Navigant Research Blog

Could On-Demand Mobility Finally Pave the Way for Vehicle-to-Grid Integration?

— September 27, 2016

EV RefuelingA decade ago, when discussion of modern plug-in electric vehicles (PEVs) was just getting ramped up again, one of the big potential selling points was the concept of vehicle-to-grid (V2G) integration. For a variety of reasons, it never quite caught on. However, as automakers, suppliers, and a variety of service providers have made a flurry of announcements about deploying autonomous vehicles into ride-hailing services in recent weeks, the time may also have arrived for V2G.

The idea behind V2G was to enable two-way communications and power delivery between PEVs and charging outlets. In addition to electricity flowing into the vehicles’ batteries to enable mobility, PEVs could also provide power back to the grid when needed to cover peak demand loads. A number of automakers have worked with utilities over the years to test out the concept, including Ford. When the automaker built a fleet of 20 prototype Escape plug-in hybrids for field testing in 2008, the cars were loaned out mostly to utilities to evaluate V2G.

Benefits of V2G

For customers, potential benefits of participating in a V2G system include possible rebates for contributing power back to the grid or discounts on charging during off-peak times. Utilities using V2G would have access to a buffer of power during load spikes that would reduce the need to build out extra generating capacity.

Unfortunately, sales of PEVs have turned out to be far lower than many projected a decade ago, with fewer than 120,000 sold in 2015. At the same time, there are more than 3,300 electric utilities in the United States, all with different (and incompatible) systems. With relatively few PEV owners, many with low-range battery EVs, there wasn’t a huge demand for V2G from consumers concerned about being left with insufficient range when they needed their vehicles.

Enter the era of autonomous on-demand mobility (AMOD). Navigant Research’s Transportation Outlook: 2025-2050 report projects that as the world becomes increasingly urbanized and crowded in the next 3 decades, there will be a push toward AMOD to solve the combined problems of air quality, safety, and urban congestion. Most if not all of the autonomous vehicles used to provide these services are also expected to be electric.

New Business Models

Large fleets of more standardized EVs should ease some of the technical issues involved with V2G and could provide the critical mass of fleet size needed to make the investment worthwhile for both utilities and fleet operators. By taking individual owners out of the equation, the fleet management system could cycle some percentage of these autonomous vehicles through V2G-enabled charging stations during the peak hours of electricity demand to provide the needed buffer.

In a world of dramatically reduced retail vehicle sales and the possibility of automakers running these mobility services, such a scheme could also be beneficial to today’s auto dealers. Those dealers could turn their focus to providing maintenance services for fleets, and while vehicles are onsite, they could participate in the V2G system. If utilities were to share part of the savings from not having to expand generation capacity with these mobility and service providers, it would contribute to a new revenue model. As the transportation ecosystem transforms in the coming decades, everyone in the supply chain will need to look at innovative approaches to building a sustainable business.

 

Take Control of Your Future, Part IV: Power Generation Shift

— May 20, 2016

Oil and Gas ProductionDale Probasco and Rob Patrylak also contributed to this post.

In the initial blog of this series, I discussed seven megatrends that are fundamentally changing how we produce and use power. Here, I discuss how the shift in the power generation fuel mix is changing our industry.

Generation Fuel Mix Shift Is Accelerating

The electric grid in the United States has relied heavily on nuclear and coal-fired plants to serve as baseload generation for the overall system. According to the U.S. Energy Information Administration (EIA), U.S. electric generating facilities expect to add 26.1 GW of utility-scale generating capacity in 2016. Most of these additions come from three resources: natural gas (8 GW), solar (9.5 GW), and wind (6.8 GW), which together make up almost 93% of total planned additions.

The Navigant Energy Market Outlook has projected this level of expansion in natural gas and renewable assets for several years. For 2016, Navigant expects higher natural gas (16.3 GW) and solar (13.2 GW) expansions than EIA is projecting. Navigant forecasts wind expansion will be lower at 6.1 GW, suffering a bit from extremely low natural gas prices and the ongoing decreases in installed costs for solar (decreasing faster than the installed cost of wind).

This shift toward natural gas and renewables will continue as many different factors affect generation fuel strategies, resource plans, and decision-making. Among these factors are sustained low natural gas prices (see Navigant’s natural gas price forecast), state and federal renewable incentives, the implementation of environmental regulations such as the Mercury and Air Toxics Standard, and the threat of new carbon legislation such as the Clean Power Plan (see also my earlier blog in this series on this topic). Today, this shift is accelerating even more because of increased interest from customers in renewable power (customer choice) and the rapidly declining installed costs, which are making renewables more competitive with traditional fuel sources (including coal and nuclear).

What Does This Mean to Generators?

As a result, the economics have changed and some of the existing (coal and nuclear) assets are experiencing eroded profit margins. These margins, in turn, are resulting in challenging economics and, in some cases, significant devaluation. Increasingly more generation assets are at risk of becoming stranded investments, as the fuel mix is shifting more quickly than anybody envisioned. Coal-to-gas switching has caused coal plants to consider retirements and, with low gas prices and the impact of renewables off peak, there is more pressure to decommission nuclear assets. There have been several early shutdowns, confirmed announcements, and threatened early shutdowns in recent years, including the recommendation from Omaha Public Power District (OPPD) management last week to discontinue operations at its Fort Calhoun nuclear station. Generators are reevaluating the role of each of their plants, as well as how and if the plants should fit into their portfolio, leading us to the following observations:

  1. Coal and nuclear plants operate at reduced revenue while still required to maintain system reliability/stability as long as their required economics are met.
  2. Coal plants (designed as baseload) are required to operate more as cycling units. This requirement drives up cost and reduces efficiencies, which may mitigate some of the environmental gains made as a result of more off-design operations.
  3. These economic pressures are driving numerous coal plants out of the market and increasing the possibility of stranded assets.
  4. Nuclear assets have been hurt as well and are requesting market assistance and incentives to keep operating. Savings measures such as Capacity Resource Adequacy payments and even state legislatures have been looking at approaches that can improve the economics for both nuclear and coal in order to maintain fuel diversity and keep these baseload plants running.
  5. Efficient gas plants are operating more in areas of ample gas supply and infrastructure.
  6. All generating plants are seeking ways to reduce operations and maintenance (O&M) costs while maintaining reliability.

As evidenced by Navigant’s Generation Knowledge Service (GKS), the average capacity factor of coal plants has declined by 20%-30%, which translates to a 20%-30% drop in gross revenue opportunity. Very few companies can easily adapt to this type of drop in gross revenue. At the same time, driven largely by increasing amounts of variable renewable generation, these coal plants have been asked to perform more as cycling plants, which drives up overall operating costs and reduces efficiency. To deal with the combination of lower realized revenue and higher operating costs, companies are evaluating their plants to determine if they can survive in the new world or if they should be repowered or retired. They are actively seeking new ways to reduce costs through fewer planned outages and higher operating efficiencies while maintaining high reliability to support the increased use of variable generation.

And to Make Things Worse: The Move from Big to Small Power

Additionally, with the rapid growth of distributed generation (DG), all central generation (coal, gas, nuclear, and wind) will face more changes in their role on the grid. DG installations are expected to reach 19 GW in 2016; thus, DG is growing faster than central station generation (26.1 GW additions, minus 7.9 GW retirements, using the referenced EIA forecast). On a 5-year basis (2015-2019), DG in the United States, with some variance by region, will grow almost twice as fast as central generation (98.4 GW vs. 57 GW).

Path Forward

As a path forward, generators must clearly define the mission of each generating unit to understand their new role and how to survive economically. To succeed, companies must do the following:

  1. Conduct a strategic review of generating assets and determine what, if any, changes need to be made in generation portfolio and/or in how these assets are managed under several regulatory and commodity pricing scenarios.
  2. Find ways to reduce O&M costs while maintaining the reliability required by the independent system operators during target operating periods (for plants that will continue to run in the near term).
  3. Have a strategy to manage significant reductions in staffing levels and loss of critical experience across the board, including dealing with the impacts on funding pensions and local economies when plants are retired.
  4. Plan for a changing workforce that will need to include deeper knowledge of digital technology and an understanding of how to optimize operations in a more variable power market.
  5. Aim to operate fossil assets globally, as companies that do so may find it easier to survive than generators focused solely on North America or Western Europe.
  6. Seek new sources of revenue to replace the capital-intensive position for large generating plants by considering investments in renewables and distributed energy resources.

An understanding of the above data points and how they affect your company and the rest of the industry is crucial to shaping our energy future. Navigant can help you develop and use this information to influence the key decision makers, regional transmission organizations, and state agencies that are shaping the future of the industry. If you’re not sitting at the dinner table shaping a future that works best for your company and your customers, then you just might be the entrée.

This post is the fourth in a series in which I will discuss each of the megatrends and the impacts (“so what?”) in more detail. My next blog will be about delivering shareholder value through mergers and acquisitions. Stay tuned.

Learn more about our clients, projects, solution offerings, and team at Navigant Energy Practice Overview.

 

Smaller Utilities Explore Energy Storage-Enabled Solutions

— April 20, 2016

GeneratorWhile California’s investor-owned utilities have received the most media attention for their high-profile energy storage procurements, smaller municipal and cooperative utilities around the country are beginning to recognize the value that energy storage can provide. The services that energy storage systems (ESSs) can provide these smaller utilities may differ from larger organizations, as will their procurement processes.

One notable difference is that municipal and cooperative utilities are generally able to make much quicker decisions regarding investments, as they are not as burdened by regulatory oversight and financial commitments to shareholders. Many of these organizations have been exploring the diverse benefits that energy storage and microgrids can provide, particularly as renewable energy developments become more common for smaller utilities. It is estimated that member-owned electric cooperatives in the United States have nearly 240 MW of solar PV capacity online or in development, which may bring about the need for energy storage to effectively integrate these resources and ensure grid stability.

Problems to Solve

Much of the interest from publicly owned utilities in energy storage and microgrids stems from the generally large geographic area that these entities control. In addition, many customers are located at the end of long feeder lines in relatively remote areas. As utilities see load growing at the end of these isolated circuits, issues around relatability and the need for significant new investments will arise. This challenge is magnified by the fact that many public utilities do not own generation assets, making it different to control frequency and voltage on their system when the generators feeding power are potentially hundreds of miles away. Increasingly cost-effective energy storage is emerging as an ideal solution to these problems by allowing utilities to defer investments in new infrastructure, enabling greater control over their networks and improving reliability for remote customers.

Emerging Solutions

Municipal utilities are able to solve challenges using energy storage either distributed throughout their service territory or at a single facility. For example, the Eugene Water & Electric Board in Eugene, Oregon is developing a solar PV and energy storage microgrid utilizing a 500 kW lithium ion battery from developer Powin Energy. The system will ensure the operability of critical facilities in the event of an outage as well as reduce the expensive peak demand energy the utility buys on wholesale markets. Eventually the utility may look to sell excess capacity into energy markets themselves. An alternative model is being tested by the Glasgow Electric Plant Board in Kentucky, which will deploy distributed ESSs at the homes of 165 customers in partnership with Sunverge. The systems will charge at night when costs are low and discharge during the day or during peak demand, reducing the need to supply additional power and lowering overall costs. This network of ESSs will also provide detailed, real-time insights about the local grid’s performance and ensure customers have power in the event of an outage.

These programs demonstrate the various ways that smaller utilities can enjoy the benefits of energy storage while improving service for their customers and integrating local renewable resources. As energy storage costs continue to fall, there will be numerous opportunities for the nearly 3,000 publicly owned and cooperative utilities in the United States to benefit from the technology.

 

Tracking the Rise of Distributed Energy Resources

— December 21, 2015

While leaders from nearly 200 nations reached a historic agreement in Paris last week to limit greenhouse gas (GHG) emissions, market forces are already driving the growth of distributed energy resources (DER). This rapidly evolving technology landscape is forcing stakeholders throughout the industry to reconsider the structure of the grid itself in addition to the economics of generating, distributing, and consuming electricity.

Utilities and regulators have taken widely differing stances on the deployment of these resources. While some are beginning to embrace the DER trend by developing new products and services and demonstrating the necessary flexibility to evolve, others have been lobbying aggressively to limit or halt their spread. Although all DER represent a shift away from the traditional centralized grid, the potential of different technologies to disrupt the industry varies considerably. While the term disruption can be somewhat vague, in this sense it refers to developments that can alter the relationship between incumbent service providers and their customers or require significant new investments in grid infrastructure. Navigant Research’s recent report, Distributed Energy Resources Global Forecast, explores the growth and impact of DER worldwide.

New Players Emerging

The DER expected to be the most widely deployed over the coming decade are actually those that will cause the least amount of disruption to the industry; demand response (DR) and fossil-fueled generator sets are already widely deployed and have not resulted in significant change in the industry. Equipment to charge electric vehicles (EVs) is expected to be one of the fastest growing DER segments worldwide. This emerging technology is expected to add significant load on the grid and necessitate new business models by both utilities and third parties to effectively manage this new resource, including vehicle-to-grid capabilities. Some utilities have begun experimenting with innovative programs to own new infrastructure and benefit from the integration of EVs.

Disruption on the Horizon

The rapid growth of distributed solar PV is proving to be disruptive to the industry, generating contentious debates over proper compensation for system owners as well as causing a need for new technologies on the grid to help maintain stability. Along with solar PV, the most disruptive new DER technology in the coming decade may be distributed energy storage systems (DESSs). These systems can provide end users with the ability to consume most of the power they generate onsite, lower their bills, and have power available during an outage, among other benefits. Customers empowered with these technologies may have a radically different relationship with their local energy service provider. Several utilities have taken an active role in this growing industry by offering energy storage and solar PV solutions directly to their customers. Energy providers that fail to adapt to new technologies may find their customer base migrating to alternative solutions.

The growth of DER technologies will bring about the need for a greater level of coordination between stakeholders on the grid to enable a two-way flow of energy and services between customers, utilities, and potentially between customers themselves. Known as the Energy Cloud, this concept can lead to the development of new players within the industry, such as the role of a network orchestrator to ensure a balance of supply and demand on the increasingly distributed and complex network. While the future of DER in most areas may rely heavily on new regulatory frameworks, there is no doubt that the ground is shifting under the global industry and the need for new business models is only a matter of time.

 

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