Energy Finance Report

Renewables Can Play a Big Role in Puerto Rico's Fresh Start

Posted by Jeffrey Karp on 6/27/17 11:23 AM

This article originally appeared on Recharge.

Just two years ago, the future seemed promising for renewable energy development in Puerto Rico. Much of the groundwork was established, numerous developers had entered into Power Purchase Agreements (PPAs) with the state-owned utility, PREPA, and discussions were ongoing with funding sources.

However, decades of fiscal irresponsibility and bad deals finally caught up with Puerto Rico, leading to a terrible debt crisis. The government defaulted on bonds, sales taxes escalated to 11% (higher than any mainland state), and businesses began fleeing the island.

The generous incentives that initially had attracted development dried up. For the last couple of years, energy investment has been at a virtual standstill, with the exception of Oriana Energy’s solar plant that commenced operations in May 2017.

Despite these setbacks, and with the Commonwealth’s [government's] bankruptcy filing in May 2017, the Puerto Rican government now has a second chance to regain its financial footing, and the development of renewable energy may play an integral part in accomplishing such a task.

In 2010, the Commonwealth enacted Renewable Energy Portfolio Standards (REPS) that required 12% of the island’s electricity to come from renewable sources by 2015 and 20% by 2035. Following the enactment of the REPS, utility PREPA entered into dozens of PPAs with renewable energy developers agreeing to purchase the power to be generated. By the end of 2015, Puerto Rico had 318MW of renewables in place, according to latest available data from the International Renewable Energy Agency.

However, as Puerto Rico became mired in its debt crisis, developers were unable to secure financing as investors grew fearful of funding long-term energy deals with PREPA. Adding to the uncertainty, due to PREPA’s financial woes, the utility serially renegotiated the terms of developers’ PPAs, which only served to make investors more jittery about financing the underlying renewable energy projects. Eventually, most of the agreements expired before the power plants could be financed or built.

Despite its financial travails, Puerto Rico’s commitment to renewable energy has not waned. In June 2016, Congress passed the Puerto Rico Oversight, Management and Economic Stability Act (PROMESA). The legislation, intended to provide Puerto Rico with a pathway out of its debt crisis and establish a baseline for fiscal responsibility, also established the framework within which investment may occur. In providing a blueprint for interested investors, PROMESA also reaffirmed Puerto Rico’s commitment to renewable energy.

Recognizing that PREPA was incapable of shouldering the burden of energy development entirely on its own, PROMESA emphasized the need for public-private partnerships that shifted the initial funding burden to private investors. In April 2017, a P3 Summit was held to encourage developers and investors to collaborate with the Commonwealth on a wide variety of infrastructure projects, including energy, water, waste management, and transportation. The presentation on the energy sector reaffirmed Puerto Rico’s commitment to achieving the REPS of 20% renewable energy by 2035.

In setting the stage for infrastructure investment, PROMESA created an Oversight Board, which has authority over revitalization and infrastructure development. Importantly, the Oversight Board may “fast-track” projects deemed “critical,” such as projects that reduce the Commonwealth’s reliance on oil and diversify its energy sources. Moreover, the Oversight Board gives priority to privately-funded projects.

Following PREPA’s recent settlement with its bondholders, we understand the utility is ready to reengage with developers to amend PPAs that have been in limbo for several years. Many of these developers already have performed much of the engineering for these renewable energy projects. Once PREPA amends the extant PPAs, the underlying projects would qualify as “existing projects,” which would enable the Oversight Board to prioritize them.

In light of these recent fiscal and regulatory developments, investors again are inquiring about “shovel ready” renewable energy projects that require funding. Investors also may have gained a level of comfort having seen Oriana Energy successfully reengage in Puerto Rico. Since May 2017, the company is operating the largest solar plant in the Caribbean at 58MW, the power from which PREPA is purchasing pursuant to a renegotiated PPA.

Puerto Rico appears primed for renewed interest by energy investors. For several years, investors have been unwilling to accept the risks inherent in financing long-term energy projects in which PREPA is the counterparty. More recently, these concerns have shown signs of abating as PREPA has successfully engaged with its bondholders, and the Oversight Board created by the PROMESA legislation appears to have imposed an acceptable level of fiscal discipline on the Commonwealth.

With solar energy on the cusp of coming to Puerto Rico, the question is which financiers will enter the market soon enough to bathe in the sunlight.

Jeffrey Karp is a partner in the Washington, D.C. office of Sullivan & Worcester LLP and leader of the firm’s Environment, Energy & Natural Resources practice group. Zachary Altman, an associate, and Paul Tetenbaum, an intern at the firm, were co-authors of this article.

Topics: Energy Finance, Renewable Energy, Energy Investment, Puerto Rico, Power Purchase Agreements, Renewable Energy Portfolio Standards

Opportunities Abound in the U.S. Offshore Wind Market

Posted by Jeffrey Karp on 5/30/17 12:52 PM

Offshore wind projects have taken root in America. The country’s first operating offshore wind farm, in Block Island, Rhode Island, began contributing energy to the power grid in December 2016. Now, more than 23 offshore wind projects — collectively expected to produce 16,000 MW of power — reportedly are being planned. Thus, opportunities abound for developers, contractors, and investors in the U.S. offshore wind market.

The recent spike in offshore wind activity has been fueled largely by a surge of political interest. Some critics have decried President Trump’s apparent lack of commitment to renewable energy, but the U.S. Department of the Interior (DOI) has proved to be a willing partner in offshore wind energy development. In March 2017, DOI leased 122,000 acres off the coast of North Carolina to Avangrid, a subsidiary of Iberdrola, a Spanish company. Recently, DOI also finalized a lease with a Norwegian company, Statoil, for Long Island, New York waters. DOI evidently sees a future for U.S. offshore wind. According to a spokesperson, the Bureau of Ocean Energy Management currently is receiving annual rent payments of over $4 million for offshore wind project leases.

State activities also have primed the pump for offshore wind development. In August 2016, Massachusetts Governor Charlie Baker signed a law requiring utilities to procure 1,600 MW of electricity from offshore wind facilities by 2026. In May 2017, the Commonwealth’s Department of Energy Resources issued a request for proposals to develop up to 800 MW of offshore wind. New York Governor Andrew Cuomo announced that the state would commit to installing 2,400 MW of offshore wind by 2030, furthering his goal that renewable energy resources would supply 50% of New York’s power. To that end, in January 2017, Governor Cuomo approved Deepwater Wind’s 90 MW, 15 turbine South Fork Wind Farm project, which is expected to power 50,000 Long Island homes.

Moreover, the Maryland Public Service Commission recently awarded two developers, U.S. Wind and Skipjack Offshore Energy, contracts to build offshore wind farms totaling 368 MW. The projects are expected to create 9,700 new direct and indirect jobs.

With each completed project the supply chain grows stronger and developers become more efficient, making each successive project more cost-effective. For example, the estimated total cost of the South Fork project already has decreased 25% since Deepwater Wind’s first projections, and the energy generated is expected to cost 30% less per unit than at Block Island. Furthermore, the Department of Energy predicts that the cost of offshore wind energy will fall 43% by 2030. As this trend continues, there will be greater incentives to promote offshore wind as a clean energy resource.

Also, each successful project increases investor confidence. Deepwater Wind, developing its second offshore wind project, is owned by D.E. Shaw, a hedge fund and private equity firm managing over $40 billion in assets. Moreover, both Citigroup and HSBC have expressed interest in financing future offshore wind projects.

The U.S. offshore wind market is growing rapidly and approaching maturity. State and federal government actions appear to support a long-term horizon for offshore wind development. With every completed project, production and financing costs will continue to drop, the market will grow, and new jobs will emerge. The question now is whether the players in the renewable energy market — developers, investors, contractors, and vendors — are well-positioned to reap the rewards of this burgeoning industry.

Jeffrey Karp is a partner, Zachary Altman is an associate, and Leigh Ratino is a law clerk with Boston-based law firm Sullivan & Worcester LLP.

Topics: Energy Finance, Renewable Energy, Energy Investment, Energy Project Finance, Offshore Wind, Wind Energy, Energy Project

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

Is Preparing for an ITC Stepdown the Same as Preparing to Fail?

Posted by Joshua L. Sturtevant on 12/11/15 3:12 PM

Solar_Finance.jpgThe scheduled stepdown of the solar Investment Tax Credit (ITC) from 30% to 10% at the end of 2016 has become a bit of a political football among the pro-solar crowd. Even mentioning the possibility of a stepdown occurring can lead to accusations of negativity from extension advocates. However, despite the negative connotations of discussing the ITC in the context of a decline rather than an extension, it would behoove participants in the solar markets to at least consider what life at 10% could mean to them. That is particularly true after a whirlwind of a week in Washington that, if anything, has made the fate of the ITC murkier than ever.

Anyone hoping for clarity on the possibility of an extension issue would have a hard time sifting through all of the data points that were floating around the market this week. It’s probable that even lawmakers had trouble keeping up with all the insertions and removals from various committees’ versions of the extenders package as well as a rife rumor mill that included whispers of a possible GOP offer to extend for a year. Even the exact nature of an extension is unclear, as everything from a straight extension to a more graduated stepdown to a start of construction rule has been mooted.

Despite headwinds created by the difficult operating environment that has been the hallmark of U.S. politics in recent years, advocates have been arguing strenuously in favor of an extension and their logic is sound. An extension of the ITC would certainly make for an easier operating environment, particularly for developers and suppliers going forward. An extension would also seem to make sense in the context of broader national goals and initiatives. For example, many states that have lagged behind leaders in deploying solar are currently working on legislative changes to third party ownership rules, net metering and other policies that might prove fruitless if the value of the ITC were to decrease. Additionally, the transition to the implementation phase of the Clean Power Plan (CPP) would certainly be eased by an extension.

It is also true that solar energy is no longer just a ‘blue’ issue. For example, Senate Republicans have been recently showing signs of support for an extension. The Green Tea Coalition groups in the Southeast and religious groups advocating for solar, not to mention job growth in red regions, have all ensured that it is no longer just Greens calling for support for solar.

However, despite some impassioned vocal support and some solid logic behind extending, the extension is no sure thing. In stark contrast to some of the data points above is the reality that a recent Republican uprising in the House and a Congress, which is expressly setting itself against a lame duck President, make deal-making a difficult proposition. Additionally, it stands repeating that the stepdown, already on the books, faces an uphill battle, whether principals are willing to come to the table or not.

It has been notable that, despite support for the major CPP initiative and a leadership role in the Paris talks, the Obama White House has not been inclined to show much public support for an extension. Perhaps it has been determined that the CPP will allow long-term goals to be accomplished, while the job losses in the short-term are viewed as a casualty to pure economics and the business cycle. Perhaps the White House simply has bigger fish to fry.

Given the uphill nature of the battle the solar industry is currently fighting, it would be prudent for business leaders to spend time preparing for an extension-free outcome. This could mean different things to different companies of course; M&A activity could increase as some will seek to become acquired and some will become acquisitive in the hopes that scale could provide insulation against negative outcomes. Others will shift business models to exploit boutique opportunities, or will depend on contractual relationships with solid partners to ensure continuity. However, not considering these options, or others, is akin to being the ostrich who sticks its heads in the sand at the sign of danger; ignoring the issue doesn’t ensure that it will go away.

Anecdotally, solar energy advocates seem to be overwhelmingly in favor of an ITC extension. While it is likely not a necessary factor in the long-term success of the technology, which is increasingly proving itself on its own merits, it is also true that a timely extension would increase the likelihood of short-term solar growth, particularly in the C&I sector. An extension will also almost certainly insulate tens of thousands of jobs from elimination over the next 18 months. For these reasons, it makes sense for the industry and its advocates to argue strenuously for an extension. Based on the events of the past week, it seems that the odds on an extension are potentially rising. Our best guess is that a start of construction rule will make its way into an Appropriations bill.  

However, despite best efforts, it may just end up being the case that the credit is not extended. Even if it is, a start of construction rule will still cause disruption in the market, as has been the case in the wind industry multiple times in recent years. Because of the possibility for turbulence, managers should be planning for a less stable future. Management teams have fiduciary obligations to investors (often friends and family in the solar world), contractual obligations to partners and customers and moral obligations to employees. To fail to prepare for the stepdown, or at least a bumpy ride, is to fail in those obligations and is short-sighted, particularly since there is still time to put plans in place to address various contingencies.  However, the clock is ticking…

Topics: Energy Policy, Energy Finance, Solar Energy, Renewable Energy, ITC, Investment Tax Credit

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 jsturtevant@sandw.com.

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

Roundtable Discussion: Distributed Energy Opportunities in the Mid-Atlantic

Posted by Joshua L. Sturtevant on 11/11/15 10:34 AM

Blog PictureAs energy infrastructure is adapted to achieve greater energy efficiency and resiliency to combat threats from storms to terrorism, distributed generation (DG) has emerged as an opportunity for investors and developers who want to play a part in the modernization.

On November 5, 2015, Sullivan and Worcester and SEIA co-hosted a roundtable discussion to explore DG opportunities in the D.C., Maryland, Virginia and Delaware region. The panel was comprised of industry experts with diverse perspectives, and included 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 (WGL).

Mr. Hendrix explained that the panelist’s approach to DG is a bit like the Indian proverb of group of blind men who, upon touching very different parts of an elephant, try to describe what they felt. They are all describing part of the same animal, but are only expressing what is within their grasp. The modernization of energy infrastructure in the mid-Atlantic is somewhat similar in that there are disparate parties in the form of private developers, utilities, regulators and consumers all contributing to developments on the ground.

Supporting Bracken’s proposition, the panelists each described their view on the future of DG in the region. Mr. Moore of Washington Gas provided his perspective that “DG is in WGL’s DNA,” suggesting that DG sources are simply viewed as part of the generation mix at WGL, an increasingly common approach among utilities. Ms. Sleeper and Mr. Hendrix explained the industry’s position that Property Accessed Clean Energy (PACE) financing provides opportunities for property owners to take control of their ability to “go solar” and support DG. Mr. Vanamali added that policy goals should reflect the notion that the transition to a DG smart-grid should not leave behind the low-income community and create DG technology “deserts.”

As the market comes to grasp with DG, Commissioner Hoskins noted that although Maryland has not opened a “grid of the future” docket, the consequences of DG are being discussed currently throughout various proceedings all over the country. If the viewpoints of diverse grid participants are going to be heard and considered, greater participation in Commission dockets is needed and would improve the outcome.

A brief excerpt of the event can be found here.

Topics: Energy Policy, Energy Efficiency, Energy Finance, Distributed 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

Avoiding Distressed Sale Situations in Solar

Posted by Joshua L. Sturtevant on 11/3/15 7:26 AM

Time to use solar energyThe word on the street is that completion risk heading into the scheduled, dreaded investment tax credit (ITC) step down is already becoming an issue for solar developers. In short, there is a general fear on the part of market participants that solar projects currently in development won’t meet the IRS’s qualifications for being placed in service before the end of 2016, when the ITC is scheduled to decline from 30% to 10%. This would make many projects in the current environment economically unviable.

For debt and sponsor investors, making the wrong bet on renewable projects would amount to incurring an opportunity cost as commitments to failed projects would foreclose capital deployment elsewhere. There would be a similar story for tax equity investors – perhaps compounded by the fact that tax equity is more ephemeral in nature than other sources.

Unlike debt and sponsor investors who could, short of some other restriction, redeploy capital in the new year; tax equity investors have limited opportunity to play around with tax periods thanks the ITC step down, and may lose undeployed tax liability or at least find it difficult to shift that liability to another project. For developers, this ITC story is perhaps most catastrophic as they depend on asset sales to recoup development costs and overhead, hopefully with a margin on top. Most asset buyers are incredibly weary of taking on the risk described above. Anecdotally, this has meant that large projects without permitting completion are already, over a full year before the ITC step down, facing a bit of an uphill battle to get financed. It can be expected that larger commercial and industrial projects will face similar obstacles over the next few quarters, if they haven’t already.

As the last round of tax equity of this current great wave of solar projects tries to find a home, some developers may intend to place completion risk bets intentionally and aggressively by holding fire sales at the end of the year. However the laws of supply and demand would seem to dictate that, in most cases, the opposite story will be the more prevalent one – that tax equity dollars will have the pick of the litter with respect to projects. While returns could be maximized by a few, it seems more likely that a game of high stakes musical chairs will leave some developers with this strategy without a tax equity capital source – or perhaps with offers far below their return thresholds.

Even a distressed market scenario is far from a sure bet. While plain vanilla investment theory tells us that everything has a price, that doesn’t always play out in real life, particularly in the solar development world. Recent events in Puerto Rico lend support to this exception to the rule as orphaned projects there in the wake of repayment shenanigans by the government have made it clear that some risks cannot be overcome, even at cut rate prices. It is unclear whether completion risk will be viewed the same way as credit risk, but the situation in that undercapitalized territory does provide a stark guidepost.

Developers need to be taking steps now to avoid the pain described above later. In many cases, they will need to be ready to provide completion guarantees to buyers, which need to be backed by real balance sheets – whether their own or that of an EPC backstop. Insurance products could provide another solution. Some may need to accept higher soft costs in the form of legal and tax opinions on placed-in-service dates. This will be the case even if, or maybe especially if, lawmakers shift the ITC to a ‘start of construction’ type regime to mirror what has been done to extend the usefulness of the production tax credit (PTC) in the wind space.

To ensure maximized returns, developers should therefore use all haste in ensuring that key components of their projects are done – and done right. Permits need to be pulled as soon as possible, interconnection costs need to be finalized, land needs to be secured and offtakers must be signed. It also increasingly looks like it will mean addressing the supply disruptions that may already be occurring. It finally means avoiding gaps and utilizing market-ready document suites for all counterparty agreements. All of this is true, even if it means deploying more speculative capital than most are used to.

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

Topics: Energy Policy, Structured Transactions & Tax, Energy Finance, Distributed Energy, 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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