U.S. States & Regions
States and regions across the country are adopting climate policies, including the development of regional greenhouse gas reduction markets, the creation of state and local climate action and adaptation plans, and increasing renewable energy generation. Read More
Although much of the discussion about climate change impacts has focused on increases in temperature and the rise in sea level, changes that impact our nation’s water resources could have the greatest impact on society. A quick glance at recent newspaper headlines—heavy spring rains leading to massive flooding of the Mississippi River, historic drought covering large parts of Texas, and extensive wildfires spreading across Arizona—provides more than enough evidence of how vulnerable we are to water-related extreme events.
While these events have led some to ask whether they are caused by climate change, this question misses the mark. Individual weather events are not “caused” by any single phenomenon—and climate change’s contribution to individual events will not be resolved cleanly in the years to come. What virtually all climate scientists agree on, however, is that the climate is already changing, all weather events now form under different conditions than they used to, and this change is increasing the probability of extreme weather events happening. It makes sense to learn what we can from actual events and avoid getting caught up in an irresolvable debate about why a particular event happened. We would be better served by learning more about what is at risk from extreme events and what we can do to better manage and minimize those risks.
A recent interagency draft report, National Action Plan: Priorities for Managing Freshwater Resources in a Changing Climate, highlights both the extensive economic and social risks that we face as a nation from the impact of climate change on water resources and the critical steps we need to take to begin facing up to these challenges.
The report documents the changes in our climate system that are already evident and are likely to increase over time. Warmer air and sea surface temperatures and rising sea levels are only part of the picture. Total precipitation has increased by about 5 percent over the past 50 years, and the amount of precipitation that occurs during the heaviest downpours has increased by 20 percent. However, regional variations appear likely with increased precipitation in the northern part of the country while areas in the south, particularly in the southwest, are likely to get drier. The strengthened hydrologic cycle puts wet areas at risk of getting wetter while dry areas are at increased risk of drought. Areas dependent on water from melting snow packs may also face substantial changes as more precipitation falls as rain rather than snow and as earlier snowmelt changes the timing and quantity of water availability.
The implications of these changes cut a wide swath across our economy and environment. Water availability is critical in sectors as diverse as agriculture, electricity generation (hydroelectric, but also fossil fuel generation and nuclear power), heavy transport, mining and mineral exploration, and storm water management. Beyond economic factors, water is also critical to ecosystem wellbeing, wildfire management, and public health.
In order to more effectively manage these risks, and to enhance the resiliency of our water resource systems, the report sets out six general recommendations and 24 specific actions that should be undertaken by federal agencies and their partners. It calls for a more formal planning process, highlights the need for improved information, enhanced capacity building, better integration across related issues, and better tools for assessing vulnerabilities, and recommends expanded water use efficiency.
These actions are by no means a cure-all for the challenges we face in managing the increasing demands on our water resources in a changing climate. Nor are they a substitute for slowing the rate and magnitude of climate change through reducing emissions of greenhouse gases. The most effective risk management strategy is to avoid the risk all together. But with climate change already underway, we are too late to avoid some changes, and adaptation will be critical to reducing economic and environmental costs. We need only to look at the costs and suffering from recent extreme weather events to understand the risks we face.
Comments on the draft plan are being accepted until July 15, and can be submitted to: http://www.whitehouse.gov/administration/eop/ceq/initiatives/adaptation/freshwater-plan
Steve Seidel is Vice President for Policy Analysis
Throughout the beginning of 2011, the Regional Greenhouse Gas Initiative (RGGI) —the first mandatory carbon dioxide (CO2) cap-and-trade program in the United States—was successfully defended by state legislators in three states where attempts were made to remove those states from the program. In the second week of May, the states of Delaware and Maine defeated bills proposing withdrawal, while in New Hampshire, Senators did not pass the House’s version of a withdrawal bill. But on May 26, New Jersey Governor Chris Christie announced that his state will leave RGGI by the end of the year.
Participating RGGI states cap CO2 emissions from power plants (those with generation capacities of at least 25 megawatts) and auction most of the emissions allowances. (Each allowance lets a power plant emit one ton of CO2.) RGGI’s CO2 emission allowance auctions raised $789.2 million for the 10 participating Northeast and Mid-Atlantic states from 2008 to the end of 2010. Meanwhile, consumers on average saw their monthly utility bills increase by less than $1. As highlighted in a February RGGI report, this allowance auction revenue has benefited the 10 participating states via investments in clean energy technology and energy bill assistance. These investments are creating clean energy jobs, saving consumers money, and deploying technologies that reduce the environmental impact of power generation.
This post also appears in the National Journal Energy & Environment Experts blog in response to the question: What should drive fuel efficiency?
At a moment when it appears to many that our government can’t do anything right, the current approach to regulating vehicle fuel economy and greenhouse gas (GHG) emissions is a bright spot.
After decades of failing to tighten corporate average fuel economy (CAFE) standards, and several years when California and other states began to take the matter of setting vehicle GHG standards into their own hands, the federal government finally got its act together. In 2007 Congress enacted the Energy Independence and Security Act of 2007, tightening CAFE. In 2010, NHTSA and the U.S. Environmental Protection Agency (EPA) jointly set GHG and CAFE standards, and California agreed to conform its rules to the federal ones. NHTSA and EPA are hard at work at a second round of standards for light duty vehicles, as well as the first-ever set of similar rules for medium and heavy duty trucks.
We now have the Congress, federal and state regulators, industry and public interest groups aligned on a policy framework that is meeting important national goals of reducing oil dependence and GHG emissions, providing regulatory consistency and certainty to the industry, and creating a climate favorable to investment and innovation.
The auto industry is responding successfully. The plug-in hybrid electric Chevy Volt won the 2011 Motor Trend Car of the Year, 2011 Green Car of the Year, and 2011 North American Car of the Year. It’s also selling well. But PHEVs are just part of the story. The Chevy Cruze and Hyundai Elantra are among the nine vehicles in the U.S. marketplace that get more than 40 miles per gallon. They were also among the 10 top-selling vehicles last month. Higher sales of fuel-efficient vehicles across the board contributed to strong sales and combined profits of nearly $5.9 billion for the three U.S. automakers in the first quarter of this year.
Higher gasoline prices are heightening consumer interest in these vehicles. But we cannot rely on oil prices alone to drive us to the next generation of vehicles. Oil prices are too volatile to motivate the sustained business investment we need. And the price we pay at the pump doesn’t reflect the true cost of oil to our country. Half of the 2010 U.S. trade deficit was from oil – that’s $256.9 billion we sent overseas last year alone. The U.S. EPA estimates that the energy security benefit of reducing oil dependence is on the order of $12 per barrel. And gasoline burning inflicts enormous damage on our air quality and climate. For example, the transportation sector is responsible for more than a quarter of U.S. GHG emissions and is a major contributor to smog.
The beauty of the fuel economy and GHG standards is that they are performance based. They set targets based on important public policy goals – i.e., oil savings and GHG reductions – but leave it to industry to find the best way to meet them. They don’t “pick winners.” They should remain the core of our public policy framework for transportation.
But our current set of vehicles and fuels may not be up to the job of meeting our long-term goals. In order to level the playing field with the incumbent technologies that have benefited from nearly a century of infrastructure development and fuel-vehicle optimization, we need to make some public investment to jumpstart alternative vehicles and fuels. This has to be done carefully. We need a savvy, adaptive strategy that ensures that any subsidies are only temporary, leverages public investment with private dollars, spawns experiments and learns from them, and rewards environmental and efficiency performance.
It is not clear whether hydrogen, natural gas, electricity, or biofuels are the long-term solution to our energy and environmental challenges. But we need to continue to keep the pressure on all of them through performance-based standards, research them all, subsidize limited deployment to see how they perform in the real world, and leave it to industry and consumers to determine their ultimate success in the marketplace.
Judi Greenwald is Vice President for Innovative Solutions
This post also appeared in the National Journal Energy & Environment Experts blog in response to a question about oil use and the future of electric vehicles.
Whether or not electric vehicles (EVs) take off will ultimately depend on consumer acceptance of new technology. But public policy and technological progress are just as important, as we highlight in our new report on the transportation sector.
Indeed, electric drive vehicles powered by batteries or hydrogen fuel cells could revolutionize transportation in the United States, saving considerable amounts of oil while also reducing the sector’s impact on our global climate. And the EVs on the market now are off to a great start, winning national and international awards.
Nearly all major automakers are planning to introduce these vehicles in the coming years, and I applaud automakers like Ford that have committed to building alternative drivetrains in significant number for the long haul. Companies like Ford understand climate change and the need to reduce our impact on our global environment while not sacrificing our mobility. For EVs to achieve that goal, we need policies like a clean energy standard that aim to decarbonize our electrical grid. I’m sure Ford is also investing in this space because they see a market opportunity.
The private sector has invested billions of dollars in developing, manufacturing, promoting, and distributing EVs in the last decade. From a map on our website, you can see that policymakers across the country are supporting EVs because they want their region to benefit from this burgeoning market.
Policymakers should rely on private capital as much as possible to build out the EV charging infrastructure so we can balance the desire to support alternative vehicles while also tackling our nation’s budget deficit. To that end, we should coordinate policy related to EV purchase and home charging nationwide so private players can enter new markets more easily. The most efficient way to “refuel” these vehicles is not yet clear, and we should use policy to help provide the foundation to let the market work.
Another element that is critical to the success of these vehicles is its most expensive component – the battery. Not only do we need aggressive R&D to develop batteries with much higher energy density, we also need to figure out what to do with these batteries at the vehicle’s end-of-life. About 80 percent of the battery’s capacity is still usable at this point, resulting in the largest untapped resource in this space today.
If we achieve the right mix of policy, technological progress, and consumer acceptance, there’s little reason to doubt that alternative vehicles will have a significant impact on the car market in this decade. It appears that it will be tough to kill the electric car this time.
Eileen Claussen is President
Today the National Academies released the final report in its most comprehensive assessment of climate change entitled America’s Climate Choices.
Statement of Eileen Claussen
President, Pew Center on Global Climate Change
May 12, 2011
I applaud the National Academies for providing policymakers and the public with this comprehensive and authoritative study to advance the country’s response to climate change. America’s Climate Choices reaffirms the overwhelming scientific evidence – climate change is real and the case for action is clear.
Left unchecked, climate impacts pose significant risks to our economy and security. If we continue to ignore and delay acting to minimize these very real risks, we are inviting more severe impacts and greater costs. Meaningful action will increase certain costs, but clear-headed analyses show those costs will be manageable and far outweighed by the economic, security, and environmental benefits.
In the year since the first installments of America’s Climate Choices were published, extreme weather events have affected millions of lives and cost billions of dollars in the U.S. and across the world. Current flood damage along the Mississippi River and drought-induced wildfires that have ravaged more than 2 million acres this year in Texas are the latest reminders of the risks we will face and the need to act to address our growing vulnerabilities.
We also agree with the National Academies that more studies and scientific findings alone will not advance sensible energy and climate solutions. Straight-forward answers about the risks and growing costs we face from inaction and the economic costs and opportunities from advancing innovative energy solutions must be effectively communicated to broader audiences in a clear and honest way.
From Washington, to Wall Street, to Main Street, Americans need a fair shake on the energy-climate debate. They need a clearer understanding of our climate and energy challenges and what it means to them. We look forward to building on the work of America’s Climate Choices to advance this conversation so the choices America makes enhance our security, grow our economy, and protect our environment today and for generations to come.
Pew Center Contact: Tom Steinfeldt, 703-516-4146
Changing Planet is a three-part series of town hall events intended to encourage student learning and dialogue about climate change by gathering scientists, thought leaders, business people, and university students to discuss the facts of climate science, the dynamics of its impact and to brainstorm solutions. The series is prodiced in partnership between NBC Learn (the educational arm of NBC News), the National Science Foundation (NSF), and Discover magazine.
The first town hall event, Changing Planet: The Impact on Lives and Values, was hosted at Yale University and moderated by NBC News Special Correspondent Tom Brokaw. The discussion explored themes of human health, national security, economic opportunity and competitiveness, moral or religious values, environmental justice, and what climate change means for youth. The panelists were Linda Fisher, Dupont’s chief sustainability officer; Rajendra Pachauri, director of the Yale Climate and Energy Institute and a Nobel Prize laureate; Billy Parish, founder and coordinator of the youth-oriented Energy Action Coalition; and Katherine Hayhoe, associate professor in the Department of Geosciences at Texas Tech University and an expert on the intersection between Christian fundamentalism and climate change.
A second Changing Planet: Clean Energy, Green Jobs and Global Competition town hall was hosted at George Washington University on April 12, and focused on the economic advantages of climate change solutions, including clean energy policies and technologies and creation of market green jobs. Tim Juliani, Director of Corporate Engagement, was a panelist and provided our perspective on the clean energy debate. Other panelists included: Ken Zweibel, a professor at GWU, Phaedra Ellis-Lamkins (head of Green for All), and Chris Busch (director of Policy and Programs at the Apollo Alliance). NBC News reporter Anne Thompson moderated this event.
Read Discover Magazine's story on Building a Green-Collar Economy with a full transcript of the Changing Planet: Clean Energy, Green Jobs and Global Competition town hall.
The third town hall will be held at Arizona State University in the fall of 2011, and its suggested focus will be “Keeping It Fresh: Our Water Future,” impacts of how communities are adapting, or preparing to adapt to, changing availability of fresh water..
In addition to the Changing Planet town halls, NBC Learn and NSF worked together to produce a series of 12 online video reports looking at the impact of climate change in various locations around the world. From Bermuda’s tropical seas to the Arctic Ocean, each story follows scientists in the field who are studying the dramatic impacts of rising temperatures in the air, in the water, and on land. The series is narrated by Anne Thompson, Chief Environmental Affairs Correspondent for NBC News. Watch the full video series here.
The State of Maryland released a new report earlier this year recommending a course of action to adapt to our changing climate. This report is the latest in a series that began in 2007 when Governor Martin O’Malley issued an executive order to establish the Maryland Commission on Climate Change. The commission was charged with addressing the causes of climate change and adapting to the most likely impacts. In 2008, the Maryland Climate Action Plan was released, addressing impacts, mitigation, and economic concerns.
Among the impacts highlighted in the Climate Action Plan was sea level rise, projected to be more than a foot by mid-century and as much as 3 feet by 2100. If the highest rates are realized, most tidal wetlands would be lost and about 200 square miles of land would be inundated. The bay would also suffer additional stresses as restoration goals become more difficult to achieve. Aquatic species composition will change and increased nutrient runoff into the bay will make water quality goals much harder to meet. Impacts are projected to occur inland as well with heat waves greatly increasing the risk of illness and death. The average year will have 24 days above 100°F by the end of the century. Ground level ozone, formed under prolonged, high temperatures will increase, resulting in more respiratory illnesses, especially among vulnerable populations.
The Action Plan addressed the adaptation needs of coastal regions but only highlighted the need to pursue the development of adaptive strategies for other affected sectors. In response, work began on a report specifically for adaptation in these other sectors. Earlier this year, the culmination of this effort was released as the Comprehensive Strategy for Reducing Maryland’s Vulnerability to Climate Change, Phase II: Building societal, economic and ecological resilience. The report provides the basis for guiding and prioritizing state-level activities with respect to both the climate science and adaptation policy within short to medium-term timeframes.
- Human Health: Conduct vulnerability assessments to gain a better understanding of risks and inform preventative responses by assessing potential health threats and the sufficiency of Maryland’s response capacity. The impacts to food safety and availability must also be evaluated.
- Agriculture: Increase crop diversity, protect against incoming pests and disease, and intensify water management through research, funding and incentives. Enhance existing Best Management Practices (BMPs) and land conservation targets including revising targets for agricultural land preservation. BMPs that are geared toward protecting water quality in the Chesapeake Bay are likely to be significantly shifted as changes in seasonality and precipitation occur.
- Forests and Terrestrial Ecosystems: Expand land protection and restoration and revise targeting priorities. This includes integrating climate data and models into existing resource assessments and spatial planning frameworks as well as developing adaptation guidance for local government planning. Management practices to reduce existing forest stressors should also be adjusted. High elevation forest species such as the red spruce or Eastern hemlock will likely disappear from Maryland as will the Baltimore Checkerspot butterfly and ecosystem management plans must reflect these future changes.
- Bay and Aquatic Ecosystems: Restore critical bay and aquatic habitats to enhance resilience. It is recommended that the state be proactive in the design and construction of habitat restoration projects due to their importance in enhancing the resilience of aquatic ecosystems. Dam removal projects on Octoraro Creek in Cecil County and Raven Rock Creek in Washington County have resulted in reduced stream temperatures and moderated stream flow, boosting connectivity between habitats and resilience of fish and other transient species.
- Water Resources: Ensure long-term safe and adequate water supply for humans and ecosystems. Reduce the impacts of flooding and stormwater by removing high-hazard water supplies and preventing inundation and overflow of on-site disposal systems. On-site disposal systems already lead to raw sewage leakage in Maryland are likely to worsen with increases in extreme precipitation. These failing septic systems must be improved or replaced.
- Population Growth and Infrastructure: Plan for precipitation-related weather extremes and increase resilience to rising temperatures by identifying investment needs to prepare for weather emergencies and improving stormwater management strategies. Urban tree canopy should also be increased to provide urban heat reduction, stormwater reduction, and air filtration.
Not every state has an adaptation plan, and Maryland is one of only two states (Virginia) in the Mid-Atlantic region to have completed one or made progress. However, both North Carolina and South Carolina have Climate Action Plans that call for an adaptation report and more states are moving towards producing adaptation plans. Maryland is at risk from a variety of ill-effects due to climate change and the identification and implementation of key adaptation measures will ensure the state minimizes the impacts and costs of climate change in the long run. Other states would do well to take heed, and move to minimize their costs as well.
Dan Huber is Science & Policy Fellow
On April 12, 2011, Governor Jerry Brown signed SBX1 2, which increases California’s Renewable Portfolio Standard to require 33% of electricity to come from renewable sources by 2020. The law replaces an Executive Order created by Governor Schwarzenegger in 2009, which called for the same renewable energy target. It makes the 33% by 2020 target legally binding, which sends a market signal that the state is committed to developing renewable energy resources. The new legislation was sponsored by Senator Joe Simitian (D – Palo Alto) and is one of the most aggressive RPS policies in the country.
The new bill is an extension of a law passed in 2006 that required 20 percent of California’s electricity to come from renewable sources by 2010. However, the new law includes publicly owned utilities (POUs), while the previous law applied to only investor-owned utilities (IOUs) and electric service providers (ESPs). This means the new legislation will cover 100% of the state’s electricity, instead of only the 76% provided by IOUs and ESPs. Under the new measure, about 75% of the renewable generation is expected to come from IOUs and ESPs, with the remainder coming from POUs.
The policy is projected to reduce greenhouse gas emissions below business-as-usual levels by the equivalent of 12 to 13 million metric tons of carbon dioxide per year by 2020.
At the moment, our attention is riveted by the events unfolding at a nuclear power plant in Japan. Over the past year or so, major accidents have befallen just about all of our major sources of energy: from the Gulf oil spill, to the natural gas explosion in California, to the accidents in coal mines in Chile and West Virginia, and now to the partial meltdown of the Fukushima Dai-ichi nuclear reactor. We have been reminded that harnessing energy to meet human needs is essential, but that it entails risks. The risks of different energy sources differ in size and kind, but none of them are risk-free.
This is a summary of California’s Cap and Trade Regulation, as adopted by the California Air Resources Board (CARB) on October 20, 2011. CARB amended these regulations as of September 1, 2012. These changes are not yet reflected in the summary below, but can be found here. The cap and trade program is part of the state of California’s compliance with Assembly Bill 32, the Global Warming Solutions Act of 2006.
SUBARTICLE 1: TABLE OF CONTENTS
SUBARTICLE 2: PURPOSE AND DEFINITIONS.
SUBARTICLE 3: APPLICABILITY.
SUBARTICLE 4: COMPLIANCE INSTRUMENTS.
SUBARTICLE 5: REGISTRATION AND ACCOUNTS.
SUBARTICLE 6: CALIFORNIA GREENHOUSE GAS ALLOWANCE BUDGETS.
SUBARTICLE 7: COMPLIANCE REQUIREMENTS FOR COVERED ENTITIES.
SUBARTICLE 8: DISPOSITION OF ALLOWANCES.
SUBARTICLE 9: DIRECT ALLOCATIONS OF CALIFORNIA GHG ALLOWANCES.
SUBARTICLE 10: AUCTION AND SALE OF CALIFORNIA GREENHOUSE GAS ALLOWANCES.
SUBARTICLE 11: TRADING AND BANKING.
SUBARTICLE 12: LINKAGE TO EXTERNAL GREENHOUSE GAS EMISSIONS TRADING SYSTEMS.
SUBARTICLE 13: OFFSET CREDITS ISSUED BY ARB.
SUBARTICLE 14: RECOGNITION OF COMPLIANCE INSTRUMENTS FROM OTHER PROGRAMS.
SUBARTICLE 15: ENFORCEMENT AND PENALTIES.
SUBARTICLE 16: OTHER PROVISIONS.
Citing the authority of the state’s Health and Safety Code, this Article establishes the California Greenhouse Gas Cap-and-Trade Program which aims to reduce greenhouse gas (GHG) emissions by establishing an aggregate GHG allowance budget for covered entities and providing a trading mechanism for compliance instruments. This subarticle provides definitions for terms in this Article.
The Program applies to the six major GHGs and also to nitrogen trifluoride (NF3) and “other fluorinated” GHGs (defined in the Definitions Section). The Program applies to the following sources in the state whose annual emissions equal or exceed 25,000 metric tons of GHGs as measured in the equivalent amount of carbon dioxide (“CO2e”):
- production facilities (cement, cogeneration, glass, hydrogen, iron and steel, , lime manufacturing, nitric acid, petroleum and natural gas systems, petroleum refining, pulp and paper manufacturing, self-generation of electricity, and stationary combustion);
- electricity generating facilities and importers;
- suppliers of natural gas (utilities, distributors and suppliers of blended fuels that contain natural gas);
- suppliers of RBOB (reformulated gasoline blendstock for oxygenate blending) and distillate fuel oil (position holders and importers) and suppliers of blended fuels that contain these;
- suppliers of liquefied petroleum gas (refiners, etc.) and suppliers of blended fuels that contain this fuel; and
- suppliers of carbon dioxide.
These covered sources have a compliance obligation for every metric ton of CO2e emitted from their associated activities that generate a compliance obligation, which differs for each covered source (see §95852), such as fuel combustion, process emissions, etc. The first compliance period—for entities whose annual emissions equaled or exceeded 25,000 metric tons CO2e in any year from 2008-2011—begins January 1, 2013. The second compliance period—for entities whose annual emissions equaled or exceeded 25,000 metric tons CO2e in any year from 2011-2014—begins January 1, 2015. The compliance obligation remains in place until GHG emissions fall to less than 25,000 metric tons of CO2e per year during one full compliance period, or if the entity shuts down. GHG emissions must be reported and verified under the Air Resources Board’s (ARB’s) Regulation for the Mandatory Reporting of Greenhouse Gas Emissions.
This subarticle allows for voluntary participation in the Program by entities engaged in the above-listed activities but falling below the annual 25,000 metric tons CO2e threshold.
This subarticle also allows for other market participants to participate. Non-covered entities, including those operating a registered offset project, may apply to purchase, hold, sell, or voluntarily retire allowances under the Program. Verification bodies, offset registries or early action offset programs as identified in subarticle 14 do not qualify to hold allowances but may qualify as a “registered participant.”
The Executive Officer must create California GHG allowances and assign each allowance a unique serial number. Each allowance represents limited authorization to emit up to one metric ton in CO2e of any GHGs. The allowance does not constitute property or a property right. The Executive Officer may issue and register offset credits, provided that all provisions set forth in subarticle 13 are met.
Entities may use various instruments (such as allowances, offset credits, sector-based credits, as described in this rule) to comply with this section of the law.
Only a registered entity or an entity registered with an approved external program (pursuant to subarticles 12 or 14) can hold a compliance instrument. To register, an entity must complete an application. The application must designate a single authorized account representative and a single alternate authorized account representative. The accounts administrator may deny an application based on information provided or if the accounts administrator determines the applicant has provided false or misleading information, or withheld information.
An entity that meets or exceeds the inclusion threshold must register with the account administrator within 30 calendar days of the reporting deadline in the ARB’s Mandatory Reporting of GHG Emissions (MRR) if the entity is not covered as of January 1, 2013; or by January 31, 2012 or within 30 calendar days of the effective date of this regulation, whichever is later, for an entity that exceeds the inclusion thresholds for any data year 2008 to 2011.
This subarticle also describes the different account types used for compliance and by the Executive Officer. Each entity can have at most one holding account, one limited use holding account, one compliance account or one exchange clearing holding account. When the Executive Officer approves a registration for a covered entity, an opt-in covered entity, or a voluntarily associated entity, the accounts administrator will create a holding account for the registrant. When a covered entity or an opt-in covered entity completes the registration process, the account administrator will create a compliance account for the entity, into which the entity may transfer compliance instruments at any time. A limited use holding account with transfer restrictions will be created for an entity that qualifies for a direct allocation. An exchange clearing holding account with transfer restrictions will be created for a voluntarily associated entity. The Executive Officer may remove compliance instruments from a compliance account to satisfy a compliance obligation. The accounts administrator will also create accounts under the control of the Executive Officer, including: an Allocation Holding Account, used to hold the allowances when they are created; an Auction Holding Account, into which allowances are transferred from holding accounts of entities for which allowances are being auctioned; a Retirement Account, to which the Executive Officer or other entities transfer compliance instruments from compliance accounts that are to be retired; an Allowance Price Containment Reserve Account, into which serial numbers of allowances allocated to this application will be transferred and from which the Executive Officer will authorize sales at allowance reserve sales; and a Forest Buffer Account, into which ARB will place ARB offsets credits generated from a forest offset project, which will be used in the case of unintentional project reversals.
This subarticle also describes the selection and responsibilities of a single authorized account representative and a single alternate for each account.
This subarticle also requires registered entities to disclose direct and indirect corporate associations with other registered entities. Beneficial holding relationships between registered entities must also be disclosed.
The first compliance period is from January 1, 2013 to December 31, 2014. The second compliance period is from January 1, 2015 to December 31, 2017. The third compliance period is from January 1, 2018 to December 31, 2020.
At the start of the first compliance period, in 2013, the annual total allowance budget is 162.8 million CA GHG allowances. In 2014, the last year of the first compliance period, the annual allowance budget decreases to 159.7 million CA GHG allowances (1.9% decrease). In 2015, the first year of the second compliance period, allocations start at 394.5 million CA GHG allowances and decrease to 370.4 million CA GHG allowances (6.11% decrease) at the end of the three-year period. The allowance budget increases from the first to second compliance period because the program covers a larger number of entities starting in the second compliance period (See Subarticle 7). In the first year of the third compliance period, allocations start at 358.3 millions of CA GHG allowances and decrease to 334.2 million CA GHG allowances (6.73% decrease) at the end of the period.
Renewable electricity that is used in California but does not count towards Renewable Portfolio Standard compliance can result in retired CA GHG allowances.
Covered entities are subject to the Mandatory Reporting Regulation and to record retention requirements.
This subarticle sets forth the phase-in of coverage of different types of covered entities. Operators of facilities (i.e., industrial facilities like cement and glass producers), first deliverers of electricity (which are electricity generating facilities in California or electricity importers), and suppliers of CO2 who exceed the annual emissions thresholds described in Subarticle 3 are covered beginning with the first compliance period. Suppliers of natural gas, suppliers of RBOB and distillate fuel oils, suppliers of natural gas liquids, and suppliers of blended fuels who exceed the emissions thresholds above are covered beginning with the second compliance period.
Operators of facilities have a compliance obligation for every metric ton of CO2e for both stationary combustion and process emissions.
First deliverers of electricity must hold allowances to cover both in-state stationary emissions and emissions associated with electricity imported into California from a jurisdiction without an approved, linked GHG emissions trading system.
Natural gas suppliers have a compliance obligation for all GHG emissions that would result from combustion of all fuel delivered to end users in California, save for fuel delivered to covered entities.
Suppliers of gasoline “blendstock” – RBOB and distillate fuel oils – have a compliance obligation for all GHG emissions that would result from combustion of all such fuels that are imported or delivered to California.
Suppliers of natural gas liquids have a compliance obligation for the GHG emissions that would result from full combustion of all fuel consumed in California.
Suppliers of carbon dioxide have an aggregated compliance obligation for every metric ton of CO2 supplied for use in California and imported, less any CO2 that is verifiably sequestered.
CO2 emissions from specified source categories count toward reporting thresholds but do not count toward an entity’s compliance obligation. These include: verifiable biomass-derived fuels such as agricultural crops or waste, wood and wood wastes; biodiesel; fuel ethanol; biogenic municipal solid waste; biomethane; specified fugitive and process emissions; and emissions from geothermal generating units and geothermal facilities.
A covered entity that exceeds the relevant emissions thresholds in any of the three years preceding the start of a compliance period is a covered entity for the entire compliance period. Entities that first exceed the emissions threshold during an ongoing compliance period have a compliance obligation for all of their annual emissions in the first year that they exceed the threshold and each year thereafter.
Covered entities are limited in the number of offset credits that they may surrender to meet their compliance obligations. The ratio of offset credits used for compliance by a covered entity to the covered entity’s total compliance obligation (i.e., all of its covered emissions) must be less than 0.08. Moreover, sector-based offset credits cannot account for a ratio over 0.25 of the quantitative usage limit on compliance instruments in the first compliance and second compliance period and 0.50 of the quantitative usage limit on compliance instruments in subsequent compliance periods.
Covered entities have an annual compliance obligation equal to thirty percent of their GHG emissions from the previous year. Submission of allowances pursuant to the annual compliance obligation for a given year is due November 1 of the following calendar year (depending on a covered entity’s deadline under the reporting program). Surrender of allowances pursuant to a covered entity’s triennial compliance obligation is due by November 1st of the calendar year following the third year of the compliance period.
Surrendered allowances must be from an allowance budget year that is from the same year, the previous compliance year, or the last year of a compliance period for which a triennial compliance obligation is calculated.
A covered entity that fails to surrender sufficient allowances pursuant to its compliance obligation must surrender allowances to cover four times its “excess emissions” (i.e., the difference between the entity’s compliance obligation and the number of allowances and or offsets surrendered on time by the entity). At least three-fourths of the compliance obligation for untimely surrender must come from CA GHG allowances or allowances issued by a GHG ETS. Up to one-fourth can be fulfilled by ARB offset credits or other compliance instruments. The untimely enforcement surrender is due within five days of the first auction or reserve sale conducted by ARB following the applicable surrender date. If covered entities fail to surrender such allowances, enforcement actions will be undertaken. Three-fourths of the compliance instruments used to fulfill the untimely surrender obligation will be transferred to the Auction Holding Account, while the remaining one-fourth will be deposited in the Retirement Account.
This subarticle specifies how the allowances under the cap shall be allocated.
The Allowance Price Containment Reserve will be allocated as follows:
- One percent of the allowances from budget years 2013-2014,
- Four percent of the allowances from budget years 2015-2017, and
- Seven percent of the allowances from budget years 2018-2020
Ten percent of the allowances from budget years 2015-2020 will be allocated to the Auction Holding Account on December 15, 2011 for future auctions. Auction proceeds from will be deposited into the Air Pollution Control fund and will be available upon appropriation by the Legislature for designated purposes.
Allowances are freely allocated to electrical distribution utilities. Electrical distribution utilities receive 97.7 million allowances in 2012 with the annual cap adjustment factor declining by roughly 2 percent per year each year thereafter. The Executive Officer will place an annual individual allocation in the limited use holding account of each eligible distribution utility on or before January 15 of each calendar year.
Allowances are also freely allocated to covered industrial sources based on the methodology described in Subarticle 9. As the table below shows, industrial sectors are classified according to leakage risk (the risk that industry would locate somewhere other than California to avoid GHG regulations) and assigned different assistance factors. The higher the assistance factor, the more allowances are directly allocated to covered industrial facilities.
Direct allocations of GHG allowances are specified for covered industrial facilities from the sectors listed in Subarticle 8 and electrical distribution utilities.
Direct allocations of GHG allowances are specified for covered industrial facilities from the sectors listed in Subarticle 8 and electrical distribution utilities.
Direct allocations to covered industrial facilities are based on a product output-based allocation calculation methodology for industrial sectors with benchmarked product outputs (e.g., paper products, refined petroleum products, and steel) and on a thermal energy-based calculation methodology for other industry sectors. The direct allocation to a covered industrial facility in a given year is a function of the applicable output-based or thermal energy-based benchmark, the facility’s actual output or energy use, the industry sector-specific assistance factor (see table in Subarticle 8), and an adjustment factor that declines over time to reflect the declining cap level.
All direct allocations of allowances to investor-owned electrical distribution utilities are placed into a limited use holding account for each electrical corporation. Publicly-owned utilities can split their direct allocations of allowances between a limited use holding account and a compliance account with an advance notice to ARB. In 2012, one sixth of the allowances placed in a distribution utility’s holding account must be offered for sale at each of two auctions scheduled for 2012. After 2012, all allowances in a utility’s limited use holding account must be offered for sale at auction each year unless they are for a budget year that is after the current calendar year. Auction proceeds obtained by an electrical distribution utility shall be used exclusively for the benefit of retail ratepayers of each electrical distribution utility. Investor owned utilities are required to ensure equal treatment of their customers or customers of electricity providers and community choice aggregators.
A placeholder is included for direct allocations for natural gas distribution utilities.
In 2012, two auctions of California GHG Allowances will take place on August 15 and November 14. Beginning in 2013, subsequent auctions shall be conducted on the twelfth business day of the second month of each calendar quarter. The Executive Officer will hold two auctions each quarter – the Auction of Allowances from the Current and Previous Budget Years and the Auction of Allowances from Future Budget Years. During each quarter’s Auction of Allowances from the Current and Previous Budget Years, one fourth of the allowances allocated for the current calendar’s budget year will be offered. In 2012, each Auction of Allowances from Future Budget Years will offer half of the allowances designated for the advanced auction from the 2015 budget. Beginning in 2013, each Auction of Allowances from Future Budget Years will offer a quarter of the advance auction allowances designated for advance auction from the budget year three years subsequent to the current calendar year. Entities owning limited use holding accounts may consign allowances for sale in the quarterly auctions and accept the auction settlement price for such allowances.
Auctions will consist of a single round of sealed bidding. Auctions shall include an auction reserve price (i.e., a price floor below which no allowances will be sold). For 2012 and 2013, the auction reserve price for 2013 vintage allowances will be $10 per metric ton CO2e. For calendar years after 2013, the auction reserve price will equal the previous calendar year’s auction reserve price plus an increase of an annual rate of 5 percent plus inflation. The auction reserve price for 2012 auctions of vintage 2015 allowances will be $10 per metric ton CO2e.
For auctions conducted in 2012-2014, a single entity with a compliance obligation or a group of such entities with a corporate association (see below for definition of corporate association) can purchase no more than 15 percent of the total allowances offered in any given auction. Any other single auction participant is limited to purchasing no more than 4 percent of total allowances in any given auction. These limits do not apply, though, to investor-owned electrical utilities.
This subarticle also includes provisions governing auction administration and registration. In particular, California allowances may be offered through an auction conducted jointly with other jurisdictions to which California links, provided the joint auction conforms to this subarticle’s requirements.
This subarticle governs the operation of the Allowance Price Containment Reserve. Only covered entities, including opt-in covered entities, can purchase allowances from the Allowance Price Containment Reserve. The first reserve sale will be conducted on March 8, 2013. Subsequent sales shall be conducted six weeks after each quarterly allowance auction. All allowances in the reserve shall be offered for sale at each such reserve sale. These allowances shall be divided into three equal-sized tiers with varied pricing. In 2013, the reserve allowance prices shall be: $40 per allowance for the first tier; $45 per allowance for the second tier; and $50 per allowance for the third tier. After 2013, these prices shall increase each year at an annual rate of 5 percent plus inflation.
This subarticle regulates the practices involved in trading and banking of allowances.
It establishes the maximum number of allowances held by any entity in a calendar year, called the “holding limit.” The holding limited is calculated as follows:
Holding Limit = 0.1*Base + 0.025*(Annual Allowance Budget – Base)
· “Base” equals 25 million metric tons of CO2e
· “Annual Allowance Budget” is the number of allowances issued for the current budget year
Limited exemption from the holding limit is allowed for allowances transferred to a compliance account for a year, up to the amount of emissions reported in the previous year. The limited exemption is the sum of all previous annual transfer limits, will be reduced by the sum of the entity’s emissions over a compliance period on December 31, and will be assigned by the Board according to set requirements if a positive or qualified positive verification statement is not made.
The Executive Officer may not approve transactions that would exceed an entity’s holding limit. Holding limits of entities with corporate associations will be treated as those held by a single entity unless they are prohibited by law from coordinated market activity including transfer of instruments. If an entity is found in violation of the provisions of this subarticle, the Executive Officer may also limit the number of instruments held by an entity to an amount sufficient to cover its reported emissions, subject an entity to additional annual surrender requirements, and suspend or revoke registration of entities.
This subarticle sets the requirements of trades acceptable to the accounts administrator. The administrator must have the following information before a transaction settlement is completed: the account number and representative of the seller and purchaser, the serial number of the instrument, the transaction date, the settlement date, the price, and the account number and representative of whom the instrument is to be held in benefit.
It also establishes that allowances for a current or previous compliance period may be banked, while allowances for a future period may also be held. Allowances do not expire until they are surrendered to and retired by the Executive Officer, are voluntarily retired, or are retired by an external trading system linked to the California system.
This subarticle allows compliance instruments from approved external (i.e., outside of California) greenhouse gas emissions trading systems to be used to meet the requirements of this program. Approval of external systems may be given by the Board after public notice and comment in accordance with California Administrative Procedure Act. Allowances issued by external systems are not subject to the quantitative offset usage limits in this Article, but external offset and sector-based offset credits are subject to the quantitative use limits when used to meet a compliance obligation under this Article.
Offsets must be GHG reductions or removals that are “real, additional, quantifiable, verifiable, permanent and enforceable.” The Board shall provide public notice of and opportunity for public comment prior to approving any Compliance Offset Protocols.
This subarticle describes the requirements for Compliance Offset Protocols. To be approved by the Board, a Protocol must: establish data collection and monitoring procedures that are relevant to the offset project type; establish a “conservative” business-as-usual baseline; account for leakage through activity-shifting and market-shifting; account for quantification uncertainty; ensure GHG reduction permanence; include a mechanism ensuring sequestration permanence; and establish the length of the crediting period. The details for achieving each of these delineated requirements is left for the Protocol to address and the Board to ensure are upheld. The crediting period for a non-sequestration project can be no less than 7 years and no greater than 10 years while a sequestration project crediting period must be no less than 10 years and no greater than 30 years. In addition to complying with an approved Compliance Offset Protocol, an offset project must also be located in the United States, Canada or Mexico.
This subarticle also describes the details for registering an offset project for listing. The project operator (or their “designee”) must be registered with ARB and must not be subject to a hold restriction on their account. They must also attest to ARB as to the truthfulness and completeness of the project submission as well as acknowledge that they are voluntarily entering the Cap-and-Trade program complete with the accordant regulatory requirements. The project listing must contain all of the information required for that project type based on the appropriate Protocol (once developed). There are four Compliance Offset Protocols: Ozone Depleting Substance Projects, Livestock Projects, Urban Forest Projects, and U.S. Forest Projects. If the project listing is incomplete in that context, the ARB (or the registry being used) must notify the operator or designee within 30 days. If the project list is complete the listing status is changed to “Proposed Project” pending approval for listing by the registry. Projects rejected by the registry may be appealed to the ARB (who, in turn, may consult with the registry in making a final determination).
This subarticle describes requirements for verification of GHG emissions reductions or GHG removals from offset projects. An offset project operator must obtain the services of an ARB-accredited verification body for the purposes of verifying projects. Verification for offset projects other than sequestration must be done annually while the verification for sequestration projects must be done once every six years. To perform verification services, a given project cannot be verified by the same service provider for more than six years in a row (for any project type). A service provider must be at least three years removed from verifying a particular project before reengaging with that same project again. This subarticle also contains detailed information on procedures that verification service providers must follow, as well as the procedures to be employed to ensure that there exists no conflict of interest that could compromise the independence of the verification service provider.
A registry offset credit, representing one metric ton of CO2e, will be issued only if the project is listed pursuant to the requirements in this subarticle, the emission reductions or GHG removal enhancements were issued a Positive Offset or Qualified Positive Offset Verification Statement, and ARB (or the registry being used) has received this statement from an ARB-accredited verification body. ARB (or the registry being used) will issue an offset credit no later than 45 days after a Positive Offset or Qualified Positive Offset Verification Statement is received. ARB or the registry must notify the Offset Project Operator of the issuance within 15 days of issuing the credit. If offset credits originate from an offset project submitted through an Offset Project Registry, this Registry must retire the original credits issued in its system before ARB issues a compliance offset credit for the same amount retired by the Registry. ARB will only issue compliance offset credits for a project submitted through a Registry after reviewing the project related documentation and ensuring all regulatory criteria have been met for compliance offset credits.For forest sequestration projects, a portion (the amount to be determined in the Compliance Offset Protocol for U.S. Forest Projects) of the offset credits issued must be placed into the Forest Buffer Account. If ARB determines that there has been an unintentional reversal it will retire offset credits in the amount of tons reversed from the Forest Buffer Account. If an unintentional reversal lowers the project’s actual standing live carbon stocks below its project baseline, the project will be terminated by ARB or an Offset Project Registry. Another project may be initiated within the same boundary. If an unintentional reversal does not lower the project’s actual standing live stocks below its baseline, the project may continue without termination as long as the unintentional reversal has been compensated by the Forest Buffer Account. If an intentional reversal occurs, the Project Operator shall give notice in writing to ARB and the Offset Project Registry and provide a written description of the intentional reversal within 30 days of the reversal. The Project Operator must submit ARB offset credits or other approved compliance instruments in the amount of CO2e reversed within six months of notification by ARB , and new offset projects may not be initiated within the same boundary.
Offset Project Registries can apply to provide registry services under this article. Their primary business must be operating an Offset Project Registry for voluntary or regulatory purposes. They may not act as an Offset Project Operator, Authorized Project Designee, or offset project consultant, or act as a verification body once approved as an Offset Project Registry. Offset Project Registries shall use Compliance Offset Protocols approved pursuant to this subarticle to determine whether an offset project may be listed with the Offset Project Registry for issuance of registry offset credits. Any credits issued by a Registry are subject to ARB review before being transitioned into compliance offset credits. Credits issued by a Registry cannot be used for compliance until ARB reviews all relevant project documentation and determines that the credits meet all regulatory requirements. The subarticle describes requirements placed on Offset Project Registries for reporting and verifying GHG emissions reduction projects.
This subarticle describes the requirements placed on offset credits used for early action. Offset credits from projects registered with an approved third-party offset program (according to the procedures outlined in Subarticle 13 for Offset Project Registries) or from a program that meets a list of requirements described in this subarticle shall be accepted by ARB for early action use. The requirements placed on early action offset credits specify that the GHG reductions: must have occurred between January 1, 2005 and December 31, 2014; must result from an early action offset project that is listed or registered with an Early Action Offset Program prior to January 1, 2014, must result from a project located in the United States, and must result from the use of one of the approved offset quantification methodologies.
Once an offset credit that is issued by an approved third-party offset program is determined by ARB to meet the criteria in this subarticle, ARB will assign an ARB serial number to the offset credit. When ARB retires a credit, it will notify the third-party program to simultaneously retire it. An ARB offset credit may not be issued for an early action offset credit that has been retired, cancelled, or used to meet a voluntary commitment, or surrender obligation in any voluntary or regulatory system.
Any offset credits issued by an approved third-party program must be verified by an ARB-accredited verification body.
ARB may consider for acceptance compliance instruments issued from sector-based offset crediting programs that meet requirements in this subarticle and originate from developing countries or subnational jurisdictions within those developing countries. Sector-based offset credits may be generated from Reducing Emissions from Deforestation and Forest Degradation (REDD) and other sources as yet to be defined.
The relevant legal jurisdiction is the State of California, including the authority of ARB and the Superior Courts of the State of California. The ARB Executive Officer may suspend, revoke, or place restrictions on account holders who are found to be in violation of this Article. Violation of this Article can include failure to surrender a sufficient number of allowances to meet the compliance obligation, and penalties may be assessed pursuant to Health and Safety Code section 42403(b).
This subarticle provides for severability and confidentiality. Emissions data submitted to the ARB is public information, but reporting entities can request that material be classified as confidential based on the entity’s belief that the information is either trade secret or otherwise exempt from public disclosure under the California Public Record Act.