Navigant Research Blog

Australia Leading Solar PV plus Storage Innovation

— May 23, 2016

Rooftop SolarImprovements in technology and cost have allowed solar PV plus storage systems to become an attractive investment in many parts of the world. However, what remains to be determined are the optimal business models to unlock the full value of these systems. Pairing solar PV directly with energy storage holds the potential to dramatically transform the electricity industry and provide customers with cleaner and more secure power at a predictable price. Despite the potential, there has been little consensus in the industry on the best way to deploy these systems on existing grids and on how to overcome the significant barriers that the required upfront investment presents. 

Although solar PV and energy storage systems (ESSs) have been paired up in microgrids and remote settings for decades, their integration into existing electrical grids presents new challenges. Innovative models for the ownership and operation of these systems are being explored around the world, driven in part by the increasing funding flowing into the distributed energy industry. Australia has been at the forefront in the development of distributed energy resources, and two recently announced projects in the country offer different paths forward.

Dueling Approaches

In early adopter markets around the world, two primary models for deploying solar PV plus storage systems are emerging. Many stakeholders in the industry believe the optimal way to deploy these systems is through incumbent utilities and electricity providers that can leverage technical experience and access to financing. The recently developed suburb of Alkimos Beach in Western Australia was seeking a community-scale solution to help manage an increasing number of distributed solar PV systems and limit the need for new infrastructure to serve its growing population. The neighborhood elected to work with local energy provider Synergy to deploy a 1.1 MWh lithium ion ESS that is being fed by over 100 solar PV systems located on rooftops throughout the area. In addition to reducing costs for customers, managing the intermittency of PV generation, and limiting the need for new infrastructure, the project provides Synergy an opportunity to use community engagement as a way of combating the threat of grid defection.

Alkimos Beach is not the only community in Western Australia exploring innovative ways to harness the power of the solar PV plus storage combination. The community of White Gum Valley has chosen a different path toward a sustainable, local energy system both in terms of ownership and technical design. Most homes in the community will have both solar PV and battery ESSs onsite that will be operated in concert. In addition to the physical distribution of energy storage in this model, systems in White Gum Valley will be owned by the company managing most of the community’s apartment buildings. The company will act as a utility by owning assets and retailing energy directly to customers, a rare situation in Australia’s regulated electricity markets.

The Path Ahead

These two projects may provide some unique insights into how solar PV plus storage solutions can be optimally developed. They provide clear examples of some of the major debates in the distributed energy storage industry, such as whether it is better for systems to be centrally located or distributed, or if they should be owned by utilities or by customers. While it may take several years for these projects to illuminate the merits of one approach versus the other, they may be a sign of things to come as the distributed energy industry takes shape.

 

Fracking Boom Drives Increase in Wastewater Treatment

— May 23, 2016

PipelineHydraulic fracturing (commonly referred to as fracking) has been around for many decades, but only recently has it been at the forefront of oil & gas exploration in the United States. Even with the recent downturn in natural gas prices, producers are continuing to frack. According to Scientific American, hydraulic fracturing consumes up to 9.6 million gallons of water per well, and many wells are located in arid regions like Texas.

There are a number of opinions about the process, both favorable and unfavorable. But one thing is for certain: hydraulic fracturing consumes a large amount of water and produces a great quantity of wastewater. This wastewater can be in the form of flowback (fracturing fluid that flows back to the surface of the well after injection) or produced water (water that was already in the aquifer). These present different challenges to treatment and disposal, as flowback water contains components which make it viscous, and produced water tends to have very high levels of dissolved salts. Treatment of this water is usually overlooked in favor of injecting it deep underground in Class II injection wells. However, with increasing public awareness of fracking and advancing treatment technologies for complex contaminants in water, treatment and recycle of wastewater is becoming more viable.

Increasing Regulations

The United States and Canada are the major players in the fracking waste treatment business today. Despite rumors of the lack of regulation, hydraulic fracturing is heavily regulated, and more stringent regulations are being passed at local, state, and federal levels. Along with heavy regulation on the practice itself comes heavy regulation on the disposal and treatment of associated wastewater. For example, in Pennsylvania, the U.S. Environmental Protection Agency regulates the permitting of Class II underground disposal wells. In many other states, these are the main sink for produced and flowback water. In Pennsylvania, there are only seven active disposal wells for oil & gas use; increasing regulation, as well as changes in the economic conditions, are causing the market for water treatment to expand rapidly.

Navigant Research’s recently published Wastewater Treatment Technologies in Natural Gas Hydraulic Fracturing report analyzes the wastewater treatment market between 2016 and 2025. According to the report, revenue from treating water is expected to surpass revenue from deep well injection of produced water in 2018 and is expected to continue to grow from there. This represents a great opportunity for many of the small companies entering this market. Currently, advanced oxidation, membrane filtration, and reverse osmosis are popular treatment options for flowback and produced water streams. With the rapidly growing available revenue in fracking waste treatment, it will be interesting to see which other treatment technologies are adapted.

Revenue from Hydraulic Fracturing Wastewater Treatment by Disposal Type, United States: 2016-2025

Anne Blog Fracking(Source: Navigant Research)

 

 

The Growing Role of Energy Storage in Microgrids

— May 23, 2016

GeneratorEnergy storage systems (ESSs) have an important and diverse role in microgrids. Solar PV and other renewable distributed generation (DG) technologies require a voltage source in order to synchronize. This has typically been done with a backup generator; an ESS provides a similar voltage source but without the emissions of a diesel generator. Recent advances in microgrid automation systems, however, have made ESSs less of a necessity in partially renewable-based microgrids. According to industry leader ABB, microgrids with as much as 50% of load coming from renewable sources do not need an ESS. This is 10% higher than previously believed. Despite this, microgrids without some form of storage are not likely to become the norm, as ESSs provide a number of other advantages aside from being a voltage source. Peak shaving, smoothing power flow, and volt ampere reactive (VAR) support are just a few of the supplemental functions an ESS frequently serves. Islanding and black-start assistance further support the case for storage use in renewable DG microgrid systems.

The most recent update of Navigant Research’s Microgrid Deployment Tracker investigated the use of ESSs in microgrids across the globe. According to the report, of the greater than 15 GW of microgrid capacity accounted for in the Tracker worldwide, almost 25% utilized ESS in some form, up from a reported 17.5% of projects in the previous Tracker update in 4Q 2015. This is a result of ESSs being present in over 40% of new project capacity from the most recent update.

The chart below shows the percentage of ESS utilization by microgrid segment for both the 4Q 2015 and the 2Q 2016 Tracker. While ESS utilization grew across all categories, the commercial and industrial (C&I) and utility distribution segments saw the most significant increase, growing 40% and 23%, respectively. C&I microgrids have traditionally been led by diesel combined heat and power (CHP) systems in the past. The jump in energy storage use among microgrids in this segment likely signals a shift to solar PV and other renewable energy use that has a higher need for ESSs.

ESS Utilization by Microgrid Segment, World Markets: 4Q 2015 and 2Q 2016

Adam Wilson Blog

 (Source: Navigant Research)

This is further supported by the fact that solar PV capacity in microgrids grew by almost 840 MW since the last update of the Tracker, an increase more than 5 times greater than CHP capacity growth. The combination of solar PV and ESS is expected to grow in popularity across most segments and regions of the microgrid market. The declining price points of energy storage and solar PV technologies and an increasing focus on renewable sources are largely responsible for this shift. It has also been suggested that the combination of CHP, solar PV, and lithium ion energy storage represents the ideal mix of technologies for microgrids, particularly in the United States.

The high functionality of storage systems along with the growing presence of renewable generation in the microgrid market bode well for the future of ESS. These systems are expected to remain a core technology in the microgrid industry for the foreseeable future.

 

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.

 

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