 726 MW electric-steam facility in New York City. All consumers have the option of buying electric and gas supply from their utility under regulated rates or buying from retail marketers under competitive pricing. In 2016, CECONY was the supplier for 35% of the electricity and 71% percent of the gas delivered to its customers; O&R was the supplier for 41% of the electricity and 48% of the gas delivered to its customers. The remainder was purchased by customers from retail marketers rather than the utility (the utility still receives distribution revenues from these customers). To service customers who take supply from the utilities, gas and electricity is purchased in the wholesale market through long-term and spot transactions. The electric transmission grid, although owned by the utilities, is operated by the New York ISO, which also runs capacity, day-ahead ancillary services, day-ahead energy, and real-time energy markets.

The utilities are primarily regulated using the cost-of-service model. Distribution facilities are regulated by the New York State Public Services Commission (NYSPSC), and electric transmission facilities are regulated by the Federal Energy Regulatory Commission (FERC). The cost of supply provided by the utilities is passed through to customers. Revenue decoupling applies so that actual revenues are adjusted to match approved revenues, and the utilities are not at risk for revenue fluctuations associated with how many kWh are sold. The utilities can receive a negative revenue adjustment for failure to meet certain service standards (penalties can be as high as $400 million on the electric side, but in 2016 the utilities did not incur any penalties). There is an incentive-based earning adjustment mechanism for energy efficiency over the period 2017–2019 that potentially can range from $28 to $64 million for CECONY. If overall earnings exceed a threshold amount (typically about 0.5% above the authorized rate of return) then excess earnings are used for customer benefit rather than for profits.

New York has implemented rules that require load serving entities (LSEs) such as the utilities to achieve a Renewable Portfolio Standard (RPS) of 50% by 2030, to reduce greenhouse gas emissions by 40% by 2030, and to purchase Zero Emissions Credits to support the continued operation of nuclear power plants in upstate New York.

The business model and services for all New York utilities are being reformed through the NYSPSC proceeding called Reforming the Energy Vision. As stated in the Con Edison Annual Report 2016:

“In April 2014, the NYSPSC instituted its REV proceeding, the goals of which are to improve electric system efficiency and reliability, encourage renewable energy resources, support distributed energy resources (DER) and empower customer choice. In this proceeding, the NYSPSC is examining the establishment of a distributed system platform to manage and coordinate DER, and provide customers with market data and tools to manage their energy use. The NYSPSC also is examining how its regulatory practices should be modified to incent utility practices to promote REV objectives.”

The proceeding has passed through initial phases but reform is expected to be implemented over many years. One of the concepts is that earnings will evolve from cost-of-service to performance incentives, shared saving mechanisms, and market-based earnings as shown on the graphic below. It is expected that, over time, more and more utility earnings will come from less traditional methods.

Case study 2 graphic 3b

A recent decision in the REV proceeding required the utilities to file demonstration projects for approval by NYSPSC staff. Costs for these projects are recovered through a surcharge. Projects include an O&R online engagement platform that leverages residential customer data and analytics to help customers find energy products and services that meet their needs, and three CECONY projects. CECONY projects include a clean energy project origination, bidding and technical support platform for small commercial customers; a clean virtual power plant offering that bundles solar with storage that can be aggregated and also can test the demand for premium reliability services; and a marketing platform for distributed energy providers to target residential customers with relevant messaging.

Also in recent years, CECONY has utilized payments to customers providing distributed energy resources (DERs) to defer upgrades to the transmission and distribution systems serving growing areas. It also is currently watching (but not participating in except in the role of the distribution provider) the Brooklyn Microgrid Transactive Grid project, which is designed to ultimately allow customers with DERs to trade power directly between themselves using blockchain technology.

Volumes of distributed energy on the utility systems have been relatively limited to date but are growing. Distributed generation comprised approximately 3% of peak demand in 2016:

Case study 2 graphic 4

Source: Con Edison 2016 10Q

Due to policy decisions made by the State of New York and the NYSPC, Con Ed must transform its utility business model over the next few years. The transition is critical for the company since close to 90% of Con Ed’s earnings come from its two utilities. Con Ed and other New York utilities will be on the leading edge of changing the utility role from an energy-delivery utility to a distribution services platform provider. Over time, the NYSPSC expects that utilities in New York will transform their earnings model with less and less of earnings based on traditional cost-of-service. How Con Ed manages this transition will be critical to its future and will provide a case study for utilities across the world as they plan their own transitions.

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Hawaii Electric – Leading the Way to 100% Renewables

by Bob Shively, Enerdynamics President and Lead Facilitator

As low load growth, increasing renewable generation, closing of traditional baseload fossil fuel plants, growth of distributed resources, and decreasing cost of storage have all become a reality, energy utilities are forced to rethink business models that have worked well for many years. In our Energy Currents blog, we are exploring various utilities’ responses to the changing energy business.  This week, let’s look at Hawaiian Electric Company.

Spectacular view of Honolulu city, Oahu

Hawaiian Electric Company (HECO) and its subsidiaries, Maui Electric Company and Hawaii Electric Light Company, serve 95% of the state’s 1.4 million residents on the islands of Oahu, Maui, Hawaii, Lanai, and Molokai. Each grid is run separately as there is no electric connection between the islands. HECO is a vertically integrated investor-owned utility (IOU). Historically, Hawaii was powered mostly by petroleum-fueled power plants using imported fuel resulting in rates that fluctuated with world oil prices. Hawaii traditionally has some of the highest electric rates in the U.S. Due to the high cost of power coupled with plentiful sunshine, HECO has one of the highest penetrations of rooftop solar in the U.S. with 16% of customers having a system as of 2017. Here are some key recent events:

  • In 2014, HECO filed its integrated resource planning document — the Power Supply Improvement Plan (PSIP) — with the Hawaii Public Utilities Commission (HPUC). This plan was rejected by HPUC in 2015 stating it seemed to be a series of unrelated capital projects without focus on moving toward a sustainable business model. In rejecting the plan, HPUC released a 30-page exhibit titled “Commission’s Inclinations on the Future of Hawaii’s Electric Utilities: Aligning the Utility Business Model with Customer Interests and Public Policy Goals.” In the exhibit, HPUC expressed a desire for HECO to file a plan that would prepare the utility for a new paradigm of stable rates, clean energy, customer options, and increased reliability. A follow-up PSIP filing was rejected in 2016.
  • A 2014 proposal by Florida-based NextEra Energy to acquire HECO was rejected by the HPUC in July 2016 citing concerns over possible negative impacts on support for Hawaii’s clean energy goals, local governance, and levels of competition among entities wanting to provide energy services to Hawaii.
  • Finally in July 2017, HPUC approved HECO’s third PSIP filing. This filing laid out a path for achieving 48% renewables by 2020 (as compared to the state RPS of 30%) and 100% renewables by 2040 (five years ahead of the state goal of 100% by 2045). The plan includes a mix of technologies as described in the executive summary:

“…our action plans estimate achieving a 52 percent RPS by 2021 by adding 326 megawatts (MW) of rooftop solar, 31 MW of Feed-In Tariff (FIT) solar generation, 115 MW of demand response (DR), 360 MW of grid-scale solar, and 157 MW of grid-scale wind resources across all five islands.”

Under the plan, utility-scale resources will be acquired through an RFP process meaning that much of the capacity will be built and owned by third parties that will sell the power to HECO under power purchase agreements.

Case study 1 graphic 1

Source: HECO 2016 PSIP Executive Summary

  • HECO has decoupled rates, meaning revenues are adjusted to account for fluctuations in kWh sales and HECO does not have earnings risk based on shrinking sales. HECO passes through fuel and power purchase cost fluctuations to customers and has mechanisms to recover costs of approved renewable energy infrastructure projects through a rate surcharge.
  • HECO ended net metering in late 2015, resulting in a slower pace of new rooftop installations. Under the new plan approved in 2015, solar customers were required to choose between a “grid supply” option where customers get paid about 60% of the retail rate for any excess solar power they put onto the grid and a “self supply” option where solar power is all consumed within the facility. Grid supply customers pay a monthly minimum bill of $25 to help cover fixed grid costs. Both options are designed to encourage customers to use as much solar power internally as possible (or to store it in a behind-the-meter battery) as shown in the diagram below:

Case study 1 graphic 2Source: Rocky Mountain Institute, Hawaii just ended net metering for solar. Now what?,
October 16, 2015

  • As of mid-2017, the caps for the grid supply option had been met on all the islands and the program ended. This resulted in a large drop in the number of rooftop solar installations. But it also led to an increase in PV-battery installations where consumers no longer stayed connected to HECO. Two new options for selling solar output to the grid were approved by HPUC in late October 2017:
    • The Smart Export program is for customers with PV and a battery.  These customers are paid a fixed export rate during the periods midnight to 9 a.m. and 4 p.m. to midnight, but are paid nothing for any power put onto the grid between 9 a.m. and 4 p.m.
    • As an alternative, PV customers without a battery are offered the Customer Grid Supply Plus option. Under this option customers are paid an export rate during all time periods, but they must install a communication and control system that allows HECO to shut off export whenever needed to ensure reliable operation of the grid.  Both options require a smart inverter. 

  • HECO expects rate base growth of more than 4% a year over the next few years. HECO filed a draft Grid Modernization Strategy with HPUC in July 2017 that proposes $205 million in upgrades over the next six years. The original grid modernization plan that was rejected by HPUC proposed $376 million in mostly “wires” based grid upgrades. The new plan focuses more on “advanced technology solutions” as indicated in the blue arrows on the graphic below. As stated in the proposal, the goal is turning the HECO system into a “platform that enables the integration of customer DER and the utilization of DER as a system resource.”


Case study 1 graphic 3

Source: HECO, Modernizing Hawaii’s Grid for Our Customers, June 2017 Draft Report

In the last few years, HECO has faced unprecedented pressures to adapt its utility system. An initial effort to address the issues by merging with a larger energy company was rejected by the state regulators. HECO is now seen as a “test bed” for how to rapidly integrate renewables into a utility system without the flexibility of sharing power with neighboring regions. Through the transition, HECO intends to maintain its position as an integrated utility performing system planning and new resource integration. There is much to be learned by watching how Hawaii’s energy transition plays out.


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Update on the Expanding Mexican Gas Market

by Bob Shively, Enerdynamics President and Lead Facilitator

In an August 2016 blog post we wrote “…it appears Mexico is poised to enter a common competitive gas market with the U.S. and Canada. And there is even talk in the future of expanding pipelines into Central America to create a true uniform North American gas market. But of course, ‘the proof will be in the pudding’ as they say, and we will eagerly watch to see how market developments play out.’

So a year later – how are these developments playing out? Overall, the industry reforms are moving forward and a competitive market is emerging. Let’s take a look at some of the key areas of progress. 

Mexico new gas markets map.pngSource: ICIS webinar – Mexico’s New Gas Market, October 5, 2017

PEMEX no longer controls pipelines

Centro Nacional de Control del Gas Natural (Cenegas) was created to manage unbiased open access to pipeline capacity allowing use by gas marketers and even large end users. Open seasons for PEMEX capacity on U.S. pipelines began in February. In May Cenegas held its first open season for capacity for the former PEMEX pipeline system, now called SISTRANGAS (Sistema de Transporte y Almacenamiento Nacional Integrado de Gas Natural). Active entities in addition to PEMEX (which needed to reacquire capacity rights to serve its ongoing customers) included Shell, BP, ENGIE, Macquaire, and a number of large Mexican industrial customers.

As of September, 24 companies held capacity on the SISTRANGAS system. Numerous new pipeline projects are underway with ownership including a variety of international parties including Transcanda, IENova (Sempra), ENGIE, and Kinder Morgan. Third-party pipelines are built based on contracts with entities willing to take out firm contracts. The majority of the current third-party capacity is held by the electric company CFE.  

PEMEX no longer has a monopoly on gas sales

Under the Mexican reform law, PEMEX is required to give up 70% of its sales market over a four-year period. The new market launched in July, and in September PEMEX stated that more than 32% of the market is now being served by alternate suppliers.

Market prices are developing

Previously, gas pricing by PEMEX was capped under a formula set by the Mexican government called VPM. The price cap for northern Mexico was based on a basket of U.S. hub prices for northern Mexico and on the assumed cost of production in southern Mexico. As of July 1, the new formula used by PEMEX is based on market prices at the U.S. border and is currently set at the Henry Hub price plus $0.40/MMBtu. 

Additionally, customers are charged a balancing fee set on the cost of LNG that ranges from $0.06 to $0.14/MMBtu (Mexico’s only source of gas storage is the storage at its three LNG import facilities). The Mexican government now publishes a monthly price index based on reporting by alternate suppliers. The index, called IPGN (Índice de Referencia Nacional de Precios de Gas Natural al Mayoreo), was first published in July.  

Market hubs appear to be on the way

Mexico is now working to develop pricing and trading hubs in Mexico to reflect local price differentials and to give Mexican companies the opportunity to hedge price in pesos instead of U.S. dollars. A hub in the Yucatan may be especially important since it is not currently possible to push U.S. gas down into this region, which results in gas shortages. A new regional price mechanism could provide the transparency needed to encourage either new development of gas supply in the region or expansion of the pipeline grid to enable more gas to flow south.

MX NG infrastructure

Source: EIA Today in Energy, August 30, 2017

Is the market working?

Certainly we can conclude that the gas market evolution in Mexico is making significant progress in a short time. There are still barriers such as lack of available supply, which requires marketers to buy supply from PEMEX so that they can fulfill their sales obligations, and a lack of interest in some cross-border pipeline capacity auctions. But things are moving forward. Perhaps the biggest question now is the outcome of the 2018 presidential election. Leading candidate López Obrador has spoken out against some energy reforms, and what will happen post-election is uncertain. 





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Have We Reached the Tipping Point for Electric Vehicles?

by Bob Shively, Enerdynamics President and Lead Facilitator

“I think if we look back in a few years we would call 2017 the tipping point of electric vehicles.” ~ Arnoud Balhuizen, Chief Commercial Officer of BHP Billington speaking at a conference in September 2017.

If this quote was attributed to Elon Musk (CEO of Tesla) or maybe the head of an environmental organization we might not take much notice of it. But Arnoud Balhuizen is a top executive in the world’s largest mining company. At a time when the administration in Washington, including the President and the head of the Department of Energy, are very fossil-fuel friendly it is interesting to note that Balhuizen has a different take on the world of transport.  So, what is going on with electric vehicles (EVs)?

Governmental actions

Numerous key governments have made recent announcements that indicate strong support for the future of EVs:

  • Both France and the United Kingdom announced in July that they intend to phase out gasoline and diesel-powered cars by 2040.
  • In September, China stated that it too will phase out fossil-fuel cars and development of a specific time-plan is underway; meanwhile China set quotas for car companies to sell 10% NEVs (EVs or plug-in hybrids) by 2019 and 12% by 2020.
  • The chairwoman of the California Air Resources Board stated recently that California Gov. Jerry Brown asked her about California phasing out all fossil-fuel vehicles. (California already has stringent greenhouse gas rules that will require a significant shift to EVs if goals are to be met.)
  • And other countries such as Norway and the Netherlands are discussing even faster timetables for such as full phase out while Germany is leading discussions about EV quotas in all of the European Union.

BYD Qin, the top selling EV in China

BYD Qin, the top selling EV in China  By El monty (Own work) [CC BY-SA 3.0 (, via Wikimedia Commons

 Car company actions

Meanwhile, numerous car companies have announced a strong focus on EVs as a source of future sales:

  • GM (Chevy Bolt), Tesla (Model 3), and Nissan (the upcoming redesigned Leaf) this year are introducing mass-market cars with ranges in excess of 200 miles.
  • Volvo and Mercedes-Benz announced that all models will be available in electric versions by 2019 and 2022, respectively.
  • Volkswagen has announced plans to become the world leader in EVs by 2025 and stated that it will introduce two new models (including a cross-over SUV) in the U.S. in 2020 that will have a range of over 300 miles and will fit within the “affordable segment.”
  • Numerous Chinese car companies in addition to Volvo are actively and successfully selling EVs in their home market including BYD, Kandi, BAIC, and Chery.
  • Meanwhile, Apple and Alphabet (the parent of Google) are both spending significant R&D dollars in the EV market.

So are EVs finally real?

EVs  have been a “coming technology” in the news at least since 1996 when General Motors EV1 was introduced in California to great fanfare. But GM famously recalled all EV1s in 2002 as chronicled in the movie “Who Killed the Electric Car?” and momentum seemed lost in a world of cheap gasoline. But now, the electric business is hoping things are different as we see rapid growth in sales of EVs around the world.

number of EV cars sold, China v world

Source: LMC Automotive and market 2017 and 2018 as forecast

Utilities in the U.S. and other developed economies are struggling with slow load growth, which makes it difficult to grow earnings. But Bloomberg New Energy Finance, in its New Energy Outlook 2017, forecast that by 2040, EVs will account for 13% of electric usage in Europe and 12% in the U.S. The U.S. Bloomberg has forecast that by the early 2030s, EV sales will beat out those of fossil-fuel vehicles. Many utilities are currently putting forth proposals or implementing pilots to build electric vehicle charging stations.

In California, where the regulators initially resisted utility involvement, the attitude has changed to a belief that utilities are best suited to quickly build the necessary infrastructure to foster rapid EV growth. We believe that growth in EVs is one of the great opportunities for electric companies to overcome the current tepid load growth.

We’ll close with a quote from Jim Avery, formerly the Chief Development Officer for SDG&E. Speaking on the topic of current slow load growth, but  considering the potential of EVs, Avery said: “Think I’m worried about growth? I’m worried about how the hell to serve all of that.”

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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. 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

[2] NERA Economic Consulting, Macroeconomic Impacts of LNG Exports from the United States, p. 2, available at

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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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