Energy Storage Outlook for Ohio


New research coming out of the University of Minnesota’s Energy Transition Lab indicates that standalone energy storage can now compete with and potentially displace new gas combustion turbines installed to meet peak demand—and be cost-effective after 2022.[1] Competitive forces and declining costs confirm this outcome in research conducted by consulting firm GTM Research/Wood Mackenzie. The analysis conducted by the Energy Transition Lab on the Minnesota power sector is predicated on calculations that require consideration of the environmental benefits associated with energy storage. In a comparison of energy storage and solar energy mix against a simple-cycle, natural gas peaking plant, researchers found that both the economic and environmental benefits prevail with energy storage because of factors such as the federal investment tax credit and the reductions in air pollutants (e.g., NOX, SOX, and greenhouse gas emissions). The report also indicates the need for updating modeling tools used by utilities and regulators for resource planning. Innovative cost-recovery mechanisms for new energy storage investments should be considered as well as supporting private investments in the future. We have seen this recently with stacking revenues adopted in California as an incentive to recognize both the supply and benefits of storage, thereby offering multiple revenue streams. If weighed in Ohio, this would build on the automotive, fuel cell and battery storage sectors already active in the state for stationary and mobile sources.

In many instances, Independent System Operator (ISO) and Regional Transmission Organization (RTO) rules for storage integration have been under scrutiny because the grid operators’ current structure limits many energy storage resources from participating in wholesale power markets. Over the next ten years, the U.S. requires more than 20,000 MW of additional peaking capacity to be added to the grid according to GTM Research/Wood Mackenzie. Almost 13,000 MW alone of storage is anticipated to come online in 2023-2027. Grid barriers and limitations were a critical finding of the recent notice of proposed rulemaking on energy storage and distributed energy resources by the Federal Energy Regulatory Commission in late 2016 (Docket Nos. RM 16-23; AD-16-20-000; The lack of appropriate terms and conditions that foster the cost savings and benefits of energy storage is a national problem which the rulemaking seeks to address. Moreover, ISOs and RTOs must consider energy storage as a capacity and grid resource and include energy storage in increasing market roles. The benefits of such inclusion are increased customer service through delivery stability, improved integration of distributed and renewable energy resources, ongoing cost reductions for the customer, and long-term and strategic performance enhancements that benefit all parties and stakeholders on the grid. FERC is expected to finalize these rules in 2018.

As these findings relate to the State of Ohio, significant value and economic outcomes may exist here for energy storage. This is fostered by an increase in forecasted renewables above 2.2% of the state’s electric supply and increased needs for new electric capacity from plant life retirements of older nuclear and coal-fired plants rendered uneconomical by increased natural gas supplies from the Utica Shale. The findings also support the desirability of incentives and rate design to increase the market penetration of energy storage in Ohio. Growing opportunities for energy storage has the added benefits of bolstering renewable energy integration into the fuel profile and modernizing the transmission and distribution (T&D) grid statewide: both goals of the PowerForward initiative led by the Public Utilities Commission of Ohio (PUCO).

Therefore, greater development of energy storage in Ohio will require thoughtful leadership by the ISOs and RTOs working with the PUCO through this visioning process. Related factors to monitor in Ohio by PUCO, the utilities, and affected stakeholders include:

  • Load differentials which may exist between on peak and off-peak wholesale energy prices
  • Lack of strong and enforceable federal state and local policies to address greenhouse gas emissions for the future
  • Declining wholesale capacity prices and uncertainties regarding the ability of utilities to claim capacity credits for energy storage investments in resources
  • Frequency of fossil generation on the margin which diminishes the environmental benefits of grid-supported storage in the future
  • Low prices and small-market sizes for ancillary services (i.e., frequency regulation) at this time
  • Lack of retail rate options and incentives to support smart deployment of energy storage technologies in Ohio
  • Different capital cost structures for traditional capacity resources versus energy storage, with different performance guarantees and operating protocols
  • Increased desirability of promoting more effective integration of distributed and renewable energy resources

Ohio hosts a need for increased customer services and also many companies that are part of the supply chain for the national energy storage sector in the future. However, most of the manufacturing capacity for energy storage is occurring west of the Mississippi. Appropriate and effective incentives in Ohio would promote the long-term development of an energy storage manufacturing sector and supply chain hub in-state. The PowerForward proceedings are an important platform for consideration of these vital opportunities supporting industry leadership on storage. The next PowerForward sessions are scheduled for March 2018, and we continue to look forward to advising critical stakeholders on these opportunities for Ohio ahead. See for additional information.

Blog by Michael J. Zimmer, Executive in Residence and Senior Fellow, Ohio University Voinovich School of Leadership and Public Affairs & Russ College of Engineering and Technology. Edited by Elissa Welch, Project Manager, Ohio University Voinovich School. March 2018.

[1] “Modernizing Minnesota’s Grid: An Economic Analysis of Energy Storage Opportunities.” University of Minnesota’s Energy Transition Lab. 2017.


Community Solar in Ohio


Community solar refers to solar energy projects with multiple owners, often living in geographic proximity to a project, who share the costs and benefits of investment in this shared resource. Often referred to as ‘shared solar gardens,’ community solar has been an emerging energy development across the U.S. in recent years, stimulated in part by an increasing number of states passing community or virtual net metering policies. This shared approach overcomes the significant barriers to physically owning a solar photovoltaic (PV) generating system such as site shading, roof orientation, zoning laws, roof/system size, lack of property ownership, etc. Beyond the high up-front costs to finance a solar PV system, such barriers are central impediments to more widespread PV deployment. Since 2013, 10 states have adopted community solar enabling legislation, half of which were passed in 2015 alone. Colorado has been a national leader in community solar, while the District of Columbia (2013) and Maryland (2015) have received praise for their more newly-implemented programs from the Interstate Renewable Energy Council’s Shared Renewables Scorecard. Nevertheless, Ohio is not yet one of the states to implement formal community solar enabling policies.

The community solar issue has stimulated numerous debates both across the country and in Ohio. Electric utilities, especially for-profit, investor-owned utilities (IOUs), have been at the forefront of these debates, noting decreased company revenues due to the increase of disparate, privately-owned energy generators feeding into their grid. They have also cited the difficulty for the grid to accommodate such non-dispatchable resources since community solar is usually deployed on the distribution grid rather than as a central power source (i.e., grid operators cannot reliably control its quantity and timing).

However, with a range of models, and increased accessibility and affordability, supporters argue that community solar is actually more economically efficient than traditional rooftop solar PV. They claim that aggregating consumers on larger projects to achieve economies of scale should also appeal to utilities, as community solar projects can be sited near substations or distribution feeders and reduce interconnection challenges.

The State of Ohio has been unsuccessful in passing formal community/virtual net metering laws or similar enabling legislation to incent the development of community solar through special purpose entities (a model in which individuals develop/join a business enterprise, and assume the associated legal and financial responsibilities to develop a shared solar project). However, some utility-based community solar programs have emerged, such as the 100 kilowatt OurSolar project in Delaware, Ohio. In essence, utility-sponsored community solar programs refer to when an electric utility owns and operates a project that is open to voluntary ratepayer participation. Some electric cooperatives, such as Consolidated Electric Cooperative for the OurSolar project, have been proactive to implement community solar programs for their ratepayers. However, Ohio’s IOUs, despite various announcements and commitments to deploy more solar and other renewables as part of their future generation portfolios, have largely ignored community solar as a market option. Instead, they have chosen large-scale solar PV projects as a fuel price hedge in their generation portfolios.

Localities or local/regional programs can also implement financial incentives and other solar PV deployment strategies, such as municipal property tax exemptions or abatements for residents or businesses who invest in solar energy. Independent of formal federal or state policies to encourage community solar, some localities and local/regional nonprofits have been promoting the expansion of community solar in Ohio. For instance, Ohio Solar United Neighborhoods (OH SUN) has developed several cooperative programs throughout the state, including ones in Appalachian Ohio (Athens area), Cuyahoga County, Dayton, Delaware County, Huntington area, Lorain County, the Mid-Ohio Valley, and Worthington. Even though these co-ops are not developing off-site shared arrays or gardens, they still meet community solar’s broadest definition by offering collective economies of scale in installation costs and the bulk purchasing of materials. These programs have helped accelerate solar PV growth in Ohio, particularly by overcoming market barriers such as high up-front costs and overall complexity of solar purchasing decisions.

UpGrade Ohio, a nonprofit in the Appalachian region, was recently awarded funding through the U.S. Department of Energy’s Solar in Your Community Challenge to initiate community solar in their region. Coined ‘Solar ACCESS,’ this project will employ a unique solar finance model that allows off-site investors to purchase shares in community solar arrays in the region. The first array, slated to be 704 kilowatts, will be cited on the Federal Hocking Secondary School in Stewart, Ohio. Though no formal state policy guides this process, the Solar ACCESS project still meets the common definitional requirements of community solar by providing power and financial benefits to multiple community members, allowing folks to participate in the solar energy economy without having to install a system on their own property.

It is through these types of local programs that Ohio can gain momentum in the development of community solar. The most far-reaching definitional bounds encompass models such as community group purchasing, on-site shared solar (e.g., PV on a multi-unit building), or community-driven financial models (e.g., ‘Solarize’ programs or solar co-ops). However, off-site community solar, such as through UpGrade Ohio’s new program, perhaps offers the largest benefit by opening market access to nearly anyone, typically within an electric utility’s service territory. These types of programs achieve two key factors that most analysts argue define ‘true’ community solar: 1) for solar PV projects to include community members and positively impact local economies; and 2) for solar PV projects to aid in the transition toward community energy independence.

Ohio’s community solar market may also develop through utility-based models such as the OurSolar project. The state specifically has electric utilities that may be willing to explore and implement such programs, such as AEP Ohio and several of its rural electric cooperatives. In fact, a large percentage of the community solar projects across the U.S. are run by electric cooperatives or municipal electric utilities. Seemingly, these types of utilities will play a major role in the expansion of community solar in the immediate future, especially considering how cooperatives have access to supplemental fundraising and are unique in how they retain economic benefits for their member-owners. Moreover, because cooperatives mostly service rural areas, their land resources are ideal for large solar PV installations.

Community solar run by IOUs may be a path forward for Ohio, but this model still faces several uncertainties in Public Utilities Commission of Ohio (PUCO) and legislative discussions. These IOUs will be able to leverage benefits even further once grid modernization (i.e., PUCO’s PowerForward initiative) fosters better systems and an increased awareness of the benefits of distributed generation.

Formal enabling legislation such as community net metering may never pass in Ohio without a sizeable shift in the energy policy landscape, but grassroots leadership via small cooperative and local programs may stimulate a new community solar narrative for the state. In the interim, state stakeholder groups should be formed to study community solar strategies for Ohio, including utility billing arrangement options, facility size caps, how to include low-income populations, consumer protections, and a suite of other related issues.

CE3 Blog by Dr. Gilbert Michaud, Adjunct Assistant Professor & Cluster Analyst, Ohio University Voinovich School of Leadership and Public Affairs. Edited by Elissa E. Welch, CE3 Project Manager, Ohio University. August 2017.

Microgrid Financing Options to Facilitate Future Growth


Michael J. Zimmer, executive in residence and senior fellow at Ohio University, was recently an invited speaker at The 4th Microgrid Global Innovation Forum held May 16-17, 2017 at George Washington University in Washington, D.C. Mr. Zimmer addressed issues and innovations on evolving microgrid financing options primarily in the U.S. With other experts on his panel, “Evolving Microgrid Financing Options,” he contributed to the deeper understanding of structures to secure microgrid financing and the changing infrastructure and policies affecting microgrids. Mr. Zimmer also serves as Washington Counsel for the Microgrid Institute since its founding in 2012, and advises its newly-created Microgrid Finance Group formed in 2016. Mr. Zimmer has guest lectured on microgrids in various classes at Ohio University, in local meetings sponsored by Upgrade Ohio, and in various national fora. In the following blog, Mr. Zimmer draws from and builds upon his recent forum remarks last month.

Microgrids represent one of the fastest-growing technologies in the electric utility industry today offering multiple benefits to the state, the utilities and the customers they serve. North America hosts the largest deployment of microgrids, closely followed by Asia and Europe. The key growth driver for the future will be in the commercial and industrial arenas that will grow to represent 30% of global markets. Commercial and industrial projects are primarily driven by cost and economic benefits of solar, combined heat power, energy storage and their interface especially for hospitals, data centers, military, universities, schools and healthcare facilities. Ohio has just started to examine these questions as part of it grid modernization proceedings launched in April 2017 by the Public Utilities Commission of Ohio (PUCO).

Noting that soft costs are 50% of the development costs for microgrids, there is an increasing quest to standardize the microgrid as service model including use of more sophisticated control systems, DC power flows, better storage technologies, and closer integration with advanced metering. For many decades, the transmission and distribution (T&D) sectors were solely served by the electric utilities. Now the question is arising as to who will modernize the T&D sectors in the future? Many  stakeholders, including energy service companies, equipment vendors, the five major technology and information management companies, foreign vendors and international utilities, startups, entrepreneurial companies and telecom companies, along with the electric utilities, are seeking to serve this $400 billion per year electricity sales and services market in the U.S. Electric power is one of the most capital intensive sectors in the national  economy today scheduled to spend up to $2 trillion by 2030 to modernize the aging U.S. electric system.

The microgrid derives its value from its interwoven complexity. This is exactly what makes quantifying its value so difficult and also makes the issues of capital access and financing more challenging. Government funding typically covers only a portion of the microgrid’s costs. For the remainder, microgrids tend to rely on variations of financing models that originated in other related industries. These include such tools as direct ownership, utility rate base treatment, vendor financing, energy service contracts, power purchase agreements, leasing, debt and bond financing, green and infrastructure banks and other clean tech energy model and tools in the state marketplace. As microgrids move from the pilot or demonstration phase to fuller commercial deployment, the quest arises for more financial models and disciplined structures to support financing ahead. Right now in the United States, that there are five major viable financing models:

  1. Special microgrid investment funds;
  2. Vendor financing;
  3. Energy service companies;
  4. Utility financing (in rate base or through unregulated special entities); and,
  5. Warehouse financing.

The best way to analyze microgrid financing is from the vantage point of risk management strategies. Key areas of opportunity to differentiate and create success for microgrid project financing include:

  • A capacity maintenance agreement with regular service for the project;
  • A minimum amount of capacity guaranteed from the microgrid system to ensure a minimum bill or baseline to support project financing;
  • A solid warranty from an investment-grade vendor ideally for 1-3 years;
  • An insurance policy covering certain extraordinary costs, performance and/or the efficacy of the system designed for the microgrid;
  • A battery disposal strategy of e-wastes associated with decommissioning batteries from the project as energy storage increasingly is part of a project; and,
  • Aggregation to create scale, diversify risk and support a more attractive regulatory outcome to diminish regulatory risks for the project.

Diving deeper into warehouse financing and performance—a form of integrated development finance for portfolios of sound, developed microgrid projects—is important for flexible financing at commercially-reasonable terms and interest rates to support project development and success. Warehouse financing should be coupled with smart incentives such as clean funding mechanisms (in the 21 states that offer that special funding), green banks or under the Smart Cities movement in the United States. Finally, technical assistance with small grants for technical services and predevelopment costs are desirable to support the warehouse financing strategy.

Warehouse financing builds a project pipeline that can access the capital markets more efficiently through securitization. Short-term development and aggregation of loans occurs that facilitate secondary market participation and lower the capital costs for projects. This financing could also be coupled with credit enhancement techniques to reduce risks and round out the capital stack for a microgrid project coming from foundation program-related investments (PRI’s), donor management funds or clean technology funds at the state level. These credit enhancements could take the form of guarantees, subordinated debt, loan loss and debt service reserves, or interest rate buy downs to diminish risks and attract private capital and lending.

Warehouse financing is already being used in the U.S. for energy efficiency, PACE loans, solar project development and also recently energy storage loans. Such loans often range from 10-20 years and carry interest rates of 5-6%, plus closing costs. The state repackages smaller loans to reach a certain value of closed loans at certain aggregated levels to create scale. These packaged loans are then securitized through the secondary capital markets and the loans are leveraged with ratios ranging from 4-8 times the original values reported by various sources in Connecticut and New York. Pennsylvania also participates in its energy financing strategy in a multistate warehouse for energy efficiency loans called “Warehouse for Energy Efficiency Loans,” or “WHEEL.” This program is administered by AFC First Financial and is used by states seeking access for clean energy lending and financing. WHEEL works through the National Association of State Energy Officials (NASEO), the Pennsylvania Treasury, Renewable Funding, and Citigroup Global Markets, to package these smaller loans that are sold to bond investors. Proceeds from sales after aggregated and bonds are issued, go to recapitalize original state funds. Strict lending criteria are followed and high minimum credit scores are sought for risk management. Contractors are trained in intake and origination to ensure quality control over such programs.

For microgrids to succeed in their financing goals, their financing strategies must be built from known successes, existing capital market frameworks and often states with Green Bank or Resiliency lending programs. Success in financing balances:

  • Leveraging existing contractor networks;
  • Consulting with the financial community for project development;
  • Identifying sustainable funding sources with long-term viability; and,
  • Engaging utility partners, ensuring knowledge of available rebates and including on-bill financing mechanisms with state utilities.

When thoughtfully conducted, less taxpayer or ratepayer dollars are utilized and these programs facilitate use of public-private partnerships—“P3” structures and mechanisms in the 36 states with P3 framework legislation.

Financing support must be demanded by vendors, project developers and microgrid leaders. The industry itself will not just happen as a matter of state policy or through utilities without a market-based demand from its customer base.

Related research from a National Institute of Building Sciences (NIBS) task force augments this discussion by looking at resiliency-based mortgage financing for residential and commercial/industrial applications. Resiliency suffers from a lack of commonly-defined terms, similar to the lack of standardization in defining a microgrid, and even P3s. For a microgrid project financed with resiliency considerations in the cash flow and income aspects, determinations will still need to be made about the quantity, additionality and nature of ancillary benefits from the project. These must be guided by the industry and will be based also upon state public service commission determinations. To secure resiliency benefits and additional cash flow, the microgrid must offer:

  • A determination of hazard/risk expressed in probabilistic terms over underwriting scenarios over one or more time periods;
  • Resilience offered by the microgrid, measured against a potential disaster event based on the level of risk and potential added improvement in resilience associated with the microgrid investment;
  • Evaluation of the dollar amount of losses avoided based on the micorgrid project’s resilience to a calculated hazard risk should be developed by the sponsor over the life of the loan and also on an annualized basis;
  • Value and/or net operating income should be reevaluated based on avoided losses created by enhanced resilience from the microgrid; and,
  • Negotiation of loan terms to reflect additional value from building the microgrid and the income streams associated with the project. The lead in both isolation of those streams and calculation methodology should come from the developers and the industry itself working closely with its vendors. Additional revenue streams would facilitate consideration of larger project loans, the inclusion of development phase, down payment reductions for private lenders or interest rate reductions in return.

Despite differences across international and domestic U.S. markets, access to market-based financing will facilitate the rapid growth of the microgrid industry in the coming decade. Some in the electric industry see microgrids as the next market iteration of solar, which has grown 800% in the period from 2010-2015. Solar expanded another 119% in 2016 alone. Financing is the primary growth factor and will serve as an essential catalyst for future growth of microgrids with energy storage.

CE3 Blog by Michael J. Zimmer, Executive in Residence and Senior Fellow, Ohio University Voinovich School of Leadership and Public Affairs & Russ College of Engineering and Technology. Edited by Elissa Welch, CE3 Project Manager, Ohio University. June 2017.


Key Policy Objectives for a Smarter Grid in Ohio


Today’s electricity markets were developed in the preceding decades using prices set by the marginal cost of generation. These markets are not determined by physical laws, but by human constructs and economic principles. As such, we need to question established orthodoxies and design more effective market alternatives by embracing the proactive, innovative nature of programs like the Public Utilities Commission of Ohio’s (PUCO) PowerForward initiative. Market principles have a continuing role to play in these alternative regimes through large-scale procurement of competitive output from renewable energy plants, as well as through energy efficiency, demand-side management, and energy storage. The PJM Interconnection, Ohio’s regional transmission organization, has shown national leadership in this direction, but we need to ensure proper and accurate price signals—that provide the ability to finance and access capital—are part of the alternative delivery package.

A new market model is needed because the current system is flawed. Our current system does not guarantee sufficient price signals to maintain the high availability and capacity required for reliable electric service that we historically have been provided in PJM. It also does not achieve the deep levels of decarbonization required to sustain existing operations, nor maintain competitive market positions in public health, safety and welfare in Ohio. The default position has been the utility rate base choice, but that must change for the state to compete, attract business and foreign investment, maintain its talent base, and participate in the industries of the future.

New market frameworks are central to support projected customer demands and changes from advances in manufacturing, internet technologies, transportation, sales, etc. New markets with stronger and more accurate carbon price signals will incentivize clean energy investment rather than continuing subsidies that promote polluting historical fuels and dated equipment. New market models will also require spending to enhance and digitalize electricity networks to manage localized, multidirectional power flows and ensure resilient, reliable and stable electricity supplies. Electric utilities have generally ignored this opportunity for over a decade. Thus, transmission and distribution (T&D) modernization in Ohio will require increased investment by third parties, better capital access, and joint ventures and alliances with electric utilities to complete the necessary market reforms. While some utilities are selectively adapting operations, regulators must also increase the pace of modernization and provide more room for pilots and demonstration projects that foster third-party innovation.

Escalating shadow costs such as the cost of coal externalities, nuclear plant decommissioning, water and other public health impacts, are not calculated for continued fossil fuel use.  Other shadow costs that remain unaddressed in Ohio’s policy discussions include renewables intensity, coal health impacts (air emissions and waste toxics), methane releases, energy-water uses, and nuclear O&M and decommissioning expenses. Moreover, costs of providing system backup power storage are not reflected in the wind and solar levelized cost of energy or in their ultimate market price. There is no free ride ahead and not accounting for shadow costs does the system and the consumer a disservice.

Energy policies are increasingly geared towards expanding renewable energy as an end in itself. Yet the research literature indicates a low-carbon grid with a manageable level of costs will require the blending of nuclear, natural gas with carbon capture, combined heat and power (CHP), or other zero-carbon on-demand sources integrated with more energy storage. Redesigning markets solely to facilitate a very large uptake of renewable energy for its own sake will increasingly become economically challenging and requires more balance to succeed. These efforts could be strengthened by coupling them with goals in carbon reduction, resiliency, system modernization and maintenance of reliability. A stronger system benefits the state’s citizenry and the customers served by its utilities.

The term “smart grid” itself refers to a range of electric grid modernization efforts over the past several years. End-users and vendors seem to focus strongly on issues related to customer choice while electric utilities highlight increased reliability and resilience based upon new transmission investments. The development of a smart grid was established as a national energy policy more than a decade ago by the U.S. Congress in Title XIII of the Energy Independence and Security Act of 2007. State smart grid initiatives must utilize this federal framework that establishes several key criteria:

Increased use of digital information and control technology

  • Dynamic optimization of grid operations and resources with “cyber security”
  • Deployment and integration of distributed generation, including renewables
  • Demand response, demand-side resources, and energy efficiency deployment
  • Deployment of smarter technologies for metering, communications and distribution automation based on two-way interactions through technologies
  • Integration of smart appliances with consumer devices
  • Use and integration of advanced electricity storage, peak shaving technologies including plug-in electric hybrid vehicles and thermal storage air-conditioning
  • Timely information and control options to consumers
  • Standards for communication, interoperability of appliances and equipment connected to the electricity grid, and
  • Identification and reduction of unreasonable and unnecessary barriers to the adoption of smart grid technologies, practices and services.

The federal mandate to the states is clear, but has often been ignored over the past decade. Clearly, Congress has demanded an electric grid future that is more resilient, secure, efficient and reliable to foster new and desirable services through technologies. The corresponding state guidance should focus on removing barriers and impediments to fully achieve these Congressional goals. Any contrary state actions, or inactions, may risk preemption under existing law. Subsequent guidance on standardization has been developed from Engineering Laboratory at the Department of Commerce’s National Institute of Standards and Technology (NIST). NIST seeks a solid framework and roadmap for smart grid interoperability standards and additional R&D support. The Federal Energy Regulatory Commission (FERC) has also provided guidance on such issues as interconnection policies, integration of renewables, demand-side management and energy storage. States ignoring this clear-cut guidance to date operate at continuing peril and are not necessarily regulating in the public interest consistent with existing federal law.

The State of New York has attempted to offer leadership by allowing utilities to earn returns for their shareholders by advancing clean energy solutions rather than only by investing increased capital in the expansion of the greatest T&D capacity. This renders the utility more neutral and a more competitive and balanced player in the marketplace to improve the energy and financial efficiency of the state energy grid. By using more transparent price signals in retail energy markets, utilities will be able to deploy more renewable generation, demand-side management and energy-efficiency projects where they can address grid congestion in high-use areas. All users will benefit as the utility shifts to providing customers with the electric services and characteristics they seek to achieve instead of superimposing what regulators and utilities think they should want. The ratepayers will no longer be merely price takers, but increasingly drive the markets and quality of service through customer choice. Similar regulatory programs are being pursued in Hawaii, California, Massachusetts, Maryland, Texas and Connecticut. New reviews are being launched in Colorado and Illinois.

Ohio also needs an increased focus on measures to prevent blackouts, clear rules on cyber security and improved smart power grids. The role of providers and innovation is indispensable for enabling active consumers and providing them with a new slate of high technology options and increased levels of customer service. This will open up the market to move beyond the inherent limitations of a utility monopoly and the regulatory protections of those monopoly franchises set for markets in the 1930s. Already, generation has been deregulated, stranded costs have been paid, and non-bypassable charges should be deemed anticompetitive. Similar deregulated results have been achieved for independent third-party services by unregulated entities, distribution is increasingly facing deregulation because of the advent of technology choice, and the only vestige of continual need for monopoly services appears at the transmission level within the state.

In conclusion, this market transformation will be alleged to foster a death spiral and reduce profitability. However, such scare tactics are often advanced as a foil to maintain the status quo. Increased choices, diversification and fuel supply focused on the long-term goals of decarbonization offer an opportunity for new business services based on energy solutions: energy storage, electric vehicles and service, energy customer services, steam capture and waste heat service, demand-side management, on-bill cost recovery, new loan financing, water services, enhanced broadband,  and more centralized energy management of customer services, equipment and energy controls. Rural solutions will require flexibility to accommodate differences and scale from their urban counterparts.

With such a transformation, communities will be empowered to more closely manage their energy needs, provide better customer service for their citizens, and move to more benign energy choices. Demonstrative pilot program can show the opportunities of the future for enhanced quality of life.  Consumption and profits will rise based upon better suites of service choices and smarter operations in an increasingly digitalized world. Energy can become the tool driving urban and rural economic development for all customers.

The competitive future of Ohio, its manufacturing base in the clean tech industry, robust supply chain, retention of its STEM student talents, and human resource attraction hang in the balance for better future energy jobs. A 19th-century fuel orientation will not satisfy the market requirements of the 21st century. Only a smarter grid which fosters the new industry sectors for product design and energy solutions grounded in sustainability will secure our competitive advantage in energy.

CE3 Blog by Michael J. Zimmer, Executive in Residence, Ohio University Voinovich School of Leadership and Public Affairs & Russ College of Engineering and Technology. Edited by Elissa Welch, CE3 Project Manager, Ohio University. May 2017.

The Future of Energy Policy in 2017


The economics worldview grounded in supply and demand for shale development is tempered by the salient question: Can we keep the current global financial system operating as we reach limits that are economic, geopolitical and price-driven in nature? This is a central question that the Trump Administration will face come January 20, 2017.

Also on the table:

  • Can the price of oil and other commodities be kept high enough?
  • Can the price of renewables provided by solar and wind trend low enough to replace or supplement the fossil fuel status quo?
  • Can we still keep the return on investment high enough to attract capital?
  • Can workers earn adequate wages to support higher energy prices and still buy necessary goods?
  • Will rising interest rates constrain debt access?
  • How will increasing inflation impact purchasing power and reconstruction of economic demand?

Often critical linkages are missed. Unless markets and companies remove barriers and offer near-term substitutes that replace energy products that are cheaper than currently available—without requiring a huge transition in machinery or infrastructure—the country is at risk for deep financial problems. Unbridled markets without socioeconomic balance or conscious and sustainable capitalism creatively destroy jobs via such innovations, increase debt burdens, and stretch the consumer’s ability to pay. This may also be part of the U.S. economic inequality and productivity decline in the past decade.

Global affluence seems to slow growth in OECD countries. Demographics and regulation fuel a lack of productivity (and increase costs) as more complexity with costs are shifted to the citizenry. Workers have less time to be productive in their jobs as shown since 2000. Monopoly and oligarchy concentrations in many U.S. industries foster suboptimal outcomes and inefficient rent transfers. These are reflected in predatory consumer pricing and price responses that exacerbate inflation and stranglehold economic principles.

Affluence can only be maintained with cheap energy—and it will likely not be from oil due to escalating production costs. And it will likely not be from coal because of environmental costs and other externalities. Nuclear is vulnerable to cost overruns of monumental risk and cost exposure. But time has shown that a strategy of cheap energy is short lived, and not based on values that endure.

Energy affluence can only be achieved with permanent value by efficiency, waste heat recovery, combined heat and power, demand-side management, building design efficiency, and/or increased supply diversity with renewables coexisting with nuclear. The role of natural gas will be to shape demand with an immediate supply of fuel for electricity. Government policy in the long-term is better served to cover the initial cost hurdles to facilitate the required energy transition.

Technology including energy storage, materials science, electrochemistry and IT solutions will optimize the end game and make a difference.

New business models and access to capital will be required to support this transition. This can only occur with regulatory reform and modernization that fuels market access to innovation and creative solutions that advance markets beyond the limits of the entrenched status quo.

The business opportunity is too great to not foster an all-of-the-above portfolio energy strategy that promotes innovation, technology, efficiency, and the value-added information delivered by it. These energy products and services have national value and export value that are not limited to the fuels themselves.

Otherwise, we will be stuck with 19th-century fuels, used in 20th-century infrastructure, wondering why we cannot compete and meet the escalating global challenges of the 21st century.

CE3 Blog by Michael J. Zimmer, Executive in Residence, Ohio University Russ College of Engineering and Voinovich School of Leadership and Public Affairs. Edited by Elissa E. Welch, CE3 Project Manager, Ohio University. January 2017.

The Clean Power Plan’s Legal Path



The Clean Power Plan (CPP) issued by the U.S. EPA in August 2015 represents a hallmark in regulatory and judicial actions.  However, on February 9, 2016, the U.S. Supreme Court stayed implementation of the CPP by a 5-4 vote pending judicial review at the lower court level.  This decision in no way reflects a decision on EPA’s rule itself.  Rather, the Supreme Court ruling—made before the death of Associate Justice Antonin Scalia—has simply delayed implementation of the EPA rule pending review at the U.S. Court of Appeals for the District of Columbia (DC Circuit).  The DC Circuit is scheduled to hear the case on June 2, 2016 with a decision to be rendered later in the year.  The DC Circuit is likely to be favorably disposed to EPA’s plan as our analysis below shows.  Their ultimate ruling is critical because if the Supreme Court is later deadlocked at 4-4 on an appeal of the DC Circuit’s ruling, then the DC Circuit decision will stand (although it could be reviewed again later once a full complement of nine justices is empaneled).

The CPP issued by EPA is based on Section 111 of the Clean Air Act (CAA) authorizing performance standards for both new and existing sources.  The plan seeks to reduce power plant emissions through state compliance plans (SCPs) to be implemented by 2022.  More detail on the CPP can be found here:  However, despite flexible compliance mechanisms, 27 states and other manufacturing groups filed to appeal the CPP rule.

Prior legal challenges to block EPA from finalizing CPP rules had failed up until the Supreme Court stay in February.  Generally, CPP opponents claim EPA is overstepping its authority under Section 111(d) of CAA, and since EPA’s plan extends deeply into unchartered legal territory, the Supreme Court decided to stay further actions.  While EPA cannot compel the states to take additional action on the CPP right now, it can still advance understanding of emissions trading and benefits of greenhouse gas (GHG) regulation.  Almost 20 states are still moving forward with development of their SCPs.

Legal Issues

When the Clean Air Act was enacted and later amended in 1990, there were two different versions of Section 111(d) in the final statue from the House and Senate.  These differences were never reconciled in Conference Committee before being signed by the President.  Indeed, EPA chose to follow the Senate version of this section in the CPP because it prohibits the agency from writing a second rule controlling a pollutant that is already regulated.  Since GHGs are not regulated from power plants elsewhere in Section 112, the EPA would be free to regulate them under Section 111. In fact, EPA believes it is simply upholding current law following its 2009 Endangerment Finding that GHGs (including CO2) meet the necessary guidelines to be regulated under the existing Clean Air Act, and thus the CPP is not intended to foster conflict but merely adhere to existing law.

The CPP’s definition of the “best system of emission reduction” is also being challenged. EPA believes this system can be applied to entire power sector on a statewide basis.  In contrast, opponents believe the system is limited to individual emitting sources, since all emission sources within a state are not equally integrated into the power sector.  CPP proponents favor EPA’s expertise and flexibility in determining the scope of the rule.

Additionally, federalism is being advanced as an issue by some states that do not wish to implement a national policy that runs counter to state authority.  This same issue has arisen related to water and healthcare with the states as well.

Timing is also a challenge. While the DC Circuit plans to rule on this case later in 2016, because of the annual rotation of law clerks in the DC Circuit every August, appellate justices could lose research continuity and support soon after the hearing thereby impeding progress.  Separately, if the Supreme Court elects to hear an appeal of the DC Circuit decision in early 2017, a final decision is likely not until 2018 from the Supreme Court on the merits of the case.  Regardless, the final outcome could hinge on the 2016 elections, as the party that wins the White House will likely appoint the next justice to the Supreme Court (replacing Justice Scalia).

Precedent and Conclusion

History shows a judicial deference to EPA decisions.  The authors reviewed all judicial rulings at the DC Circuit since President Obama took office (2009-present) in cases where EPA was the Appellee and an Appellant was challenging an EPA policy (or ruling) previously upheld at a lower court.  Out of the 289 cases reviewed, EPA’s record at the DC Circuit was 239 wins, 30 losses, and 20 mixed results.  Only slightly more than 10 percent of the time did EPA lose outright on cases decided before the DC Circuit, evidence of deference to EPA at the Appellate Court level.  Recall the DC Circuit’s ruling might prove to be pivotal because lower court rulings stand when the Supreme Court has a tied vote (e.g. 4-4).

The international Paris Agreement in December 2015 adds broader interest and pressures for GHG regulations.  The Paris commitments may need additional policies in the U.S. beyond the CPP and tax incentives to succeed—an opportunity for tools under existing law to be used for the first time to reduce emissions.  For example, Section 115 of the Clean Air Act could support GHG action beyond the power sector in the U.S. by offering broad country reciprocity over any air pollutant anticipated to harm or threaten public health or welfare in a foreign country.  The U.S. already treats GHG emissions as pollutants and the United Nations Framework Convention on Climate Change offers the U.S. the reciprocity required to pursue Section 115.

The CPP is a part of an ongoing public debate in the U.S. regarding energy and environmental policy.  Pivotal to that public debate will be the judicial rulings on the CPP likely to arrive in early 2017 by the DC Circuit.  With the prospect of Congressional action on climate policy unlikely, all eyes are on the courts to decide if the first, nationwide policy limiting GHG emissions in the U.S. will take effect or not.

Addendum: On May 16, the DC Circuit announced that oral arguments will be delayed until September 27, 2016.  Furthermore, the case will be heard en banc by the full panel of DC Circuit judges, rather than the usual, smaller three-judge panel.  Experts believe that the en banc review at this step of the judicial review will expedite final resolution of the legal issues surrounding the Clean Power Plan.

CE3 Blog by Daniel H. Karney, Department of Economics and Michael J. Zimmer, Executive in Residence & Senior Fellow, Ohio University; Edited by Elissa E. Welch, Project Manager, CE3. May 2016.


What is at Stake? Assessing the Real Impact of the Clean Power Plan


On February 9th, 2016, the U.S. Supreme Court issued a stay on the implementation of the U.S. EPA’s Clean Power Plan (CPP).  Hearings on the case will be held during the summer with a potential decision likely by end of the year.  Future blog entries will discuss the political and legal aspects of the case.  The purpose here is to discuss the impact of the CPP nationwide if it were ultimately implemented.

The EPA’s website says the CPP is “a historic and important step in reducing carbon pollution from power plants that takes real action [emphasis added] on climate change.”[1]  The key step in determining the veracity of this claim is figuring out what “real action” means.  Appealing to the logic of the scientific method is the best way to generate fact-based conclusions.

Scientists like experiments, and scientific progress often comes from experimental results.  For instance, start with two petri dishes: one labeled “control” and the other labeled “treatment”.  Add bacteria to the treatment dish and watch the bacteria colony grow, while the control dish remains dormant.  This simple experiment demonstrates the basic logic of the scientific method; keeping all else equal, observe the effect of changing one variable between the control and treatment scenarios.  The same logic can be applied to determining the CPP’s real effect.

To start, EPA summarizes the CPP’s impact as follows: “When the Clean Power Plan is fully in place in 2030, carbon pollution from the power sector will be 32 percent below 2005 levels, securing progress and making sure it continues.”[2]  The problem with this characterization is that it only presents the “treatment” scenario; that is, EPA states what would happen with CPP implementation.  Indeed, the logic of the scientific method requires us to look at the difference between the treatment (“with CPP”) and control (“without CPP”) scenarios when determining the impact.  Therefore, what would be the emission levels in the “control” scenario without CPP implementation?

Fortunately, EPA conducted a Regulatory Impact Analysis (RIA) that provides the information necessary to implement our “scientific method”-based analysis.[3]  Below is Table ES-4 from the RIA that provides CO2 emission projections for a base case without CPP implementation and two policies cases under CPP implementation.  The two policy cases are labeled “rate-based” and “mass-based”, respectively, but for this analysis the distinction is not important.  Consider the base case the “control” scenario and the policy cases the “treatment” scenario.

CPP Table ES-4

The Table ES-4 reports projections emission projections out to 2030 for the base case (or business as usual) and policy cases.  By 2030, the policy cases both achieve a 32 percent reduction from the 2005, just as EPA claims (see the last column of the table).  However, the base case without CPP implementation projects an emissions reduction of 17 percent by 2030 relative to the 2005 baseline.  This is mainly due to the falling price of natural gas generation relative to coal generation, where the former is significantly less carbon intensive than the latter.  But, importantly, this change in the generation mix is independent of CPP implementation and thus included in the control scenario (i.e., base case).  Therefore, the difference between the control and treatment scenarios is only 15 percent, not 32 percent!  That is, implementing the CPP, all else equal, leads to a 15 percent difference between in the emission level from existing power plants by 2030.[4]

As litigation surrounding the CPP proceeds during the summer, it is important to remember what is really at stake: 15 percent.  While that 15 percent reduction in U.S. power plant emissions might seem small, it actually represents over 400 million short tons of CO2 reductions, which is equivalent to all 2011 carbon emissions from Spain.[5]

CE3 Blog by Daniel H. Karney, Department of Economics, Ohio University.

[4] This analysis relies on the results from EPA’s model of the U.S. electric power sector given a set of assumptions.  Different assumptions – for instance, a higher economic growth rate – change the model results.  Furthermore, a different model with a different model structure might yield different results and therefore different conclusions.