Latham's Clean Energy Law Report

Carbon Trading: A New Dawn in China

Posted in Environmental and approvals

By Paul Davies and R. Andrew Westgate

This document is a translation of the recently released Tentative Measures for the Administration of Trading of Carbon Emissions Rights promulgated by the National Reform and Development Commission (“NDRC”) on December 10, 2014.  As discussed in a recent article by Latham & Watkins partner Paul Davies, this development represents the first details the NDRC has provided on how the national carbon market in China, currently the world’s second largest consumer of energy, will work.  This translation was prepared for clients of Latham & Watkins for informational purposes only, and should not be relied upon as an official translation or interpretation of Chinese law.

 This article was originally published by China Law & Practice and can be found here.

Low Carbon Fuel Standard Overview

Posted in Environmental and approvals

Joshua Bledsoe and Michael Dreibelbis of Latham & Watkins, recently co- wrote a LCFS Fact Sheet with the International Emissions Trading Association (IETA). The article is available on IETA’s website and below:

The California Global Warming Solutions Act of 2006 (aka Assembly Bill 32 or “AB 32″) mandates a reduction in California statewide greenhouse gas (GHG) emissions to 1990 levels by 2020. The Low Carbon Fuel Standard (LCFS) is one of the primary Emission Reduction Measures promulgated by the California Air Resources Board (ARB) to achieve AB 32’s 2020 target. It is expected to contribute approximately 20% of the required statewide GHG reductions under AB 32.

The LCFS focuses on the transportation sector and requires a 10% reduction in the carbon intensity (CI) of gasoline and diesel from 2010 levels by 2020, with CI targets designed to become more stringent each year. The CI of fuels, expressed as grams of CO2e per megajoule, is calculated across the full lifecycle of transportation fuels (i.e., well-to-wheel) and includes all GHG emissions associated with producing, distributing, and using the fuel.

Who is regulated by the LCFS?

  • Typically, a producer within California or the importer of a refined/final product constitutes the Regulated Party.
  • Suppliers of low-carbon fuels (e.g., electricity, biofuels, natural gas) can “opt-in” to Regulated Party status and generate LCFS credits that can be sold to another party that needs them for compliance.

How does one comply?

Each Regulated Party must ensure that the overall CI score for its fuel pool at least meets the annual target for the given year. Excess CI reductions from one type of fuel can be used to compensate for insufficient reductions in another fuel. A fuel that has a CI below the target for a given year will generate LCFS credits on a volumetric basis (i.e., the more low CI fuel one sells, the more credits one generates). Conversely, a fuel with a CI above the target will generate deficits, also on a volumetric basis. Each LCFS credit represents one metric tonne of CO2e avoided and each deficit represents one metric tonne of CO2e added – both as measured against the pertinent year’s CI target.

In each annual compliance period, a Regulated Party must balance its deficits with credits. The banking of surplus LCFS credits is allowed and credits do not expire due to passage of time. A negative balance for a calendar year that persists until April of the next year results in the Regulated Party being out of compliance. Regulated entities can comply by:

  1. Lowering the CI of their fuels (e.g., via efficiency improvements anywhere in the lifecycle, blending lower carbon fuels); and/or
  2. Purchasing LCFS credits from other Regulated Parties.

The LCFS also imposes recordkeeping requirements (e.g., retention of Product Transfer Documents) and quarterly reporting requirements that must be followed to remain in compliance.

Relationship with Cap-and-Trade Program

While the LCFS has surficial similarities to ARB’s other carbon trading regime, the Cap-and-Trade Program (e.g., both trade in increments of one metric tonne of CO2e), the two operate separately. Among other key differences, the two regimes: (1) establish distinct compliance instruments that are non-fungible across programs; (2) use different compliance instrument tracking systems; (3) require different registrations; and (4) have different rules regarding trading confidentiality. Entities covered by the LCFS and the Cap-and-Trade Program need to comply with both regimes, and cannot use over-compliance in one program to compensate for under-compliance in the other.

What’s next for the LCFS?

The LCFS has been challenged in both California state court and US federal court, and ARB largely has been successful defending the Program. However, due to procedural errors committed by ARB during the initial adoption of the LCFS regulations, the CI targets have been frozen at 2013 levels. ARB presently is attempting to cure these procedural flaws by readopting the Program. Concurrently, ARB also is overhauling many aspects of the LCFS, including but not limited to credit cost containment, credit invalidation procedures, and enforcement of violations.

ARB anticipates extending the LCFS beyond the scheduled 2020 sunset date, just as with the other AB 32 Emission Reduction Measures it implements. Finally, ARB has expressed interest in linking the LCFS with similar programs in Oregon, Washington, and British Columbia.

Governor Brown Orders California’s First Mandatory Water Restrictions

Posted in Environmental and approvals

By Paul Singarella, Lucas Quass and John Morris

On Wednesday April 1, 2015, in the wake of the state’s four-year drought and a winter that brought record-low snowfalls, Governor Brown issued an executive order mandating statewide water use restrictions for the first time in California’s history (the “Executive Order”).  The Executive Order follows on the heels of state legislation signed by the Governor on March 27, which appropriated approximately $1 billion for water projects including emergency drought relief.

Governor Brown announced the Executive Order from a snow-bare Phillips Station in the Sierra Nevada mountains, in his words, “standing on dry grass where there should be five feet of snow.”  The same day, state regulators announced that the state’s snowpack was only at five percent of normal, presaging a very small amount of spring snowmelt that Californians rely upon to replenish their reservoirs.  This January reportedly was the driest January in California since recordkeeping began in 1895.

To address the ongoing drought, the Executive Order primarily aims to: (1) conserve water and (2) increase enforcement against waste throughout the state.

Mandatory Water Use Restrictions

Governor Brown’s announcement builds upon recent emergency water conservation regulations, which the State Water Resources Control Board (“SWRCB”) renewed and updated several weeks ago on March 17, 2015.  The emergency water conservation regulations prohibit excessive outdoor water use and, among other things, require urban water suppliers to implement water shortage contingency plans.  The Executive Order directs SWRCB to implement mandatory statewide water restrictions to reduce potable urban water use by 25% through February 28, 2016.  These restrictions will obligate California municipal water suppliers to reduce usage as compared to 2013 levels.  Additionally, the restrictions will require areas with high per capita use to achieve proportionally greater reductions than those areas with lower uses.  The Executive Order also directs the California Public Utilities Commission to require investor-owned utilities providing water services to implement similar restrictions.  To help achieve these objectives, the Executive Order will instate the following conservation measures:

  • The California Department of Water Resources (“DWR”), in conjunction with local agencies, shall implement a program to replace 50 million square feet of lawns and ornamental turf with drought-tolerant landscaping;
  • The California Energy Commission, DWR and SWRCB shall implement a temporary statewide consumer rebate program to replace inefficient household appliances;
  • SWRCB shall implement water use restrictions on commercial, industrial, and institutional properties, requiring campuses, golf courses, cemeteries and other large landscapes to make significant cuts in water use;
  • SWRCB will prohibit the use of potable water for irrigating at new homes and developments, unless efficient irrigation systems are used, and will prohibit watering ornamental grass on public street medians; and
  • Urban water suppliers must develop and implement rate structures and other conservation pricing to maximize water reductions and discourage water waste. The Executive Order includes measures intended to monitor certain water users and prevent wasteful practices. The Executive Order adds additional scrutiny to agricultural water users, who already have faced significantly reduced water allocations. Under the Executive Order, agricultural users must provide more frequent water use information to SWRCB, which will increase the state’s ability to prevent illegal diversions, waste and unreasonable use. Additionally, the Executive Order requires local water agencies located in high- and medium-priority groundwater basins to implement the California Statewide Groundwater Elevation Monitoring Program, which mandates statewide groundwater elevation monitoring to track seasonal and long-term trends in groundwater elevations. DWR and SWRCB are tasked with monitoring these local agencies to promote appropriate enforcement and compliance. SWRCB is expected to develop emergency regulations to implement the Executive Order in the coming weeks. Following a public hearing, SWRCB may approve the regulations by early May. These conservation measures, coupled with last week’s $1 billion water package, should reduce water use, provide some emergency relief, and avoid an outright moratorium for the most wasteful uses. If the drought persists, Californians, and likely residents of other western states, may see further mandatory water conservation actions.

 Waste Prevention and Monitoring

The Executive Order includes measures intended to monitor certain water users and prevent wasteful practices.  The Executive Order adds additional scrutiny to agricultural water users, who already have faced significantly reduced water allocations.  Under the Executive Order, agricultural users must provide more frequent water use information to SWRCB, which will increase the state’s ability to prevent illegal diversions, waste and unreasonable use.  Additionally, the Executive Order requires local water agencies located in high- and medium-priority groundwater basins to implement the California Statewide Groundwater Elevation Monitoring Program, which mandates statewide groundwater elevation monitoring to track seasonal and long-term trends in groundwater elevations.  DWR and SWRCB are tasked with monitoring these local agencies to promote appropriate enforcement and compliance.

Next Steps

SWRCB is expected to develop emergency regulations to implement the Executive Order in the coming weeks.  Following a public hearing, SWRCB may approve the regulations by early May.  These conservation measures, coupled with last week’s $1 billion water package, should reduce water use, provide some emergency relief, and avoid an outright moratorium for the most wasteful uses.  If the drought persists, Californians, and likely residents of other western states, may see further mandatory water conservation actions.

Legislature Approves $1 Billion Drought Relief Legislation; Governor Brown Expected to Sign

Posted in Environmental and approvals

By Paul Singarella, Daniel Brunton and Lucas Quass

California Legislature Enacts Bill Package on Drought 

On Thursday March 26, 2015, the California Legislature adopted legislation which it describes as allocating approximately $1 billion to emergency drought relief in the state.  As more than 50 percent of the new appropriations target flood control, it remains to be seen to what extent the legislation will mitigate drought conditions.

The legislation consists of two appropriations bills (Assembly Bill 91 and Senate Bill 75) and two policy trailer bills (Assembly Bill 92 and Senate Bill 76) (collectively the “Legislation”), which were announced on March 19, 2015 by Governor Brown as a mobilization of state resources to face the fourth consecutive year of extreme drought.  Governor Brown is expected to sign and enact the Legislation imminently.  The Legislation is intended to direct state funds to drought relief on a faster track than the drought relief contained in the Governor’s January 2015 budget proposal which likely will not be approved until June.


California is currently in the midst of a record drought; this January reportedly was the driest January in California since recordkeeping began in 1895.  The state’s snowpack levels, which supply the state with water throughout the summer, are at historic lows.  There are some reports that California has water remaining in its reservoirs to last just one more year.   California’s groundwater reserves are at historic lows, and reportedly have been decreasing by 12 million acre-feet a year since 2011.  A key factor in the decline of the state’s groundwater reserves is pumping in the Central Valley for agricultural purposes and to replace surface water allocations that have been reduced and, in some cases, eliminated.  On March 17, 2015, the State Water Resources Control Board (“SWRCB”) renewed and updated its statewide emergency water conservation regulations which prohibit excessive outdoor water use and, among other things, require urban water suppliers to implement water shortage contingency plans.  If the drought continues, more curtailments on water usage are expected.

Overview of Legislation

Emergency Relief.  The Legislation appropriates to SWRCB $15 million for emergency drinking water projects, including the design and construction of connections to public water systems and the construction/rehabilitation of wells, and $4 million to provide emergency drinking water to communities affected by the drought.  The Legislation allocates $4.4 million to the Office of Emergency Services to provide communities with drought disaster recovery support.  $24 million is appropriated to the Department of Social Services to provide food assistance to people affected by the drought.  Emergency help for fisheries includes $14.6 million, mostly from the state general fund, allocated to the California Department of Fish and Wildlife (“DFW”) to continue its drought-related operations, which include fish rescues, hatchery operations and fish and wildlife monitoring.

Infrastructure.  The Legislation includes approximately $272 million from the $7.545 billion Water Quality, Supply, and Infrastructure Improvement Act of 2014, also known as Proposition 1, which was approved by California voters last November.  Specifically, the Legislation will accelerate Proposition 1 funding by allocating approximately $132 million to water recycling and demonstration projects and approximately $136 million to improve access to clean drinking water and pay for wastewater treatment in disadvantaged communities.  These appropriations can mitigate drought by producing water suitable for beneficial use and/or for groundwater replenishment.

Mitigation & Monitoring.  The Legislation makes funds available to monitor and mitigate drought conditions and potentially produce new water, including through conservation.  $11.6 million is allocated from the general fund to the California Department of Water Resources (“DWR”) to continue its evaluation of surface and groundwater conditions, expedite water transfers and provide guidance to water agencies.  $20 million is allocated to DWR to fund water use efficiency programs which reduce greenhouse gas emissions.  $10 million is allocated to the Department of Food and Agriculture for agricultural water efficiency projects which reduce greenhouse gas emissions.

The Legislation also includes funding for species and environmental preservation, including a $2 million allocation to DFW to maximize water delivery and efficiency to endangered species including their habitat, and Delta monitoring.  $4 million  is allocated to the Department of Parks and Recreation to control invasive aquatic species within the Sacramento-San Joaquin River Delta and the Suisun Marsh.  $4 million  is allocated to the SWRCB and DFW to enhance instream flows in certain stream systems that support critical habitat for anadromous fish.

Regulatory Oversight.  Approximately $23 million is allocated to the SWRCB for enforcement of water rights and water curtailment actions.

Flood Control.  The largest allocation ($660 million) is earmarked for flood control including the completion, operation or replacement of flood control projects.  While new flood control projects, or repairs to existing facilities, play a role in water capture, it appears that these aspects of the Legislation were designed to allocate funds remaining under Proposition 1E before its expiration, rather than solely focus on drought relief.  Set to expire on July 1, 2016, Proposition 1E  is otherwise known as the Disaster Preparedness and Flood Prevention Bond Act of 2006, which authorizes $4.1 billion in bonds for disaster preparedness and flood prevention projects.  Of the $660 million, approximately $320 million will be available to reduce urban flood risks and $118 million for rural flood management.  $222 million will be granted to DWR for local assistance projects.

Establishment of the Office of Sustainable Water Solutions

The Legislation establishes the Office of Sustainable Water Solutions (“OSWS”) within the SWRCB.  OSWS’s mandate is to promote sustainable drinking water and wastewater treatment solutions and safeguard the effective and efficient provision of safe, clean, affordable, and reliable drinking water and wastewater treatment services.  OSWS will be particularly focused on aiding small communities with modest resources and large infrastructure needs.  OSWS will help communities seek out state and federal funding for water supply projects.

Limited Suspension of Public Contracting and Procurement Requirements

Generally, the State Contract Act provides for a contracting process by which public agencies engage contracts through a competitive bidding process, under which bids are awarded to the lowest bidder, with specified alternative bidding procedures authorized in certain cases.  This process can be  cumbersome and may frustrate public agencies from promptly engaging in emergencies.  As several communities in the Central Valley are without water entirely, the Legislation provides public agencies with greater flexibility to respond to an urgent drinking water need and temporarily suspend the State Contract Act.

Broader Context

The Legislation is the latest response from Sacramento to attempt to address the ongoing drought.  In April 2014, the Governor issued a Proclamation of a Continued State of Emergency in response to the state’s ongoing drought, which extended his January 2014 Emergency Drought Declaration.  In 2014, Governor Brown signed a $687.4 million drought package, which offered aid to communities, food and housing assistance and funds for projects to help communities capture and manage water.  In October 2014, the Governor signed the Sustainable Groundwater Management Act, intended to address the alarming loss of groundwater reserves over the last four years, and to bring groundwater management into a comprehensive regulatory scheme. The Governor’s January 2015 budget proposal includes $532 million in expenditures under Proposition 1 and the last $1.1 billion in funds available under Proposition 1E for flood protection.

Certainly, these actions in the aggregate should make important funding available to real projects, potentially helping to produce new sources of water for beneficial use, capture and store water when available, conserving water that otherwise would be used, and mitigating the impacts of chronic drought conditions.  Given the scale and complexity of the drought, however, and should the drought persist as some scientists predict, similar and even more robust legislation may be in the offing.  These actions  may do less to provide immediate relief, than to lay groundwork important to long-term water security in  California.

Don’t Skip the Credits: The Oft-Overlooked Importance of Air Emission Credits in Mergers and Acquisitions

Posted in Environmental and approvals

By Michael Scott Feeley and Aron Potash

There is no shortage of environmental matters to navigate when buying a company or facility.  Environmental counsel must first lead a diligence effort that delineates the target’s environmental footprint and then suss out the environmental risks and liabilities attendant to the deal.  This diligence process often involves Phase I environmental site assessments, environmental, health and safety compliance evaluations, interviews of target personnel, and review of seller-provided permits, reports, and other documentation.  The knowledge gained from the diligence process feeds into negotiation of purchase agreement terms, including the purchase price, environmental representations, warranties and covenants, corresponding definitions and indemnification provisions, disclosure schedules, and permit transfer provisions.  Myriad environmental matters must be addressed, including compliance with environmental laws, the release of hazardous substances, the presence and validity of environmental permits, ongoing environmental litigation or the possibility of it, and health and safety matters.

One issue that all too frequently gets lost in the shuffle during the diligence and purchase agreement negotiation process is the evaluation of whether air emission credits are necessary to run the business, and if so, how these credits will be treated in the deal documents.  Air emission credits take many shapes and forms but, at bottom, are governmentally issued or approved authorizations to emit air contaminants.  A wide variety of facilities—from power plants to petroleum refineries to manufacturers to hospitals—must often obtain air emission credits in order to lawfully operate.  In recent years, air emission credit programs have even expanded to cover emissions beyond facility fencelines; certain companies, such as transportation fuel suppliers, must now obtain air emission credits to cover emissions linked to the products the companies sell.

This article provides an overview of the air emission credit landscape from the perspective of acquirer’s counsel (although, many of the issues we raise herein must also be dealt with by sellers in M&A transactions, as well as by environmental counsel in financings and other matters).  A first step in addressing air emission credits is to identify the applicable regulatory regime(s).  In tandem, an evaluation is needed of the target’s operations and air emissions.  It is also essential to understand market conditions for air emission credits, potential changes to the regulatory regime, and a client’s business plans for facility operation.  The structure of the transaction—whether the transaction is the stock purchase of an entire company, the asset purchase of a facility or a division, or a merger—also bears upon how air emission credits should be handled.  All of these inputs should inform deal strategy and purchase agreement negotiation.

Programs Requiring Air Emission Credits

Air emission credits are required by many different programs, and a threshold consideration is identifying which programs are applicable.  Emission credit requirements may be implemented by local, state, federal, or foreign authorities.  Some facilities, such as power plants, face numerous potentially applicable air emission credit programs.  Some of the most common air emission credit programs are described below.

In the United States, one of the most frequently encountered air emission credit programs is the federal Clean Air Act’s (“CAA”) New Source Review (“NSR”) program.  The CAA NSR program requires permits prior to the construction or modification of stationary sources of air emissions.  “Nonattainment” NSR permits are required for new and modified major sources of air emissions in areas where air pollutant concentrations exceed the National Ambient Air Quality Standards (“NAAQS”) set by the United States Environmental Protection Agency (“US EPA”) for criteria pollutants: carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, or sulfur dioxide.  In order to obtain an NSR permit, a facility must purchase air emission credits to offset any increase in emissions.  NSR air emission credits are created when a facility reduces emissions at an existing source (such as by installing more stringent control technology or shutting down operations).  The idea is that, if an area is in nonattainment with the NAAQS, no facility will be allowed to increase its emissions unless the increased emissions will be counterbalanced by an emissions reduction at another facility.  State and local regulators to whom CAA enforcement authority is delegated are left to flesh out the exact rules of the nonattainment NSR credit requirements, and these rules accordingly differ by jurisdiction.

There are also a number of cap and trade programs that regulate criteria pollutant emissions.  Although these programs vary in their particulars, they largely feature the same components: (i) the requirements that any emitter of a regulated air pollutant both (1) measure its emissions and (2) obtain emission credits commensurate to its emissions; (ii) a “cap” on the amount of market-wide credits in a given time period (which serves to limit market-wide emissions during that time period); and, (iii) the ability to trade credits among regulated entities on an open market.  Cap and trade programs have found favor because they offer regulators the ability to set the caps at levels necessary to ensure given levels of emission reductions (and to dial the caps back over time to steadily reduce market-wide emissions) and because they offer emitters compliance flexibility.  That is, regulated entities have the option of either reducing their own emissions or buying credits from parties who are able to make more cost-effective emission reductions.  These criteria pollutant cap and trade programs include US EPA’s “Acid Rain Program,” which went into effect in 1995 and targets emissions of precursors to acid rain—oxides of sulfur (“SOx”) and nitrogen (“NOx”)—from fossil fuel-fired power plants.  US EPA rolled out in 2015 a successor program, the Cross-State Air Pollution Rule, which requires power plants in twenty-three states to reduce emissions via a cap and trade mechanism.  California’s South Coast Air Quality Management District (“SCAQMD”) instituted the Regional Clean Air Incentives Market (“RECLAIM”) in 1994 to reduce NOx and SOx emissions from facilities emitting over 4 tons per year of either pollutant, including refineries, power plants, aerospace manufacturing facilities, paper mills, chemical companies, food industry facilities, printers, airline facilities, asphalt plants, and many others.  Texas’s Mass Emissions Cap and Trade Program applies to NOx emitters in the Houston-Galveston-Brazoria area, including oil and gas industry facilities, chemical companies, manufacturers, power plants, hospitals, universities, and others.

New and emerging climate change laws make matters more complex, as companies now face requirements to obtain greenhouse gas (“GHG”) emission credits.  In January 2013, California instituted an emission credit regime that caps aggregate annual emissions of GHGs from certain sectors of the economy.  Covered sectors include the following: (i) electricity generators and importers; (ii) producers of cement, glass, hydrogen, iron, steel, lime, and nitric acid; (iii) petroleum refiners; (iv) paper manufacturers; and, (v) stationary combustion sources.  In 2015, suppliers of natural gas and transportation fuels were added to the program.  The Regional Greenhouse Gas Initiative (“RGGI”), an emission credit-based regime covering power sector GHG emissions, went into effect in 2009 in 10 northeastern and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont), although New Jersey withdrew in 2011.  RGGI caps total power sector carbon dioxide (“CO2”) emissions and reduces them over time by requiring fossil fuel-fired electric power generators with a capacity of 25MW or greater to obtain allowances in amounts equal to their respective CO2 emissions.

Abroad, the European Union Emissions Trading Scheme (“EU ETS”), which began in 2005, covers over 11,000 power generation and manufacturing facilities in 28 European Union and 3 other countries.  Chinese provinces and cities, including Beijing, Chongqing, Guangdong, Hubei, Shanghai, Shenzhen, and Tianjin, began implementing GHG cap and trade systems in 2013, and a national program is planned for next year.  South Korea implemented a GHG cap and trade program in 2015.  Similar programs are underway or under consideration in a number of other foreign jurisdictions.

Due Diligence on a Target’s Air Emissions

Once the applicable regulatory regime or regimes have been identified, a potential buyer must evaluate what the business it is acquiring must do in order to comply with the law.

This task is complicated by the fact that sellers often have failed to comply with complex air emission rules and credit requirements.  Sellers may not have been accurately monitoring or reporting air emissions.  This may be a matter of not knowing what their air emissions have been (or, worse, intentional misrepresentation of those emissions to regulators).  To the extent past emissions have not been accurately reported to regulators, a facility may not have the air emissions credits it needs to operate at present levels.  In fact, a facility may have been altogether left out of emissions credit programs (such as a cap and trade program) if regulators failed to realize that the facility has emissions of a magnitude that require its inclusion.  In many cap and trade programs, the early years of the program are when credits are freely allocated by the regulators to covered facilities.  Being left out during these early years can mean missing out on an allocation of free credits.  Regulators are often loathe to disturb carefully-calibrated emissions caps by giving out additional free credits years down the road, so skillful negotiation is called for in such a situation.  If mishandled, underreported emissions problems can spell years of headaches and litigation, and in the worst case scenario, large fines or a forced facility shutdown.

Determining whether emissions have been reported properly can require careful and context-specific diligence.  Air emissions are not within the scope of a Phase I environmental site assessment, and unlike indicia of hazardous materials releases, they are not readily observable.  Even a limited environmental compliance audit will usually fail to quantify a facility’s air emissions.  In order to identify air emissions, it may be necessary to have an environmental consultant knowledgeable as to the business’s processes and emissions profile conduct an in-depth review of the equipment that is present (which may be different than the equipment that is permitted) and how emissions from the equipment are monitored and quantified.  Different jurisdictions have different rules as to how emissions need to be monitored and quantified.  For example, certain jurisdictions allow facilities to estimate emissions using emissions factors (such as by monitoring production and assuming that emissions from the facility are constant and can be determined using a conversion factor that translates production into emissions).  In other cases, a facility must continuously monitor contaminant emissions and report those emissions to regulators in real time.

One helpful tool is the annual third party auditing required by some programs, such as California’s GHG cap and trade program, to verify that facilities are accurately monitoring and reporting emissions.  If available from the seller or the regulatory agency, such reports can be helpful in gauging the risk that a facility is inaccurately reporting emissions.

Market Conditions, Regulatory Developments, and Business Plans

In negotiating the purchase agreement for a facility or company, it may be protective to specify both what kind of and how many credits will be transferred.   These issues, particularly the latter, often require an examination of the air emission credit market, actions the regulator may be taking to influence the market or otherwise modify the program, and a client’s business plans for the facility.

Emission credits come in different flavors and are often classified based on their duration and source of generation.  Certain emission credits are only good for a specific compliance period, such as a calendar year or multiyear period.  Others are good for indefinite periods.  Emission credits may also differ in how they were generated.  For example, in cap and trade markets, compliance credits are normally created and distributed by the regulator running the market, while offsets are generated by entities voluntarily reducing their emissions.  There can be wide price discrepancies between different types of credits, and the different types of credits may be subject to different regulatory requirements (such as invalidation requirements or holding limits).

Analyzing how many credits the buyer will need is more involved than asking how many the seller has to provide.  If a seller has been purchasing credits on an annual basis, the seller may not have any credits to provide to cover operations going forward.  Even if a facility receives through the transaction enough air emission credits to permit future operation at the seller’s pre-transaction production levels, additional credits may be needed if a facility is to expand production or modify its operations.

If a buyer does not obtain through a transaction the air emission credits it requires to operate a business in the future at the production levels it would like, it could be expensive to obtain the credits—or even worse, there may not be any credits available.  In certain markets, credits may be held by a relatively small number of market participants who could be unwilling to sell credits to competitors.  Or there may be far fewer emissions reductions available to generate credits than there is demand for such credits.  As one example of credit scarcity, the SCAQMD published in 2009 the following estimates of nonattainment NSR credit prices based on average market prices.  Credits necessary to permit a printing press would cost $390,000.  A spray booth at an auto body shop would require credits worth $500,000.  Air emission credits for a boiler at a hospital would run $2,000,000, the same price as permitting a tortilla chip fryer and oven at a food-manufacturing facility.  A sewage treatment plant digester and flare would increase the cost to $3,000,000, and a new landfill would really up the ante, to $140,000,000.  In order to determine how many credits would be needed, it is important to understand future production levels and credit market conditions.

Another important consideration is how regulators may modify emission credit rules over time.  Regulators will often tinker with regulatory schemes to hasten the pace of emission reductions if necessary to meet regulatory goals, or to slow the pace of reductions if the economic cost of the program is too high.  For example, regulators will sometimes shrink marketwide emission caps by reducing the value of each market participant’s holding, and buyers can protect themselves by understanding the program’s history regarding and rules governing such matters.

Closing the Deal

As to the purchase agreement itself, a key consideration is the extent to which the representations and warranties, any indemnities, and other provisions, will shift the risk of a failure to comply with air emission credit requirements.  As one example, regulators may seek to invalidate seller-held credits following the closing—even if the seller did no wrong, which is a risk the purchase agreement could be crafted to address.

The overall structure of the transaction bears upon how risk can best be shifted.  Representations and risk-shifting provisions differ among stock purchase agreements, asset purchase agreements, and merger agreements.  For example, in a public company-style merger agreement, there may be little ability to seek indemnification for breaches of representations and warranties, making pre-signing diligence all the more important.  With respect to the purchase of a single facility or a division via an asset purchase agreement, the buyer may have the ability to both (1) classify liabilities related to air emission credit noncompliance as “excluded liabilities” that the seller is stuck with and also (2) classify needed air emission credits as “transferred assets” to be conveyed as part of the deal.  If the primary risk-shifting mechanism is to be via environmental representations and warranties (and an indemnity covering any breaches), as would be common in a stock purchase agreement, then it becomes important that the representations and warranties survive for a period of time sufficient for the buyer to confirm that it, its third party auditor, and the regulator are all satisfied that the representations and warranties are accurate.

The particulars of the applicable regulatory regime and its expected evolution, a buyer’s planned use of the facility, the relevant emissions market, the seller’s processes and emissions monitoring and reporting mechanisms, the type and quantity of credits available for conveyance, and the structure of the transaction all should inform purchase agreement negotiation and pricing.  Air emission credits may often be overlooked in the transactional context, but careful attention to them is necessary if a buyer wants to be sure the value of its investment will not go up in smoke.

California’s Strict New Health Risk Assessment Guidelines May Increase Regulatory Burden on Industrial Uses and Development Projects

Posted in Energy regulatory, Environmental and approvals, Finance and project development

By Marc Campopiano and Max Friedman

On March 6, 2015, the California Office of Environmental Health Hazard Assessment (OEHHA) updated its Guidance Manual for Preparation of Health Risk Assessments (HRAs) for the purpose of better characterizing exposure risks to children from air toxics.  Using the new Guidance Manual, HRAs are expected to estimate risks that are two to five times greater than HRAs using the former methodology—even assuming no changes in air toxics exposure.  As a result, once the updated Guidance Manual has been implemented by the various air districts, it likely will expand the notification and permitting requirements for many industrial uses that require air toxics permits and may require additional analysis and mitigation for development projects that trigger the California Environmental Quality Act (CEQA).

OEHHA is required to develop and periodically update guidelines for conducting HRAs under California’s Air Toxics Hot Spots Program.[i]  The Children’s Environmental Health Protection Act of 1999 also requires OEHHA to specifically consider risks to infants and children.[ii] The Guidance Manual was last updated in 2003.

Between 2007 and 2012, OEHHA developed three Technical Support Documents (TSDs) that primarily evaluated cancer and non-cancer risks in children, including the derivation of non-cancer reference exposure levels, [iii] cancer potency factors for early life stage exposure,[iv] and exposure assessment methodologies using stochastic risk assessment.[v]  These studies underwent public and peer review and were approved by California’s Scientific Review Panel on Toxic Air Contaminants.

OEHHA issued a draft version of the Guidance Manual on June 20, 2014, with the public comment period ending on August 18, 2014.  In November 2014, the Scientific Review Panel approved an updated version of the Guidance Manual that addressed public comments.  OEHHA then adopted the final Guidance Manual on March 6, 2015.

New Methodological Changes
The core revisions to the Guidance Manual involve estimating exposure of air toxics in children.  Key changes include:

  • Revising parameters relating to overall exposure, such as:
    • Increasing breathing rates typical among children and infants;
    • Adjusting time at home and duration of exposure, which differ among infants, children, and adults; and
    • Reducing exposure assumptions for affected non-children (e.g., workers).
  • Applying a “multiplier effect” (known as an Age Sensitivity Factor) for young children (in contrast, the former methodology treated an individual the same from birth through age 70):
    • Third trimester to age 2 – 10 times multiplier;
    • Age 2 to age 16 – 3 times multiplier; and
    • Age 16 to age 70 – no additional multiplier.
  • Establishing methods for evaluating short-term exposures from temporary impacts.

What’s Next
Although OEHHA has acted, additional steps are needed before the guidelines are fully implemented at the local level.  The California Air Resources Board and California Air Pollution Control Officers Association are expected to release Risk Management Guidelines in April 2015.  Subsequently, individual air districts will need to adopt new rules or policies to implement the guidelines into their permitting and CEQA programs.

Several air districts are already evaluating implementation options.  For example:

  • The South Coast Air Quality Management District is reviewing changes to existing rules and CEQA guidance for construction and operational project phases. Staff’s proposals are tentatively scheduled for May 2015.  Staff will host three public workshops and rulemaking will include a public process for stakeholder input.[vi]
  •  The Bay Area Air Quality Management District intends to initiate rule amendments in 2015, but a specific schedule has not been set.[vii]
  •  The San Joaquin Valley Air Pollution Control District held a public workshop on October 9, 2014 to consider raising its CEQA significance thresholds to account for the higher HRA results expected under the then-proposed guidelines.[viii]

After implementation by the air districts, the updated Guidance Manual may increase the regulatory burden on industrial uses that require air toxics permits and require additional analysis and mitigation for development projects that trigger CEQA:

  • For industrial uses that require air toxics permits, the updated Guidance Manual is expected to substantially increase the number of new and existing sources that trigger notification or modeling obligations under the AB 2588 “Hot Spots” program.[ix] Staff for the San Joaquin Valley Air Pollution Control District has expressed concern that the updated Guidance Manual will make it harder for many sources—including small sources such as gas stations—to obtain necessary permits in a timely manner.[x]
  • In-progress and future CEQA projects could be significantly affected if the CEQA lead agency requires the use of the updated Guidance Manual because HRAs using the new methodology are expected to estimate impacts that are two to five times greater (or more in some cases) than HRAs prepared using the prior methodology—even assuming no change in exposure.[xi] Because many CEQA documents use a ten-in-one-million risk level as the significance threshold, this multiplier effect could result in a finding of significant impact for a higher number of projects.[xii] Staff for the South Coast Air Quality Management District has also indicated that the updated Guidance Manual could mean that relatively small, temporary construction projects result in significant health risks.[xiii] This could require a greater number of projects to complete a full Environmental Impact Report and potentially include additional control measures.
  • Workload for air districts’ staff is also expected to increase, translating into longer delays in permitting and CEQA review.

[i]   Health and Safety Code Section 44360(b)(2).

[ii]  Health and Safety Code Section 39606.

[iii] Technical Support Document for the Derivation of Noncancer Reference Exposure Levels, 2008.

[iv] Technical Support Document for Cancer Potency Factors: Methodologies for derivation, listing of available values, and adjustments to allow for early life stage exposures, 2009.

[v]  Technical Support Document for Exposure Assessment and Stochastic Analysis, 2012.

[vi] Proposed Work Plan for Implementing the OEHHA’s Revised Air Toxics Hot Spots Program Risk Assessment Guidelines, available at

[vii] Health Risk Assessment (HRA) Guideline Revisions, available at default-source/Agendas/Governing-Board/2015/2015-mar6-026-presentation.pdf?sfvrsn=6.

[viii] See Leland Villalvazo, San Joaquin Valley Unified Air Pollution Control District Draft Staff Report: Proposed Update to District’s Risk Management Policy to Address OEHHA’s Revised Risk Assessment Guidance Document (Sept. 23, 2014) at 12, Workshops/postings/2014/10-09-14_OEHHA/Draft-Staff-Report-9-23-14.pdf.

[ix]  See id.

[x]   See id.

[xi]  See Proposed Work Plan for Implementing the OEHHA’s Revised Air Toxics Hot Spots Program Risk Assessment Guidelines, available at

[xii]  See Potential Impacts of New OEHHA Risk Guidelines on SCAQMD Programs, available at

[xiii]  See id.

Agencies Modify Strategy with Desert Renewable Energy Plan Over Concerns From Local Agencies, Industry and Environmental Groups

Posted in Environmental and approvals

By Marc Campopiano, Josh Bledsoe, Jennifer Roy, and James Erselius

Concerns from local agencies, industry, and environmental groups over the long-awaited Draft Environmental Impact Report (“EIR”)/Environmental Impact Statement (“EIS”) for the Desert Renewable Energy Conservation Plan (“DRECP”)—a renewable energy and conservation plan covering 22.5 million acres of desert located in seven Southern California counties—have caused the responsible state and federal agencies to shift to a more limited phased approach.  In a March 10 statement, the four lead agencies—the US Fish and Wildlife Service (“FWS”), US Bureau of Land Management (“BLM”), California Energy Commission (“CEC”) and California Department of Fish and Wildlife (“CDFW”)—said they will initially focus on the public lands component of the DRECP, the federal Bureau of Land Management (“BLM”) Land Use Plan Amendment.

The agencies released a Draft Environmental Impact Report/Environmental Impact Statement for the DRECP on September 23, 2014, after nearly six years of work, as discussed in our previous post.  In the five-month period for public comments, which ended on February 23 after being extended from its original January 9 date, the agencies received approximately 12,000 comments.

A key concern that emerged from the comments, and which ultimately prompted the new phased approach, came from five county governments that identified fundamental questions about the structure of the DRECP as proposed.  The counties asked for more time to work with the agencies to align the DRECP’s objectives with county priorities.  Specifically, since the DRECP planning area covers private, state, and federal lands, the counties urged the agencies to reconsider the obligations that the plan would place on private land.

For example, San Bernardino holds over half of the acreage included in the plan and expressed concerns that approximately 85% of the land that the county had identified as “prime developable land” would be set aside under the plan for renewable energy development and conservation.  The county proposed instead to prioritize conservation on federal land and focus renewable energy development on private lands in areas that have marginal economic development potential or are disturbed or contaminated.  Similarly, Imperial County stated that it did not want to convert agricultural lands for renewable energy development and asked the agencies to look to non-productive private lands.

Industry comments questioned whether the plan’s streamlined permitting process for renewable energy projects in DFAs would actually lead to added efficiency.  The Large-scale Solar Association (“LSA”), for instance, expressed concerns that the complicated new process may not result in much of an improvement over the current system, since, in order to qualify for permitting benefits, projects must be sited in a very limited number of areas where streamlining may not be needed.

LSA and other renewable energy associations questioned whether the proposed DRECP reserved adequate land for development to support California’s renewable-energy goals.  LSA called insufficient the 177,000 acres slated for development and 183,000 acres slated for assessment for potential development within development focus areas (“DFAs”), which are areas the DRECP designates as having a high potential for renewable energy.  LSA also argued that small, scattered parcels are not easily amassed into a site suited for utility-scale development.  The California Wind Energy Association (“CalWEA”) likewise targeted the DRECP’s assumptions, questioning whether the DRECP’s target of 20,000 megawatts by 2040 and its wind-specific planning targets would be adequate to support California’s goal of reducing greenhouse gas emissions to 80% below 1990 levels by 2050.  CalWEA contended that 12,500 megawatts of wind energy would be needed by 2040 compared to the 3,070 megawatts provided for in the plan.

Federal agencies also weighed in on the proposed DRECP.  EPA commended the agencies for laying the foundation for a more considered, integrated framework for the construction of renewable energy projects, but asked for a more thorough discussion on a range of issues, including impacts to ephemeral streams and other sensitive waters, the impact of construction and fugitive dust emissions on air quality, the threat to avian mortality posed by solar installations, and the inclusion of protected land in the Silurian Valley.

Conservation groups expressed concerns that the protections in the proposed DRECP are inadequate.  The National Parks Conservation Association (“NPCA”) stated that the DRECP failed to assure long-term protection for sensitive desert wildlife or protect valuable habitat in the Eagle Mountain area, which supports habitat and corridors for imperiled wildlife such as the desert tortoise, bighorn sheep, and golden eagle.

The agencies’ next step under the phased approach will be to focus on development and conservation on public lands managed by the BLM, including designating areas with high potential for renewable energy development or conservation.  The agencies expect that the phased approach will provide additional time to work with stakeholders on the remaining two DRECP components:  (1) a General Conservation Plan (“GCP”), which would streamline the permitting process under the federal Endangered Species Act; and (2) the Natural Community Conservation Plan (“NCCP”), which would set out a strategy for the protection of plants, animals, and desert habitat to simplify compliance with the California Endangered Species Act.  The agencies said the added time will allow them to evaluate alternative approaches, including a tailored, county-by-county approach.

The agencies have emphasized that they will continue interagency coordination to maintain the linkages between the BLM Land Use Plan, GCP, and NCCP.  However, until the GCP and NCCP are completed, the DRECP would not provide incidental take coverage for renewable energy development on state or private lands in the plan area and, therefore, may offer reduced “streamlining” benefits.  The delay in completing planning efforts on state and private lands also may slow development efforts, as it remains unclear when the proposed “DRECP Coordination Group” would begin processing applications for renewable energy and transmission projects and whether the newly formed procedures would actually be expedited compared to traditional permitting pathways.

California Launches Major Rulemaking to Amend Low Carbon Fuel Standard

Posted in Uncategorized

By Joshua T. Bledsoe, Michael Dreibelbis, and Max Friedman

I. LCFS Readoption

On February 19, 2015, the California Air Resources Board (ARB) will take feedback on proposed regulations implementing the readoption and updating of California’s Low Carbon Fuel Standard (LCFS), with formal readoption targeted for the Summer of 2015.  Triggered by legal defects during the original adoption of the LCFS Program, ARB initiated the rulemaking after the U.S. Supreme Court denied certiorari regarding the constitutionality of the program.  ARB is building on a series of workshops held last year to institute a variety of major changes to the LCFS, going far beyond the largely procedural defects that catalyzed the rulemaking.

The LCFS, which was adopted pursuant to the Global Warming Solutions Act of 2006 (commonly known as “AB 32”), requires fuel suppliers to reduce the carbon intensity of transportation fuels to 10% below 2010 levels by 2020.  Those who over-comply generate credits that can be sold to those who miss their targets (and thus have deficits).  While the 10% target has not changed, a number of regulations pertaining to how that target is achieved, including the schedule of annual reduction requirements between 2016 and 2020 would be modified under ARB’s proposal.

II. Carbon Reduction Schedule

The current LCFS regulations contain a schedule of carbon intensity reductions to achieve the mandated 10% total reduction by 2020.  This “compliance curve” is frozen at its 2013 level by court order until ARB completes the readoption process.  As such, the original compliance curve has been disrupted and requires a more rapid acceleration through the final five years in order to achieve the desired reductions by 2020.  A summary of ARB’s proposed acceleration is below:

Table 1:  Comparison of Previous and Proposed Percent Reduction Requirements for Carbon Intensity over 2016-2020 Period
Year Current Reduction Percent Proposed Reduction Percent
2016 3.5% 2.0%
2017 5.0% 3.5%
2018 6.5% 5.0%
2019 8.0% 7.5%
2020 and beyond 10.0% 10.0%


This accelerated schedule flattens interim reduction targets, but places a considerably higher burden on the final three years of compliance, potentially creating a tight credit market during those years.  ARB has employed aggressive assumptions about technological innovations and the mix of available fuels during this period.  For example, ARB assumes that electric vehicles will generate 10x as many credits in 2020 as in 2013 and renewable CNG 32x as many credits.

III.       Cost-Containment Provisions

In an attempt to alleviate concerns about the ability of the market to produce enough credits in coming years, ARB is proposing to establish a “credit clearance market” whereby regulated parties can purchase credits from other market participants to make up credit shortfalls.  In the event of a credit shortfall, an inflation-adjusted credit price ceiling of $200 would apply.  The “credit clearance market” would function somewhat similarly to the consignment auction process in ARB’s Cap-and-Trade Program, with several key differences, including that ARB would publish the names of entities participating in the credit clearance market, including the number of credits that each participating entity must buy or sell.

Entities that are unable to obtain credits needed for compliance during the credit clearance event would be able to “carry over” deficits per a “5×5” rule:  5% interest on carried-over deficits with total debt due within 5 years.  Market participants previously expressed concern about the credit clearance proposal during ARB workshops, noting its potential to distort the market in ways not envisioned by ARB.

IV. Enforcement Mechanisms

The proposed rules would include a robust invalidation regime for LCFS credits, deficits, and carbon intensity determinations (an “Approved CI”), similar to the current ARB rules for emission offset credits in the Cap-and-Trade Program.  The new rules would allow ARB to delete an Approved CI or invalidate LCFS credits for a variety of reasons, including noncompliance with laws during credit generation.  This expansion of the invalidation regime could open the door to the kind of uncertainty that market participants have experienced in the Cap-and-Trade Program offset market.  ARB also proposes changing the definition of a violation to encompass each separate net deficit, which will allow for differentiation among small- and large-scale offenders.  However, the penalty for a single violation would shrink from a presumption of $35,000 to a maximum of $1,000.

V. Indirect Land-Use Change

ARB calculates carbon intensity using the CA-GREET model, which measures direct life-cycle emissions from “well to wheel,” including a fuel’s production, transport, storage, and use.  The Board also supplements this calculation with a calculation of indirect impacts on emissions due to land-use change (iLUC).  For example, carbon sequestered in soil and organic matter can be released when non-agricultural land is converted to agricultural use for growing biofuel crops.  Going forward, ARB proposes to modify its iLUC values for certain biofuels, including ethanol refined from corn, sugarcane, and sorghum and biodiesel from soy and palm.  These changes are based on new research regarding land-use changes and are lower than previous iLUC values, providing a benefit to ethanol producers.

Additionally, ARB will update the CA-GREET model, as well as the OPGEE model, which estimates carbon intensity for crude oil production and transport to petroleum refineries.

VI. Miscellaneous Further Changes

In addition to these major modifications to LCFS regulations, ARB has proposed a number of other important changes.

First, ARB would simplify the process for certifying certain established, compliant fuels and the procedures for generating them.  Under a new two-tiered system, stakeholders proposing to register pathways for established fuels (e.g., starch- and sugar-based ethanols) generated in a conventional manner would receive expedited approval.  Those seeking pathway approval for more novel fuels (e.g., cellulosic alcohols) or technologies to generate them would receive elevated scrutiny from ARB.

Second, certain innovative technologies for producing crude oil would offer the potential to generate additional credits.  Since 2011, producers that employ carbon capture and sequestration or solar steam generation have been eligible for credits, but no one has yet attempted to apply.  To facilitate such projects, ARB now proposes to:  (a) reduce the minimum threshold for carbon intensity reduction from such technologies from 1.0 gCO2e/MJ to 0.1 gCO2e/MJ or even lower in some cases; (b) simplify calculations of credits generated; (c) allow crude producers, in addition to refineries, to earn credits; and (d) add solar and wind electricity generation and solar thermal generation to the list of technologies that can yield credits.  Similarly, refineries would become eligible for credits if they invest in modifications that produce fuel derived in part from renewable feedstocks.

Third, petroleum refineries also would become eligible for credits if they employ low-energy-use refining processes, although these credits would not be available for sale.  Some smaller refineries could further benefit from a proposal to allow them to opt out of ARB’s statewide calculation of baseline average carbon intensity for all crude fuels produced in the state.  Instead of being judged against the 2010 baseline for the entire state, small, low-energy-use refineries could set their own baselines.  They would receive this opportunity only once and it would be irreversible, making the calculation a potentially risky one.  For those refineries subject to the statewide baseline, calculations of volume contributions would now come from government data, rather than reporting by the refineries themselves.

Fourth, additional transportation credits also would become available for electricity used not only by roadway vehicles (as is now the case), but also by trains and electric forklifts.

Finally, recordkeeping and reporting requirements for stakeholders also would change in important ways.  Minimum record retention would increase from three to five years. Quarterly reporting requirements would shift from a 60-day period in which parties can compile their data and reconcile it with that of their business partners to a “45/45 Schedule,” allowing 45 days to report data and an additional 45 days to reconcile it.

VII.     2030 Extension

While ARB proposes to institute many changes to the LCFS via the readoption process, one thing that has not changed is the fundamental target of a 10% reduction in carbon intensity by 2020; both the target reduction and the final date remain the same.  Nevertheless, ARB asserts that it intends, in a subsequent rulemaking, to extend the LCFS program through 2030 and apply aggressive new CI reduction targets for the 2020-2030 period.

White House Updates Draft Guidance on Climate Change Considerations in NEPA Review

Posted in Environmental and approvals

By Joshua T. Bledsoe and Stacey L. VanBelleghem

On December 18, 2014, the White House Council on Environmental Quality (CEQ) released revised draft guidance on the consideration of greenhouse gas (GHG) emissions and climate change in National Environmental Policy Act (NEPA) review.[1]  The CEQ previously issued this guidance in draft form in February 2010.[2]  Rather than finalize that draft, the CEQ opted to issue significantly revised draft guidance and open a 60-day public comment period, which closes on February 23, 2015.[3]

One of the most notable changes in this revised draft is that the CEQ addresses the question of whether agencies should monetize costs and benefits of a project.  The CEQ notes that the use of cost-benefit analysis depends on whether it is relevant to the choice among alternatives.  However, when agencies choose to include this analysis, the CEQ endorses the Federal social cost of carbon estimates as a “harmonized, interagency metric that can provide decision makers and the public with some context for meaningful NEPA review.”[4]  Following a June 27, 2014 U.S. District Court for the District of Colorado decision invalidating a final Environmental Impact Statement for failure to disclose the costs associated with GHG emissions and ignoring the social cost of carbon estimates,[5] there has been much uncertainty about the use of these estimates in NEPA documents.  The court decision and the 2014 Draft Guidance represent a shift in the use of those estimates, which were developed for significant federal rulemakings.  However, the extent to which agencies will use these estimates in NEPA review remains to be seen.  The revised draft acknowledges the limitations of the social cost of carbon estimates, including the fact that they were developed for rulemaking analysis, the estimates vary over time, and they are associated with different discount rates.[6]

Among other notable changes in the 2014 Draft Guidance, the CEQ definitively stated that agencies’ assessment of direct and indirect climate change effects should account for upstream and downstream emissions.[7]  This position goes further than the 2010 proposal, which stated that evaluation of upstream and downstream effects “must be bounded by limits of feasibility.”[8]  This new language could expand the scope of analysis for some agencies that had previously declined to consider upstream and downstream emissions.  Moreover, unlike the 2010 guidance, which did not apply to Federal land and resource management actions, the 2014 Draft Guidance specifically applies to those actions and includes guidance on biogenic sources of GHG emissions from land management actions.[9]

Other aspects of the revised guidance build upon and clarify concepts included in the 2010 Draft Guidance.  For instance, the 2010 Draft Guidance encouraged agencies to include a quantitative assessment of GHG emissions for projects expected to have direct GHG emissions of 25,000 metric tons or more on an annual basis.[10]  The 2014 guidance continues to recommend 25,000 annual metric tons of GHG emissions as a “reference point” for emissions warranting a quantitative assessment.[11]  Like the 2010 Draft Guidance, the 2014 Draft Guidance encourages agencies to include considerations of GHG emissions and climate change in alternatives analysis, mitigation considerations, and the evaluation of the environmental consequences of a proposed action.

The revised guidance is likely to result in expanded evaluation of GHG emissions and climate change impacts in agency NEPA review and is anticipated to have implications in the near term.  Indeed, while CEQ did not intend the 2010 Draft Guidance to become effective until its issuance in final form,[12] agencies commonly cited it in NEPA documents.  Similarly, while the preamble to the 2014 Draft Guidance states that it will be effective “once finalized,”[13] agencies are expected to refer to it in NEPA documents on an ongoing basis—particularly since the 2014 Draft Guidance expressly encourages agencies to apply it, “to the extent practicable,” in ongoing reviews.[14]  As the guidance is initially applied at the project-level, such environmental reviews may be prolonged.

[1]           Council on Environmental Quality, Revised Draft Guidance for Greenhouse Gas Emissions and Climate Change Impacts (Dec. 18, 2014) (hereinafter “2014 Draft Guidance”).

[2]           Memorandum from Nancy H. Sutley to Heads of Federal Departments and Agencies Regarding Draft NEPA Guidance on Consideration of the Effects of Climate Change and Greenhouse Gas Emissions (Feb. 18, 2010) (hereinafter “2010 Draft Guidance”).

[3]           Notice Of Availability, Request For Public Comments On Revised Draft Guidance For Federal Departments And Agencies On Consideration Of Greenhouse Gas Emissions And The Effects Of Climate Change In NEPA Reviews, 79 Fed. Reg. 77801 (Dec. 24, 2014).

[4]           2014 Draft Guidance at 16.

[5]           High Country Conservation Advocates v. U.S. Forest Service, No. 13-cv-01723-RBJ (D. Colo. June 27, 2014).

[6]           2014 Draft Guidance at 16.

[7]           Id. at 11.

[8]           2010 Draft Guidance at 3.

[9]           Compare 2010 Draft Guidance at 2 with 2014 Draft Guidance at 8, 16-18.

[10]          2010 Draft Guidance at 1.

[11]          2014 Draft Guidance at 18.

[12]          2010 Draft Guidance at 12.

[13]          79 Fed. Reg. at 77818.

[14]          2014 Draft Guidance at 14.

PJM Proposes Capacity Performance Rules That Will Present New Opportunities and Risks for Clean Energy Resources

Posted in Energy regulatory

By Michael Gergen and Eli Hopson

In response to poor performance by many generation resources in the PJM region during the 2014 “Polar Vortex” and concerns over the increasing reliance on natural gas-fired generation resources in the PJM region, PJM filed under Section 205 of the Federal Power Act (“FPA”) proposed “Capacity Performance” rules to revise its capacity market, known as the “Reliability Pricing Model” or “RPM”, with the Federal Energy Regulatory Commission (“FERC” or “Commission”) on December 12, 2014.  In connection with its filing of proposed tariff revisions, PJM also filed under both Sections 205 and 206 of the FPA proposed revisions to its Operating Agreement which would narrow force majeure for non-performance.  PJM’s proposed revisions to its capacity market construct, if implemented, would present clean energy resources with new opportunities and risks regarding their participation in PJM’s capacity market, by, among other things, allowing participation by energy storage resources.

PJM’s filing of its proposed Capacity Performance rules follows months of stakeholder deliberation over various straw proposals, and the proposed rules as filed with FERC contain a number of significant differences from the proposal last considered in the stakeholder process. PJM’s goal is for its new Capacity Performance rules to go into effect April 1, 2015.  PJM’s proposed Capacity Performance rules are based in part on the ISO New England’s “Pay for Performance” rules, which FERC approved in mid-2014.  PJM’s proposed Capacity Performance rules would establish a new capacity product—Capacity Performance Resources—with higher performance standards that would likely earn significantly greater capacity market revenues. The revisions would also significantly increase financial penalties for Capacity Resources that have cleared in the RPM auctions and that fail to perform when called upon by PJM during certain emergency conditions on the PJM grid.  Moreover, the revisions would also add a new definition for “Capacity Storage Resources,” which would include hydroelectric, flywheel, and storage resources as well as a new definition of “Intermittent Resources” which would include “Generation Capacity Resources with output that can vary as a function of its energy source, such as wind, solar, run of river hydroelectric power and other renewable resources.”

PJM also proposes to limit instances of force majeure for Capacity Generation Resources to only include instances of “Catastrophic Force Majeure,” defined in the proposed revisions to the Operating Agreement as widespread failure of the transmission system or fuel delivery system in all of the PJM area. As a result, unexpected individualized or localized risks will no longer excuse non-performance, and the determination of whether an event satisfies the “Catastrophic Force Majeure” definition will be made independently by the Office of Interconnection, rather than by a market participant.

Capacity Performance Resources Expected to Perform During Emergency Action Periods

PJM’s proposed Capacity Performance rules would fundamentally change and significantly increase the expectation for performance by capacity resources as they would be expected to provide energy and reserves when called upon by PJM, though their performance (and associated financial charges and credits) under PJM’s proposed “no-excuse” standard for failure would be determined based on their operation during “Emergency Action” periods. Rather than imposing front-end eligibility requirements for resources wishing to enter the market as Capacity Performance Resources (as was previously contemplated by PJM on August 20th and October 7th, including multi-hour performance capability), the Capacity Performance rules proposed before FERC seek to put the onus on capacity market sellers to provide “reasonable assurances” that their resources will perform when called upon during Emergency Action periods, (which PJM assumes, but does not guarantee, will occur as much as 30 hours per year in the summer and winter seasons). Under the proposed Capacity Performance rules Capacity Performance Resources will be required to have combined start-up and notification times as well as minimum down times that do not exceed one hour. To increase market competiveness, PJM proposes to impose a must-offer requirement on all resources that qualify as Capacity Performance Resources beginning in the 2018/2019 Delivery Year, with limited exceptions. All resources that qualify as Capacity Performance Resources will not have the option of not submitting offers or submitting offers as Base Capacity Resources without facing penalties. At the same time, PJM proposes that Intermittent Resources, Capacity Storage Resources and Energy Efficiency Resources, may, but will not be required to, submit offers as Capacity Performance Resources.

Substantial Penalties for Failure to Perform During Emergency Actions

Capacity Performance Resources that fail to perform during Emergency Actions will have to pay substantial penalties. PJM has patterned its penalty structure after that of ISO New England’s “Pay for Performance” standard. Rather than factoring in a resource’s forced outage history in determining acceptable levels of performance for future years, PJM proposes to adopt a more stringent, “no excuses” policy that simply compares a resource’s actual performance during Emergency Action hours and subjects any and all performance shortfalls to a “Non-Performance Charge” as high as an annual stop-loss of 1.5 times Net CONE times all of the resource’s committed capacity (where Net CONE is the first year total net revenue that a new resource would need to recover its capital and operating expenses, net of any returns in PJM’s energy and ancillary services markets).  Although Net CONE varies based on the geographic region and the year, RTO-wide values for the 2017/2018 RPM auction were $351.39/MW-day.   Due to the proposed revisions to the Operating Agreement discussed above, the only acceptable excuse for non-performance will be if a resource is on a planned or maintenance outage pre-approved by PJM.  As PJM states in its filing letter, “the proposed Non-Performance will impose serious adverse financial consequences on resources that do not perform during emergencies” and could turn a seller’s “RPM revenue stream into an RPM expense stream if its resource performs poorly in multiple emergencies during the Delivery Year.”

Alternatively, resources that exceed expected performance will be eligible to receive “Performance Payments,” collected from revenues generated by Non-Performance Charges. Under the proposed Capacity Performance rules, all market participants are eligible to receive Performance Payments, including non-Capacity Resources that “stand in” for non-performing Capacity Resources outside of the resource’s obligation period, effectively rendering any performance during such periods bonus-eligible.

Phased Transition to New Market

PJM proposes to complete a market transition to a 100% Capacity Performance Resource product by the 2020/2021 Delivery Year. Until that time, a resource failing to meet the Capacity Performance Resource standard will continue to be eligible to participate as Base Capacity Resources.  With the exceptions discussed above for Intermittent Resources, Capacity Storage Resources and Energy Efficiency Resources, which will be able to participate as Base Capacity Resources also, all other resources that do qualify as Capacity Performance Resources will only be eligible to participate as Capacity Performance Resources. By the end of the transition period, all capacity resources will be expected to make the transition to the Capacity Performance Resource standard.  PJM also proposes that resources such as storage, wind, and solar to aggregate to submit Sell Offers with other Energy Efficiency Resources located within the same Locational Deliverability Area (“LDA”) as either Base Capacity Resources or Capacity Performance Resources.  While not entirely clear, it appears that the proposed revisions also seek to exempt from the must offer requirement for Base Capacity Resources those resources that are exempt from the must offer requirement for Capacity Performance Resources.

PJM has requested that the Commission accept its proposed Capacity Performance rules by April 1, 2015.  PJM also requested that the Commission establish an extended comment period, with a deadline of January 12, 2015 for stakeholders to submit comments (or 31 days from the date of PJM’s filing), however, the Organization of PJM States filed a Motion to extend the comment period to January 20, 2015 given the length of the PJM filings.