Energy Finance Report

New York Seeks Value for Distributed Energy and Reevaluates Net Metering

Posted by Joshua L. Sturtevant on 1/7/16 12:02 PM

Co-author Morgan M. Gerard

NY_REV_Notice.jpgOn December 23rd, 2015, The New York State Public Service Commission (NYPSC) issued a Notice under which it is soliciting comments concerning the value that Distributed Energy Resources (DERs) contribute to the distribution grid system. It is also soliciting feedback on a successor methodology to its current Net Energy Metering (NEM) policy that will help drive development in the interim. Both of these issues are being tackled by the NYPSC as part of New York’s broader Reforming the Energy Vision (REV) initiative.

New York needs critical energy infrastructure to the tune of billions of dollars at the same time that utility revenues are falling. Additionally, more distributed generation (DG) is coming online, including DG resources that net meter to the grid, and therefore potentially shift the pro rata costs of grid maintenance onto non-DG owners.  In response, the NYPSC opened the REV docket in an attempt to reconcile these trends as well as prepare for a more resilient and energy efficient future. 

It is hoped that the policies and rules promulgated under REV will facilitate the adoption of greater on-site and near-site energy resources and efficiency approaches, known under REV as Distributed Energy Resources (DERs). Under this new framework, DER owners will be able to sell their generation to utilities as well as directly to commercial and retail customers. Due to the complexities inherent in such a model, the Commission has worked with incumbent utilities who will help achieve ambitious DER goals by operating as Distributed System Platforms (DSPs), which will coordinate grid-wide DER activities as a market administrator, not unlike a distribution level independent system operator. 

However, a complication has arisen under this new paradigm: What is the value of these DERs to the system? Assessing the value of DERs is a key component in constructing an efficient market as transactions will consist of interactions among customers and service providers, and also between utilities and DER providers. It is also true that in the absence of clarity regarding the value of DERs it will be difficult to attract private capital to projects under development. Because of these complications, and the need to both resolve uncertainty and ensure that the burdens of systemic grid maintenance and upgrades are not being bypassed by DER and grid-exiting customers, a mechanism is required to establish accurate pricing. 

It was made clear in the NYPSC Staff’s Track Two White Paper that the system value of DERs will be divided into two components: 1) the energy value and 2) all other values associated with distribution-level resources. The energy value in New York is established by power markets and is called the location-based marginal pricing (LMP), a methodology where the price of energy at each location in the New York State Transmission System is equivalent to the cost to supply incremental load at that location. The full value of a particular DER can be expressed as the LMP plus the distribution delivery value (the value of D); together known as “LMP+D.” In the NEM Interim Ceilings Order, the Commission further elaborated that “[the] ‘value of D’ can include load reduction, frequency regulation, reactive power, line loss avoidance, resilience and locational values as well as values not directly related to delivery service such as installed capacity and emission avoidance.”  The Notice indicates that the NYPSC is seeking to establish a new methodology and process for determining the full value of DERs prior to December 31, 2016.

Determining the value of DERs to the grid system implicates possible changes to the future of net energy metering (NEM), which in the Empire State is a statute-based incentive that allows small generators of electricity to sell their excess generation into the grid subject to an overall cap. If a new value is being placed on all DERs, and DER outputs can be purchased by the utility and non-utility actors in real-time, the question of how the current NEM regime can co-exist within the REV marketplace is begged.  Despite this gray space, Staff saw no reason to adjust NEM for the mass-market per the Track Two White Paper, and stated that a bill-crediting mechanism used in NEM should continue to be considered as part of a successor to NEM. It also stated that changes to NEM should be focused on larger projects with substantial net export of electricity. 

The Commission decided in the subsequent Net Metering Ceilings Order that “until these valuation efforts [the value of D] are completed, and incorporated in tariffs that recognize the full benefit of DER, net metering must continue, to avoid the disruption of DG development efforts that would contravene the State’s energy policies.” Despite an overall lack of change, the cap on NEM under the Ceilings Order is now allowed to float to avoid “repeated disputes over the proper level of the ceiling . . . and shall be allowed to float in the interim until the calculation and application of ‘the value of D’ and other issues affecting valuation of DER is decided.”  In addition, and in recognition of the various paths NEM policy could take going forward, the current solicitation also seeks comment on how the Commission should consider the transition “from NEM,” and indicates that they favor a scenario where “a single comprehensive process should be embarked upon to adequately address the range and complexity of the questions raised [in this matter].”

The “value of D” may be the necessary component to determine how DERs, specifically on-site generation and microgrids, contribute to the efficiency and resiliency of the grid. Although New York is starting the process of targeting the valuation metric, and many DER providers and NEM advocates may disagree with the method, for the purpose of project financing the “value of D” may lend the clarity needed to ensure the stability of the REV-driven marketplace.  To take part in the discussion over NEM and the value of DER to the distribution system, potentially interested parties are able to respond and comment to the Notice until April 18, 2016.

Topics: NY REV, Microgrid, Distributed Energy, Distributed Energy Resources, Net Energy Metering, Reforming the Energy Vision, NEM, DG, DER, value of D, Distribution, New York Public Service Commission, Distributed Generation, LMP+D

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

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

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

Nation’s Capital Explores Modernized Energy Distribution

Posted by Van Hilderbrand on 8/11/15 12:34 PM

Co-author Morgan Gerard

The District of Columbia’s Public Service Commission (PSC) opened Formal Case No. 1130 in June 2015 to explore modernizing energy distribution and the associated impacts of distributed generation and microgrids on the existing grid system. The PSC is soliciting comments on the docket until August 31, 2015. It appears that at this stage, the PSC’s interest is purely informational and that the PSC is interested in making the process collaborative. The PSC will be holding a kick off event on October 1, 2015 to set out an initial overview of the current energy distribution system in the District and to discuss the future plans of the Commission’s investigation.

DC ThinkstockPhotos-477221723The process of lighting up homes and businesses under the purview of the PSC can be divided into two components - generation and delivery. Generation was modernized in 1999 as the District was transformed into a non-utility competitive market. Today, District residents have the right to choose which company generates their electricity and can even opt-in to community solar or virtual net metering arrangements. Improving electricity distribution is the next challenge for the PSC and the city where grid resiliency, distributed generation, and energy efficiency concerns need to be balanced against maintaining grid safety, reliability, and cost-effective standards. These concerns are at the center of the PSC’s latest formal case.

The PSC is interested in distributed generation and microgrids because the nation’s capital suffers from that same challenge as other major U.S. cities - there simply isn’t enough vacant and available land to develop large scale projects. For cities to modernize and upgrade generation to cleaner resources, distributed generation in the form of residential and commercial rooftop solar, in-house combined heat and power systems (CHP), and demand-side energy efficiency upgrades may be the only options. To develop these resources, the PSC and the city must look to both incentivize the on-site generation resources and ensure their interconnectivity to the grid.

Emerging Electricity Delivery Modernization Concerns

One impact being explored in the formal case is the affect distributed generation and microgrids may have on the safety and reliability of the existing grid system as a whole. In many competitive generation states and jurisdictions like the District, the local utility maintains the distribution lines that connect grid level power producing assets to homes and businesses. As many smaller distributed generation assets come online, two concerns emerge that must be addressed. First, the distribution lines may become overwhelmed by the influx of new generation. Second, long transmission and distribution lines may no longer be the most efficient form of electricity delivery. Instead, localized distribution may be the answer to increase the efficiency of electricity production and consumption.

Microgrids play a major role in the idea of localized distribution. A microgrid is a smaller grid system that carries local distributed energy resources along local distribution lines. Microgrids can isolate or “island” themselves from the larger utility grid, thus improving resiliency as macrogrid events will not jeopardize power reliability within a particular microgrid. For example, an islanded microgrid system would have been useful in the District when an outage of a Potomac Electric Power Company (“PEPCO”) transformer in Maryland caused power disruptions in downtown D.C. and at the White House. If a system of localized generation and distribution networks had been in place, the transformer outage may not have plunged these areas into darkness.

The evolution of privately owned microgrids may be particularly challenging since the utility currently owns the entire fixed wire distribution network. Additionally, regarding distributed generation, the utility is the sole arbiter of what assets are able to come online without a regulatory or legislative mandate. Thus, the proceeding initiated by the PSC may look to address the barriers that inhibit the proliferation of these efficiency measures in the District.

PSC—Eyes on REV

In an age of carbon consciousness, energy efficiency and cyber attacks, the PSC is interested in figuring out how to make distributed generation and microgrids a part of the modern strategy. Given the early stage of this proceeding, it is unclear how energy delivery modernization will be accomplished, but the District will likely keep a close eye on the New York process for lessons learned with its Reforming the Energy Vision (REV) docket. REV is revamping incumbent utilities as “platforms for distributed technologies,” and envisions these platforms as a transmission line “gatekeepers” with grid demand response, energy efficiency, and distributed generation coordination under the utilities’ purview. The modest four page PSC Order initiating the delivery modernization proceeding is not yet proposing measures of REV proportion, but notably the New York process has been thus far a cooperative proceeding with the incumbent utilities, which may serve as a model for collaboration in the nation’s capital.

Topics: Utilities, NY REV, Energy Security, Energy Policy, Energy Efficiency, Microgrid, Distributed Energy, Solar Energy, Renewable Energy

Six Questions to Consider about Microgrids

Posted by Jim Wrathall on 7/14/15 2:30 PM

microgrid ThinkstockPhotos-156606910


What is a microgrid?

The traditional electricity distribution model can be viewed as a “macrogrid,” using a large centrally located power station to provide electricity over an extensive service territory. This model was designed during the early days of electrification with the objective of providing affordable and reliable power to as many customers as possible. However, with technological advancements, a localized microgrid may provide the multiple benefits of grid resiliency and cleaner, more efficient energy production and distribution. Regarding resiliency, the microgrid may be able to disconnect or “island” from the macrogrid, minimizing and isolating blackout incidents and providing for power redundancy. Concerning energy efficiency, the microgrid uses local sources of energy to serve local loads, reducing energy loss in transmission and distribution. Additionally, this smaller grid can more easily deploy distributed energy resources (DER) such as solar energy and combined heat and power (CHP) to meet grid demand.

Why the push towards microgrids?

As stated above, microgrids provide the dual benefits of energy efficiency and resiliency. Picture Superstorm Sandy in Manhattan, if downtown had the capability to island and maintain power notwithstanding the downed Con Edison station? Or, perhaps, picture the upper east side of Manhattan being able to provide some power to the seven million people left without electricity? Even the nation’s capitol is vulnerable, as demonstrated when a PEPCO transmission line recently took out power in downtown D.C., with power disruption affecting federal buildings including the White House Complex. Not to mention, electricity can be saved by diminishing losses from long transmission.

Ok great! Why not build microgrids everywhere?

Currently, developers face uncertainties as there is not a clear policy or regulatory path in place, thus affecting the potential to obtain private financing. Previously, we lacked the technological capability to deploy a variety of distributed generation (picture roof-top solar, a traditional combined heat and power station, and a small wind turbine working together in different locations) through a set of advanced, real-time controls to manage energy demand across the entire microgrid. While the idea of a clean-tech microgrid is relatively new, the concept of a microgrid is not so new. University campuses, military bases and some industrial parks have been operating them for years, maybe even decades, but all such grids are on a solitary campus with one stand-alone energy customer. What is new is the desire to place microgrids throughout a utility grid system servicing commercial customers, perhaps in competition with the utility. The potentially competitive relationship with the utility may be why we haven’t seen microgrids popping up everywhere, unless they are utility-sponsored.

What is the utility’s stake in microgrid adoption?

Where a third-party, non-utility provides electric generation and distribution to retail customers, the utility may have a lot at stake. The traditional model always has been the use of a macrogrid, in which a solitary utility provides both the generation and distribution of electricity for a specified geographic area, their “service territory.” Simplifying the regulatory terrain, utilities are heavily regulated in exchange for their exclusivity and must set rates through a proceeding before the state’s public service commission (PSC). This is why electricity bills typically remain constant because change can only occur in a rate making proceeding. Depending upon how the state set up its relationship with the utility (during the late 1800s or through some subsequent restructuring), the utility may own its right to exclusivity, making it very difficult for a state to change its laws.

Some states and their utilities have opened the market to multiple electricity generating entities and, for example, enabled solar providers such as SolarCity through third party roof-top leasing. However, utilities have invested a great deal of capital in fixed wire distribution systems that physically connect your homes or businesses to electricity. Microgrids would directly compete with such fixed wire distribution; therefore, utility resistance may be expected. Depending upon the jurisdiction, fixed wire distribution may be the exclusive franchise of the utility. However, some states, like New York with its Reforming the Energy Vision (REV) docket, are seeking to modify the utility relationship, showcasing the vast differences in utility precedent by jurisdiction.

Are there other obstacles to microgrid adoption?

Lawmakers and public service commissions may need to realign their energy laws and regulations to enable the clean-tech microgrid. For example, to make a private microgrid financeable, the developers will need to know approximately how many customers (ratepayers) they can lock into their grid. Many states have competition laws that allow customers to choose their electric generation supplier. This approach may disadvantage a financed microgrid, as customers may be able to switch providers. Also, it is unclear what level of regulation microgrids will experience. Are they utilities? The common answer is most likely not, but the question remains: will there be any requirements in place to prevent rate spiking? Another unknown, will the microgrid as a whole be able to net-meter to the macrogrid? What will the interconnection procedures look like? The list of uncertainties needs to be addressed to provide developers and financers with better clarity.

With all of these challenges, what is the future for microgrids?

There is accelerating momentum behind the push to deploy microgrids. SolarCity already is offering a microgrid service to collaborate with municipalities and universities. With more severe and unpredictable storms and increased vulnerability to cyber-attack, microgrids are becoming the next horizon for our energy future. Utility and policy concerns are surmountable as demonstrated by REV and the market restructurings that enabled competitive generation. To gain a foothold, the microgrid revolution will take a tailored approach to local issues, and will be led by some pioneering developers, and, perhaps, a handful of forward-thinking utilities that are ready to capitalize on a new opportunity.

Topics: Utilities, Energy Policy, Structured Transactions & Tax, Energy Storage, Energy Efficiency, Microgrid, Energy Finance, Distributed Energy, Energy Management, Solar Energy, Renewable Energy, Public/Private Partnership, Wind

EDGE Distributed Energy in Focus: How Can Hybrid Resources and Microgrids Overcome Financing Challenges?

Posted by Jim Wrathall on 7/8/15 2:48 PM


In Sullivan & Worcester’s most recent quarterly newsletter, the EDGE Advisory, we address one of the major advancements in distributed energy clean-tech, the microgrid. This year has seen major headway in the deployment of hybrid distributed energy resources and microgrids, along with accompanying innovation in financing for these solutions. Several leading players in solar, battery storage and advanced power management automation have announced major investments in new microgrid adaptable technologies.

Expanding sources of financing will be critically important to achieving growth in this emerging sector. However, hybrid distributed generation and microgrid projects raise unique operational, technology and regulatory issues that must be carefully assessed in evaluating and structuring financing. The ability of the financial markets to understand, accept and properly price these factors will impact the pace and breadth of deployment of these technologies.

Financial investors focus on several key gating and due diligence items in evaluating microgrid and hybrid projects. Major considerations include:

Wind turbine and small town in Germany• Resource evaluation and costs—economic returns on these projects are somewhat different than the standard renewable energy installation as microgrids involve an interplay of various technologies to create a small grid eco-system that may involve innovative pricing for maintaining distribution fixed-wire channels, regulatory overlay and cyber-security concerns.

• Power control technology assessment—advanced software controls are necessary to deploy multiple, and sometimes diffuse, generation sources to meet grid demand. Additional cyber-security measures may become a compulsory added cost feature.

• Portfolio aggregation—financing a microgrid entails an aggregation of assets that may be attractive to investors as a grid system may be pooled into a yieldco structure.

• Valuation of grid services—the public benefit of supplementing the macrogrid for added services like demand management may be difficult for PSCs to quantify, but may allow for opportunities for utility partnerships and perhaps supplemental income to power generation for investors.

• Valuation of grid resilience and security functions—the added resiliency and security benefits may be difficult to quantify. Valuation metrics need to be developed to determine the overall macrogrid public benefit that added energy security provides.

Microgrids present complex regulatory issues, as they involve the erection of wires, substations, conduits and other facilities that require rights of way, easements and interconnection to the larger grid. Unlike utilities, private microgrid owners do not enjoy the powers of eminent domain. Nor can they “rate base” their investments like utilities. Microgrids should be incorporated in a manner to avoid redundancies and overlaps with utility planning and facilities. Other obstacles include lack of an existing regulatory framework, unclear safety standards, utility opposition and permitting delays. With respect to utility opposition, three factors can be particularly problematic: (1) excessive fixed and stand-by charges; (2) interconnection barriers; and (3) restrictions on rights to sell back to the grid.

Financing frameworks for hybrid distributed energy and microgrid projects present unique considerations and may require time to gain acceptance by money center banks and other financial institutions. Leasing, shared savings, and portfolio models can borrow from existing approaches used for single-technology solar and wind transactions. Developers and investors looking at particular states or projects also should identify existing programs seeking to establish standard rules and procedures for addressing the regulatory issues cited above. To the extent such efforts are in process, there may be opportunities to shape the standards and ultimately to optimize prospects.

For other insights on microgrids and the future of distributed energy please see our EDGE Advisory for a full report.

Topics: Energy Security, Power Generation, Microgrid, Energy Finance, Distributed Energy, Energy Management, 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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