Energy Finance Report

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

Reforming the Energy Vision (REV) Round Table Discussion

Posted by Joshua L. Sturtevant on 9/25/15 9:51 AM

skyline manhatten

New York’s Reforming the Energy Vision (REV) proceeding has the potential to change the way the electric industry functions in that state and beyond. The Empire State’s vision, which includes delegating distribution duties to utilities, reserving generation opportunities for third parties and shifting to a more renewable-focused generation mix, will change how business is done there while also potentially providing a template for other jurisdictions preparing for life under the EPA’s Clean Power Plan.

However, there are hurdles to overcome. Customers will not tolerate a reduction in reliability or resiliency. Nor will the benefits of clean generation be as joyously embraced if higher costs are the result. Outdated technological capabilities, security issues, job displacement and shareholder issues all create concerns that need to be addressed. That said, tremendous opportunities could exist for technology providers, generation platforms, financiers and others if the current vision of REV is implemented. Microgrid and cutting edge renewables are being promoted. Grid and demand management technologies will be in high demand, and legislative and financial support for projects will continue to ensure a favorable development environment for those with projects.

Please join the Sullivan & Worcester, LLP Energy Finance Team on October 1st live in our New York offices, or by dial-in, as we host a roundtable discussion on the REV proceeding and the unique business opportunities it could present. Panel participants include industry experts with unique perspectives on REV such as 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. Interested parties can register here.

Topics: NY REV, Energy Policy, Energy Finance, Legislation, Distributed Energy, Energy Management

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

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

photovoltaic cells and high voltage post.

Co authors Van P. Hilderbrand and Morgan M. Gerard

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

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

The Final Plan’s Approach to Carbon Emission Reduction

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

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

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

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

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

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

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

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

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

State Incentives

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

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

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

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

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

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

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

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

Nevada ThinkstockPhotos-78779262

Co-author Morgan Gerard

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

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

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

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

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

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

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

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

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

Co-authors Jim Wrathall, Van Hilderbrand and Morgan Gerard

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

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

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

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

Energy Policy Modernization Act Quiet on Renewables

Posted by Joshua L. Sturtevant on 7/24/15 11:15 AM

Both the Senate and the House made progress on their respective updates to 2005’s Energy Policy Act this week. The general press has focused mainly on the fact that the long-term ban on oil exports was not lifted (which doesn't necessarily mean a lift of the ban is dead). However the absence of support for renewable distributed energy resources was equally stark in the eyes of renewable energy advocates.

Some speculate that support for renewable energy resources may be added during the legislative revision process; some have even posited that an extension to the 30% solar investment tax credit could end up in this legislation after it went unaddressed in the tax extenders bill recently released by the Senate Finance Committee. Also, certain aspects of a more distributed generation-focused future, including efficiency, a smart grid and microgrid technologies, are more specifically addressed.

That said, the lack of specific support for solar, wind and other generation sources in a document that underpins what is ostensibly an "all of the above" approach to national energy policy will be alarming for renewable energy advocates.

The Senate version can be found here. The House version can be found here. While pundits expect a relatively easy preliminary reconciliation process given the similarity of the two versions, it is less clear when final legislation might actually be put to vote.

Topics: EPMA, Energy Efficiency, Energy Finance, Legislation, Distributed Energy, Solar Energy, 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