Energy Finance Report

The New Gold Standard for Building Performance - PEER

Posted by Van Hilderbrand on 7/19/16 10:20 AM

Co-authors Jeffrey M. Karp and Morgan M. Gerard 

PEER.jpgElectricity-grid vulnerabilities were deeply exposed in the wake of Superstorm Sandy and its associated storm surge, as a single outage at a substation caused a sweeping black-out across downtown Manhattan, New York. Making matters worse, climate change science anticipates that future storms will be both stronger and more frequent.  To facilitate and improve the security, resiliency, and reliability of the macrogrid system, the U.S. Green Building Council (USGBC) has developed PEER, Performance Excellence in Electricity Renewal, the nation’s first comprehensive, consumer-centric, data-driven tool for evaluating power system performance. 

Modeled after the Leadership in Energy and Environmental Design (LEED) certification program, PEER seeks to incentivize the development of smarter buildings and communities by adopting a rating system that addresses power quality and supply availability, ability to manage interruptions and mitigate risk, and increase restoration, redundancy, and microgrid capabilities.

The expectation is that as a critical mass of buildings and developments achieve PEER certification, the electricity-grid system will become stronger and more resilient, thus preventing disasters caused by extreme-weather events.

PEER Will Help Create a Market to Capture the Benefits of Smart Grid Capabilities

Today, there are no adequate markets and metrics to capture the benefits that smart grid capabilities and smarter buildings provide to the larger electrical system, although proceedings like Reforming the Energy Vision (REV) in New York are attempting to tackle this challenge. PEER helps fill this major market gap by providing an opportunity for power technologies, systems, and other innovations to gain competitive advantage. 

The PEER program also may serve to assist in the creation of monetization pathways for service providers seeking to enable grid secure benefits.  For example, once the PEER rating system is used more broadly, commercial tenants and buyers may demand resiliency benefits for which they may be willing to pay a premium to reduce exposure to power-outages, business interruptions, and other grid losses.  For instance, a Whole Foods may be willing to pay an energy premium for the security that its refrigerators and air-conditioning will not lose power in a storm event, hedging the risk of spoiled stock.  Similarly, an investment bank with on-site servers may also be willing to pay the premium for the security that their servers will not stop trading—preventing potential losses from reconciliation events.  Thus, PEER may bring new participants into the energy mix such as main street corporates and traditional real estate firms as they learn about the benefits of and opportunities provided by expanded demand response capabilities, distributed renewable generation, and smart grid readiness.

Projects eligible for PEER certification may involve everything from retrofits to existing buildings and infrastructure, to a newly developed business campus. Projects first must be registered with the Green Business Certification Inc. (GBCI), which administers the LEED certification program, as well as several other performance standards rating certifications.  GBCI provides a toolkit for developers to self-screen projects and prepare their application for certification.  To achieve certification, projects are considered against four metrics: (1) reliability and resiliency; (2) energy efficiency and environment; (3) operational effectiveness; and (4) customer contribution.  The PEER process is relatively new, with only a few projects working their way through the new program, but once the new standard catches on certifications are expected to increase.

Microgrids, the Nation’s Capital, and PEER

A particular concern for national security is the susceptibility of the District of Columbia to flooding and black-outs due to its close proximity to several rivers. This concern has prompted the White House to announce significant targets for federal buildings to combat grid vulnerabilities and the D.C. Public Service Commission to further examine grid modernization through an open case, Formal Case 1130.

Earlier this month, USGBC and GBCI, in partnership with Urban Ingenuity, sponsored a meeting to support the District of Columbia’s efforts to encourage the development of microgrids, generally a localized, self-contained, contiguous power generation system within close proximity to demand. Microgrids provide grid efficiencies and resilience because they can “island” themselves off from larger macrogrid disturbances.  Thus, during a stress event on the macrogrid, microgrids can help service the larger system, isolate the event and prevent it from causing sweeping outages, and serve as a “power oasis” to the affected public.  

The development of microgrids are the kind of project that will be supported by a PEER evaluation and certification. The availability and widespread acceptance of PEER’s metrics will serve as a tool to incentivize the development of microgrids and other types of energy innovations that help facilitate movement of the electrical system towards a smarter-grid marketplace.  

 

The Energy Finance Report will continue to monitor PEER as the program matures.

Topics: Distributed Energy, Renewable Energy, United States Green Building Council, USGBC, LEED, Resiliency, Performance Excellence in Electricity Renewal, PEER

Hedging with Distributed Renewable Generation Sources in Times of Fossil Fuel Price Volatility

Posted by Joshua L. Sturtevant on 3/11/16 2:20 PM

Volatility_Ahead.jpgCo-author Morgan M. Gerard

Until very recently, mainstream power purchasers have not viewed renewable energy as a reliable hedge against other energy sources, mostly because the costs associated with constructing or purchasing the output of renewable energy systems were very high. However, renewable energy generation systems are increasingly being viewed by large and small consumers alike as a viable hedge against fossil fuel price volatility.

Two main factors have contributed to this. First, recent price declines in both hard and soft costs have precipitated a decline in installation costs. In other words, systems are cheaper to install, making renewables more attractive on an absolute basis. Second, myriad models for both direct ownership and third party ownership have allowed beneficiaries of renewable systems to lock-in long-term pricing certainty. Against this backdrop of profound changes to the cost and ownership structure of renewable energy sources, volatility in natural gas prices has forced power consumers to evaluate the attractiveness of alternatives.

Renewable Energy Prices are Falling

The price of constructing renewable energy projects has dropped precipitously in recent years. For example, according to the Department of Energy (DOE), wind power prices have reached an all-time low, and Power Purchase Agreements (PPA) for wind fell from rates around 7 cents/kilowatt-hour (kWh) in 2009 to an average of 2.4 cents/kWh in 2014. Dramatic price declines have been seen in the solar space as well. For example, between 2008, and 2014, the cost for a PV module declined from $3.57/watt (W) to about $0.71/W. Total install costs declined due to these hardware declines, the reduced soft costs brought about by DOE and industry efforts, and the increase of standardization in contract terms: the total cost of utility-scale PV systems fell from $5.70/W in 2008 to $2.34/W in 2014—a decrease of 59%. Additionally, Deutsche Bank recently predicted that the price of solar would reach grid parity in most states this year. That prediction seems increasingly sound in the face of the extensions of the Investment Tax Credit (ITC) and Production Tax Credit (PTC) late last year.

 Renewables Provide Price Certainty for Offtakers

It is both the decline in costs noted above and the ability of renewable sources to provide cost certainty over long time periods that allow these sources to be utilized in a hedging capacity. Consumers benefit from the output of renewables in two main ways. The first is through direct ownership, also called ‘on balance sheet’ ownership. The second is through a contractual relationship with a third party owner, typically through a lease or a Power Purchase Agreement (PPA). Direct ownership is most prevalent among large, sophisticated entities such as utilities and corporates, while contractual relationships predominate in residential and commercial and industrial (C&I) contexts, though these are by no means hard and fast rules.

Regardless of whether the system is on balance sheet or not, the usefulness of the system as a hedge is simply a function of cost certainty. In the context of an on balance sheet system, there is a known up-front cost and relatively easy to calculate annual costs in the form of insurance and maintenance; once the solar or wind facility is built the owner of the generation source will be able to forecast his fixed costs over the lifetime of the project. In the context of a contractual relationship such as a lease or PPA, the costs are typically clearly known by the consumer as contracts are often set price, or contain an easy to calculate escalator. While obvious, is also important to emphasize what is not a part of the long-term cost structure of renewables; fuel inputs. Given that costs are possible to calculate, the lack of input prices, and the fact that certainty is locked in for the long-term due to long asset lives and contracts terms, renewables provide the best widely available opportunity for long-term energy pricing certainty in existence.

The contrast against traditional sources could hardly be more stark. According to the Wall Street Journal, as natural gas has become an increasingly prominent fuel in the international energy mix, increasingly erratic weather patterns (like El Nino and last year’s polar vortex) have sent commodity traders “scrambling.” Data from BNP Paribas SA shows that realized volatility (a measure of day-to-day price moves) hit an eight-year high for the two-month period covering this past December and January. Additionally, natural gas trading in 2014 “was four times as volatile as the U.S. stock market by that measure, the data shows.”

Renewables May Provide for Future Additional Cost Savings and Revenue Streams

On top of current cost savings and hedging opportunities, renewables have the added benefits of both producing monetizable environmental attributes and helping owners avoid added costs related to carbon production in the future. Environmental attributes already have value in some jurisdictions, and it seems likely that list will grow with the implementation phase of the Clean Power Plan potentially looming and developments such as New York’s Reforming the Energy Vision program underway. Additionally, it has been reported that one of the goals of COP 22 will be the implementation of a “carbon tax”. While it seems unlikely that the U.S. would sign up to a carbon tax regime in the near term, the likelihood of it doing so within 10, 15 or 20 years seems potentially higher. In addition, given that fossil fuel markets are global in nature; additional carbon tax programs abroad could conceivably impact volatility in the U.S., another factor that makes a potential hedge in the form of renewables attractive.

Conclusion

Renewable energy has traditionally been more expensive for the output provided than fossil fuel sources. Additionally, as a result of the energy boom in North America consumers in the United States have paid slightly lower prices for electricity in recent years. On a strictly short-term basis, it is often true that traditional sources are cheaper than renewables. However, the extreme volatility that exists in commodity markets reduces the ability of consumers to effectively account for their fuel costs in the long-term.

In contrast, the price declines in renewable energy sources coupled with the ability to accurately account for long-term costs have made renewables attractive, and consumers have taken notice. Berkshire Hathaway Energy has already adopted renewables as a fuel-hedge for its various portfolios. Additionally, tech players like Google, Apple and Microsoft are all experimenting with distributed renewable energy to take control of their energy consumption regarding both price and source. Big box stores like Wal-Mart, Walgreens, and most recently Whole Foods, have chosen renewables not only as an environmentally responsible energy choice, but a smart fiscal choice as well. Even as the price of traditional energy remains relatively low, a combination of commodity price volatility in that space and price declines in the renewables space have led consumers of energy to find renewables to be an attractive alternative.

Topics: Distributed Energy, Solar Energy, Renewable Energy, Distributed Generaton, Wind Energy, Grid Parity, Natural Gas, Volatility, Natural Gas Volatility, Electricity Price

Solar Storm- Net Metering in Nevada

Posted by Joshua L. Sturtevant on 1/29/16 2:13 PM

Co-author Morgan M. Gerard

Battles over net energy metering (NEM) policy are currently raging nationwide, and are only expected to intensify in the face of the recent investment tax credit (ITC) extension. NEM, a state statute-Solar_Storm_.jpgbased policy incentive that allows small generators of electricity to sell their excess generation into the grid typically subject to an overall cap, has been a great contributor to the proliferation of residential rooftop solar. It has also stimulated commercial and industrial-sized facilities in some locations, particularly those jurisdictions that allow for the slightly more complicated ‘virtual’ net metering approach. 

However, as solar has gained greater market penetration, utilities have increasingly pushed back against NEM. As with many issues, the arguments on both sides of the NEM debate are complicated. Opponents, typically utilities, claim that NEM policies shifts pro rata grid costs from solar customers onto the rest of their rate-paying base. They also argue that the rates being paid to the small producers are too high. NEM advocates, on the other hand, claim that these arguments are overblown, and are merely smokescreens promoted by utilities more worried about embedded monopoly powers than pro-rata grid costs.

Even in jurisdictions where support for the practice remains, such as New York and Massachusetts, debates are occurring over the value of solar, grid cost sharing and caps, suggesting that the net metering of today may not look like the net metering of tomorrow. In other places, proponents are undermining net metering policies by using a ‘death by one thousand cuts’ approach, where benefits are chipped away to the extent that policies are rendered functionally moot.

Perhaps nowhere has this latter approach more prevalent in recent times than in Nevada where clashes have occurred at the legislative level, in front of the Nevada Public Utilities Commission (NPUC), and have more recently spilled over to the courts.  After the NPUC surprisingly voted to enact changes which would essentially render the current NEM regime unviable, residential solar customers filed a class-action law suit on January 12 against their utility alleging, among other things, that NV Energy is seeking to monopolize energy production by crippling the solar market. They also allege that rising rates have caused net metering customers to experience a 40% cost-hike. 

How did the debate over NEM in Nevada get to this point?

Nevada has been one of the fastest growing solar markets in the country in recent years, particularly in the residential space. Rapid growth allowed the state to reach its 3 percent solar net metering cap in August of last year, leading the NPUC to extend payments under the old program until the end of 2015 to buy time to evaluate next steps. However in December, the NPUC voted to cut net metering payments by half while simultaneously raising the fixed fees for solar customers to around 40% by 2020. Additionally, the NPUC is applying these changes retroactively, which distinguishes actions in Nevada from those in other states that have altered their net metering, and means these new prices will apply not only to new solar customers, but to existing customers as well. 

This decision was met with significant backlash by local solar companies, customers and advocates and even gained the attention of the three major Democratic candidates for the 2016 presidential election. As a result of the decision and a general lack of support for solar, three major solar companies have decided to pull back significantly from Nevada. For example, Vivint suspended its plans to expand into Nevada right after the August cap was reached, but continues to release statements condemning Nevada’s continued actions as a barrier to it ever deciding to reenter the state. SolarCity announced on January 6, 2016 that it was ceasing operations in Nevada, thus eliminating more than 550 jobs and closing its newly minted training center.

Sunrun has also declared its exit from Nevada citing the actions of Nevada politicians, the NPUC and NV Energy. Additionally, on December 24, 2015, the Nevada Bureau of Consumer Protection filed a petition with the NPUC, explaining that the new ruling “is not consistent with the Governor's stated objectives of SB374 or the governor's initiatives and focus to increase jobs and employment for Nevada residents. Now, solar customers have joined the fight by filing the class-action suit with similar allegations against the NV Energy.

Potential Ripple Effects

In the wake of the extension of the ITC, many believe that debates in the solar space will take on a distinctly local flavor in the years to come. In the absence of an extension, it was likely that solar projects would have had difficulty attracting low cost capital.  However, with federal incentives secured, many believe that solar in general, and the residential market in particular, are set to explode over the next few years.  Although the credit extension will likely positively impact solar development, it has also made battle lines clear and has provided ammunition for opponents of rooftop solar who will now strategically pick at other incentives, arguing that the extension has rendered them unnecessary. Nevada provides a good, early example of this.

It is also true that as more distributed solar comes online, grid management policies will need to be reexamined to ensure both fairness and continuity of service. Recent battles at state utilities commissions have resulted in favorable outcomes for proponents of solar. However, if the NPUC ruling is a sign of the times, it is possible that it could be a bumpy road ahead, particularly in states nearing their NEM cap. 

Topics: Distributed Energy, Solar Energy, ITC, Net Metering, Net Energy Metering, Investment Tax Credit, NEM, DG, Distributed Generaton, rooftop Solar, Rooftop PV, NPUC, Solar Rooftop, Solar Roof, Nevada, NV Energy, Net Metering Battle, Nevada Public Utilities Commission

New York City Examines Issues Facing Rooftop Solar

Posted by Morgan Gerard on 1/20/16 11:39 AM

Kramer_Testimony.jpgThe New York City Council is considering a breakthrough bill to mandate installation of solar power systems on all municipal buildings.  The Big Apple in many ways has already taken the initiative and adopted policies to promote cleaner air and combat the local greenhouse gas emissions that contribute to climate change. To this end, the de Blasio administration has articulated the goal of reducing greenhouse gas emissions by 80 percent by 2050.  Merrill L. Kramer recently testified at a hearing on the bill where he applauded the Council’s initiative, but also discussed the private market challenges facing roof-top solar that may hinder the Mayor in achieving his carbon reduction goals.  Particularly, Mr. Kramer identified delays and bottlenecks at the Department of Buildings (DOB) and New York City Fire Department (FDNY) for obtaining permit approvals, and the lack of a "one-stop shop" decision-making authority to identify problems and implement processes for streamlining permitting.  Mr. Kramer highlighted the manual review process for solar permit applications as the single largest obstacle to deploying roof-top generation, causing delays for projects already on a tight timeline. The State of New York offers city residents a property tax abatement for the value of their panels, which expires at the end of the year. 

Mr. Kramer offered three recommendations: that new regulations be adopted to "Permit the Use of Full Professional Self-Certification for All Solar Rooftop Installations," that the FDNY implement "E-Filing and Other Automated Procedures" to streamline the variance process, and that "an ad hoc Solar Task Force composed of empowered representatives of the Administration" be established together with solar installers, homeowners, and other stakeholders to improve processes and programs to expedite solar deployment and lower the cost of installations. Mr. Kramer concluded by saying he and the solar community are "encouraged by the Administration’s commitment to eliminating obstacles to the use of solar power in the City. These steps will have the effect of allowing more and more New York City residents to convert to solar power, reducing the costs and burdens on the City, increasing employment, improving the air, and making the Mayor’s solar initiative a success."

Merrill L. Kramer's video testimony can be found here.

The full text of Merrill L. Kramer’s testimony before the New York City Council can be found here.

Topics: Distributed Energy, Solar Energy, New York City, DG, DER, Distributed Generaton, New York City Solar, New York Solar, rooftop Solar, Rooftop PV, new york city rooftop solar

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

2015 Year in Review - Renewable Energy in the U.S.

Posted by Joshua L. Sturtevant on 12/23/15 3:33 PM

2015-_Green.jpgCo-author Morgan M. Gerard

Despite the low price of oil throughout the year, 2015 may have been an inflection point for renewable energy as a competitive generation source in the U.S. Deutsche Bank has noted that renewable sources, like solar, have reached, or will soon reach, grid parity with fossil fuel sources in many states. As non-fossil energy has become more economically viable, the industry has responded by standardizing and streamlining project processes, and by accessing financing vehicles like yieldcos and public bonds. Despite growth, the past year has also been a tumultuous one full of unexpected developments and policy shifts including the COP 21 agreement and the Clean Power Plan (CPP), and the formation of intriguing grassroots coalitions, like the green tea party. All of these developments were, of course, set against the specter of a potential step-down of the Investment Tax Credit (ITC), and its surprising last-minute revival. The following is a breakdown of some of the major developments impacting renewables in 2015.

COP 21

On the world stage, nearly 200 leaders, including representatives from key nations such as the United States, China, Russia and India, adopted an agreement that seeks to reduce global emissions. Expectations were tempered going into the much-anticipated conference with France calling for a binding treaty, and the U.S. balking at an arrangement that would almost certainly be struck down by a Republican-led Congress. In the end, the agreement established a long-term goal of maintaining a temperature rise “well below 2 degrees Celsius.” To achieve this objective, each country must submit emissions targets by 2020 with an ongoing reporting requirement. This victory for climate change advocates may serve as a leading indicator for a growing market for renewables.

The Clean Power Plan

The Clean Power Plan serves as the unofficial, yet primary domestic implementation framework for the COP 21 agreement. The CPP was promulgated by the Environmental Protection Agency (EPA) under its Clean Air Act (CAA) authority to regulate ambient emissions from stationary sources. The final Plan sets a target of a 32 percent decline in carbon dioxide emissions from 2005 levels by 2030, and contemplates a much larger role for renewables in the nation’s energy mix. Under the CPP each state will submit a compliance plan to achieve the emissions targets by retiring coal fired facilities, increasing natural gas as a fuel source and incorporating more renewables.

However, as the year draws to a close, the final disposition of the plan is far from certain. Hours after the regulation was published in the Federal Register, twenty-seven states filed more than 15 separate cases against the EPA, which have been consolidated before the U.S. Court of Appeals for the District of Columbia Circuit. In support of the CPP, 18 states, including New York and California, have sought to defend the EPA.

Before the merits of the case are even addressed, 2016 will see a three-judge panel address a “stay” of the rule, which halts the CPP’s implementation until the litigation is finalized. The parties seeking the stay, including West Virginia, feel that by meeting their prescribed standard they will be irreparably harmed. Renewable energy advocates argue that the granting of the stay could greatly damage the efficacy of the rule and its ability to be implemented in accordance with CPP (and unofficially COP 21) targets.

Solar_Panels_and_Wind_Farm.jpgThe Production and Investment Tax Credits

While the U.S. government has sought to assist the nascent renewables industry through tax credits in recent years, through most of 2015 the long-term status of the Production Tax Credit (PTC) and Investment Tax Credit (ITC) appeared grim. The PTC has been the great driver of the wind industry as it provides 2.3 cents per kilowatt-hour generated by a wind facility. Its expiration in 2014 led to a noticeable drop off in new wind projects. The ITC, which has been the driver of solar and also serves as a potential alternative credit for wind, provides a credit for 30% of the development cost of a renewable project, and is applied as a reduction to the income taxes for that person or company claiming the credit. The ITC was originally slated to be cut from 30% to 10% for non-residential and third-party-owned residential systems, and to zero for host-owned residential systems by the end of 2016.

Congress had been considering a PTC extension, which passed the Senate earlier this year. However, many thought an ITC extension was “off the table,” despite the fact that the reduction in credit value would render solar as unviable in many areas of the country. Thus, the industry was swept by uncertainty throughout the year. After solar businesses spent the past year reconsidering their business models to ease the pain of the step-down and speeding along projects to clear the credit requirements, Congress, to the surprise of industry, authorized the extension of both the PTC and ITC. The ITC will now be in place for an additional five years, including three years at the current value, followed by three years of more graduated step-downs. The impact of the ITC extension is set to be significant, and will likely inject new life into abandoned projects, protect existing jobs, support additional job creation and ensure that the renewables sector remains poised for an upward growth trajectory.

Yieldcos

In addition to using tax equity, larger solar companies have been able to raise public funds through the “yieldco” approach. Yieldcos are dividend growth-oriented companies, typically created by a parent company that bundles renewable and/or conventional long-term contracted operating assets in order to generate predictable cash flows. With about one dozen YieldCos now trading on North American exchanges, the vehicle has seen explosive growth in the last year.

The cost of capital required for energy projects has been reduced via the YieldCo model due to access to cheap corporate debt and as their use of standardized project structures and documents have lowered transaction “soft” costs. YieldCos have created efficient homes for the assets that large companies formerly kept on their balance sheets and have additionally allowed nascent entities to raise relatively cheap capital for acquisitions. They have also facilitated diversification of the renewable energy investor base as typical dividend-focused individual investors have been able to "go green" as an alternative to low yield bonds in a way that has been difficult in a tax credit-driven environment. Arguably, this has lowered return expectations, and therefore the cost of capital, further.

However, despite significant growth in 2015, the future of the YieldCo model is less than certain as the fourth quarter of 2015 saw great variability in YieldCo share prices. The reasons are myriad with theories addressing MLP values, rising interest rates, negative public statements from management teams, a slowing Chinese economy, lower oil prices, capital constraints and YieldCo disassociation from parents entities all being floated as potential reasons for recent losses in shareholder value. While it is important to decouple share price from the ability of a YieldCo to remain in business, lower share prices paired with rising interest rates could hinder the ability of many entities to continue to grow portfolios and dividends at current rates.

Distributed Energy Resources—Grid of the Future Proceedings

ThinkstockPhotos-178976522_1.jpgIn the wake of super-storm Sandy and the ensuing power outage to downtown Manhattan, the New York Public Service Commission (NYPSC) is proactively exploring revamping incumbent utilities to better incorporate Distributed Energy Resources (DERs) to ease the transition toward a more dynamic and robust energy generation and distribution system. DERs present a challenge to the tradition grid system, which only envisions energy flowing in one direction, typically from one large source located far from the end user. The proliferation of DER has caused a grid issue in that energy now flows bi-directionally—from the utility customer’s generating system into the utility.

NYPSC’s Reforming the Energy Vision (REV) docket envisions many user-sited DERs that will sell capacity into the system or to other energy consumers. Utilities will act in a new capacity, Distributed System Platforms (DSPs), as “gatekeepers” to a multi-sided platform market with the utility functioning as the platform provider. The utility will facilitate the transaction between the DER owner/operator and the consumer.

Similarly, California is also experimenting with incorporating and leveraging DER formally within their grid framework. The California Public Utility Commission is in the process of facilitating the utilities to develop distribution resource plans (DRPs) that incorporate DER into utility grid-planning and investment regimes. Currently, the Commissions’ mandate is for the utilities to determine the value of DER to their systems, specify where on their systems DER should be incorporated, and propose demonstration projects.

Solar in the Southeast

Developments in several Southeastern states, such as North Carolina, Georgia, Florida and South Carolina are highlighting changing shifts in attitudes toward solar in previously unfriendly jurisdictions. Policymakers in the Southeast are enabling both increased utility scale solar and the introduction of rooftop generation. For example, the Georgia legislature, thanks in part to a coalition comprised of environmentalists and conservative Republicans known as the green tea party, passed the Solar Power Free-Market Financing Act of 2015. The new law opens up third-party ownership of leased rooftop solar projects up to a maximum of 10 kW generation capacity.

Similarly, in South Carolina, utilities were required to submit their plans to implement the Distributed Energy Resource Program Act (DERPA), which mandates programs to achieve at least 2% renewable energy adoption by 2021, including plans to invest in or procure distributed resources. Earlier this year, Southern Carolina Electric & Gas (SCE&G) and Duke Energy reached separate agreements with state regulators, ratepayers and environmental advocates on programs for meeting this objective. SCE&G committed to invest $37 million to install approximately 84 MW of solar on the state’s electric grid by 2021, including 42 MW of utility-scale solar and 42 MW of residential, commercial-industrial, and community solar. Duke Energy agreed to a $69 million program to place in service 53 MW of utility-scale solar and 53 MW of residential and commercial solar.

Net Metering Debates

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 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 maintained that costs are shifted to non-net metering customers. The utility recommended 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.

Regulators and legislators from Nevada and California are considering whether NEM has run its course as a method to encourage solar adoption, or if the policy is a fair method of compensating rooftop generators. Utilities argue, not without merit in some cases, that they are purchasing electricity at a dollar rate greater than what it would take them to generate an equivalent amount of electrons. Moreover, electrons are only part of the story, as utilities still need to provide solar customers with standby power and voltage support to turn on their appliances and open their garage doors. Thus, NEM is heavily tied into the “grid-of-the-future” discussions as utility’s role evolves from vertical integration to DER network operators.

Offshore Wind

One of the drawbacks to renewables increasing their percentage share of the domestic energy mix is that these sources are intermittent with solar PV only generating electrons when the sun shines and wind turbines only turning when the wind blows. However consistent power - base-load - is still required, usually in the form of a fossil-fueled plant, or a nuclear facility. Offshore wind has long been touted as the next big addition to the U.S. energy mix since the wind blows harder and more consistently offshore, which would potentially allow this renewable energy source to replace some portion of base-load. Offshore wind had a rocky start in the United States as these large infrastructure projects face difficult regulatory obstacles, including a maze of permitting and environmental laws and requirements as well as classic NIMBY issues. One prominent example is the first proposed off-the-coast wind farm, Cape Wind, which has faced 14 years of litigation surrounding its development process. However, many are hoping that the start of construction of the Block Island Wind Farm off the coast of Rhode Island will trigger a gale force of offshore wind energy

Looking Ahead to 2016

The year ahead shows promise for the U.S. renewable industry—the COP 21 agreement and CPP set the stage for policies to drive and incentivize renewables, new states are opening as potential markets for both utility scale and residential rooftop solar and grid systems across the country are adapting to incentivize greater DER deployment. The stabilizing extension of the ITC and PTC ensures that these energy sources remain financeable in the New Year, and new financers may feel comfortable entering the market as the industry matures. With these policies in place, the U.S. has the opportunity to deploy more renewable infrastructure to meet stated targets, and those working in the renewable energy industry have cause for cheer this holiday season.

Topics: NY REV, Energy Policy, Energy Finance, Distributed Energy, YieldCo, Solar Energy, Renewable Energy, Wind, COP21, Renewable Energy 2015, Distributed Energy Resources, CPP, Green Tea Party, Net Metering, Net Energy Metering, NEM, DG, Energy Project Finance, Renewable 2015, Green Energy, Green Energy 2015, Solar Energy 2015, DER, Offshore Wind, Clean Power, clean power plan, Georgia Solar, 2015, energy, Wind Energy, Energy Project, Green 2015, California DRP

California’s Net Metering Rates Preserved, but Debate over the Value of Solar is Ongoing

Posted by Joshua L. Sturtevant on 12/16/15 1:17 PM

Co-author Morgan M. Gerard

Utilities_NEM.jpgMany of the polices that helped enable the proliferation of rooftop solar installations in California, specifically net metering at the retail rate of electricity, have been preserved by the state’s Public Utilities Commission (CPUC), at least for the time being.  Although net metering has come under fire in recent years, the Commission in a proposed decision issued this past Tuesday, sided with the solar industry despite utility claims that rooftop generators are overcompensated for their electricity, and do not share in covering the maintaining costs of the grid.   

The Cases For and Against Net Metering

Net metering in California allows solar generators to sell excess generation back into the grid at the retail rate of electricity.  This mechanism sounds simple in theory; however, grid management in an age of distributed generation (DG) is becoming increasingly complicated. Hundreds of megawatts of solar electricity are produced in California during sunny hours when residents are not at home that flow through to the grid. This output suddenly and dramatically drops off  during periods of cloud cover and in the evening peak hours when traditional plants are needed to prevent the interruption of power.

Additionally, utilities argue, not without merit in some cases, that they are purchasing electricity at a dollar rate greater than what it would take them to generate an equivalent amount of electrons.  Moreover, electrons are only part of the story as utilities still need to provide solar customers with standby power and voltage support to turn on their appliances and open their garage doors. 

On the other hand, the rooftop solar industry is still in its relative infancy and installation can be expensive to homeowners. Net metering provides a mechanism to help manage the costs. In 2013, as more rooftop solar entered the system, California passed state law AB 327, which mandated that utilities evaluate the costs and benefits of DG to the grid, including the future of the net metering program. This summer, the utilities submitted to the CPUC Distributed Resource Plans (DRP) that proposed mechanisms that make the deployment of DG cost effective and beneficial to the grid. However, this grid evaluation opened the door to a contentious dispute over net metering, with many solar proponents advocating that net metering is a fair form of compensation, and that any attempt to adjust its rate is an attack on the new industry.

The CPUC sided with the solar industry in its decision, and declined to impose new demand charges, grid access charges, installed capacity fees, standby fees or fixed similar fees to net metering customers. Despite a big win, there are some new considerations for solar, including the CPUC’s proposal to include a one time connection fee and non-by passable charges used to subsidize low-income and efficiency programs.

Time of Use Pricing on the Horizon

The next battle appears to be time-of-use (TOU) pricing, where customers are charged real time for the price of electricity. Under this framework, the solar energy generated during off-peak hours would be priced significantly lower than the energy produced by utilities during peak hours.  TOU, in theory, is simply supply and demand economics—when the demand for electricity is great, the price is higher. However, TOU may lack price transparency as solar customers may not readily understand tariffs and the value of their over generation.

Rooftop Solar Battlegrounds and Considerations

Battles like those taking place in California are taking place in commissions across the country as the grid modernizes. It is unclear what the future holds for net metering, as many predict additional challenges to come. Even in states where net metering is not currently empowered and states have not initiated “grid-of-the-future” proceedings, the value of DG and its effects on the grid will be a continuous debate going forward. Although the battles over net metering may be just the growing pains for a maturing solar industry, the potential for an ITC extension, decreasing costs, federal mandates like the Clean Power plan and current and future state programs will likely ensure the attractiveness of solar going forward. 

Topics: Energy Policy, Distributed Energy, Solar Energy, Renewable Energy, Net Metering, Net Energy Metering, California Public Utilities Commission, NEM, CPUC, DG, Time of Use Pricing, TOU, Distributed Generaton, Distributed Resource Plans, DRP

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

Discussing the Investment Tax Credit- Panel at MDV-SEIA’s Solar Focus

Posted by Joshua L. Sturtevant on 11/23/15 10:37 AM

I moderated a panel at MDV-SEIA’s Solar Focus event to discuss what is arguably the hottest, most impactful topic in the solar space today – the Investment Tax Credit (ITC), and specifically, its scheduled step-down at the end of calendar year 2016.

The ITC is a controversial topic. Arguably, and while this is probably not a popular opinion among readers of this page, the 30% ITC may have run its (very successful!) course. Hardware and install prices have plummeted in recent years. Traditional capital markets are being accessed through bond offerings and YieldCos. Even stodgy holdout utilities in the southeast are becoming more active in the solar space. More solar has been built in recent quarters than any other generation type.

And yet . . . solar remains a small part of the overall generation mix, and many states, including those with great insolation numbers, remain untapped markets. Some have estimated that up to one hundred thousand jobs might be in jeopardy if the step-down occurs. An ongoing 30% ITC would make it easier for many states to comply with their potential Clean Power Plan (CPP) obligations. The U.S. is arguably at the cusp of a real shift in its energy mix that might be delayed, if not derailed, if the credit is not extended.

As noted before, the panel was excellent. Tony Clifford, the CEO of Standard Solar and a very vocal proponent of an ITC extension, discussed the ways industry participants can support the ITC extension effort. Sara Rafalson of Sol Systems walked through a very visceral representation of what a drop to a 10% solar ITC would look like in individual states. Finally, Scott Hennessey of Solar City discussed federal legislative updates.

Some key takeaways from the presentations and the robust Q&A that followed:

  1. A 10% ITC renders most state markets unviable at a 7-8% cost of capital – the Northeast and California may still be in play (but expect overcrowding).
  2. An extension has garnered increasing Republican support in the Senate (the House is another matter).
  3. The Solar PACs have had real trouble keeping up with opposition spending due to lack of donation support.
  4. The panelists seemed to agree that ‘start of construction’ is the extension path with the greatest odds.

For additional insights into efficiently maximizing ITC and business planning for a potential post-ITC environment, contact Josh Sturtevant at [email protected].

Topics: Energy Policy, Structured Transactions & Tax, Energy Finance, Legislation, Distributed Energy, YieldCo, Solar Energy

Are Seesaw Share Prices Impacting YieldCo Buying Power?

Posted by Joshua L. Sturtevant on 11/12/15 11:57 AM

Make money.YieldCos have been hammered lately, both in the stock market (though things have recently been picking up) and in the press. The reasons are myriad with theories addressing MLP values, rising interest rates, negative public statements from management teams, a slowing Chinese economy, lower oil prices, capital constraints and YieldCo disassociation from parents entities all being floated as potential reasons for recent losses in shareholder value.

Over the past year or so, many have become hopeful that the YieldCo model, in the absence of an IRS-compliant Renewable Energy REIT structure, would become a viable way to access relatively cheap public market capital for transitional energy projects. Thus far, that has played out according to plan, as the YieldCo form has exploded. The question now becomes, do the current issues with share price deflate those hopes in any way? Should developers be concerned about the ability of YieldCos to be viable asset buyers?

While it is important to decouple share price from the ability of a YieldCo to remain in business (to a point) there is one important aspect of recent share price declines that everyone with an interest in renewable energy markets should pay attention to. From a recent Seeking Alpha piece:

…YieldCos need to issue new shares (generally at higher prices than their IPOs) from time to time to raise capital for new investments as most of their cash flow gets wiped out by paying dividends. However, they are facing difficulties on this front due to depressed renewable energy stocks and an oversupply of YieldCos in the market, making investors reluctant to pay higher prices.

Compounding this problem is the fact that it is highly likely that debt issuances will, at some point in the short- to medium-term, become a more expensive proposition. Today’s rates are historically low, and despite its occasional equivocation, the Fed has been preparing the market for rises in the discount rate, which will indirectly impact borrowing costs for corporate issuers. In short, more expensive capital may make it difficult for YieldCos to buy more assets, thus hindering the ability to increase dividend growth in a cycle some have compared colorfully to a Ponzi scheme.

While it would be disingenuous to suggest that an inability to raise new capital is not problematic in the long-term for YieldCos and those that sell assets to them, they have cash and investment appetite in the near term. With the ITC step-down looming, the near term is what most developers, looking to sell over the next 12-18 months, are concerned about at present.

If the premise that YieldCos are viable partners through the ITC step-down is true, developers and other sellers of projects should consider what their projects would need to be saleable. While we have preached the benefits of standardization, project readiness and on this page in the past, certain principles stand repeating in the face of transacting on an accelerated timeline with sophisticated counterparties. Market-ready document suites should be used. Tax structuring should ensure optimization of benefits under IRS-compliant structures. Projects need to be ready for primetime and not presented as ‘shovel ready’ if they aren’t as it is unlikely that Yieldcos will be willing to take on much in the way of completion risk.

Even if publicly-traded YieldCos are viable partners in the short-term, recent negative perceptions may have asset sellers shifting their gazes elsewhere. For those looking to move away from these partners, it could be a good time to consider private models that are funded by sources such as pension funds and insurance companies with lower return expectations than traditional sources and therefore greater ability to both monetize developers’ projects and exhibit staying power after the ITC drop off.

While the share price roller coaster investors have been on may not be that amusing, asset sellers shouldn’t be any more concerned about counterparty risk with YieldCos than they were earlier this year. YieldCos remain a viable counterparty in the near term and, while they may indeed have trouble raising capital in the future as share prices lag, and as cheap debt becomes harder to come by due to the decoupling of these entities from their parent’s balance sheets and the threat of a rising interest rate environment, the ITC step-down should be a far greater concern, both on a macro level and in the context of time.

Disclaimer: The above is not intended to be, nor should it be construed as, investment advice.

Special thanks to Morgan Gerard who assisted in the preparation of this post.

Topics: Energy Policy, M&A, Structured Transactions & Tax, Power Generation, Energy Finance, Distributed Energy, YieldCo, 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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