Energy Finance Report

Odds on an Solar Investment Tax Credit (ITC) Extension Seemingly Rising by the Minute

Posted by Joshua L. Sturtevant on 12/16/15 7:22 PM

Members_only.jpgDespite “grinchy” recent predictions from some, the solar industry looks set to receive some holiday cheer with the odds on an investment tax credit (ITC) extension seemingly rising by the minute. Many credit the ITC as one of the predominant factors behind the surge of solar in the U.S. Despite some pushback from House Republicans last week, the lower chamber is set to vote on an omnibus appropriations bill by the end of this week, which includes a five-year extension of the credit.

The five-year extension would include a three-year continuation of the current 30% credit, keeping the status quo intact through 2019. This would be followed by three years of graduated step-downs. The credit would step-down to 26% in 2020 and 22% in 2021. It would finally drop to 10% in 2022. Some have speculated that the extension was a trade for a repeal of the decades-long oil export ban, which has been a sore spot for the GOP in recent years.

Until recently, and despite some pockets of great optimism, everything from posts on this page to share prices to long faces at conferences reflected pessimism regarding the possibility of an extension. However, while the bill’s failure is always a possibility, odds on an extension for the solar investment tax credit have risen dramatically in recent weeks. In short, it looks like the optimists have won this round. Admitting that one is wrong doesn’t always have to be painful… 

Topics: Structured Transactions & Tax, Solar Energy, Renewable Energy, Oil & Gas, ITC, Oil Export Ban, Investment Tax Credit, Congress

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

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

REV Conference Recap: Opportunities for Distributed Generation in New York

Posted by Joshua L. Sturtevant 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

greenlightbulb-ThinkstockPhotos-469361066.jpg

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

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

Are YieldCos Insulated from the Looming ITC Stepdown?

Posted by Joshua L. Sturtevant on 8/7/15 6:15 AM

Co-author Morgan Gerard

With about one dozen YieldCos now trading on North American exchanges, the vehicle has seen explosive growth over the past 18 months. According a recent report by Deutsche Bank, and despite some gloominess surrounding other renewable energy investing approaches, the outlook on these structures is strong.

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.

Despite the financing advantages of YieldCos, there is overriding market uncertainty within the solar industry in the face of the expected stepdown of the Investment Tax Credit (ITC) from 30% to 10% at the end of 2016. However, Deutsche Bank is confident that many YieldCos will not feel the impact as they have “already untangled themselves” from their tax equity partners and replaced their contributions with increased debt. Deutsche also claims that YieldCos have the potential to facilitate the move to solar grid parity through capital structure, as equity is trading at a lower cost than debt.

Based on such projections, and given the ongoing uncertainty of the usefulness of the ITC over the next few years, developers should be working diligently to ensure that their project pipelines are ready for scrutiny from potential YieldCo partners. Projects should be priced accurately and account for market-rate developer and EPC fees. Standardized document suites should be utilized and transactions must be structured efficiently and in compliance with tax rules. Developers also need to avoid the trap of presenting "shovel ready" projects without any land rights, executed revenue contracts or permits in place. Taking these steps and avoiding these pitfalls is critical as anticipating and meeting the needs and expectations of YieldCo acquirers will likely be an increasingly important objective for developers heading into a stormy period.

In a recent Sullivan & Worcester newsletter, we discussed the fundamentals of the YieldCo structure. For that report as well as additional insights on the future of distributed energy, please visit our EDGE Advisory.

Topics: Structured Transactions & Tax, Distributed Energy, YieldCo, Renewable Energy

Sullivan & Worcester logo

About the Blog


The Energy Finance Report analyzes developments in energy finance as well as provides updates and perspectives on market trends and policies.

Subscribe to Blog

Posts by Topic

see all