From District Energy Magazine, Fourth Quarter, 2016
As we head into the fourth quarter of 2016, there are some pretty obvious trends at work in the U.S. energy industry. One, coal use is in rapid decline, especially at U.S. colleges and universities. Two, the era of large, remote central station power generation is also behind us, with a clear transition to more distributed generation and cleaner resources like solar and wind. Three, customers are now more attentive to factors other than simply price for power and energy, and they are increasingly alert to buying factors like location, availability, resiliency, carbon intensity and sustainability. This last trend is analogous to "buying local, buying small" or regional "farm-to-table" trends where local markets create economic multipliers by keeping the energy spend recirculating in the local economy. Informed community leaders are seeking local energy solutions. This has been the fundamental underpinning of community energy across Scandinavia for decades, but only recently has it been sprouting green shoots here in the U.S. After more than 30 years in the clean energy industry, I am finally feeling like we have reached the tipping point toward more efficient and sustainable energy systems for our cities, communities and campuses.
In August, the U.S. Energy Information Administration released a report that indicates coal use has declined by 64 percent at U.S. colleges and universities since 2008, from 2 million short tons in 2008 to 700,000 short tons in 2015. Consumption declined in each of the 57 institutions that used coal in 2008, and 20 of these institutions have totally discontinued use of coal. This trend is due to multiple factors including today's comparatively low cost of natural gas; an increase in emissions compliance requirements and related cost avoidance; and to a large extent, political influence and policy pressure from efforts like the Sierra Club Beyond Coal campaign, the American College and University Presidents Climate Commitment and escalating student engagement to reduce carbon intensity of campuses. Campuses are clearly shifting to cleaner and more efficient technologies; many are integrating CHP, contracting for renewables and investing steadily in energy efficiency measures to reduce fuel and water consumption. According to recent research by IDEA, many institutions are both evaluating and implementing blackstart and islanding capabilities to enhance their microgrid functionality for greater reliability during grid interruptions or extreme weather events.
Beyond campuses, we also see growing interest in microgrids for communities and clusters. U.S. installed microgrid capacity is expected to grow 115 percent and reach 4.3 GW over the next five years, according to GTM Research's recent report U.S. Microgrids 2016: Market Drivers, Analysis and Forecast. This is a promising forecast, but analysts add that business opportunities for microgrids remain hampered by policy and regulatory hurdles as well as private-sector financing models that fail to account for the myriad public-sector benefits that microgrids can provide. This disparity in value modeling is a principal focus of the Microgrid Resources Coalition. The MRC aims to inform, educate and advocate for regulatory reform to help reasonably monetize the benefits of microgrids, such as grid support, balancing capacity for intermittent renewables, and enhanced resiliency and locational grid functionality. The MRC is working toward opening markets for multiuser microgrids to enable investors and utilities alike to deploy these "non-wires" solutions, especially in those locations with power congestion problems or housing mission-critical or public safety operations.
If you think about it, energy-dense operations like research centers and laboratories, campuses and health care facilities often represent load clusters for both power and thermal energy, especially process cooling and heating. Locating a district energy/CHP/micro-grid nearby can solve a number of issues. First, having resilient generation closer to the load reduces risk of business interruption during extreme weather. Second, locating generation sources near thermal loads creates opportunities for more efficient district energy/CHP systems to recover and use surplus thermal energy, reducing regional emissions at the same time. Three, local generation can offset expensive capital investment in substations and traditional wires distribution, which may negatively impact rates for all consumers.
Utilities have expressed interest in owning and operating microgrids through partnering arrangements and potentially as rate base investments. Recent surveys of utility executives suggest that finally the perception of distributed energy/ microgrids has shifted from threat to business opportunity. According to GTM Research, from 2010 to 2014, about 90 percent of microgrids were owned by the end user, such as a university or manufacturing facility. That share has declined to 74 percent of the market in 2015 and is expected to be about 38 percent of the market in 2016. Utilities' market share, which was 2 percent in 2014 and 5 percent in 2015, is expected to increase to 18 percent in 2016. A larger trend is toward mixed ownership of microgrids, with large public institutions anchoring the asset from a district energy/ CHP facility and the grid point of common coupling expanding out beyond the core campus to encompass nearby buildings needing a higher level of energy reliability. The utility sector is increasingly interested in deploying microgrids as a customer retention strategy while simultaneously addressing capacity shortages from bulk power retirements and avoiding substation upgrades related to grid congestion. The microgrid can represent a win-win-win approach if the regulatory treatments can be modernized as well. The challenge remains in properly valuing and allocating the societal and operational benefits to the grid regardless of who "owns" the microgrid.
A fundamental problem is a historical regulatory structure that primarily rewards utilities for simply adding to rate base. As a result, investor-owned utilities have an incentive to invest in traditional wires and substations as the means to grow earnings, when in fact the more beneficial option might be siting local generation to anchor a microgrid for a large customer or to address a load pocket or support the development and renewal objectives of a segment of a city. This dichotomy needs research and analysis so that utilities move beyond defensive postures when district energy/CHP hits their planning radar.
There is currently a regulatory proceeding in Rhode Island (RI PUC Docket No. 4568) aiming to better determine the value of distributed energy resources. Regulators need more and better feedback on the grid value of local generation assets. Too often, utilities view district energy/CHP/microgrids as a threat, destructive to earnings as opposed to an appropriate technology solution for a large commercial, industrial or institutional customer with load density and mission-critical needs. If the regulatory paradigm were to allow utilities to invest by partnering or owning microgrids, the local economy might capture multiple benefits. Clearly, industry needs a functional model to assess the real-time operational value of distributed energy resources to more fully unlock investment. IDEA and the MRC have recently submitted a proposal to Lawrence Berkeley National Laboratory that intends to support refinement of the Distributed Energy Resources Customer Adoption Model to evaluate and price locational considerations for microgrid assets in traditional electricity distribution grids.
From my recent conversations with prominent members of the microgrid industry, it is pretty clear that the trend toward self-sufficiency among end users is picking up steam. One large company reported 70 microgrid projects currently under development. The primary market drivers seem to be end users seeking enhanced reliability and resiliency. End users are recognizing the potential exposure to costs of business interruption from the growing frequency of extreme weather events along with the reality of an aging electricity grid infrastructure. They desire greater operational flexibility and want to exert greater control over energy budgets while also integrating more renewable resources to reduce carbon emissions.
Additionally, the industry is recognizing the inherent limitations of solar when designing for enhanced resiliency, and projects of scale are incorporating district energy/CHP to enable greater functionality and efficiency in both power and thermal applications. In California, where the electricity grid is undergoing rapid decarbonization, solar plus battery storage seems to be taking hold. In less temperate climates like Minnesota with extreme summer heat and winter cold, district energy-scale thermal storage - both heating and cooling - enables instantaneous conversion of surplus power into valuable forms of usable thermal energy. Through heat pumps and electric boilers, negative-price wind power can be cost-effectively converted to useful thermal energy for use the following day rather than relying on the more expensive battery storage approach.
The overarching trend in the U.S. is clearly toward cleaner, more distributed forms of energy, even without the direct impetus of the Clean Power Plan or the 2015 Paris Agreement of COP21. We cannot relent now, while so much work remains. But it is beginning to feel inevitable that we will modernize and decarbonize our community energy systems. To steal an optimistic phrase from Martin Luther King Jr., "The arc of the moral universe is long, but it bends toward justice." For the first time in my career, I have an abiding confidence that our energy future is finally bending toward cleaner, more efficient energy solutions for our cities, communities and campuses. Let's keep up the good work.#News #PresidentQuarterlyMessage #2016 #Q4