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

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

Nevada Solar Update: Senator Harry Reid Takes On Warren Buffet’s Berkshire Hathaway in Net Metering Debate

Posted by Jim Wrathall on 9/8/15 8:00 AM

Nevada ThinkstockPhotos-78779262

Co-author Morgan Gerard

Nevada’s solar net metering policies will continue until year end, perhaps in part thanks to Senator Reid (D-NV) who threatened to intervene in the state’s Public Utilities Commission’s (PUC) review of the policy. Senator Reid, a staunch renewable energy advocate, believed that residential solar in Nevada had gotten a “lousy deal,” and pointed the finger at Warren Buffet’s Berkshire Hathaway. The Silver State’s Senator was referring to changes to Nevada’s net metering program, which gave solar-rooftop homeowners credit for system’s over-generation up to an aggregate of 3% of the peak load of Nevada’s Berkshire Hathaway-owned utility, NV Energy. As solar installations quickly neared the 3% cap, renewable advocates struck a compromise with NV Energy in supporting Senate Bill 374, which raised the limit to 235 megawatts of residential systems to qualify under net metering through the end of the 2015.

NV Energy had assured the legislature that this cap wouldn’t be reached until 2016; however, the net metering boundary had again been reached, and to catastrophic effect for some solar installers. The second largest U.S. rooftop solar installer, Vivint Solar, ramped up operations in July in reliance on enjoying stable net metering policies. In response to learning the cap was nearly at capacity, Vivint exited the state after only two weeks of operation, leaving a warehouse and 30 employees in its wake.

The deal struck with the Senate’s bill also moved jurisdiction over the broader net metering issue to the PUC, which approved an extender on the existing net metering and rebate policies to stabilize the residential market. The PUC will re-review net metering polices and grid costs before the end of the year, and NV Energy has submitted a thousand page proposal to include new fees, taxes and a nearly $14 demand charge for rooftop solar system owners.

This demand charge would force solar systems owners to in essence pay a “premium” for demanding electricity from the grid based on their peak usage during the month. Solar users would be charged for electricity by NV Energy: first, with a basic service charge; second, an energy consumption charge, based on total consumption in a given month; and third, for demand, based on the highest capacity required during the given billing period, measured in 15-minute intervals during that month’s billing cycle. Thus, NV Energy’s demand charge would require the peak demand each month to be multiplied by $14, a hard hit for any homeowner’s electric bill.

While NV Energy is promoting policies that make roof top solar potentially uneconomic, Warren Buffet has boosted his holding company’s massive investments in large-scale renewable energy—an attractive investment in the state due to Nevada’s ample solar incentives for industrial sized installations for businesses and power companies. The state has enacted a sizeable Renewable Portfolio Standard (RPS) and provided property tax exemptions for utility-scale projects. Although, as the holding company is monetizing the federal Investment Tax Credit (ITC) and taking advantage of these favorable state policies, residential roof top solar has lagged behind due to a combination of an ad-hoc interconnection policy, historically inconsistent solar rebate programs and lack of a residential property tax exemption. Net metering was among the incentives available to homeowners to become self-generators; however, the battles over the cap are disincentivizing the growing industry.

Utilities maintain that solar, net metering customers are not participating in contributing to the fixed costs of the grid and shifting costs onto non-solar customers while still reaping the benefits of consistent grid power. Although solar energy has only reached a one-percent penetration rate in the United States energy mix, the storyline in Nevada is unfolding all over the country as utilities grapple with distributed generation. Some states are moving towards more utility owned renewables, like in South Carolina where the local utilities are mandated to submit plans to include and procure distributed energy resources. On the other hand, New York and California are experimenting with different rate schemes that would allow the utility to survive and perhaps thrive in a distributed energy environment. The Nevada Public Utilities Commission is set to vote before December 31, and Senator Reid is set to interfere stating that the “monopolistic attitude that no longer works and the utilities can’t keep people from generating their own electric power in a diversified and much greener system.”

Topics: Utilities, Energy Policy, Legislation, Distributed Energy, Solar Energy, Renewable Energy

Offshore Wind Has Come to the U.S.; EPCs Can Help It Gain Momentum

Posted by Jeffrey Karp on 8/27/15 10:08 AM

Co-authors Jim Wrathall, Van Hilderbrand and Morgan Gerard

Offshore wind energy could add 4.2 million megawatts to the generating capacity of the U.S., according to the National Renewable Energy Laboratory, but the U.S. market has stalled almost completely, hindered by regulatory uncertainties, political opposition, litigation and a lack of available financing. Recently, however, several broad market and regulatory themes have emerged—record low energy prices, technology improvements, the start of construction of the first commercial offshore project near Rhode Island’s Block Island and increasingly favorable federal and state policies for renewables such as the Clean Power Plan—that give reasons to believe that the sector has reached an inflection point in 2015. The question now is how to build and sustain the momentum.

Please see our publication on ENR.com for more information about offshore wind: Offshore Wind Has Come to the U.S.; EPCs Can Help It Gain Momentum

Topics: Utilities, Energy Policy, Structured Transactions & Tax, Power Generation, Energy Finance, Legislation, Wind

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

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

Lessons from the Recent NY REV Conference

Posted by Joshua L. Sturtevant on 8/7/15 10:14 AM

Several members of the S&W Energy Finance Team attended Infocast's recent NY REV Summit. Speakers ranged from utility and regulator representatives to CEOs of technology and service providers, all eager to discuss the latest in New York's ongoing Reforming the Energy Vision (REV) proceeding. Several key themes emerged during the two day event:

1. Collaboration between stakeholders to ensure a viable final rule is key. While the Department of Public Service (DPS) has, by all accounts, been running a very efficient and inclusive stakeholder feedback process (despite a lack of participation by consumer rights groups), it will not be surprising to see more divergent views emerge as details emerge and implementation becomes more imminent. Therefore, it may become increasingly difficult to keep all stakeholders in the fold.

2. Structuring the rule to avoid FERC (and other regulatory) issues is a concern. Many expect REV to serve as a template for other states going forward. It can similarly be viewed as a test case/battleground for those who stand to lose out under alternative power futures. Many speakers mentioned early-stage collaboration with the FERC to ensure that later challenges are avoided, or at least more easily overcome.

3. Technical issues need to be resolved. Several speakers noted that cyber security risks associated with giving generation responsibilities to independent entities is a very real issue that needs to be contended with. The idea of overcoming the hurdles caused by handling 'two way traffic' with antiquated metering and distribution equipment was also discussed.

4. The role of utilities - and repercussions of changing roles - need more thought. While the conceptual shift of utilities toward transmission entities has merit, challenges in the form workforce retraining/redeployment, legislatively mandated rates of return, losses of shareholder value and transfers of property all need to be addressed.

5. Reliability cannot be ignored. Even if the ultimate vision of widespread, clean distributed generation is highly desirable to many New Yorkers, many speakers noted that there would also be little tolerance for reductions in reliability along the way. This could have practical implications for the time it takes to transition from the current status quo to the new vision - and proponents may need to pragmatically accept that lead times on these changes could be measured in years rather than months or quarters.

For the latest on REV, readers can review the latest DPS white paper which was released last week. Additional background can be found in last year's "Reforming the Energy Vision" staff report. Energy Finance Report readers should also keep their eyes open for a save-the-date for S&W's own REV event on October 1st, and can contact Josh Sturtevant for more details.

Topics: Utilities, NY REV, Energy Policy, Energy Finance, Distributed Energy

Senate Energy Bill Includes Funding For Smart Energy and Water Efficiency Pilot Projects

Posted by Jerry Muys on 7/29/15 10:08 AM

In an era conscious of water scarcity, the water-energy nexus made the agenda of the Senate Energy and Natural Resources Committee, which is considering broad based, bi-partisan legislation, the “Energy Policy Modernization Act of 2015.” The nexus between water and energy refers generally to the fact that the provision of water and wastewater services tends to be highly energy intensive, while most types of power generation tend to be highly water intensive.

Water pipesA provision in the bill that has received surprisingly little attention in the industry press would require the Department of Energy to establish a “smart energy and water efficiency pilot program” that would award grants to a limited number of utilities, municipalities, water districts, Indian tribes and Alaska Native villages, and other authorities that provide water, wastewater, or water reuse services. The grants would fund pilot projects that “demonstrate unique, advanced, or innovative technology-based solutions” to the so-called water/energy nexus -- the policy challenge posed by fact that conventional energy production tends to be highly water consumptive, while the provision of water-related services tends to require large amounts of energy.

Although the eligibility language of the bill is somewhat imprecise, it appears that the grants would be limited to technologies that (1) increase the energy efficiency of water, wastewater and water reuse systems; (2) otherwise improve such systems to help communities make measurable progress in conserving water, saving energy, and reducing costs; (3) support the implementation of innovative and unique processes and the installation of established advanced automated systems that provide real-time data on energy and water; or (4) improve energy-water conservation and quality and predictive maintenance through technologies that utilize internet connected technologies, including sensors, intelligent gateways, and security embedded in hardware.

Grants would be awarded based on: (1) energy and cost savings; (2) the uniqueness, commercial viability, and reliability of the technology; (3) the degree to which the project integrates next-generation sensors software, analytics, and management tools; (4) the anticipated cost-effectiveness of the pilot project through measurable energy efficiency savings, water savings or reuse, and infrastructure costs averted; (5) whether the technology can be deployed in a variety of geographic regions and in a wide range of applications; (6) whether the technology has been successfully deployed elsewhere; (7) whether the technology was sourced from a manufacturer based in the United States; and (8) whether the project will be completed in 5 years or less.

The bill would authorize the appropriation of $15,000,000 to fund the program. Grant recipients would be selected not later than 300 days of enactment of the legislation.

The Energy Finance Report is closely monitoring the progress of the Energy Policy Modernization Act of 2015, which has so far been quiet on renewable energy generally. As waste heat, particularly in water based heating systems, is anticipated to be next big horizon for energy efficiency, the Senate Finance Committee’s grant may be a step in the right direction for the water/energy efficiency industry.

Topics: Water Energy Nexus, Utilities, Water, EPMA, Energy Policy, Energy Management

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