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iStock-482651289Attention Energy Currents readers!

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Low Costs Continue to Drive Growth of Renewables

by Bob Shively, Enerdynamics President and Lead Facilitator

The U.S. Energy Information Administration (EIA) recently reported that in the last four years, over half of the new utility-scale generation capacity in the U.S. has come from renewable technologies:

Utility scale capacity additions

Source: EIA Today in Energy, January 10, 2018

As shown in the graph on the right, renewable growth in 2017 primarily came from wind and solar photovoltaic installations. In addition to what is shown here, the EIA estimates an additional 3.5 GW of distributed solar photovoltaic installations.

Meanwhile, the majority of plant retirements came from fossil fuel power plants:

Utility scale electric generating capacity retirements

Source: EIA Today in Energy, January 9, 2018

The more than 15 GW of renewable capacity installed well exceeded capacity required to meet renewable energy portfolio mandates. Not too many years ago, growth in renewables seemed driven by government mandates. Now clearly something else is driving the growth: price.

Prices in both wind and solar technology have declined dramatically in recent years:

Utility scale wind costsutility scale solar PV costs
Source: Lazard Levelized Cost of Energy Analysis – Version 11.0

When compared to other sources of new capacity, renewables are a clear winner. It is important to note that these are unsubsidized costs before any tax benefits are included.

levelized costs of new gen sources for 2020

Source: Lazard Levelized Cost of Energy Analysis – Version 11.0

Following are some of the power purchase agreements for renewable power that have recently been covered in the press. These all are the results of offers by for-profit generation developers who are in the business to make money.

MX flag

  • Mexico’s market operator CENACE held its third long-term energy auction in late 2017. The winning bids for renewable energy (which included wind and solar) cleared at a price of $20.57/MWh. At this price, three buyers (CFE, Iberdrola, and Cemex) bought over 5 million MWh of energy plus the corresponding clean energy certificates.
  • CN flagThe Canadian province of Alberta announced results of its long-term power auction in December 2017. Through the auction the province selected 600 MW of wind power at a price of $37/MWh.
  • An Xcel Energy of Colorado All Source Solicitation filing in December 2017 reported RFP (Request for Proposals) results CO flagwith 42.3 MW of wind with a median price of $18.10/MWh, 29.7 MW of solar at $29.50/MWh, 5.7 MW of wind/battery projects at $21/MWh, and 16.7 MW of solar/battery projects at $30.60/MWh.

Watching these deals come in, it is clear that we now have a new paradigm in electric supply resource planning. Not only are renewable projects in areas with favorable resources coming in as the lowest-cost new power source, they are coming in at prices lower than the cost of running many existing power plants. In 2018 and beyond, we can expect to see ongoing retirements of existing units.


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ComEd Chicago – Building a Future Grid Under Performance-based Rates

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 2017 we began looking at specific U.S. utilities and how they are responding to the changing future of the energy company. We recently looked at Hawaii (Hawaii Electric – Leading the Way to 100% Renewables) and New York (Con Edison New York – Transitioning to a Distributed Services Platform Provider). In this post we explore ComEd, an electric-only utility that serves 3.8 million customers in Illinois.

ComEd’s service territory comprises most of northern Illinois including the Chicago metropolitan area. ComEd owns only transmission and distribution facilities. All generation was divested during deregulation. Customers of ComEd can choose distribution-only service with supply provided by a third party or can buy bundled service with supply provided by ComEd under regulated rates. Illinois also has an active municipal aggregation program where some communities choose to provide supply on behalf of their residents.

ComEd is owned by Exelon Corporation, one of the largest integrated energy companies in the U.S. Exelon has three major business lines including generation (35,500 MW of merchant generation including 20,300 MW of nuclear power), energy sales and service (the energy sales and services company Constellation), and transmission/delivery (6 electric and/or gas utilities including ComEd). Following are some important points to understanding ComEd’s transition to the future:

  • ComEd’s earnings provide approximately 40% of the overall earnings for Exelon Corp. Exelon states that the parent company’s mission is to be the leading diversified energy company by providing reliable, clean, affordable and innovative energy products.  Exelon believes that an integrated business model provides them a unique view into the transforming industry and allows them to take advantage of a broad range of opportunities, rather than betting on any one segment of the industry.  Exelon owns six nuclear power plants in Illinois.  Two were slated to be closed due to low market revenues until Illinois passed the Future Energy Jobs Act (FEJA) in 2017. FEJA included a Zero Emissions Standard (ZES) which provides for payments to nuclear power plants in recognition of their zero-GHG generation.


  • ComEd is regulated by the Illinois Commerce Commission (ICC). The ICC uses a formulaic ratemaking method that sets rates on an annual basis as shown in the graphic below.  ComEd does not have revenue decoupling, so earnings fluctuate annually based on actual sales.

PBR formula
Source: Presentation by Anil Dhawan, ComEd Sr. Electrical Engineer June 2014

  • The formulaic ratemaking provides regulatory certainty through use of a predictable, repeatable process. But it also has provided ComEd some of the lowest ROEs in the U.S.  For example, the current ROE is 8.59%, set using the formula based on the average 30 year Treasury yield + 560 basis points for a risk premium – a 5 basis point penalty for failure to achieve performance based metrics in prior years. Performance metrics include budget controls, outage duration and frequency, safety, customer service, efficiency and productivity, and environmental compliance. To obtain the formula ratemaking, ComEd agreed to meet infrastructure investment targets and to create at least 2,000 full-time equivalent jobs or make payments to a state job training program. The utility’s failure to meet these requirements or certain other performance targets can result in discontinuation of the formula rate, in which case rates would be frozen at current levels until a new general rate case is completed.


  • The 2011 Illinois law, the Energy Infrastructure and Modernization Act (EIMA) that approved the new formulaic ratemaking process also authorized a $2.6 billion ComEd grid modernization program. Illinois was recently recognized by the Gridwise Alliance as second highest U.S. state for grid modernization.


  • In addition to creating the ZES, the 2017 FEJA law extended the formulaic ratemaking through 2022, set an RPS goal of 25% by 2025, and set demand reduction targets of 17% by 2025. Under the law, ComEd will be able to ratebase certain energy efficiency and rebate expenditures meaning they can earn a rate-of-return on these.  The law also laid out a path to transition from net-metering for DERs to a value-based payment (locational and time-based).


  • The ICC initiated the Next Grid Study in September 2017. The study’s goal is to address critical issues facing Illinois’ electric industry in the future and to provide a final result discussing opportunities, challenges, and recommending actions. Current working groups include: a) new technology deployment and grid integration, b) metering, communications and data, c) reliability, resiliency, and cyber security, d) customer and community participation, e) electricity markets, f) regulatory, environmental and policy issues, and g) ratemaking.


  • In preparing for the future, ComEd notes three key trends: accelerating technology innovation, exploding levels of data, and the connectivity of everything.  The result is customers who demand more choices, more control, and more convenience.  Given these trends, ComEd believes utility services will need to evolve:


Emerging utility models
Source: Perspectives in Grid Transformation from Illinois, Jane S. Park, Com Ed VP of Regulatory and Policy, November 2, 2017


  • ComEd believes that future of utilities lies in value generation through platforms:

Value generation.png

Source: Perspectives in Grid Transformation from Illinois, Jane S. Park, Com Ed VP of Regulatory and Policy, November 2, 2017


  • And it sees the industry organization around four interactive layers:

A vision.pngSource: Perspectives in Grid Transformation from Illinois, Jane S. Park, Com Ed VP of Regulatory and Policy, November 2, 2017

  • Current programs ComEd is using to test these concepts include the ComEd Energy Marketplace platform which allows consumers to purchase energy-related products and obtain point-of-purchase rebates, a community energy storage pilot, a proposed microgrid project, and replacing 18,000 ComEd-owned streetlights with new “smart-ready” LED lights (these will allow municipalities to remotely dim lights for energy savings, remotely brighten or flash them for safety, and receive immediate notification of lamps in need of maintenance).

ComEd is an example of a utility that is attempting to move rapidly to face a changing future.  ComEd has worked closely with its regulator the ICC to put in place regulatory mechanisms that support this transition, even though ComEd has accepted a low ROE in return for regulatory certainty.  The Illinois legislature has been proactive in passing laws that support the transition, while also attempting to provide for a key driver in Illinois politics – maintaining jobs.  The ongoing Illinois NextGrid Study will drive future policy changes.  ComEd will likely be a model utility for others to study in designing ways to manage a successful transition to the future energy world.

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What Could Change the Future of U.S. Natural Gas Demand?

by Bob Shively, Enerdynamics President and Lead Facilitator

A basic concept of economics is that when prices go down, demand goes up. This certainly has been true for U.S. natural gas in recent years:

U.S. Gas Consumption and Price

Robust supply delivered by shale gas has driven down prices, and projections tell us we can expect this robust supply to last well into the future. But it appears that U.S. domestic gas demand may not have much more room for growth. For now, the great hope for the gas industry appears to be growth in exports.

The EIA predicts that:

  • residential and commercial use will remain flat
  • transport use will grow but will remain a small factor in overall consumption
  • industrial use will grow slowly
  • electric generation use will decline initially given growth in renewables and price competition with coal power plants before growing again in the mid 2020s

Forecast U.S. Gas Demand

But, the EIA forecasts significant growth in export demand.

Let’s consider variables affecting demand in each sector.

Residential and Commercial
Residential and commercial demand in the short term is mostly driven by weather. Assuming weather patterns don’t change much in the next few years and that efficiency continues to improve, there is little expectation that demand in these sectors will grow.

Growth in gas-heavy industries such as chemicals and refining may continue if gas prices remain low. Petrochemical plants currently planned for or under construction suggest that industrial demand will continue growth similar to that of recent years. But other factors affect industrial growth including economic conditions and the costs of other feedstock and fuels. A shock in any of these areas could halt demand growth.

Electric generation
Unlike the other sectors, there is more uncertainty around electric generation. Electric load growth has been stagnant since 2008 and appears it will remain that way in the short term. Without electric load growth, the potential for generation gas demand is simply a question of how gas generation compares to other generation sources, notably renewables and coal.

Renewables are expected to continue rapid growth, which has the potential to cut into gas generation output. And if gas prices rise, coal generation becomes more economic than gas generation for existing units. We have already seen some fuel switching from gas back to coal and will likely see more in the next year. If coal and nuclear unit retirements occur as planned, most of their generation will be replaced by gas output. But if policies emanating from Washington delay retirements, this too could drive down gas use.

Natural gas has potential for use as a transport fuel for fleet vehicles, heavy trucks, railroads, and shipping. While this potential is large, the infrastructure required is significant and would take many years to build out. So, transport is not expected to be a significant source of demand in the near term.

Exports are the biggest hope for short-term demand growth. With one major LNG export facility already in service and six more slated to come online in the next two years, U.S. LNG export capability will grow significantly. What’s uncertain is how much gas will flow through these facilities – it will depend on global market conditions including gas prices in other supply regions of the world and demand in regions such as Asia, Europe, and South America.

Exports to Mexico are more predictable. Mexico’s use of natural gas is growing rapidly, and the availability of low-cost U.S. supplies through an expanding pipeline network is quickly bolstering Mexico’s use of U.S. natural gas. The combination of LNG and pipeline exports could boost overall demand for U.S. supply by as much as 20% in the next decade. But even this good news is tempered by concerns that push from the current U.S. Administration to renegotiate NAFTA could interrupt or restrain future gas trade between the two countries.

Are there dark clouds on the horizon?

With expanding exports, the future for natural gas in the U.S. looks robust. But, there are ominous factors that cannot be ignored.

There is the distinct possibility that in the longer term, gas-fired generation will shrink. While at least half of the coal capacity in the U.S. is expected to retire in the next decade, renewables are rapidly growing and continue to cut into gas generation run hours. And, for the first time ever, both utility-scale wind and utility-scale photovoltaic units have lower long-term levelized costs than gas units.

In states with robust renewable resources, some analysts foresee a future where existing gas units are no longer needed. Many still believe that gas units will be required to provide system flexibility for variable renewables, but even under this scenario the number of hours of use gets less and less. And system operators are rapidly developing other means of managing renewables including scheduling across large geographical regions, incenting flexible loads to match usage to renewable output, and implementing thermal and battery storage. And, once most of the coal generation is retired, the next big source of greenhouse gas emissions (GHG) in the electric industry will be gas-fired units. Already we have seen the construction of new units in California fall into question based on carbon emission goals.

Second, in states with significant GHG emissions goals, one way to reduce emissions is to use electricity for space and water heating instead of gas. Given that water and space heating loads make up around 90% of residential and commercial demand, such a shift could result in a significant loss of business for the gas industry.

In some regions, gas utilities already are considering a future with reduced natural gas usage. Some are encouraging growth of renewable natural gas. Others are looking into power-to-gas technologies that would use renewable electricity to power an electrolysis process to create hydrogen that could be delivered through the existing gas infrastructure. While the short-term outlook appears rosy, now may the time for gas companies to plan for what could be a very different future.

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A Look at Blockchain Technology and Electric Trading

by Bob Shively, Enerdynamics President and Lead Facilitator

In January 2009, the bitcoin – a new form of currency – made its global debut. The previous year saw a financial crisis in which trillions of dollars of wealth was destroyed by an economic collapse at the hands of large financial institutions. In the wake of such turmoil, bitcoin developers were determined to offer a means of electronic payment independent of any centralized authority.

The software underlying the bitcoin is called blockchain technology. According to Don and Alex Tapscott in their 2016 book Blockchain Revolution, “the blockchain is an incorruptible digital ledger of economic transactions that can be programmed to record not just financial transactions but virtually everything of value.”

While blockchain experts struggle to explain the technology in layman’s terms, the key take-away is that blockchain technology allows peer-to-peer transactions without a middleman. It’s like making a digital payment to someone with no third-party service required. No checking account. No PayPal. No Google Wallet. Just you and the counterparty.

And today blockchain technology is making its way into electric markets as a means of electric trading. Here is a look at the latest developments.

Adapting to System Changes

Both bulk electric system operators and distribution engineers are grappling with how to adjust the system so that it operates safely and reliably with growing penetrations of renewable and distributed resources. Many energy business pundits believe the ultimate solution is to combine battery storage and flexible loads. This may require market participation by large numbers of residential and commercial customers with multiple devices behind their meters.

But this leads to the question: How can the industry create a transactive market in which:

  • localized prices send economic signals…
  • …to a diverse set of consumer-owned devices…
  • …to stimulate the desired behavior given grid conditions?

As Enerdynamics facilitator Dan Bihn once told me, “my utility should just tell me what load curve it wants to see at the meter, give me the right price signals, and let me manage my own load.”  Technology is making this possible, but current regulation and markets are not there yet.

Challenges to a new world of price-responsive demand include:

  • the massive amounts of data that must flow (think of each device in your home potentially responding differently to a price signal and every response being tracked);
  • the many parties along the delivery chain currently involved in a single transaction;
  • and the lack of consumer trust in a post-Enron world.

Is Blockchain the Answer?

Some believe that blockchain technology is key to allowing parties to transact directly – no central intermediaries required. To fully understand this concept, look at the entities involved in an electric transaction in the Texas market:

Given this structure, you cannot:

  • sell power to your neighbor
  • switch suppliers each hour
  • or get paid for creating locational grid benefits

All transactions in this structure must go through multiple intermediary parties such as marketers and the system operator.  But use of blockchains promises an alternative. When paired with smart contracts that automatically allow participants to transact under certain conditions, blockchains could open the market to easily facilitated distributed energy trading. This trading may include energy and other grid requirements like frequency regulation and voltage support from battery systems or smart inverters.

Of course, much needs to be resolved before this concept becomes reality. Regulations need to change. Load forecasts and balancing need to be managed in a way that ensures the grid stays balanced and that settlements for imbalances flow seamlessly. Methods for handling disputes may be required, and participants must feel confident the system is not subject to manipulation or hacking.

Despite the obstacles that remain, numerous energy companies and technology start-ups are testing blockchain-based trading. Examples include:

  • European energy companies Enel and E.ON, which recently traded 24 MWh using the blockchain-based Enerchain platform; (Watch a video from E.ON discussing their pilot.)
  • Power Ledger, which has facilitated residential power trading in Australia
  • Numerous other companies vying to enter the market including Slock.it, Oneup, LO3 Energy, ConsenSys, The Sun Exchange, Conjoule, Electron, eMotorWerks, Drift, and Grid Simplicity

Certainly some will be more successful than others, and some may not succeed at all. But it’s possible that one or two may be the future Microsoft or Apple of the transactive energy grid.

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Environmentally Beneficial Electrification May Save Electric Utilities From the Death Spiral

by Bob Shively, Enerdynamics President and Lead Facilitator

Some electric industry observers suggest that utilities will never again see steady electric load growth. Jim Rogers, the former CEO of Duke Energy has been quoted as saying: “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.”

Indeed, the latest forecast from the Energy Information Administration (EIA) forecasts a 0.8% average annual growth between now and 2050.

Source: EIA Annual Energy Outlook 2017

Declines in sales coupled with growing economic opportunities for rooftop solar and other distributed energy resources (DERs) has utilities worrying about the so-called utility death spiral. Utilities with primarily fixed costs have sales declines that result in rate increases; this encourages more load to leave the system, which results in more rate increases. It’s an ultimate deadly spiral of business decline.

Environmentally beneficial electrification

In recent years, environmentalists have encouraged the electric industry to focus on energy efficiency – attaining the same end-user benefits while consuming less energy. The concept was that less consumption meant less generation, which meant less environmental impact. This exacerbates the potential for a death spiral. But a new paradigm is now emerging. With the current priority to reduce greenhouse gas (GHG) emissions and slow global climate change, the concept of emissions efficiency rather than energy efficiency is taking shape. This concept is outlined in a recent Electricity Journal article titled “Environmentally beneficial electrification: The dawn of ’emissions efficiency.’”

Emissions efficiency means providing consumer benefits for the least amount of negative environmental outcomes, including the least amount of GHG emissions. It concludes that moving three key energy uses – vehicle transport, space heating, and water heating – from fossil fuels to electricity can provide significant environmental benefits while continuing to fulfill consumer desires.

How environmental benefits work

The authors of the above-mentioned article considered a hypothetical electric utility with 100,000 consumers and a generation mix of 50% coal-fired, 40% combined-cycle gas turbine, and 10% gas-fired combustion turbine. These customers were assumed to use a mixture of fuel oil, electric resistance heaters, electric heat pumps, propane, and natural gas to heat their homes and water. Gasoline and diesel powered their cars. Upon the upgrades shown below, GHG emissions were modelled to drop by 25%.

Two things are worth noting in the above model:

  • Penetration of electric vehicles (EVs) is small.
  • Significantly more emissions reductions could be achieved by converting the electric generation mix to utilize zero-emissions generation like wind, solar, or nuclear.

Will electrification result in significant electric load growth?

The concept of beneficial electrification creates new growth opportunities for electric utilities. Electric vehicles (EVs) utilize electricity in the range of 25 to 35 kWh per 100 miles. A homeowner driving an EV 10,000 miles in a year would add 2,500 kWh of energy consumption to his bill. With a typical U.S. residential account currently using about 10,000 kWh per year, the addition of an EV could increase that home’s electric usage by 25%. Adding heat pumps for water heating and space heating might add an additional 4,000 kWh per year. The net total increase in electric usage would be 65% — all while significantly reducing the GHG emissions from the home.

Given these numbers, it seems electric utilities have much to gain by touting the environmental benefits of electrification. And this may be the big opportunity that can save these companies from the utility death spiral.

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LNG Dawns on the High Seas

In the 1920s, cruise ships made a leap in transportation fuel from coal to heavy fuel oil. Cruise boat, entertainment ship, the Aegan sea, blue sea water, ocean, close upSince that time, the industry has vastly expanded with luxury liners sailing on nearly every ocean while pampering passengers with well-appointed rooms, fine dining, theme-park amenities, and Broadway-style stage shows.

While the cruise ship experience has evolved, the ships’ fuel remains heavy oil, but that may soon change. In Fall 2018, Carnival Corporation (Carnival) is set to take delivery of the world’s first liquefied natural gas (LNG)-powered cruise ship. With 15 additional LNG-fueled ships on order for three companies in the cruise line industry, the dawn of the LNG-fueled cruise ship era appears to be on the horizon.

Environmental regulations

Concern for the environment is driving the change in fuel as regulations from the International Maritime Organization (IMO) become more stringent to reduce exhaust gas emissions. Conventional cruise ships produce air pollution that includes sulfur dioxide, nitrous oxide, carbon dioxide, carbon monoxide, and particulate matter. LNG does not produce sulfur oxides and emits less nitrous oxide and less particulates. Traditional heavy oil has been a fuel mainstay because it is cheaper than low-sulfur fuels, but adding scrubbers to reduce pollutants is expensive and can off-set some of the initial savings. Currently, LNG is cheaper than low-sulfur fuel, but not cheaper than heavy oil. So environmental regulations, not price, may be the catalyst for the industry to switch from heavy oil to LNG.

 Carnival leads the way

Carnival, the world’s largest cruise ship company, is leading the transformation from heavy oil to LNG. The company, which owns 10 brands, has ordered seven LNG-powered ships to be used by several of its cruise lines: AIDA Cruises, Carnival Cruise Lines, Costa Cruises, and P&O Cruises. Meyer Werft laid the keel for the first ship, AIDAnova, in September at its facility in Papenburg, Germany. The ship is scheduled for completion in about a year; the remaining six ships will be delivered between 2018 and 2022 and will be built by Meyer Werft and Meyer Turku in Finland. The AIDAnova will be the first ship to burn LNG – both on land and at sea – as its primary fuel. All new ships will be dual-fuel vessels that also can burn marine gas oil.

Other cruise vacation companies also are turning to LNG. Disney Cruise Line will take delivery of three new LNG-fueled ships between 2021 and 2023 from Meyer Werft. MSC Cruises has four LNG-powered ships on order for delivery between 2022 and 2026. The ships will be built by STX France. Lastly, Meyer Terku is building two new hybrid LNG-powered ships for Royal Caribbean Cruises that will be ready in 2022 and 2024. Royal Caribbean also plans to test fuel cell technology on future ships.


Infrastructure and fuel distribution are critical to the success of the cruise ship industry’s fuel transition. Said Tom Strang, Senior Vice President for Maritime Affairs for Carnival: “We have to build it…It’s not something you can just turn up and buy in the way you can with marine-gas oil or heavy fuel.” [1]

To that end, Carnival signed an agreement with Royal Dutch Shell to purchase LNG for the first of its two new LNG-fueled ships. One ship will receive gas from an LNG bunker vessel at the Gas Access to Europe (GATE) terminal in Rotterdam, the Netherlands, while the other ship will refuel at available Western Mediterranean ports. Fortunately, significant LNG infrastructure exists in Europe to accommodate the needs of the cruise ship industry. Disney is considering sites at Port Canaveral, Florida – the departure point for many of its cruises – as a fuel storage and LNG distribution point.

Shell video

The next few years will see the delivery of 16 cruise ships all powered by LNG and the development of a global fueling infrastructure to accompany it. It’s the largest fuel-related change in the cruise line industry in almost a century and largely reflects the industry’s growing commitment to a cleaner environment. Carnival, Royal Caribbean, and Disney are leading the charge for now, but the potential for ferry services and other cruise line companies to jump on board will only solidify this ever-growing market niche.


[1] Stieghorst, Tom, “The Future of Cruise Propulsion:  Increasingly LNG Fuels New Builds,” Travel Weekly, September 11, 2016.

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