How Now, CHP and DG?

A resurgence of interest is appearing in combined heat and power (CHP) and distributed generation (DG) options in many states, including specific interest from industry and the so-called “MUSH” markets (that is, municipalities, universities, schools and hospitals). Supportive state policies and incentives, technology support by vendors, ESCOs with low capital costs, and environmental incentives are combining to create a more conducive environment for CHP and DG projects. For example, the highly anticipated U.S. EPA rules regulating GHG emissions from existing facilities and supportive state policies will accelerate interest from and implementation by industrials, IT and MUSH market organizations.

CHP and DG projects, when coupled with intelligent energy efficiency from network and system optimization, offer substantial costs savings in industry and commercial uses. Commercial uses could dwarf potential in residential and industrial uses in some states. Smart dollars invested in O&M can finance the replacement of fans, motors, drivers, mechanical and heat needs to maximize CHP and DG efforts. Additionally, as the internet of things evolves, the electricity grid becomes more connected and more powerful with the addition of sensors and IT communications to supply sources. For example, cloud computing vs. server investment can reduce energy costs. Similarly, machine-to-machine (“M2M”) technologies that allow wired and wireless devices to communicate will drive smart manufacturing and innovative supply technologies. If done correctly, this shift will spur capital projects and investments, so long as projects produce quantifiable energy and cost savings over time, on a scale that allows financial pro formas to work and satisfy investors’ return expectations. The net result of these efforts is improved operations and analytical capability to monitor and sustain better system performance.

Common barriers to the implementation of CHP and DG projects have been:

• Social & knowledge: equipment vs. software and IT involving a lack of technical assistance and better managing the equipment and IT interface;
• Financial structuring, sources of capital & access: will come with better management, verification, data and protocols;
• Structural: utilities, public service commissions with policies and regulations that are not modernized to reflect market and technology realities;
• Traditional & outdated policies represent stale, non-consumer and non-market based thinking that stifle service and economic development;
• Capital & banking sources with risk management profiles reflect a lack of energy lending experience; and
• Cash flows that hamper internal hurdle rates of owners or fail to consider available incentives.

The best natural markets with incentives and market inducements based upon collective research and literature review include California, Massachusetts, Oregon, Utah, New York and Connecticut. States to watch as they design/improve incentives include Texas, Washington, Ohio, Michigan, Maryland, New Mexico, Minnesota: Pennsylvania, West Virginia, New Jersey and Illinois.

Current market forces, supportive regulatory and environmental policies, reliability and resilience concerns, and a wider array of fuel supply and technology improvements could represent the best market opportunity for CHP and DG in all sectors in more than 50 years. Here’s why:

1. Capacity. A coalescence of available fuels, technology and the need for capacity has never been better for MUSH markets, industrials, IT and server loads, and municipal landfill and wastewater treatment facilities. The best regions include New England, the Mid Atlantic, California and Texas.
2. Utility Business Model. The traditional business model of rate design for utilities is no longer serving its intended purpose, as customers demand better solutions, technology and services than the utility is willing or able to provide. When subject to rate design increases and regulatory attacks, continuing cost pass-throughs, riders and surcharges for declining service get expensive with diminished technology access and limited or no digitalization. The budget to support the old regulatory compact is dead as median income customers in the U.S. experience declining annual disposable income, and industrial and commercial margins are challenged.
3. New Values for Performance. Power quality, reliability, volatility in price, and service responsibility for customer care and sustainable outcomes now exceed historical electricity market priorities. Industrials seek sustainability and a reduction in or removal of price volatility while seeking reliable and economical energy. Pricing values outweigh tax incentives and net metering reliance as customers realize the best rate to be paying is avoiding the costs of their own retail rate and the volatility, insecurity, and unreliability it poses.
4. Variable Utility Market Response. The utility market response will vary based on fuel mix, individual utility priorities and recognition that the U.S. marketplace is more appropriately regarded as individual sub-markets with differences in the DOE regions. For example, because the natural gas market is volatile, seasonal in pricing, and considered a backup fuel strategy, it should be weighed as such to preserve the benefits of CHP and DG. For these and other reasons, in some regions utilities will be a friend of CHP and DG and others a foe, so that one blanket policy will not fit all and could be inappropriate.
5. Financing. Financing models need to be revisited as U.S. banks are no longer lenders in the CHP and DG energy markets. Capital structuring, sourcing and third-party financing will need to evaluate and replace leasing and project finance models because of evolving accounting standards outcomes. The real game changer might be utilities with their cost of capital advantages fostering more joint ventures to develop these projects, and increased mandates on utility billing. New sources of loans are appearing from specialty funds, pension investment funds and high net worth family funding to replace the banks.
6. Microgrids and T&D Costs. Microgrids, in conjunction with energy storage, energy efficiency and demand management co-strategies, will help accelerate CHP and DG implementation. More and more customers are seeking to avoid T&D costs—which will be rising faster than new generation costs this decade—and also avoid cost surcharges and line losses. To succeed, CHP and DG projects need to be fully integrated with load management efforts, conservation strategies and avoided water costs.
7. EPA Regulations. Regulations for new SIP implementation for GHGs for existing facilities will accelerate the shift to CHP and DG, along with other requirements for mercury, boiler MACT, ozone, water and rules. (Interested in learning more? Check out CE3’s Energy Webinars Series archives.)
8. Market Share. Based on our research and literature review, it is likely that 10 states will comprise over 60% of the U.S. market with an energy storage capacity whose share will grow to 25 states and reach to 80%. This would track the collective experience in the past with total energy, cogeneration, power marketing and renewables in the U.S. The whole country would likely not participate in the final market outcome.
9. Need for Data. Case studies, data, and validation of project performance and operational efficacy will lower CHP and DG project costs—so will insurance and more robust markets for renewable energy credits (RECs) and emissions credits to offset project costs. Third-party financing sources and owners must share their case histories and provide operating data for insurance, financing, resilience, cyber security and weather performance values to be measured, verified and scored.
10. Big Data Benefits. Big data and energy analytics will accelerate the desirability of CHP and DG alternatives to the customer, vendor, insurer, and technology solutions developer. Data also establishes the benefits of avoiding energy shifts to time-of-day pricing for each hourly or daily energy transaction, i.e. transactive energy with attendant volatility and lack of stability for planning.

Herein lies the best market opportunity in the U.S. in the past 50 years: Through the implementation of the above strategies, market volatility and uncertainty can be reduced or removed. The role of the traditional utility service can evolve to add value via the next-gen, market-ready solutions of CHP and DG, initiatives that differentiate price from value in a complex and changing market. Only then and through CHP and DG can we harmonize the dilemma of using 19^th century fuels in a 20^th century electric power infrastructure to support the sophisticated demands of a more modern utility service in the 21^st century.

For more information about the state of CHP, check out our Energy Webinar from November 5, 2013, archived here: http://www.ohio.edu/ce3/resources/webinars.cfm.

CE3 Blog by Michael J. Zimmer, Executive in Residence & Senior Fellow, Ohio University; Edited by Elissa E. Welch, Project Manager, CE3

 

Microgrids: An Integrated 21st-Century Solution

In 2012, Pike Research estimated that the global microgrid market would grow to US $17.3 billion by 2017. An impressive figure for certain. Even more impressive is the updated estimate released in early November by Navigant Research: by 2020, revenue from deployments of microgrids will be more than US $40 billion. They attribute this upward estimate in part to a recognition that the projects (new and retrofits) require a greater level of investment than previously thought.

North America continues to be a hotbed for microgrid development. The Navigant report finds that North America has a total planned, proposed and deployed microgrid capacity of 2.7 megawatts, a little more than half of which is currently online. This figure represents 65% of microgrid capacity worldwide. Commercial and industrial applications, currently estimated at 30 across the U.S., could climb to 300 in the next two years as the high-profile likes of Oracle Corp., EBay, University of California at San Diego, Lockheed Martin Corp., the U.S. Department of Defense and others champion their use. Green Energy Corp., a U.S. builder of commercial-scale microgrids, estimates that 24,000 U.S. commercial and industrial sites could be developed with large-scale microgrid conversions. And that doesn’t even include the other types of microgrids such as institutional/campus, community/utility, military and remote applications. For example, New York City and other East Coast communities are quickly reviewing microgrids to increase grid resiliency against extreme weather events. As we see time and time again, having power in times of crisis is invaluable for emergency response, healthcare facilities and rapid recovery.

So then, just how do we go from 300 to 24,000? Or even more?

First, let’s review the basics. A “microgrid” is defined as an integrated energy system of distributed energy resources and multiple electrical loads operating a signaled, autonomous grid – either in parallel to or islanded from the existing utility power grid. The types of technologies that can be integrated into a microgrid system are even more numerous than the applications themselves: distributed generation (DG), renewable energy and storage, energy infrastructure, demand-side management (DSM), and other energy-efficiency strategies. This bodes well for manufacturers of these applied technologies at home and abroad, such as Siemens, General Electric, ABB and more.

With increasing customer-owned distributed energy resource loads, it is essential to consider how these new resources will operate within the current wholesale market. Certainly, the entire notion of microgrids challenges the traditional business model of utility-based infrastructure and the system in use today. But considering that power outages cost business and government an estimated US $104 to $164 billion annually, there is ample reason for change. Other reasons are more application specific: the military seeks more reliability in the electric grid to circumvent vulnerabilities in their missions. Threats of cyber-attacks on critical infrastructure are partially driving the U.S. military interest. Disturbances in electric supply also impact industry and commerce causing significant losses of information, efficiency and productivity. If the trend for microgrid deployment continues, utilities will have to adapt to a new model of generation, transmission and distribution, and be open to the benefits that can result. Kevin Sullivan, business director at DNV KEMA, finds the following benefits for microgrid deployment:

• Improves energy reliability and security of supply especially critical in healthcare and military operations
• Net excess energy revenues and efficiencies (in the near future) will support funding of new grid investments
• Ability to self-optimize assets with full self-control of energy operations where the microgrid operator has both supply and demand control and responsibility
• Defers infrastructure investments to better match a visible and controllable load profile making peak load choices and longer-term investments more accurate
• Enables emissions reductions that support sustainability targets when renewable energy assets are deployed and balanced
• Supports a net zero strategy and the Microgrid Optimization Model
• Increases reliability and back-up capability when storage options are deployed  
• Allows management of generation variability with renewable energy sources

But 24,000? Rethinking the policies and promoting a supportive market environment are still necessary.

The Policies
Understanding how and when microgrids draw from and sell back to the grid is essential to the evolving energy paradigm in the U.S. Policies that tackle interconnection, pricing, net metering and standby rates will help microgrids to succeed in integrating into the existing business model and move it forward. Public policy leadership for successful grid modernization must provide:

1. External funding from both public and private sources to promote realistic and cost-effective solutions, starting with pilot projects as necessary.
2. Utility rate design that takes into account avoided costs for generation, transmission and distribution which are avoided by the microgrid and DG choice. The rate subsidies now in place subsidize the utility, and not the customer, through net metering.
3. Tougher air conditioning, TV and appliance standards to ease summer peak challenges, and state-based policies that promote on-site power technologies and storage, increased energy-efficiency standards, cost-effective renewable resources, merchant transmission and enhanced building codes.
4. Updated standby/back-up power rates that consider alternative rate designs without gouging customers.
5. Amended franchise laws and “public utility” definitions that exempt DG and microgrids.
6. Assurance that microgrids qualify for incentives in grant, tax code and public policy systems along with traditional generation, fuels and T&D to receive equal rewards and avoided cost recognition.
7. Updated infrastructure considerations for utilizing public rights of way for grid connections.
8. Ending state regulation as a “public utility” which is no longer necessary for steam, cooling and hot water sales from a microgrid or DG project.
9. Ways to promote and leverage microgrid development partnerships between utilities, financiers, vendors, IT and telecom companies.
10. Model rules and standards for shared energy and community development programs in rural and/or underdeveloped areas where density and customers offer a different scale and value proposition.

The Market Environment
Understanding the detailed economics of developing and operating a microgrid is critical for its success—all aspects must be considered. Different sizes, classes and locations of microgrid development targets will respond to different price signals—diversity in a microgrid portfolio optimizes its potential to effectively price products and offer services to its customers. Sophisticated tools can assess the economic, operational and emissions impacts of particular microgrid developments across various investment and deployment scenarios for the end-user’s benefit. For more on this topic, check out this IEEE report. Wholesale and retail electricity markets will need to adapt and harness the opportunities that microgrids represent for improved reliability, power quality, less price volatility, better control and smarter forecasts.

A thorough review and understanding of these issues by policymakers and project developers will help position microgrids as the “missing link” in leveraging energy security, state-based renewable portfolio standards and energy efficiency standards (such as Ohio’s Senate Bill 221 and those across the U.S.)—and could pave the way for the creation of a modernized, integrated North American grid based on electric stability, reliability, resiliency and security. For now at least, the piecemeal approach is gaining traction that cannot be ignored.

By Michael J. Zimmer, Executive in Residence, Energy and the Environment with Elissa E. Welch, Project Manager, CE3