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EPA Proposes to Eliminate Affirmative Defenses for Many Clean Air Act Violations

Posted in Environmental

The U.S. Environmental Protection Agency (EPA) issued a proposed rule on September 5, 2014 that would prevent states from including affirmative defenses in their Clean Air Act state implementation plans (SIPs) for emissions exceedances that occur during startup, shutdown and malfunction (SSM) periods.  The proposal would also require several states to revise their existing SIPs so as to conform with EPA’s new approach to affirmative defenses.

EPA’s proposal modifies an earlier February 2013 proposal and arises from a Sierra Club petition asking EPA to revise roughly 40 different SIPs.  Under the new proposal, EPA would largely grant Sierra Club’s petition rather than granting it only as to certain types of affirmative defenses, as EPA had previously proposed.   A list of the states affected by the proposed rule can be found on EPA’s rulemaking website.  If the rule is finalized as proposed, those states will have 18 months from the date of the final rule to submit revised SIPs.

EPA has long allowed the use of affirmative defenses in SIPs, with at least one court holding that it has the authority to do so.  But in April of this year, the D.C. Circuit held that the plain language of the Clean Air Act prohibits EPA from including affirmative defenses in its own non-SIP regulations under Clean Air Act Section 112.  EPA’s September 5 proposal extends the logic of that decision to the SIP context.  But regulated parties should also be aware that the new proposal provides a good illustration of EPA’s “Next Generation Compliance” initiative in action.  The proposal is consistent with the agency’s stated desire to simplify its regulations by reducing the number of exceptions contained in those regulations.

Regulated parties may fear that under EPA’s new proposal they will be unduly penalized for emissions exceedances caused by events beyond their control.  They can take some comfort in understanding that even without affirmative defenses, the Clean Air Act’s penalty provisions do allow the agency and the courts some discretion in setting penalty amounts.  Thus, going forward, facility owners that experience an emission exceedance because of events beyond their control can still argue, on a case-by-case fact-specific basis, that it would be inappropriate to impose any penalties.

Comments on EPA’s proposal are due by November 6, 2014, and, under the terms of a settlement agreement with Sierra Club and WildEarth Guardians, EPA is required to issue a final rule by May 22, 2015.

Environmental Impact Analysis Required for Natural Gas Facilities Clarified in Court Decision Denying Residents’ Challenge to Compressor Siting Approval

Posted in FERC, Natural Gas

A New York town’s challenge to the Federal Energy Regulatory Commission’s (FERC) siting authorization for a natural gas pipeline compressor station was rejected by the U.S. Court of Appeals for the D.C. Circuit in Minisink Residents for Environmental Protection and Safety v. FERC.  The court’s August 15 decision denying the petition for review of residents of the Town of Minisink, when read in conjunction with its decision earlier this year in Delaware Riverkeeper Network v. FERC, delineates the scope of environmental impact analysis that the court will require of FERC  under the National Environmental Policy Act (NEPA).

Residents of the Town protested the compressor station’s location and urged FERC and Millennium to pursue an alternative site referred to as the Wagoner Alternative.  The Wagoner Alternative would have resulted in the compressor station being located in a less populous area but would have required the replacement of a seven mile pipeline segment (called the Neversink segment).  In developing its environmental assessment, FERC had actively considered the Wagoner Alternative but concluded that because of the need to replace the Neversink segment, the environmental impact associated with the Minisink location would be less and the Minisink location was therefore preferable.  FERC’s decision approving the Minisink proposal was split 3-2, with former Chairman Wellinghoff and current Chairman LaFleur dissenting, both Commissioners concluding that the Wagoner Alternative was the better option.

Fundamental to the D.C. Circuit’s decision was its finding that FERC had adequately analyzed the Wagoner Alternative and that there was ample evidence to support its determination that the Wagoner Alterative would have a greater impact due to the need upgrade the Neversink segment.  The petitioners attempted to undermine this finding by pointing to a Millennium PowerPoint presentation that they alleged showed that even if the compressor station were to be located in Minisink, Millennium still planned to replace the Neversink segment.  The court, however, did not consider the PowerPoint persuasive in light of both Millennium’s representation to FERC and Millennium’s counsel’s representation at oral argument that Millennium had no current plans to replace the Neversink segment.

In an instructive footnote, the D.C. Circuit contrasted this case to its recent decision in Delaware Riverkeeper, where it held that FERC improperly segmented and failed to consider the cumulative impact of four connected pipeline construction projects.  The court clarified that the “critical” factor in Delaware Riverkeeper was that all of the pipeline’s projects were either under construction or pending before FERC for environmental review at the same time.  The court acknowledged that the issue before them in Minisink Residents would potentially be “more troublesome” if Millennium were now planning to pursue the Neversink upgrade.

Appeals Court Validates FERC Regional Planning Mandate as Reasoned Evolution of the Open-Access Electricity Transmission System

Posted in FERC

The Federal Energy Regulatory Commission’s (FERC) Order No. 1000 mandate that going forward the high-voltage electric transmission grid be planned and fairly financed regionally by all of its operators and beneficiaries, survived myriad challenges from 45 petitioners in the unanimous August 15 decision of a three-judge panel of the U.S. Court of Appeals for the D.C. Circuit in South Carolina Public Service Authority v. FERC.  The rigorous 97-page opinion rejected challenges coming from all directions to the 2011 rulemaking entitled “Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities.”

According to the panel, nearly all of the challenges misapprehended Order No. 1000’s regional planning mandate.  The court repeatedly emphasized that Order No. 1000’s mandate is nothing new, but rather the next step in evolving efforts under section 206 of the Federal Power Act to combat undue discrimination.  That evolution, the panel explained, began in 1996 when Orders No. 888 and No. 889 required that electricity transmission be “unbundled” from sales and offered via the internet pursuant to open-access tariffs, and 11 years later continued in Order No. 890’s directive that a transmission provider standardize how it measures available transmission capacity and open to its customers the process for planning transmission upgrades and expansions.

The panel’s decision affirmed FERC’s authority to require each of the key elements that FERC prescribed for regional transmission planning.  Those elements include:

  • All public utility transmission providers are required to participate in a regional planning process, and non-public utilities such as cooperative or municipal utilities effectively must also participate pursuant to a reciprocity requirement carried forward from Order No. 888.
  • The planning process must include procedures for taking into account federal, state and local laws and regulations affecting transmission, such as federal air quality rules and state or local renewable portfolio standards.
  • Transmission tariffs must be amended to remove provisions that confer on the incumbent transmission provider a right of first refusal to construct, own, and operate new regional transmission, thereby opening the regional process to input, innovation, and investment from non-incumbents and new entrants, subject to state and local restrictions on siting and eminent domain.
  • A methodology must be added to transmission tariffs for allocating up-front the cost of new regional transmission facilities, consistent with six principles, including a causation principle directing that the allocation be roughly commensurate with the benefits received by those consumers required to pay, and a prohibition on one region allocating costs to its neighbors without their advance consent.

FERC Chairman Cheryl LaFleur promptly praised the panel’s decision upholding Order No. 1000 in its entirety as critical for inducing the “substantial investment in transmission infrastructure [needed] to adapt to changes in its resource mix and environmental policies.”  In its decision the panel noted that the electric industry in 2008 estimated the infrastructure investment needed at $298 billion between 2010 and 2030.

Following FERC’s lead, the panel chose not rule at this time on challenges that elements of the regional planning mandate violate the Mobile-Sierra doctrine —eponymously named for two 1956 Supreme Court decisions —which limits FERC’s authority unilaterally to alter the terms of bilateral contractual relationships.  FERC explained that it would not rule on these challenges in the context of Order No. 1000, but would instead address them in connection with a transmission provider’s filing of tariff amendments in compliance with the Order.  Mobile-Sierra challenges prosecuted at that time are unlikely to succeed since precedents interpreting the doctrine give the Commission much greater leeway when implementing industry-wide changes to tariffs than when seeking to alter individual contracts.

NJ Energy Resilience Bank Funds Distributed Energy Resources

Posted in Project Development and Finance, Renewables

Last week, the New Jersey Board of Public Utilities (BPU) approved an agreement with the New Jersey Economic Development Authority (EDA) to establish and operate an Energy Resilience Bank in the state.  The BPU approved a plan to direct over $200 million in federal aid to the bank.  The Energy Resilience Bank (ERB) will focus on the development of distributed energy resources at critical facilities throughout the state, aiming to minimize the impacts of widespread power outages like the one Hurricane Sandy caused.

The ERB will be focused on providing capital, both low-interest loans and grants, to critical facilities that offer the greatest resilience benefits, including water and wastewater treatment plants and hospitals.  Subsequent funding will be directed toward other critical facilities, such as transportation, emergency response and schools that can function as shelters in case of emergency.  While other states, including New York and Connecticut, have recently launched green banks, the ERB will be the first to focus on resiliency.

The launch of the ERB followed a National Renewable Energy Laboratory study that found that distributed generation and microgrids are integral to energy resiliency.  Distributed generation and microgrids have the potential to ‘island’ electricity at critical facilities with on-site generation, retaining power during bulk-power system blackouts.  These technologies provide additional benefits such as increasing efficiency by cutting transmission losses and incentivizing clean energy deployment.

New York launched its Green Bank in December with an initial capitalization of $210 million.  The New York model focuses on private-sector investment proposals and aims to support financing for local energy efficiency and clean-energy projects that larger financial institutions typically overlook.  New York’s Green Bank envisions support such as credit enhancements, co-investing with the private sector in a loan fund for clean energy, loan warehousing/short-term project aggregation and similar arrangements.  Connecticut launched the first green bank in the country in 2012, and, according to their 2013 report, roughly ten dollars was invested by private sources for every one dollar of ratepayer funds invested.  It remains to be seen whether New Jersey will similarly leverage private investment in its model.

Get LinkedIn to Updates on Mexico’s Energy Reforms

Posted in Natural Gas, Power Markets

The energy reforms in Mexico have generated significant interest from energy investors around the world. McDermott has created a new LinkedIn Group, McDermott Discussion Group: Mexico’s Energy Reforms, to discuss legislative developments and their impacts on the changing energy private investment climate. Members of our team are well studied in these reforms and we will be posting updates on legislative developments and market updates. We encourage group member discussion and comments as well. Group participants stand to gain insight from our lawyers who are studying the reforms, from their peers who are also considering opportunities in Mexico, and from Mexican government officials who are tasked with executing the reforms.  The impact of the reforms will be felt across the board, covering the oil, gas and power sectors.

Click here to join our group. If you have any questions or technical issues, please contact Taylor Shekarabi.

D.C. Circuit Rules that FERC May Not Segment Its Evaluation of the Environmental Impact of Related Natural Gas Pipeline Construction Projects, Regardless of Whether They Are Separately Proposed

Posted in FERC, Natural Gas

The D.C. Circuit Court of Appeals recently issued an opinion holding that the Federal Energy Regulatory Commission (FERC) violated the National Environmental Policy Act (NEPA) when it segmented its evaluation of the environmental impact of four separately proposed but connected projects to upgrade the “300 Line” on the Eastern Leg of Tennessee Gas Pipeline Company’s natural gas pipeline system.  Going forward, the court’s ruling will likely compel proponents of interrelated or complimentary pipeline projects to seek their certification on a consolidated basis and will require FERC to evaluate their cumulative impact.

Tennessee Gas’s challenged Northeast Project was the third of four proposed upgrade projects to expand capacity on the existing Eastern Leg of the 300 Line.  The Northeast Project added only 40 miles of pipeline, while the four proposed projects combined to add approximately 200 miles of looped pipeline.  FERC approved Tennessee Gas’s first proposed upgrade, the “300 Line Project,” in May 2010.  While that project was under construction, Tennessee Gas proposed three additional projects to fill gaps left by the 300 Line Project, one of which was the Northeast Project.   As part of its review of the Northeast Project, FERC issued an Environmental Assessment (EA) required by NEPA that recommended a Finding of No Significant Impact.  The EA for the Northeast Project, however, addressed only the Northeast Project’s environmental impact without reviewing the cumulative impact of all four projects.

The D.C. Circuit held that FERC was in error for failing to consider the cumulative impact.  Under NEPA, the D.C. Circuit explained, FERC must consider all connected and cumulative actions.  The D.C. Circuit found no “logical termini,” or rational endpoints to divide the four projects and found the projects were not financially independent.  Rather, the court found the Northeast Project was “inextricably intertwined” with the other three improvement projects that, taken together, upgraded the entire Eastern Leg of the 300 Line.  The court held that FERC must analyze the cumulative impact of the four projects and remanded the case to FERC for consideration.

The Court emphasized that in this case, “FERC was plainly aware of the physical, functional, and financial links between the two projects.”  Regardless of whether an interstate pipeline initially plans to embark on a series of related upgrades, once FERC is aware of the interrelatedness of proposed expansion projects, it must take care to review any cumulative environmental impacts that may arise.

The D.C. Circuit’s decision may also be a warning that FERC must pay greater attention to the NEPA review in pipeline construction projects.  The D.C. Circuit also has before it this term a case alleging that FERC did not sufficiently consider the environmental review of the siting of a new pipeline compressor station in light of less environmentally intrusive alternatives.  See Minisink Residents for Environmental Preservation and Safety v. FERC, Case No. 12-1481.  Both cases take issue with the rigor of FERC’s environmental review under NEPA, and the D.C. Circuit’s decisions may signal a new era of increased focus on the environmental review process.

For more information, please contact your regular McDermott lawyer or:

Karol Lyn Newman: + 1 202 756 8405  knewman@mwe.com
Dan Watkiss: + 1 202 756 8144  dwatkiss@mwe.com

Italian Decree on the Cut of Incentives for Photovoltaic Plants Enters into Force

Posted in EU Developments, Renewables

by Carsten SteinhauerSabine KonradAnna VescoArne Fuchs and Riccardo Narducci

On 25 June 2014, Law Decree no. 91 /2014 (the “Decree”) regarding among others “urgent measures … for the limitation of costs applied to electricity prices” has entered into force. The Parliament has now 60 days to confirm and convert the Decree into law—possibly with amendments—or to repeal it. A repeal is unlikely, considering that these measures are politically strategic to the Renzi Government, which has invested its credibility in the reduction of electricity bills for small and medium-sized enterprises through a reduction in the annual cost of PV incentives. Please click here to read the full article.

The Supreme Court’s Greenhouse Gas Permitting Decision – What Does It Mean?

Posted in Environmental

The U.S. Supreme Court today partly upheld and partly rejected the U.S. Environmental Protection Agency’s federal Clean Air Act permitting regulations governing greenhouse gas (GHG) emissions from stationary sources.  The decision is mostly a victory for EPA, and its narrow scope means that it will almost certainly not disrupt, let alone invalidate, EPA’s ongoing Section 111(d) rulemaking to set GHG emission limits for existing power plants.  At the same time, the decision does not necessarily mean that EPA’s 111(d) proposal is free from legal challenge.  That is because the decision does not address 111(d).

Today’s decision concerns the Clean Air Act’s two stationary source permitting programs – the prevention of significant deterioration (PSD) program and the Title V program.  In 2010, EPA announced that it was including GHG emissions within the scope of both programs.  Various states and industry groups challenged that announcement, and today, the Supreme Court partly agreed and partly disagreed with the challengers.

First, five justices (Scalia, Roberts, Kennedy, Alito and Thomas) held that a source’s GHG emissions, standing alone, cannot trigger the obligation to undergo PSD and Title V permitting.  That part of the decision is a loss for EPA.  But the second part of the decision is a victory for the agency.  Seven justices (Scalia, Roberts, Kennedy, Ginsburg, Beyer, Sotomayor and Kagan) held that EPA can require sources that are subject to PSD “anyway,” because they emit other types of pollutants in significantly large quantities, to control their GHG emissions.  In sum, GHG emissions cannot trigger the obligation to undergo PSD permitting, but EPA can use the PSD permitting process to impose source-specific GHG emission limits on facilities that trigger the process for other reasons.

The decision does not address EPA’s authority to impose substantive limits on GHG emissions using other statutory provisions such as Clean Air Act Section 111(d).  Readers interested in the ongoing debate over EPA’s Section 111(d) authority may wish to log into a complimentary webinar that McDermott is offering on Thursday, June 26.  The webinar will discuss EPA’s recent 111(d) proposal for existing power plants and will cover various topics that affected parties may want to address during the public comment period on that proposal.  Click here to register.

EPA Publishes its Proposed Regulations for Existing Power Plants – Starting the Public Comment Period

Posted in Environmental

Today, the U.S. Environmental Protection Agency (EPA) published in the Federal Register its June 2, 2014, proposal to regulate greenhouse gas emissions from existing fossil fuel-fired power plants.  The act of publication triggers the start of the 120-day public comment period, meaning that interested parties must submit comments to the agency by no later than October 16, 2014.

On Thursday, June 26, McDermott will be hosting a complimentary webinar on critical issues to address during the comment period.  Click here to register.

The Third Piece of EPA’s Clean Power Plan: GHG Emission Limits for Modified and Reconstructed Power Plants

Posted in Uncategorized

The U.S. Environmental Protection Agency’s proposed greenhouse gas (GHG) regulations for “new” and “existing” power plants have received substantial media attention, but regulated parties should also be aware of the third piece of EPA’s self-styled “Clean Power Plan”:  Proposed carbon dioxide (CO2) emission limits for “modified” and “reconstructed” electricity generating units (EGUs).

EPA proposed CO2 limits for “modified” and “reconstructed” EGUs on June 2, 2014, the same day it issued its proposed regulations for existing power plants, but it did not release its proposed regulatory text for those limits until several days later.  The proposed regulatory text is now available on EPA’s website, and power plant owners and operators should scrutinize it carefully – it amends the proposed regulatory text that EPA released in January 2014 in connection with its proposed limits for “new” power plants.

As defined in EPA’s regulations, “modified” units are existing units that undergo a physical or operational change that results in an increase in their hourly rate of air emissions, while “reconstructed” units are existing units where components have been replaced to such an extent that the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility, and it is technologically and economically feasible to meet the emission standards set by EPA.

Under EPA’s June 2 proposal, neither modified nor reconstructed steam units would have to install carbon capture and storage technology or meet the more stringent CO2 emission standards that EPA has proposed for newly constructed units.  Instead, those units would be required to meet an emission standard based on a combination of best operating practices and equipment upgrades (to improve the unit’s efficiency).  Modified gas turbines would be required to meet the corresponding emission limits for new gas turbines.

More specifically, the proposal would set different standards of performance for different types of units, as follows:

  • Modified fossil fuel-fired EGUs (i.e., utility boilers and integrated gasification combined cycle (IGCC) units):  the source must meet a EGU-specific emission limit (a) determined by the EGU’s best historical annual CO2 emission rate from 2002 to the date of modification, plus an additional 2 percent emission reduction, or (b) determined depending on whether the modification occurs before or after the EGU becoming subject to a Clean Air Act Section 111(d) state plan.  For option (a), the limit must be at least 1,900 pounds of CO2 per net megawatt-hour (lb/MWh-net) for sources with a heat input exceeding 2,000 million British thermal units per hour (MMBtu/h), or 2,100 lb/MWh-net for sources with a heat input of 2,000 MMBtu/h or less.
  • Reconstructed fossil fuel-fired EGUs:  sources with a heat input exceeding 2,000 MMBtu/h must meet a limit of 1,900 lb/MWh-net, and sources with a heat input of 2,000 MMBtu/h or less must meet a limit of 2,100 lb/MWh-net.
  • Modified or reconstructed natural gas-fired stationary combustion turbines:  sources with a heat input exceeding 850 MMBtu/h must meet a limit of 1,000 pounds of CO2 per gross megawatt-hour (lb/MWh-gross), and sources with a heat input of 850 MMBtu/h or less must meet a limit of 1,100 lb/MWh-gross.

Importantly, modified and reconstructed units that are modified or reconstructed after they become subject to a state plan for existing power plants would remain subject to that plan (in addition to being subject to the limits set forth above) even after their modification or reconstruction.

EPA estimates that few EGUs would be affected by the rulemaking, and estimates compliance costs of $0.78 million to $4.5 million (in 2011) and CO2 reductions of 133,000 to 266,000 tons in 2025.  EPA estimates combined climate benefits from CO2 reductions (and health co-benefits from SO2, NOx and PM2.5 reductions) of $18 million to $33 million at a 3 percent discount rate for emission reductions in 2025 for the lowest emission reduction scenario, and $35 million to $65 million at a 3 percent discount rate for emission reductions in 2025 for the highest emission reduction scenario.

The proposed standards would apply at all times, including during startup, shutdown and malfunction periods.  The proposal articulates the same continuous monitoring requirements, emissions performance testing requirements, continuous compliance requirements, and notification, recordkeeping and reporting requirements as those proposed for newly constructed sources in EPA’s January 2014 proposal.

Once the full proposed rule concerning modified and reconstructed plants is published in the Federal Register, interested parties will have 120 days to comment.  EPA will hold joint public hearings for this proposal and the proposal concerning CO2 emissions from existing power plants.