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Weaknesses in North America’s energy infrastructure needlessly inflate costs

The condition and future of North America’s energy sector is the subject of constant and intense debate. Much of the attention focuses on ways to calibrate the changing blend of fossil fuels and renewables in our overall supply mix, as well as other supply-related issues.

But whatever that mix may be today or tomorrow, few people seem to know that the industry is separately and chronically burdened by major structural inefficiencies in its day-to-day operations. These market efficiency gaps are indirectly triggering unnecessarily high energy prices throughout many of North America’s most highly populated regions. At the same time, they’re cutting into investor profits.

 But there’s good news: these inefficiencies can be repaired.

 First, what are they? 

Inefficiencies in energy infrastructure arise from sub-optimal asset management practices in our energy markets, impacting a wide array of assets from conventional fossil-fueled power plants, hydroelectric facilities, and nuclear plants; to large-scale wind and solar installations; to gas suppliers and other participants in the electric power industry.

Across much of the United States and Canada, these assets are geographically clustered into state-specific or multi-state “markets” known as independent system operators (ISOs) or regional transmission organizations (RTOs). With slight variations between them, these federally-established entities coordinate, control, and monitor operations of a region’s electrical power system. They administer their designated wholesale electricity markets and ensure grid reliability.

But frequently, owners of the individual, energy-generating assets situated within particular ISOs and RTOs systematically fail to maximize the value of their assets.

This failure carries two main consequences: first, owners fail to maximize their own profits. And second, end-users – i.e., businesses, institutions and individual consumers – pay more than they need to for energy.

One significant opportunity owner’s often miss is for energy-related business transactions that reach beyond the boundaries of their own ISO or RTO. They needlessly seal themselves off from neighboring grids

Owners miss the opportunity to boost the effectiveness and profitability of their operations in three primary ways:

First, they fail to take advantage of differentials in energy prices between grids. Energy auctions occur continuously. The intervals between sale and transmission can be one day — or even, remarkably, as short as five minutes. Owners frequently bypass arbitrage opportunities to move power from low-priced points within their grids to higher-priced points in an adjacent grid.

This failure to scout out the best price for one’s product or service betrays basic market principles. It renders markets inefficient.

The second lapse involves the under-trading of “renewable energy credits” or RECs. Denominated in one megawatt-hour units, RECs serve as proof that energy has come from a validated renewable source, such as solar or wind power. Though they’re tradable, REC holders don’t commonly trade them between grids, a practice that’s entirely permissible and easily done if one knows the rules and market options.

The third example of systematic asset sub-optimization relates to inter-grid trades surrounding capacity. Among their many, often esoteric roles, the primary mission of an ISO and an RTO is to maintain system reliability. Consequently, every grid remains scrupulously aware of the precise “peak load” of demand that its vast population of end-users may place on its particular system each year. Peak demand almost always occurs on one of mid-summer’s hottest days.

Yet grids — along with their constituent asset owners — that find themselves running the risk of peak load deficits typically don’t engage in capacity-related trading with a neighboring ISO or RTO. They instead rely upon intra-grid adjustments.

So, you may ask, if these three errors are so egregious, what’s causing them in the first place?

There are two primary reasons:

First, lots of owners simply lack the in-house knowledge or bandwidth to recognize and seize upon these opportunities. Many are investment houses, private equity firms, and hedge funds that aren’t so focused on building out the short-term operational value of their assets. They may instead focus most of their attention on first buying and then selling a property, rather than maximizing its hour-by-hour operating profitability.

Therefore, capitalizing upon these three opportunities to enhance efficiency and project value is not something that facility managers – and the often-limited personnel available to them – are able to spend sufficient time on.

Second, inter-grid deal-making is complex. Executing these strategies involves logistical, regulatory, technical, and legal complexities. The complexities multiply with international interplay between U.S. states and Canadian provinces, which heaps on additional layers of regulatory and currency-related intricacies.

Happily, however, these challenges can be overcome. Expertise exists to tackle all three types of opportunities and rectify these market shortcomings. Owners can bring in knowledgeable consultants and energy managers who can capably advise them on how to boost efficiency and boost profitability in all three of these ways.

Everyone loses in an inefficient market. It’s time for owners of energy assets to take steps to address these lost opportunities. They’d reap the benefits — and so would vast numbers of North American energy users.

Tom DiCapua is the Managing Director of Asset Optimization and Business Development. In this role Tom is responsible for overseeing the day to day Power and Natural Gas activities related to Con Edison’s Competitive Energy Businesses’ Leased Asset and Energy Management lines of business. Since joining Con Edison Energy in 2008 Tom has overseen operations of energy management agreements and successfully developed new services tailored for individual clients and sought to coordinate the various capabilities of the Con Edison Competitive Energy Businesses to better suit the energy management needs of the marketplace. Tom continues to develop strategies to build robust, client centered services.

Prior to joining CEE in 2008, Tom worked at National Grid/KeySpan, first as Automation Engineer in their generating fleet and later as a lead Electric Trader for Keyspan’s Energy Transaction Services group. Tom has Bachelor of Science in Computer Science from Siena College and a Bachelor of Science in Mechanical Engineering from Rensselaer Polytechnic Institute. 

El Nino expected to gradually weaken

Sea-surface temperatures remain slightly warmer than average across much of the Equatorial Pacific, although some slight cooling has been observed across the eastern Pacific Ocean in recent weeks. The latest long-range climate models suggest that this weak El Nino will gradually transition to a neutral phase over the next couple months. This neutral phase is then forecast to persist through the fall and likely the upcoming winter season. 

As for the September temperature outlook, slightly above normal temperatures are predicated across portions of the northern Rockies, Intermountain West, Desert Southwest, and southern Rockies. A surplus of total monthly cooling degree days of between 20 and 60 is projected across these regions of the country. Also, parts of Florida may see slightly warmer than normal temperatures in September. Much of the central and eastern United States is forecast to see temperatures average closer to normal in September. It should be noted that if the NAO (North Atlantic Oscillation) remains negative over the next few weeks, some parts of the eastern half of the United States could end up being slightly cooler than normal during September, but confidence is not high enough in that solution at this point in time.

Siemens Gamesa taps 453 MW windpower in India

Saudi Arabian renewables developer and independent power producer Alfanar has awarded the contract for two windfarms in India with a total of 453 MW to Siemens Gamesa Renewable Energy.

Siemens Gamesa will supply 206 units of its SG 2.2-122 wind turbines for the windfarms, which are expected to be commissioned by 2020. Both projects of 202 MW and 251 MW will be located in Bhuj, in Gujarat.

The SG 2.2-122 is specifically designed for India, optimized for low wind, low turbulence sites typical of extremely low power density and high efficiency markets. Siemens Gamesa said the project is a crucial milestone for the company, having sold over 1 GW to India in the current fiscal year.

According to Global Wind Energy Council, India is ranked fourth in global windpower installed capacity. The onshore potential in the country is promising as it stands at 300 GW, of which only 35 GW have been tapped. India’s government has established a target of reaching 65 GW of cumulative windpower capacity by 2022.

“Alfanar is already our customer globally and we are happy to announce this first deal with the company in India,” said Ramesh Kymal, Onshore chief executive of Siemens Gamesa in India.

“Repeated big orders such as this certainly boosts our confidence and demonstrates customers’ trust in our capabilities. With the SG 2.2-122 – a turbine made for India – we expect to deliver better value to our customers through innovative, tailor-made solutions,”

Jamal Wadi, chief executiveof Alfanar Global Development, said, “As one of the global players for developing renewable projects, we are happy to partner with Siemens Gamesa yet again, this time for part of our 600 MW portfolio awarded under the SECI bids which we are developing in Bhuj, India. With more than 3 GW of greenfield development in the pipeline for Alfanar in India, our main goal is to provide value and benefit to the community by partnering with reliable manufacturers”.

Siemens Gamesa’s has two blade factories in Nellore (Andhra Pradesh), and Halol (Gujarat), a nacelle factory in Mamandur (Chennai, Tamil Nadu) and an operations & maintenance centre in Red Hills (Chennai, Tamil Nadu).

Don’t miss POWERGEN India, which takes place on 5-7 May 2020 at the IECC, Pragati Maidan, in New Delhi. Click here for details.

Caribbean set for largest solar and storage project

The largest solar generation plus energy storage project ever to be built in the Caribbean has been announced by the government of St Kitts and Nevis, the state-owned St Kitts Electric Company (SKELEC) and Swiss energy storage firm Leclanchàƒ©.

The fully-integrated system will comprise a 35.6 MW solar PV plant and a 44.2 MWh lithium”ion battery energy storage system and will provide between 25-30 per cent of the nation’s current power generation requirements.Solar and storage plant for Caribbean islands

SKELEC and Leclanchàƒ© SA have entered into a 20-year power purchase agreement to ensure the residents of the Caribbean twin-island federation are provided with a reliable clean energy, coupled with fixed cost savings compared to the current diesel-generated power system. These savings will result in the project being fully paid for over the 20-year agreement, with zero costs being covered by the customer.

The project will housed be on government land in the Basseterre Valley under a lease between the government of St Kitts and Nevis and the project company.

Ian Patches Liburd of the St Kitts and Nevis government said: “We are set to embark on this vital solar and storage project as a key part of our renewable energy thrust that is critical to the future development of our country. The project will help solidify the financial strength of SKELEC over the next 20-plus years, while substantially reducing the islands’ fuel cost over that period.”

He added: “The expected fuel avoidance cost from the installation of the solar farm will not only be beneficial to the energy demand of the federation but represents that most viable option for securing SKELEC’s financial future.

“The solar and battery storage project represents a giant step forward in the government’s efforts to ensure a clean, safe and affordable energy future for our country. This project offers many benefits for our residents, businesses and the millions of tourists who visit St. Kitts and Nevis each year.”

Leclanchàƒ© will serve as the prime EPC contractor for the installation of both the solar PV system and battery energy storage system.

So far, Leclanchàƒ© has established a St Kitts special purpose vehicle along with local partner Solrid to fund, own and operate the facility. Once the energy generation and storage project is completed and delivered, Leclanchàƒ© will be responsible for the management of all project operations, maintenance and equipment warranties

Leclanchàƒ© chief executive Anil Srivastava said: “This project marks the first time a megawatt-scale solar energy system, stabilized by a state-of-the art lithium battery energy storage system, can be utilized to provide true “Ëœbase load’ power for a utility on a Caribbean island. It sends a strong signal to other Caribbean countries, and those around the world, that there is a cleaner, more cost-efficient and viable alternative to diesel power.”  

St Kitts and Nevis Prime Minister Timothy Sylvester Harris said: “SKELEC’s leadership in this solar generation and storage project is commendable on many levels. This project is an example of the bold thinking and actions being undertaken by our electric utility to ensure a reliable power supply and a cleaner, more sustainable environment for our citizens and tourists.”

Ground breaking for the project is scheduled for mid-October with an anticipated completion date of September 2020. 

G&W Electric buys Italian sensor maker Altea

G&W Electric Co., a global supplier of electric power equipment since 1905, has acquired Altea S.R.L., a voltage and current sensor manufacturer headquartered in Ferrara, Italy.

For more than a decade of operation, Altea has designed, developed and deployed innovative voltage and current sensors for real-time management and diagnosis of energy distribution on both overhead and underground lines for medium and high voltage power grids.

“Over the past eight years, G&W Electric has developed a strategic partnership with the experts at Altea S.R.L.,” said John Mueller, Chairman and Owner of G&W Electric. “As we continue to expand our presence in markets outside North America and enhance our power grid solutions portfolio, adding Altea to the G&W Electric family makes strategic sense. Together, we look forward to developing cutting-edge solutions for the grid of the future.”

With the demand for more advanced power grid technology including higher accuracy sensors, this acquisition provides several opportunities to integrate product lines to achieve the demands for the future grid.

Altea began operations in 2009 with the design and testing of its first innovative capacitive sensor for indoor, air-insulated applications. After the successful placement of this sensor across Italy, Altea developed a new family of combined, voltage and current sensors to meet customers’ needs for indoor, outdoor and gas-insulated substations.

FirstEnergy to close Pennsylvania coal power plant early

AKRON, Ohio (AP) — An Ohio-based energy company says it’s closing its last coal-fired power plant in Pennsylvania nearly two years earlier than expected.

FirstEnergy Solutions said Friday that its plant in Shippingport will be idled Nov. 7. The company had previously said the Bruce Mansfield plant would be shut down in June 2021.

FirstEnergy, which is going through bankruptcy reorganization, blamed “a lack of economic viability in current market conditions.”

The company has said it can’t compete in regional wholesale markets as coal and nuclear lose out to cheaper energy sources such as natural gas and renewables. FirstEnergy announced last year that it would shut down the Pennsylvania plant and its last three coal-fired plants in Ohio.

President Donald Trump has vowed to take steps to prevent struggling coal-fired and nuclear power plants from closing.

Senators look to help rural businesses be energy efficient

AUGUSTA, Maine (AP) — Maine’s U.S. senators are offering a proposal to help businesses that want to invest in energy-efficient technology.

Independent Sen. Angus King and Republican Sen. Susan Collins say the move would benefit businesses in rural states such as Maine. Their proposal is called the Combined Heat and Power Support Act.

The senators’ proposal would reauthorize and fund the CHP Technical Assistance Partnerships program for five years. They say the program has helped numerous businesses install energy-efficient equipment in Maine.

The program allows higher education facilities to provide assistance to businesses that want to invest in the technology. University of Maine is one such facility. Collins says the university has “already been a major asset to the forest products industry” in the state.

NM governor wants changes in utility regulation for more renewables

ALBUQUERQUE, N.M. (AP) — New Mexico Gov. Michelle Lujan Grisham is questioning recent decisions by a powerful regulatory commission as it weighs the pending closure of a major coal-fired power plant in a case that will test the state’s new energy transition law.

The first-year governor says reforming the Public Regulation Commission is needed to ensure the success of the landmark legislation that sets more ambitious renewable energy goals and charts a course for shuttering the San Juan Generating Station.

Lujan Grisham, during an energy summit Tuesday, announced her intention to have lawmakers consider commission reforms during the next legislative session.

“If our goal is to protect ratepayers, create economic opportunities for New Mexicans and take advantage of our state’s renewable energy potential, we have too much at stake to sit on the sidelines,” she said in a statement.

Lujan Grisham said reforms should be aimed at restoring what she called “sound decision-making” and that the commission should be “reliable and professional.”

Commissioners were unable to comment Wednesday, citing a policy that prevents them from discussing issues that are related to pending cases.

The governor’s office didn’t propose any specific reforms but plans to take comments from stakeholders ahead of the January session.

The fight over regulatory oversight comes as the Public Regulation Commission embarks on what environmentalists, consumer advocates and others say is a watershed case that will determine how New Mexico implements the Energy Transition Act signed into law earlier this year.

Public Service Co. of New Mexico recently submitted its application for closing the San Juan Generating Station near Farmington. The filing includes a mechanism for financing the closure and providing benefits and training to the workers who will be displaced. It also outlines options for replacing the lost power. All the elements hinge on the new law.

In addition to mandating emissions-free electricity by 2045, the law allows PNM and other owners of the San Juan plant to recover investments and decommissioning costs by selling bonds that are later paid off by utility customers.

The Public Regulation Commission opted to consider a portion of PNM’s application as part of an ongoing case that involved abandonment of the power plant, raising questions as to whether the new law would be applied to the decision-making process since it took effect after that case began.

That move drew criticism from the governor’s office, some lawmakers and environmentalists.

Others have voiced concerns about whether the energy law could ultimately result in higher energy costs by stripping the commission of its authority and responsibility to balance shareholder interests with those of customers and the environment.

Democratic legislative leaders echoed the governor, saying this week that the commission needs to be restructured to ensure the state meets its mandates for affordable, clean energy.

Utility executives have said residential customers would end up saving about $7 a month in the first year after the coal-fired plant closes under its preferred proposal.

They haven’t been able to say what, if any, savings customers would see after that.

It’s expected to be more than a year before regulators decide on the power plant’s closure and the replacement power, but the governor and her supporters are concerned any delays by regulators could derail plans by the utility to replace the lost power.

Aside from the governor’s push for a revamped commission, the Legislature already has cleared the way for voters to consider a constitutional amendment that proposes reducing the commission from five to three members. Instead of being elected, they would be chosen by the governor from a list of qualified candidates compiled by a nominating committee.


Short-lived German nuclear plant cooling tower demolished

BERLIN (AP) — The cooling tower of a former nuclear power plant next to the Rhine River in Germany that was online for just 13 months has been demolished, 31 years after it stopped producing electricity.

Remote-controlled excavators on Friday removed pillars that supported the tower at the Muelheim-Kaerlich plant, near Koblenz. The tower, whose top half had already been removed by a specially designed robot, collapsed under its own weight in a cloud of dust a couple of hours later.

Muelheim-Kaerlich was switched off in September 1988 after 13 months in service when a federal court ruled the risk of earthquakes in the area hadn’t been taken into account sufficiently. After a lengthy legal battle, demolition started in 2004. Operator RWE says nearly all radioactive material had already been removed by then.

A practical guide to holistic management of distributed energy resources

Paring knives are built with a specific use in mind and while one might be used to replace a missing screwdriver or open a bottle of wine in a pinch, the blade or the bottle is likely to be damaged in the process. A Swiss Army knife or a Leatherman tool would be a much better device for those jobs because they are designed to do far more things than a single paring knife. 

Herein lies an important lesson for the way organizations think about managing distributed energy resources (DERs). As the size of the new energy market grows, not only are there an increasing number of DERs, there are also more ways that energy providers want to and can use them to serve their customers. 

To manage all of that, organizations need a holistic approach that has the flexibility of a Leatherman rather than the narrow functionality of a kitchen knife. 

For many energy providers, though, their distributed energy programs have tended to be point solutions. For example, a demand response program that taps into a single type of resource such as residential thermostats. 

These types of programs are akin to paring knives that are perfect for the job they needed to do. But the energy world has changed dramatically, and the pace of change is accelerating. 

Today, a number of trends are making point solutions an unideal fit for the greater complexity of DERs in the market and the greater sophistication of energy providers looking to deploy these resources. 

The first trend is that of decarbonization with the growing number of renewable energy resources in the system such as wind power plants, and utility and residential-scale solar. Each of those assets have a very low marginal cost for the delivery of electrons, but there are intermittency issues that determine when these assets are available and how much capacity they can deliver to the grid. 

Another key trend is deregulation and competition, which is enabling energy providers to transition from the charging-for-electrons business model to a more customer-centric services model. It is difficult to underestimate the impact of how this commoditization of electricity is changing the ways in which energy providers operate, and consumer choice is one of the biggest impacts. 

Consumers have more choice than ever before, not only in who their provider is but in how they can use new distributed technologies to serve their energy needs. This growing decentralization of the energy grid through the use of assets such as smart home appliances, building energy management systems, rooftop solar, commercial- and residential-scale storage create new challenges for energy providers, and digitalization creates new opportunities. 

With the internet of things (IoT) intersecting the energy sector, energy providers can have visibility into distributed energy assets and control them in real-time.  

In a fast-moving market with these forces of decarbonization, deregulation, decentralization, and digitalization accelerating, a point-solutions based approach to managing and leveraging DERs simply cannot meet the growing needs of energy providers. 

It becomes a hindrance rather than a path to achieving organizational goals because point solutions are specific to a type of asset or use case, and therefore are not designed to scale as more DERs are added to the utility or energy provider’s customer base. 

What energy providers need is to take a more holistic, flexible approach to managing distributed energy resources. Key steps in such a flexible approach are outlined in this article starting with the first: what the definition of a distributed energy resource management system (DERMS) is. Sometimes, the definitions differ in how many resources are accounted for. 

Sometimes, the definition is limited by a lack of foresight into how the market and technology will evolve. Sometimes, it is limited in how it views customer needs. This may seem obvious but competing definitions and visions for DERMS may have implications on the type of solution that is procured.

Recognizing that different definitions of DERMS are being used in the industry, Navigant Consulting published on DERMS to help harmonize these. Accordingly, a distributed energy resource management system (DERMS) is defined as a software-based solution to monitor, forecast, and control grid-connected and behind-the-meter DERs across customer, grid, or market applications in real-time. These assets may be utility, third-party, or customer-owned, and directly or indirectly controlled by the utility. 

Please note that the definition accounts for the interests of all the key stakeholders — the customer programs team, the grid operations team, the procurement and/or energy markets team, and finally the end consumer. The utility customer programs team endeavors to have high levels of enrollment and engagement from end consumers in DERMS programs. 

The utility grid operations team wants to, at the very least, be able to manage the impact of DERs on their operations, and ideally be able to use these enrolled DERs for grid services. The utility energy supply and/or energy markets team wants to either reduce the cost of procuring energy, especially at peak times, and/or identify market monetization opportunities for the pools of DERs in the utility customer base. 

And finally, end customers want to use their DERs to deliver on energy bill savings, especially if they own these assets. Both the utility procurement teams and the DERMS solution provider can ensure that key stakeholders’ goals are met. The utility can ensure that key requirements from each group are included in the procurement process and it is incumbent on the DERMS solution provider to show how their software solution can help meet these goals.

Once an organization is on the same page about the definition of a DERMS, it’s important to choose a solution that reflects that definition. Scalability is the most important consideration in the assessment of DERMS solutions. There are actually three types of scalability to consider in any selection process:

࢖ Scalability of Types of Devices – An effective DERMS platform needs to not only support a growing number of devices within a certain category (smart home devices) but also support a growing variety of distributed energy devices, This type of scalability requires a solution that supports open standards, open protocols, and that has a flexible architecture enabled with the ability to accommodate an ever-diversifying ecosystem of assets for creating and delivering electrical capacity. One method of evaluating solutions providers is to consider the different types of devices that solutions providers have connected to and the open standards that they support out of the box. Open standards are especially important for utilities concerned about pools of DERs being stranded when newer technologies become available.

࢖ Scalability of Dispatch and Optimization – One of the most easily-overlooked characteristics of an effective DERMS solution is scalability in how the system can effectively manage the optimization of a large number of DERs. As the sheer number of devices increases, the optimization problem becomes more challenging both in terms of computational methods and computational power needed to solve it. The solution must, therefore, account for this added complexity and be able to forecast, optimize, and dispatch these DERs in real-time in ways that support customers’ needs and the organizations’ technical and financial goals. In evaluating the strength of the solutions providers, the utility may consider both the total MWs they have on their system and the total number of devices that they are optimizing as part of one computational run. These two metrics are a good indicator of the scalability of the platform solution’s optimization and dispatch capabilities.

࢖ Scalability of Use-cases – This type of scalability is related to the core analytical and computational capabilities but is worth mentioning separately. When the DERMS solution is able to deliver on multiple value streams simultaneously, which is sometimes described as value-stacking, all key stakeholders stand to benefit. Asset owners can monetize the value of their DERs faster, utilities are able to deliver on different types of market and/or grid services using the same pool of DERs, and end customers are able to see larger reductions in their energy bills. Some DERMS solutions providers tend to focus on one type of value stream only, usually because their core optimization engines are built to do just that. For forward looking utilities, a solution that focuses on a single use-case may limit  their ability to maximize the value of DERs in their customer base. Furthermore, flexibility built into the DERMS solution in being able to support use-cases that the organization has not yet anticipated is just as important. Evaluating this flexibility ensures that any organization’s investment into a DERMS is insulated from changes in technological, regulatory, and market environments in the future.

A final consideration may be to evaluate how the DERMS solution provider can integrate into the utility or energy provider’s Distribution Management System (DMS/ADMS). Such integrations help align the goals of the energy provider or utility’s operations and end-customer facing teams, and help create a seamless experience interacting with the DERMS wherein relevant information about the distribution network is passed on to the DERMS and the DERs connected to the DERMS are dispatched to be able to alleviate localized network congestion, manage system peaks, act as a generation sink for periods of excess renewables, and other grid-related services. 

In conclusion, a DERMS solution needs to account not only for the end-customer’s experience through the lifecycle of the programs they participate in, but also account for the needs of various teams within the utility or energy provider both at present and in the future.

About the Author: Sadia Raveendran is a Solutions Architect at AutoGrid, the leader in flexibility management software for the energy industry. Prior to that, she did research on carbon capture and sequestration at the MIT Energy Initiative and helped build Tata Power’s solar portfolio in India.