Energy Finance Report

Managing Grid Security in a Distributed Energy Environment

Posted by Jeffrey Karp 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

Are Seesaw Share Prices Impacting YieldCo Buying Power?

Posted by Jeffrey Karp 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

Mid-Atlantic: Distributed Energy Opportunities

Posted by Jeffrey Karp on 11/3/15 11:58 AM

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

Programs and developments of particular note include:

- Net metering and renewable portfolio standards in Maryland

- PACE financing in Montgomery County, Maryland

- Discussions around undertaking a REV-like proceeding in Maryland

- Interconnection standardization in D.C.

- Microgrid studies being undertaken in D.C.

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

- Renewable portfolio standards and net metering in Delaware

- Community solar innovations and discussions throughout the region

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

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

REV Conference Recap: Opportunities for Distributed Generation in New York

Posted by Jeffrey Karp on 10/21/15 11:38 AM

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

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

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

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


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

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

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

photovoltaic cells and high voltage post.

Co authors Van P. Hilderbrand and Morgan M. Gerard

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

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

The Final Plan’s Approach to Carbon Emission Reduction

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

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

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

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

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

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

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

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

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

State Incentives

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

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

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

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

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

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

Property Owners Increasingly Embracing Energy Efficiency Technologies

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

Co-authors Josh Sturtevant and Morgan Gerard


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

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

Energy Savings Performance Upgrades

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

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

How to Finance Your Energy Systems?

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

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

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

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

Additional Benefits and Revenue Streams

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

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

Continuous Barriers Need to be Addressed

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

Conclusion - A Paradigm Shift

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

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

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

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

Co-authors Jim Wrathall, Van Hilderbrand and Morgan Gerard

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

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

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

Is the Tide Turning for Offshore Wind in the United States?

Posted by Van Hilderbrand on 8/6/15 11:58 AM

BLOG_offshore wind turbines_ThinkstockPhotos-505771725

Co-authors Jeff Karp and Jim Wrathall

Offshore wind has long been touted as the next big addition to the U.S. energy mix. With the start of construction of the Block Island Wind Farm off the coast of Rhode Island, many are hoping the project will trigger a gale force of offshore wind energy. Offshore wind resources are abundant, stronger, and blow more consistently than land-based wind resources. The U.S. Department of Energy (U.S. DOE) estimates that 4 million megawatts (MW) of capacity could be accessed in state and federal waters along the coasts of the United States and the Great Lakes.

Indeed, macro energy supply, economic considerations, and climate-related concerns support the development of U.S. offshore wind projects in regions such as New England and the Mid-Atlantic. As traditional fossil-fuel power plants are retired from states’ energy portfolios, offshore wind energy is ready to step into the void to help meet demand through a renewable medium.

Still, offshore wind in the United States remains in its infancy. Large scale offshore projects face difficult regulatory obstacles, including a maze of permitting and environmental laws and requirements. This is no more evident than in the long-awaited 130-turbine Cape Wind project in Nantucket Sound off the coast of Massachusetts, which remains in limbo after more than a decade of planning, regulatory proceedings, and federal court litigation. Other proposed projects off the coasts of New Jersey and Delaware have succumbed to these obstacles as well.

The Outlook for Offshore Wind Energy is Bullish as All Eyes Turn to the Coast of Rhode Island

At the moment, attention is focused on the first commercial-scale offshore wind project to commence construction: Block Island Wind Farm, off the coast of Rhode Island. Deepwater Wind, the project developer, estimates the proposed wind project will generate over 100,000 megawatt hours of energy annually, supplying the majority of Block Island’s electricity needs. The first of five 1,500-ton foundations, which will support the 30 MW project, was installed last month. The project is expected to begin producing energy in late 2016.

There is optimism that if this project succeeds, it will open the door for other economically sound offshore wind projects. And, as discussed below, the factors that previously impeded development of such projects are beginning to line up favorably, thus causing industry leaders to be bullish on the future of offshore wind.

BLOG_offshore wind turbine_ThinkstockPhotos-100815677Regulatory and Legal Clarity: It is important to note that the current road block for the Cape Wind project is purely economic. During the project’s pendency, many of the regulatory and legal uncertainties driven by challenges from opponents were resolved in court rulings. Earlier this year, however, the project stalled over financing issues when its energy off-takers withdrew from their power purchase agreements. Previously, other uncertainties were resolved by the passage of the Energy Policy Act of 2005. In particular, questions of federal versus state jurisdiction and the authority of the federal government in waters up to 200 miles from the shoreline were resolved by this legislative action, which established permitting authority in the Bureau of Ocean Energy Management (BOEM), a federal agency within the Department of the Interior.

The Block Island project has clearly benefited from lessons learned by Cape Wind, as witnessed by the speed with which the former moved through the offshore wind approval process. Although the Block Island development is in Rhode Island state waters, Deepwater Wind already has “steel in the water” as a result of collaborative efforts of state regulators and BOEM. The federal agency timely awarded a right-of-way (ROW) grant for an eight nautical mile-long, 200-foot wide corridor in federal waters on the OCS for transmission to connect the wind farm to the mainland.

In part, these achievements occurred due to Deepwater Wind’s successful engagement with stakeholders. The project developer worked closely with the U.S. Army Corps of Engineers to analyze the potential environmental effects of the project under the National Environmental Policy Act, and received a Finding of No Significant Impact (FONSI) in late 2014. Also, environmental groups like the National Resources Defense Council (NRDC) were engaged and their concerns addressed by altering the construction schedule to allow migratory whales to mate from November through April, and agreeing to utilize the best available technology to protect marine life from sound harassment.

Favorable Political Climate: The political climate for offshore wind also appears to be brightening. The U.S. DOE has promulgated a national plan to support deployment of 10 gigawatts (GW) of offshore wind capacity by 2020 and 54 GW by 2030. Additionally, there remain glimmers of hope that federal wind tax incentives will remain in place, with the Production Tax Credit (PTC) extender bill passing the Senate Finance Committee in July 2015. Moreover, the U.S. Environmental Protection Agency’s final Clean Power Plan, which was announced on August 3, 2015 by the Obama administration, requires a 32 percent reduction from 2005 levels in carbon emissions from existing power plants by 2030. To reach this goal, the plan incentivizes states to implement zero-carbon emitting sources of energy, such as solar and wind.

Additional Leases: The availability of lease sites, a crucial factor for successful project development, also appears to be trending upward. BOEM, in conjunction with several coastal state governments, is poised to open the procurement process in New York and New Jersey, while stakeholders presently are being engaged in North Carolina and South Carolina. On the other hand, there are less than ten active leases, which were awarded on a competitive basis. Recipients of these leases must submit to BOEM a Site Assessment Plan and Commercial Operation Plan for approval. Thus, a BOEM-issued lease does not authorize any construction; instead, it paves the way for a full Environmental Assessment (EA) which adds at least a year onto a project’s timeline before ground breaking may occur. Acquiring projects in mid-development is also an option, but proposed lease assignments are also subject to approval by BOEM.

Financing: Obtaining project financing has been a challenge too. Financiers are wary of unproven technologies and the other risks associated with offshore wind energy, preferring to fund land-based resources with which they are familiar. Although offshore wind is a proven energy producing technology in Europe, the same can’t be said for the U.S., where the only examples are failed projects.

BLOG_offshore wind turbines_ThinkstockPhotos-465147453Yet, the landscape seems to be shifting on the financing front as well. The Cape Wind project blazed a trail through the federal and state permitting landscape identifying and removing many of the administrative and regulatory obstacles that had haunted offshore wind projects. The Block Island project secured its required $290 million in debt and equity financing earlier this year. Given the relative speed with which the Block Island regulatory approvals were obtained, regulatory risks may become less of a concern for investors. It bears reminding, however, that the Block Island project is small compared to other pending offshore projects, which have price tags in the $1-3 billion range. That said, having secured the needed permits, successfully navigated the regulatory reviews, and obtained financing, there is reason for optimism that the Block Island project will open the door for future offshore wind projects.

One such 68-turbine project being planned by US Wind, Inc., off the coast of Ocean City, Maryland, will be capable of generating 500 MW of electricity. To cover the project’s nearly $2.3 billion cost, the company plans to pursue a mix of financing mechanisms including a substantial state subsidy to be repaid after the turbines are constructed and operating. Another project from the same developer as Block Island, Deepwater Wind, is Deepwater ONE also in Rhode Island Sound. This planned 150-200 turbine project will be capable of generating from 900 to 1,200 MW. It too will carry a much larger price tag than the Block Island project. Thus, the proponents of these projects and others will look to Block Island’s success to help overcome investor reluctance to finance offshore wind projects.

Offshore Wind is Poised to Fulfill Expectations

With added certainty in the regulatory and legal landscape and a more favorable political climate, financing opportunities are poised to increase as the technology and financing models are proven. Thus, the offshore wind industry finally may fulfill its promise as a crucial resource that will curb greenhouse gas emissions and help wean the U.S. off fossil-based fuels. The Block Island project is the first to have “steel in the water,” but we believe it will most certainly not be the last.

**Sullivan & Worcester served as pro bono counsel for the Conservation Law Foundation, assisting the non-profit organization’s participation as an amicus curiae party in the federal court litigation supporting the proposed Cape Wind project.

Topics: Carbon Emissions, Energy Policy, Power Generation, Energy Finance, Legislation, Distributed Energy, Renewable Energy, Wind

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

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


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

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

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

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

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

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

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

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

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

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

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

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

Costa Rica: Future Solar Hotspot or Never Was?

Posted by Jeffrey Karp on 3/25/15 7:16 AM

power solar panel-467712912

Co-author Van Hilderbrand

Many U.S. solar developers, possibly with an eye toward declining state and federal incentives on the horizon, have recently been casting their gazes toward foreign shores in an effort to diversify their pipelines. Despite having to contend with currency issues and political risk, doing so may not be a stretch to national developers who are already battle tested from navigating dozens, if not hundreds, of domestic policy jurisdictions.

Perhaps naturally, given proximity to the U.S., many such development efforts have focused on Central America and the islands of the Caribbean. It is also perhaps natural, that given its commitment to its natural resources, its stable political environment, and its relatively stable currency, that many developers have focused on Costa Rica. Unfortunately for the enterprising developer, recent reports have noted that the isthmian nation is already “totally environmentally friendly,” using only energy from renewable sources in the first 75 days of 2015. That is no aberration, as close to 94% of its energy was generated by renewable sources in 2014. Additionally, the government is bringing a large geothermal facility on line soon. Given the state of affairs, U.S. solar developers looking to Costa Rica for short-term fixes to project pipeline shortages should probably cast their gazes elsewhere.

However, for those with a longer-term outlook, the future of solar in Costa Rica could be bright. Up to 80% of the energy capacity of Costa Rica is supplied by hydro-electric plants, which the nation hopes to decrease its dependence on given the impact that this generation source can have on the environment. Additionally, a positive long-term growth rate, a median age of around 30 years old, and successful governmental efforts to increase economic development all point to a rise in capacity requirements going forward.

The development cycle for large generation assets can be time consuming in Costa Rica, fraught with multi-step approval processes and bureaucracy, and complicated by rules about local ownership. These all serve as stimulants to begin work far before boots will actually hit the ground. Despite some current short-term market signals to the contrary, those who take the long-term positive view of solar in the land of “pura vida” would be prudent to take action sooner than later.

Please contact any member of the Energy Finance Team if you have questions regarding development in Costa Rica.

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


Topics: Power Generation, Solar Energy, Renewable Energy

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