Municipal IT departments have long been overlooked as key players in the smart city deployment process. This is changing as smart cities move beyond the pilot stage and into the era of full-scale commercial deployments. This shift, along with the maturing of smart city platforms, has left many metropolitan IT departments in a tough bind. They are suddenly getting invited to smart city meetings and asked to contribute to projects often with little additional funding or preparation.

Invited Late to the Conversation

With smart city projects on the rise, IT departments are not always brought in at the start of the conversation. Smart city initiatives originate from several places in a city such as leadership (e.g., a mayor or city council) or from a specific department (like the traffic department wanting to install intelligent traffic signals). The idea of deploying a platform often follows after the concept of a smart city has matured within a city—as highlighted by Navigant Research’s recent Smart City Platforms report.

At a Municipal Information Systems Association of California (MISAC) meeting I was asked “What can city IT departments do to manage the onslaught of requests and lack of inclusion with their municipal partners?” IT departments are already pinched for budget and have their hands full with infrastructure challenges like new and evolving cyber issues, let alone managing necessary upgrades and patches across of mixed age and provenance. What can IT departments do to manage the increased number of IT requests and temper expectations of magical IT upgrades? Here are some suggestions:

• Own the problem: Eventually all smart city programs, either deployed in a single platform or a platform of platforms, will need to be integrated with the city’s IT system. Municipal IT departments must acknowledge that the technology deployment will eventually be their responsibility and they need to prepare for it now. This could mean training staff on smart city platforms or making additional budget requests for more staff or upgraded equipment before vendors come to town. By being prepared, IT personnel can make their jobs easier while ensuring the new and effective programs are integrated more smoothly.
• Find internal partners: Most smart city programs have an owner, funder, or promoter in another department. Municipal IT department staff need to be proactive in finding partners in those departments to ensure that IT is part of the conversation from the start. This can help IT departments prepare, and more importantly, inform their colleagues and smart city boosters about existing systems and appropriately scope budgetary requests. Finding partnerships also entails staying involved as smart city deployments develop. The term develop is shorthand for evolve then change, get sidelined, deferred, and finally, become core to a city’s identity. City government is not for the impatient or faint at heart.
• Demonstrate value: Lastly, municipal IT departments may want to consider changing their approach to engaging constituents. Usually, IT works in the background, managing internally facing problems. Most citizens do not know what IT does or know the value it delivers for citizens and business alike. Smart city program deployments necessitate an opposite approach. Smart city programs are public resources. IT departments must think about how they provide value to the public, even though their primary customer is city operations itself. Being hidden and (literally) working in the trenches, can lead to being forgotten or overlooked. As IT departments provide the backbone for smart city platform deployment the public needs to know the value IT brings to the solution.

These suggestions will not instantly solve the challenge of IT being late to the conversation. They can, however, help position municipal IT leaders to be more prepared and become a core component of smart city solutions.

Two of the biggest challenges the indoor farming industry faces today are energy use and successful business models. At the intersection of these two areas is technology. Generally, the more advanced the equipment, the less energy the grow operation requires, leading to more efficient yields and quality production. This is especially true in the case of vertical farming, where the method of vertically stacking production requires the use of more efficient lighting with LEDs.

Unlike the lighting scenario, where replacing traditional high intensity discharge lights with LED fixtures reduces the energy demands of a grow system, urban farming isn’t replacing inefficient energy uses of systems, but rather is adding to them. Providing the rational justification for urban farming has become a real challenge to proponents of the market, especially in bigger cities where both the cost of utilities and rent prices are on the rise. Thus, ensuring a successful business model is crucial amidst the growing number of energy-related obstacles startups must face when entering this market.

What Exactly Is CHP?

Combined heat and power (CHP) systems generate both heat and power onsite. According to a recent white paper by the ACEEE, “CHP is not a single technology but rather an approach to using existing technologies, including those typical of traditional electric generation.” However, the efficiency gains from CHP lie in the existing technologies’ ability to capture and reuse the heat generated from the electricity that is produced. The process of simultaneously producing electrical energy and thermal energy under one system (hence the name “cogeneration”) can be especially advantageous for greenhouse horticulture.

CHP to the Rescue! … Maybe?

CHP is not a novelty concept for growers in Europe, especially in the Netherlands, where Dutch horticulturalists have benefited from the system for over a decade. In addition to electrical power and heat, CHP produces CO₂, a byproduct that is particularly useful to greenhouse growers. Through a decentralized grid architecture, cultivators in the Netherlands have been able to resell unused electricity at a rate of kilos per hour, enabling quicker returns on investments. Thus, the production of power through cogeneration can make for a solid business case when electricity prices or the power demands of greenhouse operations are high.

However, recent studies cast doubt on whether CHP has really benefited growers today in terms of the costs gleaned from energy savings (although the study did find the carbon footprint linked to the use of cogeneration is better). Part of the criticism stems from the risk of overcapacity, which would make it difficult for growers to obtain grid connection to sell the electricity. The 25^th edition of Quantitative Information on Dutch Greenhouse Horticulture found that the price advantage of using gas in a CHP as compared to using gas in a boiler is declining due to the decreasing price of the electricity that is supplied back to the national electricity grid.

The Best Way to Use CHP?

Thus, CHP may be more appropriate for certain applications than for others. Larger greenhouse facilities with natural gas infrastructure and consistent thermal demand seem better suited for cogeneration. However, an analysis of the electricity grid to determine capacity and connectivity would bode well for those considering CHP. For more information on indoor agriculture, look for Navigant Research’s recent report, Energy Efficiency for Indoor Farming.

Commercial and industrial (C&I) customers are often challenged to secure CAPEX for the deployment of distributed energy resources (DER) solutions to meet their sustainability and operational efficiency goals. However, energy service providers and utilities have continued for forge forward. Historically, to avoid these customer challenges, energy service providers and utilities have focused only on energy efficiency-based DER solutions that can meet customer short-term payback returns. This resulted in a two-pronged market that included:

• A narrow focus on fee-for-service energy efficiency-based DER, especially lighting retrofits, with a bias toward standalone project opportunities.
• The emergence of energy savings performance contract (ESPC) financing in the energy services company (ESCO) sector at large installations in the municipal, university, schools, and hospital (MUSH) sector.

Are Traditional DER Solutions Enough?

However, many C&I customers have already focused on LED lighting retrofits. Further, while the ESCO MUSH sector is established and steadily growing, C&I energy users are increasingly interested in portfolio-wide opportunities for broader energy and cost reduction opportunities. Meeting these C&I customer needs will require a more sophisticated approach that transcends energy efficiency-based DER. Energy service providers and utilities are now being required to dig into new DER solutions toolboxes to include the integration of onsite supply load management solutions, as highlighted below.

New Integrated DER Solutions

(Source: Navigant Research)

Acquisitions and Partnerships Can Offer Greater Potential

European-based energy suppliers have recognized the need for a broader and more sophisticated set of customer solutions and are adding technical depth to their DER solutions capabilities through acquisitions and partnerships. This trend includes DER-related acquisitions by Enel and ENGIE in North America. At the project transaction level, this challenge will become more pronounced as integrated DER solutions are increasingly considered for deployment in tandem.

Given this evolution, C&I energy users and DER solutions providers will see an increasingly complex interaction between building load, tariff-specific charges, and the operation of these integrated DER solutions. This interaction will require increasingly sophisticated intelligent building-enabled DER software platforms to support the growth of DER financing at C&I facilities. Navigant Research will examine these DER software platform factors in greater detail in an upcoming Utility Customer Solutions report.

Providing mass transit has always been a challenging business. Like other public good services such as postal delivery, policing, and fire protection, the need to make mass transit available to all has made it almost impossible for the service to be financially self-sustaining. Much of the discussion around today’s transportation network companies (TNCs) and future automated mobility services (AMS) highlights the existential threat they pose to public transit. But maybe they aren’t threats, after all.

The core challenge to providing a public good service is that it generally needs to be available to all—and usually at a price well below its true cost. Cities are diverse, with populations that generally cover the entire demographic spectrum from the homeless to wealthiest in our society. While a thriving modern city like New York City, London, or Shanghai has many affluent people that can afford to use TNCs or even traditional taxis, not everyone can. Even for the affluent, riding in an individual vehicle in a congested metropolis isn’t necessarily the most efficient use of time and resources, and public transit can be the best option.

TNCs in US Cities

The need for near universal, 24/7 access means that many transit lines go underutilized, leading to financial losses. Without outside support, it is challenging to reinvest in the services, make upgrades, or even perform basic preventive maintenance. Lacking funding, service suffers for everyone, including those on the most used routes.

New York City, with its population of 8.5 million, is a great example of this. In recent years, the subway lines that so many residents depend on have suffered increased outages. There are now an estimated 100,000 TNC drivers on the streets of the city, vastly outnumbering the 13,000 yellow cabs and leading to increased congestion on surface streets.

Detroit has wide swaths of low population density. Providing reliable and consistent service to low income residents poses even greater challenges and makes it difficult for those residents to get to school or work. However, a wholesale shift to TNCs or AMS is not economically viable for residents who cannot afford those kinds of services. An additional challenge is that an estimated 30%-40% of Detroiters are unbanked or underbanked. Many of these residents end up relying on cheaper, older cars that consume more fuel and emit more greenhouse gases and pollutants.

Are Multimodal Mobility Systems the Solution?

Allowing private TNCs unfettered access to city streets runs the risk of siphoning off users from the more viable, higher density routes while potentially increasing congestion. This would make providing affordable universal service to all residents even more of a challenge. Alternatively, if service providers collaborate with transit services to establish coordinated multimodal mobility systems, it can be possible to serve the needs of all residents in a way that is affordable, accessible, and financially sustainable. Leveraging apps and cloud platforms to aggregate services enables users to select the best travel combination for each trip based on cost, timing, and convenience.

Numerous companies, such as PSA’s Free2Move, are developing mobility aggregators; Ford subsidiary Autonomic is developing a Transportation Mobility Cloud for cities to use. Part of Ford’s recent investment in Detroit’s Corktown neighborhood is expected to focus prototyping some of these mobility ecosystem ideas.

A coordinated mobility ecosystem that coordinates private operators with more optimized public transit can be a benefit to all urban dwellers that need to get around.

On July 19, my colleague Pritil Gunjan wrote a blog titled “A Solar Coaster Ride for UK Prosumers.” But we were soon to find out that the UK Department for Business, Energy and Industrial Strategy (BEIS) was creating the tightest loop-the-loop and twisting screwdriver turns for prosumers. Just as her blog was published, BEIS confirmed its intent to close the small-scale feed-in tariff (FIT) program on March 31, 2019 as planned. It also stated that it will close the export tariff to new applicants at the same time.

The UK government’s own Impact Assessment paper estimates that the closure of the FIT scheme and the end of export tariffs would reduce the internal rate of return (IRR) for residential systems installed in 2019 from 7%-8% to 2%-3%. BEIS estimates that small-scale annual installations will drop from around 210 MW (with the FIT and export tariffs in place) to between 51 MW and 103 MW in 2019.

As I argue in my upcoming DER Self-Consumption Enabling Technologies report, the future of distributed energy resources (DER) lies in maximizing self-consumption to reduce the amount of electricity bought from the grid and selling grid services to create new revenue streams. Viewed from this angle, BEIS’ decision is a step in the right direction, as the FIT and export tariffs reduce the need for prosumers to embrace those models. In addition, the government could encourage innovative companies to create business models that embrace self-consumption and grid services.

Foundation and Timing Issues

The problem is that BEIS is closing the FIT and export tariff programs before setting a new regulatory framework in which prosumers can participate. In other words, the UK government is demolishing a building still inhabited by an already strained solar value chain without setting up the foundation of the new regulatory framework for small-scale renewables.

This brings timing into the equation: the closure of FITs and the export tariff will occur on the same day as Brexit is expected to happen. As Pritil argued in her article before the BEIS announcement, “the longer-term outlook for post-Brexit solar is riddled with uncertainty as energy suppliers seek more legislative reassurances.” Despite this, it seemed that the industry had found the floor in installation numbers and figured out a sustainable business model without extreme cost increases. The same Impact Assessment estimated the cost of the FIT and export tariff programs at below 0.5% of the annual energy bill of the average consumer for the next 5 years. But now, the closure of the programs brings even further uncertainty to the table. This ambiguity is unlikely to recede soon since the legislative agenda is and will continue to be dominated by Brexit-related topics, pushing energy policy to the back burner.

Under these circumstances, the government’s decision most likely will not push the industry on a long-term sustainable path. Rather, the closure of FITs and the export tariff may simply slay the remaining actors in an already weak value chain. Given the uncertainty levels, it may have been better to tweak the current incentive scheme. Doing so would have enabled the government to ensure that the IRRs remained at an even level as it built the new regulatory framework and then pushed forward with the closures.

No one likes a broken record, but I need to be one. The recent revelation of Russians successfully hacking the US electrical grid is alarming, and yet expected. It moves me to ask: Is everyone asleep at the cybersecurity switch here?

In case you’ve been snoozing or on vacation, here is what the US Department of Homeland Security revealed on July 23: hackers working for Russia penetrated hundreds of US electric utility control rooms. The attackers could have caused blackouts. First detected in the spring of 2016, the long-term attacks were executed by hackers working for a Russian state-sponsored group previously known as Dragonfly or Energetic Bear. The hackers were able to penetrate the corporate networks of utility vendors, many of whom were smaller companies without large budgets for cybersecurity. Are we to believe this is the last occurrence of hacking? Not likely—some companies still may not know they have had their facilities compromised.

Too Little, Too Late

My colleagues and I have written about this before (see the Navigant Research reports: Cybersecurity for the Digital Utility, and Managing IoT Cybersecurity Threats in the Energy Cloud Ecosystem), and it is galling that so little action seems to have occurred to foil this activity. In a previous blog, I wondered at the lack of evidence of progress thwarting the bad guys. Now those doubts seem to have credence.

It helps to take a deep breath and get some perspective, yet, at the same time, all stakeholders (utilities, vendors, regulators, the public) must act now. We cannot afford to have the grid hacked and risk losing control to a foreign bad actor, Russian or otherwise. Grid cybersecurity needs to be a top priority, not a lazy afterthought. Let’s outsmart the cyber criminals! Do I need to say that again, like a broken record?

As transmission and distribution (T&D) grids become ever more complex and diverse globally, grid visibility and reliability is important now more than ever. Today’s utilities are increasingly sensorizing their grids, adding standalone and retrofit sensors onto network assets to increase grid visibility, driving network performance improvements. Sensors such as Sentient’s MM3 Intelligent Sensor, SEL’s WSO Sensor, and Siemens’ Transformer Monitoring & Diagnostic System are examples of sensing systems on the market today. The sensor market landscape is discussed in depth in the recent Navigant Research report, T&D Sensing and Measurement Market Overview.

Annual T&D Sensing and Measurement Revenue by Region, World Markets: 2017-2026

(Source: Navigant Research)

A grid sensor deployment project involves a large capital expense to purchase, integrate, and install the sensors and update the communications networks accordingly. Additionally, sensor projects involve a smaller ongoing expense to operate and maintain the new equipment. This has been the standard delivery model for grid assets and for sensors as most current ratemaking methods allow for the cost recovery of capital spending while limiting operation and maintenance (O&M) recovery.

A Different Approach

There is another way for utilities to deploy sensors on their grids, and it is by adopting a managed service delivery method used in the software industry for over 30 years: Sensing as a Service. Under a Sensing as a Service model, a utility would form an agreement with its chosen vendor and pay an initial integration cost and an ongoing subscription cost for the vendors’ sensors to capture data on its network. This model would greatly reduce the capital expense of widespread sensor deployment and allow for upgrades and network improvements without a complete system overhaul. A shift to this model may benefit from the expanded adoption of a performance-based ratemaking model, and utilities would need to recover the O&M expenses or be allowed to capitalize the entire multiyear subscription package for cost recovery. Certainly, there are additional challenges faced by shifting to a Sensing as a Service model, but three key benefits are outlined as follows:

• Decreases utility capital spending: Without the need to purchase the sensors, utilities can save money by utilizing a Sensing as a Service delivery model. Initial integration and installation costs would be significant (as they would with the current purchasing model), but once the process is complete, the utility would essentially only pay for the data collected.
• Simplifies utility operations: By allowing a sensor vendor to install, operate, and own the sensing hardware and equipment, utilities can simplify their operations. Once the sensors are installed and integrated, the utility will simply be presented with data collected from the sensors, and can focus on the analysis and actionable decision-making based on that data.
• Enables more frequent sensor hardware upgrades: A Sensing as a Service model would allow utilities to more frequently upgrade sensors without significant capital costs. As sensing and measurement technology continues to evolve, utilities could use a managed service model to periodically update and upgrade their sensor hardware, improving network performance at a lower cost than if they had to purchase new hardware.

Opportunities for New Partnerships

Nokia currently offers a Sensing as a Service model for its communications network products, and uses blockchain technology to manage data collected on distributed assets. T&D sensing systems could employ similar technologies to greatly enhance data collection and provide significant benefits to utilities through a managed service model. Driven by a potential shift in ratemaking policy and by the benefits outlined in this blog, utilities have a lot to gain with a shift in the sensor deployment model—and sensor vendors should be lining up to help.

This blog is the final part of a four-part series.

Over the past months, I have taken a systems-level view of proof of work (POW) and digital currency mining (DCM): why its energy consumption is a problem, the economics of mining, and how those economics—together with regulatory and technology evolution—paint a bleak picture of DCM’s future.

The stage is set for the million-dollar question: if utilities must deal with roughly 92 TWh of annual energy consumption from DCM now but long-term deals with the industry aren’t sustainable, what can be done?

Discouraging Mining Could Have Unintended Consequences

Bans and restrictions are an experiment playing out in Washington, New York, and other states in the US. Utilities and utility commissions have two main options at their disposal: create premium tariffs for DCM (which can discourage miners from establishing or help offset rate spikes) or advocate for regulatory changes that restrict or ban mining activities directly.

The downside of this approach is that it might force miners underground, where their activities are harder to detect or regulate. Unlike most industrial-scale customers, DCM companies can disaggregate their loads. A DCM facility might be 40 MW in total, and it is convenient for mining companies to keep all that hardware under one roof, but they could just as easily divide their machines into 10 separate 4 MW facilities, or hundreds of kilowatt-scale facilities that could be set up in residential areas.

This trend has created public health concerns in some territories, as stacks of DCM hardware are piled in basements or old apartments not designed to handle high electricity loads and concentrated waste heat. Utilities will benefit from keeping an eye on customer meters, watching for unexpectedly high loads or unusual load curves that could indicate unsafe DCM. In the absence of broader regulations, the public safety argument may be utilities’ best bet for taking action.

Utilities Must Minimize and Shift Risk

Utilities absolutely should not be building new capacity to power DCM. DCM will be transient, and utilities risk being left with stranded assets as miners go out of business or relocate. However, some utilities are asking DCM companies to front the cash for new generation infrastructure, which shifts risk from the utility to the company. An arrangement like this could allow utilities to benefit from DCM in the short term, but long-term contracts should be out of the question.

A second option is to restrict DCM to regions where surplus electricity is available, or where curtailment is necessary (where increased power consumption benefits the grid). Doing so may prevent rate spikes for customers, but feeding electricity to DCM facilities rather than exporting it at a premium still comes with a cost. It is difficult to calculate a tariff that would reliably make the difference; the value of electricity fluctuates, and the value of digital currencies (which translate to DCM revenue) fluctuates even more.

Tread Carefully

It’s not impossible for utilities and DCM companies to reach win/win outcomes, but it is perilous. Utilities need to think long term and structure deals accordingly. The 20-30-year operational timescales for utilities do not mesh well with the hour-to-hour volatility of the DCM industry. China, once a stronghold of DCM, first encouraged mining by offering low electricity rates in exchange for profit sharing. Now China is doing its best to kick miners out—which suggests lessons learned.

Oh, and one more piece of advice for utilities: don’t let miners pay you in Bitcoin.

The intelligent buildings market has been around for about 2 decades. For much of that time, small innovative startups introduced new software applications and gained traction with the early adopter large enterprise customers. While often pilot projects, these market gains spurred major building technology companies to embark on a flurry of buying in the mid-2000s. It became clear that the integration of these nimble startups into the behemoth industry incumbents was no small feat. The significant distinctions in culture, development processes, and vision inevitably created challenges in retaining talent, maintaining innovation, and ensuring sustained growth.

The result of these pilot projects has been mixed. On one hand, today’s market-leading building technology incumbents are offering new incarnations of their core product offerings, enhanced with digital technologies and analytics. On the other hand, there remains a dynamic market of startups vying for customer dollars. However, the momentum behind Internet of Things (IoT) has piqued the interest of non-traditional major competitors from adjacent technology and services markets and activity across the traditional value chain, signaling movement toward mass-market adoption.

Learning from the Past

Two recent acquisitions by major building technology players suggest there may be some lessons learned from earlier days in the intelligent buildings market: retain the startup spirit of new subsidiaries. When Acuity acquired Lucid in February, the companies reported, “Lucid will continue to grow BuildingOS as an independent and open platform, and will continue to be led by current executives including CEO Will Coleman and Co-Founder Vladi Shunturov.” In June, Comfy announced its acquisition by Siemens, and the messaging was similar: “We will continue to operate—and grow—as an independent entity and vendor agnostic platform.”

It’s not only about the strategic integration of recent acquisitions, but also about a growing realm of partnerships opening the door to new business opportunities across the value chain. Distributors and resellers represent an important segment for shaping the mass-market adoption of intelligent building technologies. Recent moves in this segment underscore the momentum IoT is providing for the buildings industry. Yorkland Controls, a Canadian heating and cooling distributor, has announced a partnership with IoTium and SkyFoundry. A recent IoT Agenda article reports, “Yorkland Controls has lined up a series of key partnerships in areas like data analytics and secure IoT networking to carve out an offering in the space and to help its customers establish new lines of business.”

Reaching an Inflection Point

These recent moves across the value chain underscore the notion that the intelligent buildings market is reaching an inflection point. IoT is driving down costs, increasing customer awareness, and therefore removing significant obstacles to mass-market adoption. The face of competition is changing as openness, interoperability, and security become table stakes. Strategic partnerships and tech-agnostic offerings will redefine the relationships between technology and service providers and their customers.

Decarbonisation of the global energy system is one of the big challenges society faces today. The Paris Agreement, adopted in 2015, states that efforts should be pursued to limit the temperature increase to 1.5°C above pre-industrial levels. In my previous blog, I explored what such increased ambition would mean for the global energy system and what a fast energy transformation could look like. I illustrated that it is possible to bring global energy use below current levels to 435 EJ and reduce annual emissions to zero by 2050 by strong energy efficiency improvements and accelerated deployment of renewable energy. Electricity, bioenergy, and hydrogen become the main energy carriers for energy services in industry, transport, and buildings.

Electricity Generation Triples because of Electrification of Energy Services

Electricity demand is expected to triple with the electrification of heat demand in industry, deployment of EVs in transport, and electrification of space heating, space cooling, and hot water supply in buildings. To enable fast decarbonisation, renewable electricity is vital. Wind turbines and solar PV currently produce 5.6% and 1.9% of global electricity production, respectively. Ecofys, a Navigant company, developed a decarbonisation scenario in which these technologies produce over 70% of global electricity demand in 2050. High shares of volatile renewable energy sources come with periods of too much electricity and periods of too little electricity. The power system will need to provide the flexibility to match supply and demand.

Hydrogen Will Play an Essential Role in the Future Energy System

The production of hydrogen from renewable electricity (power-to-gas) and its use for power generation (power-to-power) will be essential levers for balancing supply and demand in the future energy system. In the decarbonisation scenario, about one-fifth of the electricity generated in 2050 (which equals about 60% of current electricity consumption) is converted into hydrogen for use in the industry and transport sectors, as well as in the power sector:

• Industry Sector: Hydrogen is used as feedstock in specific processes in the chemical and fertilizer industry, to produce high temperature heat, as well as for specific novel technologies like hydrogen direct-reduction steelmaking.
• Transport Sector: Hydrogen is used in fuel cells to power road, rail, and shipping vehicles.
• Power Sector: Power-to-gas provides demand-side flexibility in case supply exceeds demand, and some of the hydrogen produced is used to provide dispatchable power capacity in periods with less renewable electricity generation.

(Source: Ecofys, a Navigant Company)

The World Market for Renewables Integration Is Growing Fast

The energy system transformation is feasible, but highly disruptive. A recent report by Ecofys, a Navigant company, details this transformation. All players in the energy system will be influenced by the accelerated decarbonisation of the power system. As the levelised costs of renewable energy fall and as electrolyser technologies improve and decline in price, business models to deploy power-to-gas technologies are taking shape.

As green hydrogen’s cost decreases, its potential grows and its uptake unfolds in stages. As a result, green hydrogen’s use as a chemical feedstock in the industrial sector and as fuel in the transport sector is expected to gain momentum. In energy systems with increasing shares of variable renewable electricity, the utilisation of green hydrogen in stationary applications provides flexibility for the grid (power-to-power). This is useful at times of high generation and low demand (or vice versa) for security (e.g., grid stability) or economic reasons.

In June, a 1 GW electrolyser contract was announced by Nel ASA. Starting in 2020, the company will deliver 448 electrolysers and supporting fuelling equipment to Nikola Motor Company (Nikola). This will help support Anheuser-Busch’s recent order of 800 hydrogen-electric powered semi-trucks from Nikola. The contract is indicative of the emerging market for hydrogen, and how it is beginning to shape the transport sector.