I Overview

Tax-equity financing broadly encompasses investment structures in which a passive equity investor looks to achieve a target internal rate of return based primarily on US federal income tax benefits that are expected to be available to it with respect to an investment in a particular asset. Tax-equity investors are typically profitable, tax-paying entities such as banks, insurance companies, certain utilities and general corporate entities. As discussed in greater detail below, tax-equity investors generally invest alongside a developer who cannot make efficient use of the tax benefits associated with the underlying asset. Tax-equity financing structures are driven by tax laws that are unique to the United States; accordingly, this chapter focuses specifically on the US project finance market.

The US government subsidises the cost of many renewable power projects with federal income tax benefits. These subsidies primarily include tax credits and the ability to write off the cost of a project on an accelerated basis. There are two general classes of tax credits available for renewable projects: investment tax credits and production tax credits. The type of credit available for any particular project largely depends on the technology involved.

The first type of credit available for renewable projects is investment tax credits, which are available for investments in solar equipment, fuel cells, small wind energy property (i.e., 100kW or less), fibre-optic solar, geothermal projects, combined heat and power property, geothermal heat pump property and microturbines.2 The credits are calculated as a percentage of a project's cost, and are available in their entirety in the year the equipment is placed into operation.

The credit amount varies depending on the technology and the year in which the project begins construction. Under the current framework, solar projects that began construction by the end of 2019 qualify for a 30 per cent investment tax credit. The credit phases down to 26 per cent for projects beginning construction in 2020 and 22 per cent for projects beginning construction in 2021. Projects meeting these deadlines must be placed in service by the end of 2023 to qualify for a credit above 10 per cent.3 The credit drops to a permanent 10 per cent level for solar projects that begin construction in 2022 or later.

The credit for fuel cells, small wind energy and fibre optic solar is subject to a similar phase-down schedule as solar, but the credit expires if construction does not begin until 2022 or later, or if the project fails to be placed in service before 2024.4 Combined heat and power, geothermal heat pump and microturbine projects qualify for a 10 per cent credit as long as construction begins before 2022. Geothermal projects benefit from a permanent 10 per cent credit.5

The second type of tax credit for renewables projects is the production tax credit. The production tax credit is available for investments in wind, biomass, geothermal, landfill gas, municipal solid waste, hydropower, and marine and hydrokinetic facilities. Unlike the investment tax credit, the production tax credit is claimed over a 10-year period beginning on the date the project is placed in service. The amount of the credit depends on the amount of energy produced, and is adjusted annually for inflation.6

The value of production tax credits similarly varies depending on the asset class and year in which construction begins. For wind projects, the full value of the credit is available if construction started before 2017. The credit phases down by 20 per cent for each year thereafter through 2019, bottoming out at 40 per cent. The value of the credit then increases for projects that begin construction in 2020, but then abruptly expires for projects that do not begin construction before the end of 2020.7 The production tax credit is only available for the other eligible technologies if construction begins before 2021.8

Apart from tax credits, most of the equipment used in renewables projects qualifies for depreciation over an accelerated five-year period.9 Depreciation is an annual tax deduction for the wear and tear associated with equipment used in a trade or business. Certain renewable energy assets may alternatively qualify for immediate (i.e., 100 per cent) depreciation in the year in which the equipment is placed in service.10

One major structural limitation of the US tax subsidy regime for renewables is that the tax benefits are useless to someone who does not owe taxes. Further, special rules make it harder for wealthy individuals, S corporations and closely held C corporations (i.e., a corporation in which five or fewer individuals own more than half of the value of the stock) to claim tax credits and accelerated depreciation.11

Developers are rarely able to make efficient use of tax benefits, so they enter into what is effectively a bartering transaction with a tax-efficient investor (called a 'tax-equity investor') to whom the developer will allocate nearly all of the tax benefits in exchange for cash capital contributions for the project.

There are three primary tax-equity financing structures in the US renewables market. They are the partnership flip, the inverted lease and the sale-leaseback.

i Partnership flip

Partnership flips are the most common structure in the US renewables market. In a typical deal, the developer either contributes a project or sells it to a partnership formed between it and the tax-equity investor, to which the tax-equity investor contributes cash. The tax-equity investor is typically allocated 99 per cent of the tax benefits and some portion of the cash (usually around 30 per cent or less, depending on the project) until the tax-equity investor reaches a target yield or a fixed date passes. The fixed date will be no earlier than five years after the project is put in service. Once tax equity reaches the applicable benchmark, its share of tax items will decrease (usually down to 5 per cent), along with its share of cash. The developer will get the bulk of the cash and tax items for the remaining life of the partnership.

The basis used to calculate the investment tax credit is the partnership's cost to acquire or produce the project. If the partnership purchases the project from a developer, its credit-eligible basis will generally be the allocable credit percentage multiplied by the purchase price, subject to adjustment to remove items such as transmission equipment and intangibles that are not eligible for the credit. If the project is contributed to a partnership by the developer, rather than sold, the basis is the contributor's cost. The depreciable basis of the project is reduced by half of the investment tax credits claimed by the project's owner. Production tax credits do not require a basis reduction.

Partnership flip structures are largely dictated by Internal Revenue Service (IRS) safe harbour rules for wind projects.12 If all of the rules are followed, the IRS will respect the partnership's allocation of tax credits. The IRS has technically adopted the position that the safe harbour rules only apply to wind projects, but the renewables industry largely applies the rules across technologies in the absence of any other technology-specific guidance.13

Among other rules, the safe harbour requires the tax-equity investor to invest at least 20 per cent of its total expected investment upfront. In addition, at least 75 per cent of the total amount of the expected investment must be fixed in amount and certainty of payment. The safe harbour also requires the tax-equity investor to take neither more than 99 per cent of the tax items nor less than 5 per cent of the tax items. (There are no similar restrictions on cash sharing.) Further, the developer typically has an option to buy the tax-equity investor's interest at fair market value, but the tax-equity investor cannot force the developer to buy its interest.

Tax-equity investors in partnership flips typically want indemnification for lost tax credits and depreciation, but only if there is a breach of a representation or covenant. In investment tax credit projects, developers are usually asked to represent that the project's basis for tax credit purposes is its true fair market value. The risk of losses owing to structural risks, such as non-compliance with the safe harbour rules, is generally borne by the tax-equity investor.

ii Inverted lease

Inverted leases are another common financing structure, though they are only available for projects that qualify for investment tax credits. Unlike partnership flips and sale-leasebacks, where the project owner is the only party entitled to tax benefits, a special rule for inverted leases allows the lessor to pass the investment tax credit on to the lessee. The lessee claims the credit based on the project's fair market value (as opposed to the project's cost). The lessee must recognise income ratably over five years in an amount equal to one-half of the tax credits. The lessor is entitled to all of the depreciation.

There are two types of inverted leases: a basic structure where the developer is the lessor and leases the project to a tax-equity lessee, and an overlapping ownership structure where the lessee is a minority (typically up to 49 per cent) owner of the lessor. One of the benefits of the inverted lease is that it allows the parties to split up the tax benefits and allocate them among the parties who want them the most. For example, if a tax-equity investor only wants tax credits and the developer has some appetite for depreciation, the basic inverted lease structure makes more sense than a standard partnership flip. The overlapping ownership variant would be an improvement over the basic structure if the parties want some of the depreciation to go to the tax-equity investor.

Another advantage of the inverted lease is that the tax credit basis step-up to fair market value is free in the sense that entering into a lease is not a taxable event. The step up can have a tax cost in the other structures because the sale of a project to a flip partnership or to the tax-equity investor in a sale-leaseback is a taxable event for the developer.

Similar to solar partnership flips, there is no solar-specific guidance for inverted leases. The industry largely follows guidelines for historic tax credit transactions (which use inverted leases but call them 'master tenant' structures), and leasing principles from guidance for leveraged leasing transactions.14 These guidelines are conceptually similar to the wind partnership flip guidelines in that they try to put the tax-equity investor more at risk than a lender would be. For example, like the partnership flip safe harbours, the tax-equity investor needs to make at least 20 per cent of its investment up front. There are also some notable ways in which the historic tax credit guidance differs from the partnership flip guidance. One way is that the tax-equity investor may have a right to put its interest to the developer for less than fair market value, but the developer may not have a call option (i.e., the exact opposite of the flip guidelines).

In terms of indemnities, tax equity typically expects complete coverage for lost tax credits because of anything other than a structural risk that it explicitly agrees to bear in the transaction documents. These typically cover issues such as the lease being respected as a true lease and compliance with the safe harbour guidance.

iii Sale-leaseback

A third common tax-equity structure is the sale-leaseback. As its name implies, it involves the sale of a project by a developer to a tax-equity investor, who simultaneously leases the project back to the developer. This structure is only available for investment tax credit transactions.

In this structure, the tax-equity investor's basis for tax credit and depreciation purposes is the purchase price that it pays to acquire the project. Tax equity's depreciable basis will be reduced by one-half of the amount of the tax credits.

This is the only investment tax credit structure in which the tax-equity investor does not need to fund into the transaction before the project is placed in service. A special rule permits the tax-equity investors to claim credits as long as the sale-leaseback happens within three months of the project's 'placed in service' date.15

Both parts of the transaction still need to happen simultaneously. The extra three months makes sale-leasebacks an attractive option for developers who are not able to find a tax-equity investor during construction or pre-construction. The developer will recognise taxable gain on the sale of the project. Lease terms are typically 10 to 20 years. The developer often has a purchase option to re-acquire the project for its then-fair market value when the lease ends.

In sale-leaseback transactions, the indemnity coverage typically extends to all tax benefits, except for any loss owing to a fundamental structuring issue (e.g., the tax-equity investor not being respected as the owner of the project for tax purposes). If the sale occurs after the project is in service, the developer typically bears the risk that the transaction did not occur within the three-month deadline.

II Interplay between debt and tax equity

There are three primary sources of financing for renewable energy projects in the United States: tax equity (covered above), sponsor equity and debt. Generally, tax equity will only cover around 35 to 40 per cent of the total capital cost for solar developments and 50 to 60 per cent of the total capital cost for wind developments, so sponsors need to complete the capital stack with sponsor equity or debt (or both). More creditworthy sponsors may be able to fill the entire gap with sponsor equity or corporate (i.e., recourse) financing, but for many developers that is not an option. As a result, many renewable energy projects are financed by a combination of tax equity, sponsor equity and debt.

Debt financing is a broad term that could include non-recourse construction or long-term financing, back-leverage financing, development loans, securitisations, portfolio financings, corporate (recourse) financing, etc. The renewable project debt toolkit has many options. Below, we focus on two commonly used debt structures for tax-equity projects, and the interplay between debt and tax equity. We have not covered long-term project level debt below because, largely as a result of tax-equity investors' unwillingness to permit the pledge of project-level collateral, it is much less common than back-leveraging financing.

i Construction bridge facility

Tax-equity investors typically take minimal construction risk, but the greatest capital expenditures for any project typically are incurred during the construction phase. As a result, project developers require significant financing before tax-equity investment becomes available. One option is to obtain a construction bridge facility. This typically would be a non-recourse fully secured loan from one or more commercial banks or other private debt sources that are willing to take on construction risk. A construction bridge loan will be drawn over the course of construction of the project, as costs are incurred.

Construction debt is sized on the basis of the estimated capital costs to build the project. In addition, construction lenders typically will require the sponsor to provide a percentage of the capital costs via sponsor equity (so that the sponsor is appropriately motivated to get the project built on time and on budget). Built into the capital cost estimate will be some amount of contingency, but if there are cost overruns prior to completion, ultimately the sponsor will have to fund them or will risk defaulting on its construction debt and losing its equity in the project.

Construction bridge loan lenders typically require a full security package, including security over all of the project company's assets, and the ownership interests in the project company, along with a tight covenant package. Where the construction debt will be repaid in whole or in part with tax equity, typically the construction bridge lenders will require that the sponsor have a tax-equity commitment in hand. In that case, the construction lender will require that such commitment forms part of the collateral package so that the project can benefit from the tax-equity commitment even if the construction bridge loan lenders foreclose on the project.

The construction bridge facility will be repaid upon project completion by tax-equity financing and, if the developer wants to finance its portion of the cost of a project, by back-leverage debt. While it is not typical, in some cases, a tax-equity investor will also be a construction bridge facility lender, such that the construction bridge debt is repaid with tax-equity investment from the same provider.

Tax-equity investors will generally not accept a position structurally subordinate to long-term debt. However, in projects that qualify for the investment tax credit, they generally will accept the project level security granted to construction bridge lenders during the period between mechanical completion and substantial completion, subject to the terms of an interparty or forbearance agreement in which the lender agrees not to foreclose on the assets of the project company until the expiry of the investment tax credit recapture period.

ii Back-leveraged facility

Back-leveraged debt is different from construction or term-loan debt at the project level in that it is incurred by a borrower in the ownership chain above the project company and is not secured by a security interest in the assets of the project company. This is preferable from the perspective of the tax-equity investor to project-level debt, because tax-equity investors do not want to take the risk that a secured lender would foreclose on the project assets during the operational period.

Given that back-leverage lenders do not have project level security, it is critical that: (1) the borrower has predictable cash distributions from the project; (2) the borrower can control decisions of the project company so that it can protect the value of the project and its ability to generate revenues to repay the back-leverage debt and pay any amounts required to be paid to the tax-equity investor; and (3) that the change of control and transfer restrictions in the tax-equity documents are workable to facilitate foreclosure and a sale of the borrower's equity interests. If the tax-equity investor is permitted to divert borrower cash flows for indemnification claims or other reasons, the back-leverage lenders may require an indemnity from the sponsor. The back-leverage lenders' collateral usually will include a pledge of the shares in the borrower, as well as a pledge over the borrower's bank accounts. In the event of a default, the back-leverage lenders may foreclose on such shares or bank accounts (or both) and look to the revenues received from the project company via distributions to be repaid.

Unlike construction debt lenders, which will have significant consent rights over the actions of the project company, the back-leverage lenders will have consent rights indirectly through the covenants in the back-leverage financing agreement and voting rights of the borrower in the tax-equity documentation. If the borrower causes or permits the project company to take an action that is in violation of those covenants, then it will trigger an event of default under the back-leverage financing agreement (which, if not cured, will enable the back-leverage lenders to foreclose on the shares in the borrower).

iii A note on recapture risk

The investment tax credit vests 20 per cent per year over a period of five years. Certain events may trigger the recapture of the investment tax credit before it has fully vested, causing the tax-equity investor to lose a portion of the benefit of its investment. As a result, tax-equity investors typically require sponsors to indemnify them for recapture risk. There are two types of recapture risk. First, there is true recapture where the project company loses the unvested portion of tax credits as a result of some event that occurs after the project becomes operational. Examples of events that can result in true recapture include taking the project out of service or selling it to a third party. Transfers of partnership interests to an entity with tax-exempt or foreign owners is also problematic. Such events are largely within the parties' control.

Second, disallowance can result from a failure to properly calculate the tax credit benefit, often as a result of a misallocation of costs as eligible to benefit from the tax credit that later are found to be inflated or ineligible. This scenario is more challenging for a sponsor trying to quantify recapture risk. To address this concern, sponsors typically will obtain detailed appraisals on the value of the project. In addition, tax-equity investors sometimes will obtain insurance coverage for any losses resulting from investment tax credit recapture (and the costs of interest and penalties that may be assessed by the IRS in connection with such recapture).

Recapture risk is an issue for lenders to the extent that the tax-equity documentation allows cash sweeps to the tax-equity investor to cover recapture obligations ahead of scheduled principal and interest due and payable to the lenders. To address this risk, sponsors often provide the lenders with an indemnity covering these cash diversions.

III Recent Developments in Tax-equity

As further described below, a variety of developments affecting the legal, commercial and technological landscape of tax-equity financings continue to unfold.

i Battery storage

A key structural limitation of nearly all renewable energy generation projects – notably solar and wind – is that generation cannot be guaranteed at any given moment. Battery storage has long been seen as the solution to this problem, but until recently, battery technology and equipment costs made utility scale battery storage projects unrealistic. In 2019, technological improvements, increased market interest and regulatory developments coalesced to create a breakout year for battery storage projects.16

Under current IRS guidance, the storage portion of these combined projects qualifies for investment tax credits only if at least 75 per cent of the energy used to charge the battery comes from the solar generating equipment. Further, if the solar input is less than 100 per cent, the investment tax credits are reduced to the extent of the non-solar input.17 Increases in the percentage of non-solar input in subsequent years may cause the IRS to recapture a portion of previously claimed credits. Industry proponents are hopeful that the US Congress will pass legislation enacting new standalone investment tax credit storage projects; however, these efforts have so far been unsuccessful.

In a key regulatory development, the US Federal Energy Regulatory Commission (FERC) issued Order No. 841, which required organised wholesale power markets to create new rules for their tariffs that better integrate energy storage resources.18 After FERC denied numerous requests for the agency to reconsider aspects of Order No. 841,19 several groups acting on behalf of utilities, electric cooperatives, and municipal power providers sought judicial review of FERC's order in July 2019. While that court case proceeds, the administrators of each of the organised wholesale power markets have moved forward with proposed rules to comply with Order No. 841. In late 2019, FERC largely accepted the compliance proposals for each market and directed further compliance filings requiring each market to further address several discrete issues. That iterative compliance process will continue throughout 2020.

ii Pressure on development fees paid to related developers

The US Court of Federal Claims recently released two opinions that each concluded that development fees paid to a sponsor by a tax equity partnership (of which the sponsor was a partner) for the development of a large wind project was a 'sham transaction' that lacked economic substance, and that the fees were not eligible costs for purposes of calculating a cash grant from the US Treasury Department under Section 1603 of the American Recovery and Reinvestment Act of 2009.20 Although the cash grant programme has expired, the implications of these cases extend to projects that currently qualify for investment tax credits, which are similarly calculated as a percentage of eligible cost basis.

The court found the following characteristics of the fee transaction to be problematic: (1) the development agreement did not assign specific value to each of the services provided; (2) the accounting firm that was hired to certify the eligible costs only tested as a sampling of the costs; (3) cash to pay the fee circled through the accounts of several related entities before ending up back in the account where it originated; and (4) the developer did not introduce its accounting journal entries into evidence.

Despite the negative result for the developer in these cases, the court also concluded that development fees in general are part of a project's cost basis that can increase the cash grant award. The implication is that such fees are still valid in concept if structured appropriately. Though fact-specific, these cases will likely serve to further increase the number of tax-equity transactions in the market that rely on the purchase of a project from the developer by a tax-equity partnership to step up the tax credit basis from cost to fair market value as opposed to relying on a margin that includes the payment of a development fee.

iii Solar tariff impact

On 22 January 2018, a 30 per cent tariff was imposed on certain solar cells and modules imported to the United States, with a 2.5GW annual exclusion.21 This tariff ramps down 5 per cent each year through 2021 and expires in 2022.22 Following adoption of the solar tariff, in June 2019, the US Trade Representative granted an exemption from the solar tariff for bifacial solar panels, only to revoke the exemption in October 2019 (stating that, 'the US Trade Representative has determined, after consultation with the Secretaries of Commerce and Energy, that maintaining the exclusion will undermine the objectives of the safeguard measure'23). That revocation was challenged in the US Court of International Trade, which temporarily blocked the decision to revoke the exemption in December 201924. The US Trade Representative currently is accepting comments on the potential to revoke the exemption, but it remains in place for the time being.

The effect of the tariffs on the US solar industry has been difficult to measure. In Q3 2019, according to a joint Wood Mackenzie and Solar Energy Industries Association (SEIA) report, solar installations were up 45 per cent relative to Q3 201825. However, SEIA also found that 62,000 jobs and nearly $19 billion in new investment were lost because of the 2018 tariffs. Tariffs (and the threat of tariffs and other trade policy changes) will continue to be a concern for the solar industry in 2020.

iv Repowering

'Repowering' is the process of replacing aging wind turbines in operating projects with newer hardware. This includes replacing the existing turbines in their entirety with newer and more efficient units, and may also include replacing only certain key turbine components. While turbines typically have a lifecycle of 20 to 25 years, newer turbines are dramatically more efficient and affordable than older technologies. Ultimately, the goal in any repowering project is to improve the generating capacity and availability of the relevant wind asset, extend the life of the turbines, and maximise the availability of production tax credits. Repowered projects are eligible for a new stream of production tax credits if the fair market value of the used property does not exceed 20 per cent of the repowered wind turbine's total value.26 The value of the production tax credits for a repowered project will depend on the year in which the repowering was deemed to begin under the tax credit phase-down rules described above. Suppliers and financiers look forward to increased repowering activity during the period in which production tax credits continue to be available, but repowering activity will continue without the benefit of production tax credits as assets age and turbine technologies continue to improve.

v Offshore wind

Offshore wind projects continue to generate tremendous excitement. In 2019, the world's largest offshore wind farm – with a capacity of 1.2GW – was completed off the coast of England. However, the US continues to lag behind Europe in installed offshore wind developments. The largest ongoing development in the US – the 800MW Vineyard Wind I project – continues to advance but was delayed from its original timeline in late 2019 after the federal Bureau of Ocean Energy Management (BOEM) delayed its environmental approval. Strong state-level governmental support in the northeastern US (including Maine, New Hampshire, Massachusetts, Connecticut, New York and New Jersey) suggests that offshore wind development will continue in the region.

The US Department of Energy estimates that there is nearly 2,000GW of potential offshore wind development opportunities generating 7,200TWh per year (or roughly double current total US power generating capacity).27 While development approaching that scale is not expected, tapping even 1 per cent of that resource has the potential to power 6.5 million US homes. Many offshore wind developers are focused on the US east coast, with 23.4GW of the US offshore wind pipeline (out of approximately 25GW in total) situated there, but there are also projects in development in Hawaii, California and the Great Lakes.28 The US west coast, including northern California and Oregon, offers significant potential given historical wind data and strong governmental support. However, the topography of this portion of the coast requires use of 'floating' turbine structures, which are materially more expensive than more traditional 'monopile' designs.

Offshore wind appears to be a key growth area for renewables energy development – and applicable tax equity financing structures – in 2020 and beyond.

This article is an extract from The Project Finance Law Review, 2nd Edition. Click here for the full guide. 


1 Scott W Cockerham, Brian C Greene and Kelann Stirling are partners, and Mateo Todd Aceves is an associate at Kirkland & Ellis LLP.

2 See 26 USC Section 48(a).

3 See 26 USC Section 48(a)(6)(A)(i)-(ii).

4 See 26 USC Section 48(a)(6)(B).

5 The IRS has issued multiple sets of guidance on what it means to 'begin construction.' See IRS Notice 2013-29, IRS Notice 2013-60, IRS Notice 2014-46, IRS Notice 2015-25, IRS Notice 2016-31, IRS Notice 2017-04, and IRS Notice 2018-59.

6 See 26 USC Section 45.

7 See 26 USC Section 45(b)(5).

8 See 26 USC Section 45(d).

9 See 26 USC Section 168(g)(3)(C).

10 See 26 USC Section 168(k).

11 See generally 26 USC Section 465; Section 469.

12 See Rev Proc 2007-65.

13 This approach was confirmed to an extent in a 2015 internal memo in which the IRS national office analysed a transaction using the criteria from the wind safe harbour, even though the memo formally concluded that the wind safe harbour did not apply to solar projects as a technical matter. See Chief Counsel Advice 201524024 (12 June 2015).

14 See Rev Proc 2014-12; Rev Proc 2001-28.

15 See: Former 26 USC Section 48(b)(2); Treas Reg 1.47-3(g)(1).

16 See: Wood Mackenzie US Energy Storage Monitor 2019 Q4 Report (available at www.woodmac.com/research/products/power-and-renewables/us-energy-storage-monitor/).

17 See: IRS Private Letter Ruling 201308005.

18 See: www.ferc.gov/whats-new/comm-meet/2018/021518/E-1.pdf.

19 www.ferc.gov/whats-new/comm-meet/2019/051619/E-1.pdf.

20 The cases are Bishop Hill Energy, LLC v. United States, 135 Fed Cl 642 (2017), and California Ridge Wind Energy, LLC v. United States, 135 Fed Cl 640 (2017).

21 See: https://ustr.gov/about-us/policy-offices/press-office/press-releases/2018/january/president-trump-approves-relief-us.

22 Ibid.

23 See: https://ustr.gov/sites/default/files/enforcement/201Investigations/Withdrawal_of_Bifacial_Solar_Panels_Exclusion_to_the_Solar_Products_Safeguard_Measure.pdf.

24 See: www.cit.uscourts.gov/sites/cit/files/19-153.pdf.

25 See: www.seia.org/sites/default/files/2019-12/SEIA-Tariff-Analysis-Report-2019-12-3-Digital_0.pdf.

26 See, e.g., Rev Rul 94-31; IRS Notice 2016-31.

27 See: www.energy.gov/eere/articles/computing-america-s-offshore-wind-energy-potential.

28 See: https://acore.org/investors-watching-closely-in-the-wake-of-recent-offshore-wind-announcements.