Energy Finance Report

Managing Grid Security in a Distributed Energy Environment

Posted by Joshua L. Sturtevant on 11/24/15 10:49 AM

ThinkstockPhotos-480288900.jpgHistorically, utilities have shouldered the burden of mitigating the security risks inherent in energy generation, distribution and transmission. The utilities were, and continue to be, well-placed to do so as they benefit from historical knowledge, existing relationships with regulators and grid operators, large and highly-trained workforces and, perhaps most importantly, the ability to rate base. Although the nature of risks has evolved over the years, with terror threats and privacy concerns added to the list of conventional risks like weather events, traditional utilities have been up to the task with a few noteworthy exceptions.

However, the traditional model of energy generation and distribution is in midst of an evolution that, arguably, could be more impactful to the U.S. grid than deregulation has been. Even in competitive generation markets, retail interaction with customers has been handled almost exclusively by the utility as an energy aggregator with the ability to rate base. Places like New York are now serving as the test labs for alternate models as regulators there have been shifting their gazes toward distributed generation models where smaller, independent entities would drive power supply through resources co-located, or else located in proximity, with end users.

While there are undoubted opportunities embedded in such a model, it is also true that there are risks that need to be addressed. Distributed generation resources are arguably physically safer from attack than large, centralized plants and generally increase the resiliency of the grid. However, the opportunities being afforded to distributed generation developers and owners almost inherently means the entrance into the market of smaller, potentially inexperienced operators who, under most models, won’t have the same rate-basing opportunities as utilities.

It shouldn’t be difficult for even advocates of distributed generation-focused systems to see that such a system could be susceptible to everything from cyber attacks, both hindering the functions of the grid and creating privacy concerns, to hardware attacks, in a way that has not been the case in the past. Against this backdrop is the reality that the reliance on technology to manage the grid in a distributed generation environment will increase exponentially at just the point in history that the capabilities of threats to the grid have never been higher.

While these problems are clear, their resolutions remain murky. As a policy matter, it is still unclear where the burden for grid security will ultimately fall under new frameworks. As is often the case in the fragmented environment that is the hallmark of U.S. energy regulation, it is possible that burdens could fall unequally on classes of customers or on different market participants in different jurisdictions. In cases where burdens fall mainly on distributed generation owners, it is likely that at least one solution will be provided by insurers.

Insurers already address risks related to terror, weather, business interruptions and cyber threats among other things related to the issues noted above. However, insurance is already one of the largest, if not the largest, costs involved in the ongoing operation of renewable energy facilities after they are placed in service. Cobbling together a set of disparate coverages to mitigate risks would be too heavy a financial burden for most renewable energy operators. As a result, it is unclear that insurance products currently exist that would mitigate the risks created by the security burdens that could be placed on generators in the grid of tomorrow in a cost effective manner. We will explore this issue, as well as other issues related to microgrids, cyber security and the ‘New York Model’ of energy generation on this page in coming months. In the meantime, those who are interested in these issues can view past posts we have published on the topics here and here and view our roundtable discussion on New York’s Reforming the Energy Vision docket, which is driving some of the concerns noted above in that jurisdiction and beyond, here.

Special thanks to Morgan Gerard for her assistance with this post.

Topics: Utilities, NY REV, Power Generation, Microgrid, Energy Finance, Distributed Energy, Energy Management, Solar Energy, Renewable Energy

Mid-Atlantic: Distributed Energy Opportunities

Posted by Joshua L. Sturtevant on 11/3/15 11:58 AM

Solar panels at a roof with sun flowersThe Mid-Atlantic region (Maryland, Delaware, Virginia and the District of Columbia) is currently at the forefront of discussions regarding the next generation of distributed electricity markets. Notable developments pushing the region into the spotlight recently include M&A activity, creativity on the part of public service commissions, local innovations in PACE finance, and increasing flexibility on the part of local utilities.

Programs and developments of particular note include:

- Net metering and renewable portfolio standards in Maryland

- PACE financing in Montgomery County, Maryland

- Discussions around undertaking a REV-like proceeding in Maryland

- Interconnection standardization in D.C.

- Microgrid studies being undertaken in D.C.

- Potential third-party bidding for large-scale solar in Virginia

- Renewable portfolio standards and net metering in Delaware

- Community solar innovations and discussions throughout the region

Please join SEIA and Sullivan & Worcester’s Energy Finance team on November 5th live in SEIA’s new offices, or by dial-in, as we host a roundtable discussion on developments in the region and the unique business opportunities they could present. After Rhone Resch’s introductory remarks, Elias Hinckley will moderate a panel comprised of industry experts with unique opinions, including Maryland PSC Commissioner Anne Hoskins, Dana Sleeper of MDV-SEIA, Anmol Vanamali of the DC Sustainable Energy Utility, Bracken Hendricks of Urban Ingenuity and Rick Moore of Washington Gas. Interested parties can register here.

Topics: Water Energy Nexus, Utilities, Water, Carbon Emissions, Energy Security, Thermal Generation, Energy Policy, M&A, Structured Transactions & Tax, Energy Storage, Energy Efficiency, Power Generation, Microgrid, Energy Finance, Distributed Energy, Energy Management, Solar Energy, Renewable Energy, Wind, Oil & Gas

REV Conference Recap: Opportunities for Distributed Generation in New York

Posted by Joshua L. Sturtevant on 10/21/15 11:38 AM

REV PictureThe Sullivan & Worcester LLP Energy Finance team recently hosted an event on New York’s Reforming the Energy Vision (REV) initiative. In particular, the panel participants, including former New York Public Service Commission Commissioner Bob Curry, Mike Pantelogianis of Investec, Sarah Carson Zemanick of Cornell University and Jay Worenklein of US Grid Company, focused on how deals will get done under the new framework.

While REV is in its relative infancy, and while it is perhaps difficult to draw too many conclusions regarding business models as a result, the panelists nonetheless made some interesting points that policymakers would do well to take under consideration. In particular, the participants seemed to agree that uncertainty is one of the largest risks to investment coming into the market. Additionally, the panelists seemed to agree that getting the role of the utilities correct will not be an easy task, but could lead to interesting investment opportunities, particularly in the microgrid space.

The issues the panelists addressed can be added to others we have discussed in the past, including: 1) addressing technology risk; 2) ensuring reliability; 3) containing cost; and, 4) avoiding regulatory issues.

Those interested in viewing the program in its entirety can find it here: REV Roundtable

 

Topics: Carbon Emissions, NY REV, Structured Transactions & Tax, Energy Efficiency, Power Generation, Energy Finance, Distributed Energy, Energy Management, Renewable Energy

Hydropower Technologies Evolve In The Face of Increasing Water Scarcity

Posted by Jerry Muys on 10/20/15 7:15 AM

Water rushing through gatesParticularly in the West, hydropower long has provided a significant portion of the energy required to meet the needs of a growing population. Increasingly, however, the circumstances that led to the dominant role played by hydropower generation in providing nearly boundless energy supplies in many parts of the country are changing. Factors that were not known about or anticipated in the decades when much of our existing hydropower infrastructure was constructed are creating challenges both to the long-term reliability and continued cost-effectiveness of traditional hydropower. Climate change and other factors are predicted to alter both the timing and pattern of precipitation and associated runoff that largely determines the availability and amount of hydropower.

The magnitude of the contribution that hydropower historically has made to our Nation’s energy abundance can be seen in the statistics maintained the U.S. Bureau of Reclamation, which has shared jurisdiction over federal hydropower generation. The Bureau is the Nation’s second largest producer of hydroelectric power, with roughly 58 power plants and 194 generating units in operation accounting for an installed capacity of more than 14 million kilowatts.

However, the large-scale dams that historically have supplied enormous amounts of hydroelectric power, particularly in the Colorado River Basin and the Pacific Rim states, are no longer being built. Although they continue to operate, and some have been retrofitted with more efficient turbines resulting in marginal increases in output, our traditional reliance on hydroelectric generation no longer is sustainable. Water supply availability increasingly is being limited by the effects of climate change and other factors, while increased water demand for energy production, agricultural production, and municipal development continues unabated.

Efforts to secure the future sustainability of our energy and water resources are leading to dramatic changes in how we address what has come to be known as the “water/energy nexus.” These changes range from the adoption of alternative cooling technologies for thermoelectric power plants to greater emphasis on energy efficiency and increased use of non-traditional energy and water resources.

The impacts of climate change and other factors on the availability of traditional water supplies have posed some unique challenges with respect to the continued use of hydropower for energy generation. Reservoirs, particularly large ones, are increasingly susceptible to evaporation due to warming, with the result that less water is available for all uses, including hydropower.

The implications of reduced water levels in many of the reservoirs on which we rely for the generation of hydropower has spurred, at least in part, an entirely new technological approach to hydropower generation which is largely immune to the increasing variability of reservoir water levels. The trailblazer of this new approach has been a Portland, Oregon-based startup, Lucid Energy. Several years ago, Lucid conceived an alternative, highly sustainable model of hydropower generation that is in the process of being adopted in communities across the country. The system pioneered by Lucid involves the installation of small turbines in water distribution systems (i.e., pipes) which generate energy when the turbines spin in the flowing water.

The power generated by the turbines either can be used to off-set a utility’s own power demands, or be sold into the grid as a separate source of revenue for the utility. Portland’s local water utility was the first to install the new technology into its water distribution system, but a number of other cities, including San Antonio and Riverside California, quickly followed suit.

In addition to addressing challenges to our domestic hydropower industry posed by climate change and other factors, the Lucid technology also would seem to offer a promising model for power generation in developing countries, many areas of which often do not have access to an established electricity grid.

Topics: Hydroelectric, Water Energy Nexus, Water, Energy Security, Energy Policy, Energy Efficiency, Energy Management

Reforming the Energy Vision (REV) Round Table Discussion

Posted by Joshua L. Sturtevant on 9/25/15 9:51 AM

skyline manhatten

New York’s Reforming the Energy Vision (REV) proceeding has the potential to change the way the electric industry functions in that state and beyond. The Empire State’s vision, which includes delegating distribution duties to utilities, reserving generation opportunities for third parties and shifting to a more renewable-focused generation mix, will change how business is done there while also potentially providing a template for other jurisdictions preparing for life under the EPA’s Clean Power Plan.

However, there are hurdles to overcome. Customers will not tolerate a reduction in reliability or resiliency. Nor will the benefits of clean generation be as joyously embraced if higher costs are the result. Outdated technological capabilities, security issues, job displacement and shareholder issues all create concerns that need to be addressed. That said, tremendous opportunities could exist for technology providers, generation platforms, financiers and others if the current vision of REV is implemented. Microgrid and cutting edge renewables are being promoted. Grid and demand management technologies will be in high demand, and legislative and financial support for projects will continue to ensure a favorable development environment for those with projects.

Please join the Sullivan & Worcester, LLP Energy Finance Team on October 1st live in our New York offices, or by dial-in, as we host a roundtable discussion on the REV proceeding and the unique business opportunities it could present. Panel participants include industry experts with unique perspectives on REV such as former New York Public Service Commission Commissioner Bob Curry, Mike Pantelogianis of Investec, Sarah Carson Zemanick of Cornell University and Jay Worenklein of US Grid Company. Interested parties can register here.

Topics: NY REV, Energy Policy, Energy Finance, Legislation, Distributed Energy, Energy Management

Can the Clean Power Plan Achieve Its Carbon Emission Reduction Goal Through Increased Renewable Energy Development?

Posted by Jeffrey Karp on 9/22/15 10:41 AM

photovoltaic cells and high voltage post.

Co authors Van P. Hilderbrand and Morgan M. Gerard

As the dust settles amidst the hoopla and angst surrounding the Environmental Protection Agency’s (U.S. EPA) final promulgation of President Obama’s Clean Power Plan (CPP or the final Plan), a theme has emerged – renewables are expected to be a major energy source. From proposal in 2014 to U.S. EPA’s final rule in August 2015, the share of renewables in the agency’s forecast of the U.S. power sector in 2030 jumped from 22 to 28 percent. Concomitantly, the final Plan further highlights the anticipated strong presence of renewable energy resources in the states’ future energy mix.

The question now arises whether enough renewable energy resources can be built to enable the states' to meet their respective carbon emissions from power plants. The answer depends on whether investors will have adequate incentives and financing mechanisms to “prime the pump” and generate the requisite megawatts of renewable energy to help meet the final Plan’s emission reduction targets.

The Final Plan’s Approach to Carbon Emission Reduction

The CPP’s goal is to reduce carbon emissions from stationary energy-generating sources such as coal and gas power plants. In the final Plan, U.S. EPA assigned each state a specific emissions reduction target. The agency then provided the states with discretion and flexibility to decide how to meet those targets within the context of the CPP’s designated “building blocks” (discussed later). However, if a state fails to submit an adequate implementation plan by the 2016 or request an extension for plan development until 2018, U.S. EPA will assign the state a federal implementation plan (FIP) that will enable that state to meet its emission reduction target. A sample FIP, which creates an opted-in cap-and-trade marketplace, was released with the final Plan on August 3, 2015.

Establishment of Emissions Reduction Rates: Section 111(d) of the Clean Air Act requires that U.S. EPA determine the “best system of emissions reduction” (BSER) for pollutants such as carbon dioxide. To achieve this result, the agency examined the technologies, strategies, and measures previously implemented by states and utilities to reduce emissions at existing power plants.

Power NightThis examination yielded three “building blocks” in the final rule that a state may use to meet emission reduction targets. It may improve heat rates at existing power plants to make them more energy efficient (Building Block 1); use more lower-emitting energy sources like natural gas rather then higher-emitting sources like coal (Building Block 2); and/or use more zero-emitting energy sources like renewable energy (Building Block 3). U.S. EPA then considered the ranges of reductions that could be achieved at existing coal and natural gas power plants at a reasonable cost by application of each building block.

The building blocks were applied to coal and natural gas plants across the three U.S. interconnection regional grids - the Western interconnection, the Eastern interconnection, and the Electricity Reliability Council of Texas interconnection. The analysis conducted by U.S. EPA produced regional emission performance rates - one for coal plants and one for natural gas plants. The agency then chose the most readily achievable rate for each source (both calculated from the Eastern interconnection) and applied the rate uniformly to all affected sources nationwide to develop rate-based and mass-based standards. Although this approach created uniformity, nonetheless, each state still was assigned a different emissions target based on its own specific mix of affected sources.

Plan Implementation: As noted, U.S. EPA has enabled the states to decide the manner in which to meet their reduction targets. Thus, the CPP does not mandate specific changes to a state’s fuel mix; rather, states are free to determine how best to meet their emission reduction targets. For example, as applicable, a state may focus solely on Building Block 1 and making efficiency improvements at existing coal and natural gas plants. Conversely, a state may focus on Building Block 3 and incentivize development of more zero-emitting energy sources. Or, all three of the building blocks may be used to achieve a state’s targets.

The CPP’s approach to achieving compliance is notable because critics have argued that, under Section 111(d) of the Clean Air Act, U.S. EPA cannot regulate beyond the “fence line” (e.g., the agency can only regulate a power plant itself, and cannot count unrelated energy efficiency measures and renewable energy development toward achieving compliance). In an apparent effort to shield the CPP from legal challenges, the agency removed demand-side energy efficiency improvements as a building block in the final rule. Moreover, by not forcing the states to utilize a particular mechanism to achieve compliance, the agency’s decision-makers seem to believe the final Rule is better positioned to withstand the inevitable appeals process.

  • Larger Role Expected for Renewables: U.S. EPA contemplates that renewable energy will play a prominent role in the evolving U.S. power sector. The draft rule estimated that by 2030, 22 percent of the country’s electricity would be generated by renewable resources. In the final Plan, EPA estimates the share of renewables at 28 percent. According to the agency, this increase is a function of market forces and a continued decline in energy prices. It also is in line with the final Plan’s deeper cuts to emissions overall. The final Plan targets a 32 percent decline in carbon dioxide emissions from 2005 levels by 2030, whereas the proposed rule had a 30 percent reduction goal. Nonetheless, whether sufficient renewable energy resources are developed to help meet the final Plan’s emission reduction targets depends on whether sufficient incentives exist and risks can be adequately minimized. Potential investors dislike uncertainty, especially when it involves committing large amounts of funding to development projects over a lengthy time horizon.
  • Incentives for Renewables: The final Plan seeks to incentivize the deployment of renewable energy through early renewable procurement under EPA’s Clean Energy Incentive Program, which makes available additional allowances or emission credits for investments in zero-emitting wind or solar power projects during 2020 and 2021, prior to the rule's 2022 implementation date. As discussed below, other incentives may be provided by the U.S. Department of Energy and Congressional action on favorable tax legislation.
  • Coordinating Role with the Department of Energy: President Obama recently announced a coordinating role for the Department of Energy (DOE) in connection with the CPP. The DOE’s Loan Programs Office (LPO) will make available up to one billion dollars in loan guarantees to support commercial-scale distributed energy projects, such as rooftop solar with storage and smart grid technology. Expanded funding also is available though DOE’s Advanced Research Projects Agency–Energy (ARPA-E), which has awarded $24 million for 11 high-performance solar photovoltaic power projects.
  • Seeking Congressional Clarity on Tax Credits: By extending the compliance deadlines from 2016 in the proposed Plan to 2018 in the final Plan, U.S. EPA provided states with additional time to build out the necessary infrastructure to achieve compliance. The deadline extension also provides more time for Congress to establish clarity regarding the federal investment tax credit (ITC). The ITC presently enables investors to credit 30 percent of a project’s costs to their taxable basis, but the credit is scheduled to decrease to 10 percent on January 1, 2017 without a Congressional extension.

70,000 solar panels await activation.For renewable energy, and particularly solar, to play a seminal role in effectuating the final Plan requires a functioning solar market. Solar projects are characterized by high upfront costs and long payout periods. Without supportive policies like the ITC, solar developers may face difficulties finding suitable power purchasers, thus negatively impacting the ability to procure financing. Further, utilities may be unable to bear the full costs of the CPP without assistance from the private market. Utilities typically procure power from already-financed projects. If required to underwrite solar on their own, utilities may need to finance such projects using their credit rating and balance sheet, thus passing along infrastructure costs to ratepayers.

Although some solar proponents believe the ITC step-down will not negatively affect the market’s vitality because the price of renewables is now cost competitive enough to survive the shift, others in the industry dispute this view. Irrespective, the upcoming ITC step-down creates uncertainty in the market. The Production Tax Credit (PTC), generally associated with wind projects, recently passed through the Senate Finance Committee, provides the potential for a similar ITC revival. With the additional compliance period granted to the states in the final rule, Congress now has the opportunity to provide clarity by acting favorably on both of these tax credits by late-2016.

State Incentives

Renewable energy-friendly states have enacted legislative, promulgated regulatory enforcement mechanisms, and provided financial incentives to encourage the development of renewable energy resources. For example, some states participate in cap-and–trade programs (e.g., Regional Greenhouse Gas Initiative (RGGI)), have enacted renewable energy portfolio standards, provide favorable treatment under public utility commission regulations (e.g., favorable net-metering schemes and third-party financing for renewable energy development), and offer other state or local tax credits. The impact of such programs on carbon emission reduction is reflected in the lower targets assigned under the final Plan, for example, to California and Massachusetts - 13.2 percent (126 lbs. CO2 / MWh) and 17.8 percent (179 lbs. CO2 / MWh), respectively.

Despite Emphasis in the Final Plan, Uncertainty Still Remains Regarding Renewables Development

The final Plan provides a level of regulatory clarity, but the path forward remains uncertain in light of looming legal battles regarding whether the Plan oversteps U.S. EPA’s authority under the Clean Air Act and political divisiveness in Congress. It also is unknown whether the next U.S. President will support the rule or try to dismantle the Plan.

These uncertainties, coupled with concern over the future of the ITC, may lead to substantial implementation delays, or even complete eradication or substantial revision of the final Plan. Even if the CPP withstands challenge, nonetheless, some states may be unable to meet their emission reduction targets if adequate renewable energy financing mechanisms have not developed by 2018, the time by which state's must submit their emission reduction plans. Understandably, potential investors may be leery about committing substantial funds to renewable energy projects unless or until the likely outcome of legal challenges to the CPP can be better assessed, and regulatory and political risks more accurately calculated.

While renewable energy resources seem to be a favored approach under the final Plan, a comprehensive strategy that effectively facilitates the financing of such projects is essential to achieve the Plan’s emission reduction targets.

Topics: Utilities, Carbon Emissions, Energy Policy, Structured Transactions & Tax, Energy Efficiency, Power Generation, Microgrid, Energy Finance, Legislation, Distributed Energy, Energy Management, Renewable Energy

Tech Update: uBeam- Wireless Device Charging

Posted by Joshua L. Sturtevant on 9/17/15 8:50 AM

Seeing everyone from frenzied business travelers to teens huddled around charging stations has become almost de rigueur at airports across the globe. Part of this milieu is the accompanying nest of wires of various shapes, sizes and colors taking up space and tethering their testy owners to often tiny shelves; a truly wireless charging station has, thus far, been an unattainable dream.

However, if Meredith Perry, the founder of uBeam, is successful, wireless charging may be closer to becoming a reality than it ever has. The premise of uBeam is that charging stations will be able to charge devices wirelessly via ultrasonic transduction—a process where power is taken from a building’s electrical system and converted into ultrasonic sound waves, which are picked up by receivers affixed to the device to-be-charged and converted back to usable energy. uBeam would charge devices at approximately the same speed as if they were plugged into an outlet. The technology’s current range of about 15 feet distinguishes it from other attempts to achieve wireless recharging, such as magnetic resonance.

After receiving over 13 million dollars in investment from financial magnates such as Mark Cuban and Marc Andreeson, uBeam has sought exclusivity deals and is reportedly in talks with Starbucks, Virgin Air, Starwood Hotels, Samsung and Apple. However, the potential application of this technology reaches beyond phones, tablets and laptops to other cordless devices such as wireless headphones, watches and hearing aids.

uBeam, which has not yet released a commercial model, has the potential to become one of the most disruptive innovations of this decade, but still requires considerable fine-tuning. Many questions remain about unlimited wireless charging through ultrasonic transduction, and early adopters will be curious about safety and cost. In particular, one has to wonder how much electricity this technology will pull from the grid, especially considering the number of devices that could simultaneously charge in high traffic venues such as hotels or coffee shops. The devices’ draw from the grid raises questions regarding cost-effectiveness and who will pay for the ability to wirelessly charge. However, travelers hoping for a future without current charging inconveniences will be waiting with bated breath for a uBeam success story.

Topics: Energy Efficiency, Distributed Energy, Energy Management

Property Owners Increasingly Embracing Energy Efficiency Technologies

Posted by Merrill Kramer on 9/2/15 6:36 AM

Co-authors Josh Sturtevant and Morgan Gerard

greenlightbulb-ThinkstockPhotos-469361066.jpg

Building owners are increasingly embracing energy efficiency technologies as a way to improve their bottom line by reducing their energy and operational costs, while simultaneously reducing their carbon footprint.

In a recent analysis by Deloitte, the big four firm indicated that building managers’ views on energy generation have matured and “may be past the point of no return” after seeing firsthand the tremendous benefits that installing energy efficiency equipment can have on bottom lines. Of the sampled businesses, 79% view reducing electricity costs as critical to maintaining a “competitive advantage,” and many have instituted formal energy reduction goals. Additionally, cost cutting was cited as a motivation for 59% of respondents, and more than 55% of businesses now generate energy on-site. According to Deloitte, owners are increasingly controlling their own energy eco-systems through instituting better management controls, demand side efficiencies, batteries, and renewable power and cogeneration.

Energy Savings Performance Upgrades

A management decision to install energy efficient equipment is relatively easy to make compared to whether to invest in more costly on-site generation. Reducing energy and operating expenses through energy efficiency upgrades can provide a relatively quick payback. Retrofitting a commercial building with LED lighting for $400,000, for example, could yield a two year payback and save $200,000 a year in operating expenses. Energy efficiency however encompasses a much wider spectrum of options. These include upgrades and replacements of existing and aging facilities such as boilers and chillers, installing control, automation and building management systems, electrical system upgrades, weatherization, advanced HVAC, air handling systems and/or central plants.

These decisions can have a significant impact on building management. According to the U.S. Department of Energy, buildings account for approximately 40 percent of total U.S. energy costs, which amounts to $400 billion each year for residential and commercial buildings alone. Reducing energy use in U.S. buildings by 20 percent would save approximately $80 billion annually on energy bills, and savings from commercial buildings would account for half of this amount, or $40 billion.

How to Finance Your Energy Systems?

When making budget decisions, facility owners and managers must decide whether to internally finance, own and operate these facilities, or turn to a third party model where a vendor or sponsor develops, finances, owns and operates the facility under an energy services contract. Third party arrangements can take many forms, but most often are structured as performance based contracts where payments are tied to the level of energy savings achieved by the installed system. In this structure, both parties are motivated to achieve the highest level of energy savings at the lowest capital costs.

If the building owner has a sufficient balance sheet or creditworthiness, the owner at first blush may feel it makes most financial sense to directly install, own and operate the energy efficiency facilities. By cutting out the developer, an owner’s transactional costs may be lower, it can avoid third party operation and management expenses, will own the tax attributes such as depreciation and tax credits, and can achieve a quicker payback and higher overall return on investment.

Undertaking a comparative analysis however needs to take (1) balance sheet considerations (2) internal overhead costs, (3) tax optimization and (4) higher risks into account to make a fair comparison. For instance, a third party service model typically is structured to guarantee a specified level of energy savings to the owner, and to achieve a guaranteed total output and heat rate (efficiency) level. Financial responsibility for failure to achieve these minimum targets falls on the third party service provider. In a self-financed/owned scenario these risks and costs fall on the owner.

Third party developers also provide owners with construction and completion milestones, for which the failure to satisfy them creates 3d party liability for construction cost overruns and delay damages. The third party provider typically is liable for forced outages, increased operating and maintenance costs, insurance, labor costs and fuel price volatility (in the case of on-site generation). In short, in addition to an owner incurring the upfront capital costs for designing, permitting and installing these systems, the owner takes on the risks of cost overruns, construction delay, system operations and maintenance costs, and failure to achieve the targeted savings. An owner additionally may not be in the best position to optimize the value of the tax benefits. These factors must be given comparable consideration in deciding on the appropriate model.

Additional Benefits and Revenue Streams

While energy efficiency improvements can produce significant energy savings, the economic argument is more complex in situations where tenants are signed on a triple-net basis. Under a triple net lease, the energy savings do not directly go to the building’s bottom line, but are passed through to the tenant in the form of reduced utility expenses. Under these circumstances, the owner’s benefits immediately will appear in the form of less expensive, more competitive rental space, and potentially increased occupancy rates. The owner will also receive LEED’s points for energy cost reductions over baseline, increased building sustainability, and potentially decreased property, casualty and disaster recovery insurance costs. Longer term, the owner may be able to increase rents to offset the benefits of lower operating expenses.

Property managers also can increase their operating revenues with on-site generation even under a triple-net lease. For example, buildings may have the capability of renting out their roofs to solar developers or their utility rooms to cogeneration or heat exchange systems in exchange for rental payments and a portion of the energy sales. Owners in many jurisdictions also can engage in net-metering, or can generate incremental operating revenues by allowing the on-site system to be counted as backup generation or demand response in exchange for capacity and energy payments from the regional power pool.

Continuous Barriers Need to be Addressed

As energy technologies mature, barriers to further adoption should be considered by building owners and managers to reap the above stated benefits. First, property owners and managers need to become more comfortable with third party energy efficiency agreements as a way of adding value to property through reduced operating expenses or increased incremental revenues. Second, owners need to take into account whether installing, financing and operating energy efficiency and on-site generating facilities on balance sheet goes to their core business strengths and competencies, or detracts from their focus on real estate development. Third, owners should step back and look at their energy savings opportunities on a portfolio basis as a way of reducing financing costs, collateral obligations and increasing economies of scale.

Conclusion - A Paradigm Shift

The “mind set of businesses and consumers” has shifted in favor of energy management and efficiency. Particularly with larger capital projects, third party financing mechanisms associated with “energy as a service” will proliferate and ultimately decrease in cost. Properties are limited in what they can finance through balance sheet or non-real estate allowances for REIT structures. Third party models may be the most effective way of allowing property owners to compete with comparable properties.

Topics: Structured Transactions & Tax, Energy Efficiency, Power Generation, Energy Finance, Distributed Energy, Energy Management, Solar Energy, Renewable Energy

Understanding New York's 'Vision' -- Feature in Public Utilities Fortnightly

Posted by Merrill Kramer on 8/25/15 1:02 PM

With some of the highest electricity prices in the United States, and mindful of the massive disruptions to its electric service caused by Hurricane Sandy, New York has undertaken a major reform of its electric utility industry. This reform begins with the New York Public Service Commission (NYPSC), which has recently issued a broad-scale initiative to change the way utility service is provided that may serve as an example nationwide. The reforms will radically alter the way electric utility services are provided and priced to customers.

The far-reaching program is called the Reforming the Energy Vision, or "REV." Its major thrust seeks to decentralize power supply by encouraging businesses and retail customers to install small generating resources or "distributed energy" on site. The program includes incentives for installation of fuel-efficient power units, renewable resources such as solar and wind, and for development of microgrids and community solar. The NYPSC seeks to create a decentralized and resource diverse power supply system that can prove less susceptible to disruption caused by a single event, and replace it with a more reliable and dynamic system. The proposed reforms redefine the role of public utilities while seeking to ensure their financial survival in a decentralized power world.

Please see our publication in Public Utilities Fortnightly for more information on REV: Understanding New York's 'Vision'

Topics: Utilities, NY REV, Energy Policy, Microgrid, Energy Finance, Distributed Energy, Energy Management, Solar Energy, Renewable Energy

Managing the Rise of Distributed Energy - Emerging Utility Trends

Posted by Van Hilderbrand on 8/19/15 11:39 AM

Co-author Morgan Gerard

Much has been written and discussed over the last few years regarding the conventional utility’s “death spiral.” America’s power generation utilities have become increasingly fearful that a significant majority of their customers will generate their own electricity through innovative distributed energy technologies like rooftop solar. In other words, their customers become their competitors. As these customers migrate off the power grid, the utility’s revenues drop due to reduced load and the traditional monopoly model folds.

Utility Sunset 2Utilities have been aware of this emerging threat for some time. Now, as the price of renewables plunges and traditional coal-fired power plants are decommissioned under the Environmental Protection Agency’s Clean Power Plan, utilities have to respond to this changing environment with a new set of tools. In this post, we discuss a few trends developing across the country toward a cleaner, more affordable and more reliable grid.

Performance Based Rate Making

In Minnesota, the state’s leading utility, Xcel Energy, is pushing legislation (HF 1315) to create a performance based rate (PBR) regime that adjusts the utility’s revenue model to align with the state’s energy policy objectives while still protecting the utility’s business interests. Standard ratemaking in most states is based on the cost-of-service versus the rate-of-return. Instead of minimizing costs to achieve higher rates and greater revenues, the PBR de-couples the rate-of-return from the amount of kilowatt-hours sold, and focuses utility returns on its ability to meet a series of performance metrics that, for example, enhance the grid-system, energy efficiency, or customer value. PBR relies on setting a threshold performance level; thus, rewarding utilities for meeting targets and penalizing them for under-performance. An added benefit for utilities and ratepayers is that the PBR method may decrease the number of rate cases, which can be costly and time consuming. Thus, PBR can incentivize utilities to adapt to technological changes and promote distributed generation while continuing to recoup cost of investment and creating returns for shareholders.

Performance-based regulations will inevitably change the relationship between customers, utilities, and regulators. By tweaking their business model to meet state performance goals and create a distributed energy project-friendly market, traditional utilities in Minnesota will not only survive, they may thrive.

Platforms for Distributed Technologies

The New York Public Service Commission (NYPSC) is proactively exploring revamping incumbent utilities as “platforms for distributed technologies.” NYPSC’s Reforming the Energy Vision (REV) docket envisions these platforms as a transmission line “gatekeeper,” and the conventional utility will fulfill this role. The gatekeeper’s purview would include grid demand response, energy efficiency, and distributed generation. The NYSPC envisions utilities as Distributed System Platforms (DSP) constructing a multi-sided platform market with the utility functioning as the platform provider, similar to the interfaces found in the financial markets, credit card services, video game systems, and many internet businesses. In these markets, transactions take place in a triangular rather than linear exchange, in which buyers, sellers, and the platform provider each interact with two or more other parties rather than one counterparty exclusively. The platform provides the technology, protocols or structure through which users can interact. The NYPSC’s Staff has released its second White Paper that analyzes how to transition utilities towards the DSP market, and a feature of this transition seems to be a version of PBR that incentivizes distributed generation, low cost electricity and grid resiliency. Therefore, instead of spiraling to their deaths, New York utilities will have the opportunity to adapt as this market interface, connecting energy customers to energy producers-- a redefined role in a new energy industry as distributed generation clearing houses.

DG solarCalifornia has taken note of the REV trend and the California Public Utility Commission is in the process of creating distribution resource plans (DRPs) that incorporate distributed energy resources into utility grid-planning and investment regimes. Further, California’s model would place utilities in the role of brokering wholesale and retail grid energy, and perhaps empower the utility as a grid-edge operator similar to an independent system operator of a transmission grid. Again, such strategy may call for incentivized performance-based rate structures.

Net Metering Pushback

Utilities are not all for adapting to new and innovative business models, and in many states are continuing to push back against distributed generation. Net metering, which has incentivized hundreds of distributed energy projects, is a legislative policy that allows generators to sell back unused electricity into the utility grid. Once supported by utilities, these policies are becoming more contentious across the country since in cost-of-service versus the rate-of-return regulatory jurisdictions, there is the argument that net metering prevents utilities from recouping their full return on grid investment. Utilities have raised concerns that net metering policies create an inequitable cost sharing paradigm, whereby customers are paid for over-generation, but do not bear the responsibility or cost for updating and maintaining transmission lines.

For example, contention over net metering in Hawaii brought a regulatory proceeding to halt as the island’s utility maintains that costs are shifted to non-net metering customers. The utility recommends a model for distributed energy resources where owners would be compensated for net-metered electricity at $0.18 per kWh, which lengthens the payback period for solar infrastructure investments. Similarly, the Arizona Public Service Company (APS) established a charge for new rooftop solar panel installations connected to the electric grid through net metering, amounting to $0.70/kW—approximately a monthly charge of $4.90 for most customers. The policy was effective starting January 2014, and will be in effect until the next APS rate case.

Considering that utilities maintain ownership of the transmission lines, and in many jurisdictions that their energy generation role is still a necessity for grid stability and reliability, these companies retain a considerable amount of power over the destiny of our power markets. However, customers that have installed distributed energy projects like solar, expect to receive the net metering rates they were promised. As more utilities stop supporting net metering policies, distributed generation continues to proliferate. Thus, there needs to be a compromise between the utility, customers, and regulators that fairly accounts for all costs. Only then can a win-win solution be developed.

Thoughts for the Solar Customer, Developer, Investor

The unprecedented amount of distributed energy coming online will have to be accounted for in the future power generation industry model. Ultimately, the states will serve as arbiters that will guide the evolution of the electric industry. Many states are closely watching the developments in New York, Minnesota, California, Hawaii, and Arizona as each regulatory body considers its own solutions to balance renewable energy developments with grid maintenance, safety, and reliability. The attractiveness of distributed energy to the customer, developer, and investor will certainly depend on the solution chosen.

Topics: Utilities, NY REV, Energy Policy, Energy Efficiency, Energy Finance, Distributed Energy, Energy Management, Solar Energy, Renewable Energy

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The Energy Finance Report analyzes developments in energy finance as well as provides updates and perspectives on market trends and policies.

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