New York’s New Renewable Energy Standard

Last week’s article discussed New York’s Zero-Emissions Credit (ZEC) for nuclear power. The ZEC is one component of New York’s Clean Energy Standard (CES). The other major component of the CES is the new Renewable Energy Standard (RES). In the RES, the New York Public Service Commission (PSC) formally adopted the goal set by Governor Cuomo in December 2015: 50 percent of all electricity used in New York by 2030 should be generated from renewable resources. This goal builds on the State’s previous goal of achieving total renewable generation of 30 percent by 2015.

The RES consists of a Tier 1 obligation on load-serving entities (LSE) to support new renewable generation resources through the purchase of renewable energy credits (REC), a Tier 2 program to support existing at-risk generation resources through maintenance contracts, and a program to maximize the potential of new offshore wind resources.

The goal of the RES is to reduce carbon emissions and ensure a diverse generation mix in New York. The state’s existing nuclear facilities, supported by the ZEC program, will close in 2030 (absent a renewal of their licenses) and the RES aims to ensure that the electricity provided by those units is replaced with new renewable resources.

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NY Creates New Emissions Credit for Nuclear Plants

The New York Public Service Commission’s (PSC) Clean Energy Standard (CES), adopted in August, includes a new emissions credit—the ZEC. The ZEC, or zero-emissions credit, is the first emissions credit created exclusively for nuclear power.

The ZEC is the result of a highly politicized effort to support New York’s struggling nuclear power plants. New York’s four nuclear plants account for 31 percent of the state’s total electric generation mix. According to the PSC, “losing the carbon-free attributes of this generation before the development of new renewable resources between now and 2030 would undoubtedly result in significantly increased air emissions due to heavier reliance on existing fossil-fueled plants or the construction of new gas plants to replace the supplanted energy.” The ZEC Program is intended to keep the state’s nuclear plants open until 2029 and provide an emissions-free bridge to renewable energy.

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CaliforniaFirst PACE Program Finances Clean Energy Projects for Commercial Property

Property assessed clean energy (PACE) programs are an innovative mechanism for financing energy efficiency and renewable energy improvements on private property.  They also present a number of challenges to investors—for one, the variance between different programs (even within a particular state) and an understanding as to how particular programs work remains an impediment to investors and to scalability.  This post provides a brief overview of PACE programs generally and one particularly popular PACE program – CaliforniaFirst.

Overview of PACE

PACE programs vary by state, but most allow property owners to finance clean energy projects through a voluntary property assessment paid as a line item on their property tax bills.  Thirty-two states and the District of Columbia have enacted PACE-enabling legislation and there are active PACE programs in 19 states and the District of Columbia.  While most of these states provide financing for commercial PACE projects, only California, Missouri and Florida have active residential PACE programs.

CaliforniaFirst PACE Program for Commercial Property

The CaliforniaFirst PACE program is one of 12 PACE programs active in California and is available for both residential and commercial real property.  CaliforniaFIRST is offered by the California Statewide Communities Development Authority (CSCDA) and is currently available in more than 40 California counties, with over 330 participating local governments.

Using the CaliforniaFirst PACE program (Program), commercial property owners can work directly with a clean energy developer and the CSCDA.  The developer agrees to install the clean energy project and provide power to the property owner through a power purchase agreement or lease.  The property owner pays for the project through a contractual assessment, which appears as a line-item on the property tax bill.

The CSCDA secures the payments through a notice of assessment recorded on the property title.  The contractual assessments have priority over any existing mortgage lien.  If the property owner sells the property, the repayment obligation remains an obligation of the property.  The Program’s underwriting criteria focuses primarily on the relevant payment history and value of the property.  The clean energy project must have an effective useful life of at least five years and only new systems can be financed through the Program.  The Program is administered by a third-party administrator (Renewable Funding LLC).

As an “interim financing mechanism,” CSCDA and a clean energy developer would typically enter into an assignment and assumption agreement under which CSCDA assigns its rights to receive the contractual assessments to the clean energy developer in exchange for the clean energy developer assuming CSCDA’s financing obligations under the assessment contracts, plus certain specified costs.  The assignment term is expected to last three years.  On or prior to the end of the assignment term, CSCDA issues bonds to the clean energy developer in exchange for the property tax assessments that were assigned to the clean energy developer.  The principal amount, maturity date, amortization and interest rates of the bonds are designed, in the aggregate, to produce cash flows that replicate the principal and interest components of the contractual assessment installments.

From an investor point of view, PACE payments are a senior benefit assessment lien on the property, and a new owner of the property would inherit the solar PV benefits and the PPA/lease payment obligation though the PACE program.  In the event of a default, the remedies are fairly strong—for instance, CSCDA has the right to have the delinquent installment and its associated penalties and interest removed from the secured property tax roll and immediately enforced through a judicial foreclosure action.  In the event of foreclosure, the proceeds of the foreclosure sale would be used to pay any delinquent amounts and future installments would become the responsibility of the purchaser.

Considerations for Investors

By statute, the owner of the renewable energy improvement is not permitted to remove the improvement from the property prior to the end of the assessment term.  Investors should be aware that in the event of payment default they will not have the ability to seize the improvement and will need to rely on the public agency to foreclose on the property.  Additionally, the public agency in charge of the PACE program is a third party beneficiary with respect to the power purchase agreement or lease until the assessment lien is fully repaid and also has consent rights over any amendments to the customer agreement.  Therefore, it may be difficult for a developer or financing entity to revise a power purchase agreement or lease once it is in place.

Conclusion

PACE programs are likely to attract more investors and commercial property owners as they become more widely available and clean energy developers become more experienced working with them.  We’ve highlighted the basics of the CaliforniaFirst program for commercial property, but investors, property owners and developers should ensure that they understand the regulatory nuances of the particular program in their area.

Clean Air Act Permit Challenges — New Rules On the Way

In the United States, the federal Clean Air Act (CAA) requires all “major sources” of air pollution, such as power plants, refineries and other large industrial facilities, to obtain permits detailing the conditions under which those sources are allowed to operate. Such “Title V” operating permits, as they are commonly known, are typically issued by state environmental agencies but are subject to pre-issuance review by the federal Environmental Protection Agency (EPA). In fact, EPA is required to object to any proposed permit that it determines is inadequate, and the CAA also contains a public participation backstop to EPA’s oversight: where EPA fails to object to a permit, any member of the public that believes the permit is inadequate can petition EPA to make an objection.

In recent years, environmental organizations have increasingly used the petition process to challenge proposed permits, especially with respect to alleged inadequacies concerning greenhouse gas emissions. By statute, EPA is supposed to respond to such petitions within 60 days. But EPA routinely misses that deadline and now faces a sizeable backlog of pending petitions.

In late August, EPA published a proposed rule, which, if finalized, would create a series of new requirements for the submission and handling of Title V petitions. Most notably, the proposed rule would:

  • Create a new, mandatory, procedure for submitting Title V petitions to EPA;
  • Require each petition to follow a standardized format and contain certain minimum content; and
  • Impose a new requirement on state permitting agencies—a requirement that those agencies prepare written responses to all “significant comments” received from the public during the permit drafting stage.

EPA’s announcement of the proposed rule also includes a summary of EPA’s general approach to handling Title V petitions. The announcement includes, for example, a short summary of prior EPA applications of the CAA’s Title V provisions, as well as a list of “recommended practices” for state permitting agencies to follow when preparing proposed permits.

EPA is soliciting comments on its proposed rule. Comments must be received on or before October 24, 2016.

Massachusetts Legislation Spurs Offshore Wind Power Development

On August 8, 2016, Massachusetts Governor Charlie Baker signed into law a major energy bill aimed at putting Massachusetts at the forefront of states developing offshore wind power. The law, An Act Relative to Energy Diversity (H. 4568), requires Massachusetts electricity distribution companies to procure 1,600 megawatts (MW) of offshore wind energy by June 30, 2027. The United States currently has no offshore wind generation, but Rhode Island wind developer Deepwater Wind is nearing completion of a 30 MW offshore wind farm, which will be the first of its kind in the country. In a statement, Governor Baker’s office said the bill “spurs the development of an emerging offshore wind industry…and represent[s] the largest commitment by any state in the nation to offshore wind.”

The new law requires Massachusetts distribution companies and the Department of Energy Resources (DOER) to jointly develop a competitive bidding process for offshore wind energy generation resources by June 30, 2017. The bidding process will be subject to review by the Massachusetts Department of Public Utilities (DPU). The law permits one solicitation or multiple staggered rounds of solicitation that must result in at least 1,600 MW of aggregate nameplate capacity of offshore wind energy. If the solicitation is staggered, each round must seek proposals for at least 400 MW of capacity, and the costs in each subsequent round must decrease or the proposal will be rejected by the DPU. All proposals received during the solicitation process are subject to review by DOER.

Each distribution company will enter into a contract with the solicitation’s winning bidders for the distribution company’s apportioned market share, calculated based on the total energy demand for all distribution companies, compared to demand in an individual distribution company’s service territory. Distribution companies may use the long-term contracts to purchase renewable energy certificates, energy, or a combination. All proposed long-term contracts executed with distribution companies will be filed with the DPU and subject to DPU approval. Specifics on the solicitation, contracting, and approval processes will come when the DPU and DOER promulgate regulations carrying out the new legislative mandate for offshore wind.

The legislation represents a new chapter in offshore wind for Massachusetts. The infamous Cape Wind project—a proposed 468 MW wind farm—has been held up in the planning stages for years and its current status is uncertain. The new law is a definite step towards Massachusetts’ development of offshore wind energy generation resources. Several wind development companies already hold leases in Massachusetts waters.

New Climate Change Guidance for NEPA Reviews

In the United States, federal agencies that license, permit or finance energy and infrastructure projects must, with some limited exceptions, analyze the environmental impacts of those projects before they approve them, pursuant to the National Environmental Policy Act of 1969 (NEPA).  But to what extent must those agencies consider climate change impacts as part of their NEPA reviews? The President’s Council on Environmental Quality (CEQ) has just issued a guidance document that addresses that question.

CEQ’s guidance document—an August 1 memorandum addressed to the heads of all federal departments and agencies—urges federal agencies to consider two climate change-related topics when conducting NEPA reviews.

The first topic is the impact of a proposed project on climate change, and the memorandum urges federal agencies to approach that topic by focusing on the project’s direct, and indirect, greenhouse gas (GHG) emissions. Agencies are encouraged to calculate a project’s anticipated emissions using existing government resources and calculators, and to draw upon existing government literature on the impacts of such emissions. The memorandum acknowledges that “the totality of climate change impacts is not attributable to any single action,” but concludes that climate-related impacts are exacerbated by some government actions and encourages agencies to compare the level of emissions expected from a proposed project to the level expected under alternative project scenarios. The memorandum provides scant details on how to calculate “indirect” GHG emissions but does suggest that for projects involving fossil fuel extraction, the indirect impacts turn, at least in part, on the anticipated ultimate use of the extracted fuel.

The second topic is the impact of climate change on the project, and on the project’s impacts.Here, CEQ’s memorandum encourages federal agencies to consider a proposed project’s impacts not simply on environmental conditions as they currently exist but as they will exist in the future and reflecting any changes that are expected as a result of climate change. Thus, if a project will draw water from a river that is already being, or that will be, diminished because of changing snowfall or rainfall patterns, that is an impact that should be acknowledged. The memorandum also encourages agencies to incorporate climate change resiliency and adaptation planning into their NEPA reviews, especially when analyzing project alternatives and potential mitigation measures. The memorandum suggests, for example, that agencies consider whether a proposed project’s design makes it more vulnerable to changing climate conditions (such as, in some areas of the country, increased risk of wildfires) than alternative projects.

CEQ’s memorandum applies to all new NEPA reviews and states that agencies “should exercise judgment” when considering whether to apply the guidance to currently ongoing reviews. CEQ states in the memorandum that it “does not expect agencies to apply” the guidance to projects for which a final environmental impact statement or environmental assessment has already been issued.

EPA Raises Statutory Civil Monetary Penalty Amounts

On July 1, 2016, the US Environmental Protection Agency (EPA) issued an interim final rule that modifies statutory civil monetary penalty amounts for statutes administered by the agency. EPA’s interim final rule, which becomes effective on August 1, 2016, implements requirements of the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015 (the 2015 Act) and, according to EPA, is designed to increase EPA’s statutory civil monetary penalties to reflect inflation – significantly, in some cases – and to ensure civil penalties maintain their deterrent effects. EPA has stated that its adjusted civil penalty amounts will not necessarily affect the process it uses to assess penalties or the amounts it will ultimately assess, but EPA’s adjusted statutory penalty amounts could result in significant penalties in some enforcement cases. In some cases, EPA now has authority to impose penalties of hundreds of thousands of dollars per day per violation.

Since 1990, the EPA, like other federal agencies, has been required to review and, as appropriate, to revise its statutory monetary penalty amounts every four years to account for inflation. In practice, however, certain agencies did not follow this quadrennial requirement. The 2015 Act provides that, beginning on January 15, 2017, federal agencies, including the EPA, will be required to provide for annual cost-of-living adjustments to their statutory penalty amounts to reflect inflation.

In the interim, however, the 2015 Act requires agencies to provide for initial “catch-up” cost-of-living adjustments for civil penalty amounts through their interim final rulemakings. The “catch-up” amounts may not, by statute, exceed 150 percent of the penalty amounts in effect on November 2, 2015.

Consistent with the 2015 Act and the Office of Management and Budget’s (OMB) February 24, 2016 guidance, EPA calculated “catch-up” amounts for over 66 statutory penalties and announced the adjusted penalties in Table 2 of the interim final rule. EPA’s new, adjusted statutory civil penalty amounts vary by penalty. For example, the interim final rule increases the previous maximum $37,500 per-day penalty for violating requirements of implementation plans or permits for affected sources, major emitting facilities, or major stationary sources under the Clean Air Act (CAA) to a maximum of $93,750 per day per violation. Similarly, the interim final rule increases EPA’s civil monetary penalty under the Clean Water Act (CWA) for oil or hazardous substance discharges – previously set at a maximum of $37,500 per day per violation – to $44,539 per day per violation.

The ranges of statutory civil penalties under Table 2 of the interim final rule are, by statute:

EPA-Administered Statute Range of Statutory Civil Penalties for Violations that Occurred After November 2, 2015 and Assessed on or After August 1, 2016
Clean Air Act $8,908 – $356,312
Clean Water Act $1,782 – $257,848
Comprehensive Environmental Response, Compensation, and Liability Act $53,907 – $161,721
Resource Conservation and Recovery Act $14,023 – $93,750
Safe Drinking Water Act $9,375 – $1,311,850
Toxic Substances Control Act $8,908 – $37,500

EPA can assess its adjusted penalty amounts on or after August 1, 2016 for statutory violations that occurred after November 2, 2015; parties should consult Table 2 of the interim final rule for guidance on penalty amounts for such violations. However, for statutory violations that occurred on or before November 2, 2015, or for violations that occurred after November 2, 2015 but for which EPA assesses penalties before August 1, 2016, parties should continue to consult EPA’s existing civil penalty amounts, located in Table 1 of 40 C.F.R. § 19.4.

Transmission Planning and Construction Right of First Refusal Ruled Unduly Discriminatory, Not Mobile-Sierra Protected

The provision contained in incumbent electric utility tariffs—conferring on the holder the right of first refusal (ROFR) to construct additions to the high-voltage electrical grid, regardless of who conceived of and proposed the addition—is unduly discriminatory, the U.S. Circuit Court of Appeals for the D.C. Circuit held in a July 1 decision in Oklahoma Gas & Electric Co. v. FERC, No. 14-1281.   The court’s decision upheld utility-specific applications of the FERC mandate—a central open-access innovation of the agency’s Order No. 1000 (Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities)—that directed independent system operators and regional transmission organizations (ISO/RTO) to remove from their existing tariffs and membership agreements the ROFR provision (Removal Mandate).

Earlier in South Carolina Public Service Authority v. FERC, 762 F.3d 41 (D.C. Cir. 2014), the same court generally had upheld the Removal Mandate as applied to ISO/RTOs but had reserved judgment on whether the 60-year-old Mobile-Sierra presumption that the rates in negotiated arm’s length natural gas and power sales agreements are just and reasonable applied to the ROFR provisions of the ISO/RTO tariffs and membership agreements.  In Sierra, the Supreme Court of the United States held that the presumption applies against not only the parties to a negotiated agreement but against FERC itself; thus, if it were found to apply to the ROFR, FERC could overcome the presumption only by showing that the ROFR seriously harmed the public interest.

The court could have resolved ISO/RTO and incumbent utilities’ challenges to the Removal Mandate in either of two ways.  First, it could have determined that the context in which the ROFR provision was included in the tariffs and membership agreements prevented the presumption from applying in the first instance because of infirmities or unfair dealings in contract formation, such as fraud or duress.   Second, it could determine that the presumption did apply and then address the question of whether FERC had overcome the presumption with evidence that the ROFR in member agreements seriously harmed the public interest.  The court took the former course.  It ruled that the Mobile-Sierra presumption never applied in the first instance because (quoting Order No. 1000 and citing South Carolina), the ROFR “created ‘a pre-existing [i.e., not negotiated] barrier to entry’ for nonincumbent transmission owners.”  Citing precedent from the Seventh Circuit, the court found that “such terms” as the ROFR are “self-protective and anti-competitive [and] cartel-like.”

By cabining its holding to the anticompetitive effects of the ROFR, the court was able to bypass two other and possibly more complicated issues.  First, it bypassed the issue of whether the Mobile-Sierra presumption applies not only to the rates in regulated natural gas and power sales agreements, but also to agreement terms that affect rates.  As the court noted, both the petitioners and FERC argued the case based “on the premise” that the presumption applies to both to rates and agreements terms that affect rates.  Second and possibly more nettlesome is whether the Mobile-Sierra presumption would protect other provisions of ISO/RTO tariffs even though (quoting the court) “[t]ariffs are the mechanism through which regulated utilities unilaterally set their rates and terms of service,” whereas Mobile-Sierra protects contracts negotiated bilaterally between sophisticated parties at arm’s length.  The court held open resolution of this issue for future unilateral challenges to other ISO/RTO tariff or member agreements.

Energy Tax Extenders in FAA Bill Unlikely

As discussed in our post on April 7, US Congress extended the Production Tax Credit (PTC) under Internal Revenue Code (IRC) Section 45 and the Investment Tax Credit (ITC) under IRC Section 48 in December 2015, but failed to include extensions for certain types of renewable energy property, including fuel cell power plants, stationary microturbine power plants, small wind energy property, combined heat and power system property, and geothermal heat pump property. Some congressional leaders had stated that the omission was an oversight that would be addressed in 2016.

In March, President Barack Obama signed an extension of certain Federal Aviation Administration (FAA) programs and revenue provisions through July 15, 2016. This legislation was apparently crafted with an intentionally short timeframe to allow inclusion of the omitted PTC and ITC provisions in long-term FAA reauthorization legislation.  However, Senate Finance Committee members have indicated that the long-term FAA legislation will not include energy tax incentives. According to Tax Analysts, Senate Finance Committee member John Thune (R-SD) recently indicated that the extenders will not make it into the FAA reauthorization bill. Senator Richard Burr (R-NC) also said that the most likely vehicle for energy tax incentives would be an end-of-the-year tax bill.

IRS Revises Recent Begin Construction Guidance

On May 18, 2016, the Internal Revenue Service (IRS) revised Notice 2016-31 (Notice), its recent guidance on meeting the beginning of construction requirements for wind and other qualified facilities (including biomass, geothermal, landfill gas, trash, hydropower, and marine and hydrokinetic facilities). For a discussion of the Notice, click here. The revisions clarify that the Continuity Safe Harbor is satisfied if a taxpayer places a facility into service by the later of (1) the calendar year that is no more than four calendar years after the calendar year during which construction of the facility began, or (2) December 31, 2016. The revisions also include additional language that the Notice applies to any project for which a taxpayer claims the Section 45 production tax credit (PTC) or the Section 48 investment tax credit (ITC) that is placed in service after January 2, 2013.

The revised Notice also corrects mathematical errors in an example illustrating the application of the begin construction guidance in the Notice to retrofitted facilities. The revised example is as follows:

A taxpayer owns a wind farm composed of 13 turbines, pad and towers that no longer qualify for either the PTC or the ITC. Each facility has a fair market value of $1 million. The taxpayer replaces components worth $900,000 on 11 of the 13 facilities at a cost of $1.4 million for each facility. The fair market value of the remaining original components at each upgraded facility is $100,000. Thus, the total fair market value of each upgraded facility is $1.5 million. The total expenditures to retrofit the 11 facilities are $15.4 million. The taxpayer applies the single project rule. Because the fair market value of the remaining original components of each upgraded facility ($100,000) is not more than 20 percent of each facility’s total value of $1.5 million, each upgraded facility will be considered newly placed in service for purposes of the PTC and the ITC. Accordingly, if the taxpayer pays or incurs at least $770,000 (or 5 percent of $15.4 million) of qualified expenditures in 2016, the single project will be considered to have begun construction in 2016. Provided the taxpayer also meets the Continuous Efforts Test, each upgraded facility will be treated as a qualified facility for purposes of the PTC. However, no additional PTC or ITC will be allowed with respect to the two facilities that were not upgraded.

Taxpayers should consider talking with their advisors to discuss the application of these rules to their projects.

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