Utilities sailing into uncharted waters… What’s in store for the future grid?
20 June 2014
For decades, the electric utility business model in the US, with its trillion dollar assets, has been organised on the principles of centrally controlled generation and variable consumption. Generation was mostly delivered from coal or nuclear plants, with its product still treated mostly like a public service rather than a consumer product. This model is now increasingly under pressure from the convergence of flattening electricity demand, growth of green energy, cheap natural gas, distributed
The centralised grid
Pressures on the grid come from within, from rapidly growing requirements for infrastructure investment due to ageing infrastructure, general upkeep and reliability upgrades, all of which are creating the need for unprecedented capital investment. Added to this are the demands to harden the system, which came centre stage after widespread outages following 2011’s winter storms, 2012’s derecho in the metropolitan Washington DC area, and of course Superstorm Sandy. All this investment raises the price of delivery for power, which stretches the ability to recover necessary rates to support costs and shareholder returns.
In July 2013 we witnessed a credit rating downgrade of a major utility, due to the large amounts of planned spending to address reliability challenges. A lower credit rating makes capital to build and maintain the system more expensive for utilities, and could lower shareholder returns.
If these trends continue, even at a more gradual pace, we will be looking at a paradigm shift in the traditional utility business model. This could bring in a “natural deregulation” of today’s electric utility, replacing it with a new model based on more DER, microgrids, or virtual power plants (VPPs).
Promises of a decentralised grid
While there are some challenges to overcome, a decentralised grid has a number of positive features, including:
* The centralised grid model of generation and power distribution could have end-end- efficiencies as low as 35-40%, due to inherent losses in thermal cycles of the centralised generators, as well as extended transmission and distribution systems. On the other hand, microgrids, with efficient generation technology such as combined heat and power (CHP) situated near to point of use, could be 85% efficient.
* From the reliability point of view, the centralised grid approach to electricity production and distribution has long been susceptible to cascading effects from sometimes relatively minor events. Microgrids can act as firewalls offering enhanced reliability, amongst many other benefits. The extra security and independence from potential grid interruptions, such as blackouts and brownouts, are especially important for critical applications running at hospitals and military bases. Also, with the power source located on-site, microgrids could be less vulnerable to cyber-attacks on the grid.
* A microgrid, which uses renewable sources and CHP, can result in an estimated 50% reduction in greenhouse gas (GHG) emissions compared to a centralised plant model. In the US, the Environmental Protection Agency (EPA) has introduced proposals to curb emissions from power plants which will pave the way for new standards for power plants in 2014. This will limit emissions to 1100 and 1000 lbs per MWh of carbon dioxide for coal- and gas-fired plants respectively. Curbing emissions would require large-scale renewable integration, a concept currently dependent on expiring tax credits and the development of other technologies, such as storage.
* The average microgrid may take about 18 months to build, compared to 3-7 years for conventional power plants, with the shorter time associated with gas turbine-based designs.
* Another largely untapped application for microgrids is their deployment in the developing world, where they could mean the difference between having electricity and not having electricity.
* The convergence of smart technologies (i.e., automation, intelligence, sustainability, demand response, and storage) occurs only in one small-scale application: the microgrid. A microgrid integrates DER, storage devices, end-use loads into a single, “mini” grid which can operate in parallel with the traditional grid or in isolation from it. These technologies are currently struggling to withstand both technological and economic pressures in the larger grid.
Utilities, however, can be reluctant to endorse microgrids, except in special cases, as they erode revenue generation and lack the economies of scale inherent in a more centralised approach. They also cite safety concerns with respect to utility workers, unintentional islanding, and protection issues. Another point of concern is the lack of established comprehensive standards for microgrids.
What does the future hold for microgrids?
Microgrid deployments are expected to increase significantly over the next five years—especially in mission-critical arenas, such as in hospitals and military bases. It is also expected that the present deployments and pilots, as well as the demand in rapidly developing countries and rural communities, will increasingly push the larger-scale adoption of microgrids. This will be further reinforced by the fact that the developing world will not be able to sustain economic growth if it relies exclusively on centralised electrical systems.
Because microgrids can serve non-utility sponsors, this would appear to challenge traditional utility interests, yet they can serve both the utility and the sponsor. Utility-controlled microgrids can take advantage of the islanding features of the microgrids, which will reduce load on a stressed grid and/or defer capital investment in capacity or to meet load growth. Thus, microgrid benefits can include meeting peak load constraints and load shifting. The ability of the microgrid to defer capital investment in infrastructure acts as an alternative to more capital-intensive infrastructure projects to handle load growth, optimise the supply-load mix on specific parts of the overall grid, or provide some ancillary services such as frequency regulation.
Microgrids can also allow the utility to optimise its available resources, while maximizing the use of renewable energy, limiting GHG emissions, and still meeting load requirements. This approach is being explored in California. It is meeting the renewables targets and the aggressive mandates to limit greenhouse gas emissions, which are driving the European Union (EU) to see the most near-term growth in microgrids. However, this could be at risk if the EU backs off its environmental mandates for economic reasons. In New York, in contrast, the non- utility potential microgrid sponsors are looking at microgrids to boost system resiliency in the wake of storms, such as Superstorm Sandy. However, with no in-place policy drivers, the challenge for utilities is to develop a positive business case for microgrids.
On the other hand, the present low cost of gas has a positive effect on a number of business cases for microgrids, which often have a large proportion of conventional sources, rather than renewables sources. That may also propel some other aspects of the microgrid, such as combined heat and power (CHP) natural-gas-fuelled projects. Policy drivers, if they become a reality in the USA, may be fragmented given that there are over 50 state-level public utility commissions to navigate and from which to gain approvals.
Developers of microgrids face some different regulations based on the state they are in as the concept and definition of a microgrid does not exist nor is recognised in many states, and thus the microgrid may fall under some regulations intended for other concepts.
It may in some cases be classified as a public distribution, and in other places may fall under the regulations developed to regulate steam heating utilities if it has thermal storage. If it has components that cross public roads, then it may fall under regulations for transmission and distribution (T&D) cost allocations or may be required to obtain a municipality franchise or be obligated to serve as provider of last resort.
The coordination of several microgrids and the operation of virtual power plants may ultimately mimic the full functionalities of central power plants. This would allow DER to take the responsibility for the delivery of energy services in conjunction with, and perhaps taking over the role of, utility central generation.
As the drop in price from distributed rooftop solar falls below the price of delivered power from some of the grid (the actual cost without subsidies has reached parity with the delivered price of electricity without subsidies), so does the demand from the grid. This could require a higher cost per kwh of power delivered, which in turn makes distributed options more competitive. This can be expected to be a reality in the next ten years, or even sooner in some places in the US. Their use can be further propelled by the development of cost-effective, scalable, technological breakthroughs in battery energy storage technology.
A perfect storm
A perfect storm for the regulated utilities may be brewing if borrowing costs rise in the face of required investment in plant renewal and hardening in the face of extreme weather at a time when technologies erode power demand. Shares of utility companies have been a mainstay of conservative portfolios everywhere for generations. For risk-averse investors, utility stocks have offered reliable income, price stability, and minimal risk. This could now be in peril.
In conclusion, it can be assumed that the future US power grid may look quite different from the one we know today—and utilities and regulators alike should get ready for it now. It is not hard to envision a grid that can ultimately be split into a controlled set of independently survivable islands, and then stitched back together as needed to create a balanced network of supply and demand.
This new paradigm may mean that it is time that electric utilities re-examined new technological realities and their strategic vision for the future, as their very existence may now be in the balance.
About the author:
Nicholas Abi-Samra, Head of Department, Operational Excellence at DNV GL, is experienced in power systems, planning, operations, maintenance and smart grids. He is a professional engineer and served as the General Chair and Technical Program Coordinator for the IEEE General Meeting of 2012.
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