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
In August 2012, the federal government adopted the second of two rules dramatically increasing the fuel economy and decreasing greenhouse gas emissions from cars and light trucks.
The first rule, adopted in April 2010, raises the average fuel economy of new passenger vehicles to 34.1 miles per gallon (mpg) for model year 2016, a nearly 15 percent increase from 2011. The second rule, finalized in August 2012, will raise average fuel economy to up to 54.5 mpg for model year 2025, for a combined increase of more than 90 percent over 2011 levels. Fuel economy could reach 54.5 mpg if the automotive industry chooses to meet the greenhouse gas target only through fuel economy improvements.
The standards were adopted by the Environmental Protection Agency (EPA) and the National Highway Traffic Safety Administration (NHTSA) with the cooperation of major automakers and the state of California. Together, the standards represent the largest step taken by the federal government directed at climate change. Passenger vehicles were responsible for 17 percent of U.S. greenhouse gas emissions in 2011, and the August 2012 standards through 2025 will reduce the carbon intensity of these vehicles by 40 percent from 2012 to 2025.
Other important benefits include improving U.S. energy security and saving drivers money.
The rule for model years 2017 to 2025 is projected to cut annual U.S. oil imports by an additional 6 percent by 2025 from what would happen otherwise, or 400,000 barrels per day. When combined with the rule for model years 2012 to 2016, U.S. oil imports are expected to decline by over 2 million barrels per day by 2025, equivalent to one-half of the oil we import from OPEC countries each day according to EPA.
Most of the U.S. transportation sector relies on oil as the single energy source, meaning any disruption can hurt the economy. A study by EPA and the Oak Ridge National Laboratory estimated that cutting demand for oil would produce an energy security benefit for the nation's economy of $13.91 (in 2011 dollars) for each barrel saved. In total, the rule for model years 2017 to 2025 is expected to save approximately 4 billion barrels of oil over the life of vehicles sold during this period.
Higher vehicle costs for fuel efficiency improvements will be far outweighed by fuel savings, with the average driver saving about $8,000 net over the lifetime of a model year 2025 car compared to a model year 2010 car.
Another rule adopted in August 2011 established the first-ever fuel economy and greenhouse gas standards for medium- and heavy-duty vehicles, which include tractor-trailers, large pickups and vans, delivery trucks, buses, and garbage trucks. These standards are projected to save a combined $50 billion in fuel costs, 530 million barrels of oil, and 270 million metric tons of carbon emissions over the lifetime of vehicles for model years 2014 to 2018.
The federal government has regulated fuel economy through standards for cars and light-duty trucks for decades. The 1973 Arab oil embargo prompted Congress to pass legislation in 1975 that introduced Corporate Average Fuel Economy (CAFE) standards for new passenger vehicles only. The purpose was to improve the fuel economy of the passenger vehicle fleet to reduce oil imports.
NHTSA, an agency within the U.S. Department of Transportation (DOT), administered the original CAFE program while EPA was responsible for establishing the testing and evaluation protocol for assessing compliance and calculating the fuel economy for each manufacturer. These responsibilities are the same today.
CAFE is the sales-weighted average fuel economy (in mpg) of the passenger cars or light-duty trucks for a manufacturer's fleet. See Calculating Light-Duty Vehicle CAFE Then and Now below for details of how EPA determines compliance. NHTSA fines manufacturers that are out of compliance. NHTSA has so far collected almost $819 million in fines over the life of the CAFE program.
Since 1975, a number of changes have been made to the standards. Figure 1 provides an annotated history of the U.S. CAFE standards. A number of other countries have also instituted fuel economy standards, with most establishing more aggressive targets than the United States. See here for more details.
FIGURE 1: Fuel economy standard for passenger vehicles from MY1978-2025.
1. 1978-1985: Congress sets car standard (1978-1985)
6. Bush Admin issues new truck targets (2005-2007)
Under the federal Clean Air Act, California is the only state with the ability to set air emission standards for motor vehicles, as long as these standards are as stringent as the federal standards and the state receives a waiver from the EPA. Once California receives an EPA waiver, other states can adopt California's standards.
In 2002, California enacted the Clean Cars Law (AB 1493) to set vehicle emissions standards for greenhouse gases. In April 2007, the Supreme Court ruled that the EPA has the authority to regulate greenhouse gas emissions from the transportation sector under the Clean Air Act. In December 2007, a judge threw out a lawsuit by automakers attempting to block California from implementing AB 1493. The intersection of fuel economy standards and greenhouse gas emission standards was beginning to become clear (see here for more on California vehicle standards).
Back in December 2005, California had applied for an EPA waiver to implement its greenhouse gas standards. In March 2008, EPA denied California's waiver request. Upon taking office in January 2009, President Barack Obama ordered EPA to reconsider that denial.
In June 2009, EPA granted a waiver allowing California to regulate greenhouse gas emissions from vehicles within the state beginning with model year 2009. On September 15, 2009, EPA and NHTSA issued a joint proposal to establish new vehicle standards for fuel economy and greenhouse gas emissions for model years 2012 to 2016, which were finalized on April 1, 2010. The joint proposal reflected an agreement among EPA, NHTSA, California, and most major automakers. California promptly agreed to adopt the federal standards in lieu of its own separate standard; and did so again with the latest standards covering model years 2017 to 2025.
The latest passenger vehicle standards, finalized in August 2012 and published in the Federal Register in October 2012, cover passenger cars, light-duty trucks, and medium-duty passenger vehicles, from model year 2017 to 2025. The standards build off those set in April 2010 for model years 2012 to 2016. The standards are based on the vehicle's footprint, which is a measure of vehicle size (see Calculating Light-Duty Vehicle CAFE Then and Now).
Because NHTSA cannot set standards beyond model year 2021 due to statutory obligations and because of the rules' long time frame, a mid-term evaluation is included in the rule. Thus, standards for model years 2022 through 2025 are considered "augural" by NHTSA. The comprehensive evaluation by both EPA and NHTSA will allow for any compliance changes if necessary for the later years covered by the rule.
As seen in Table 1, the greenhouse gas standard from EPA requires vehicles to meet a target of 163 grams of carbon dioxide equivalent (CO2e) per mile in model year 2025, equivalent to 54.5 mpg if the automotive industry meets the target through only fuel economy improvements.
TABLE 1: Projected Emissions Targets under the Greenhouse Gas Standards (g CO2e/mi)
Combined Cars & Light Trucks
Combined Cars & Light Trucks
As seen in Table 2, the fuel economy standard from NHTSA requires vehicles to meet an estimated combined average of up to 48.7 mpg in 2025. This estimate is lower than the mpg-equivalent of the EPA target for 2025 mentioned above (54.5 mpg) , because it assumes that manufacturers will take advantage of flexibility available under the law designed to reduce the cost of compliance. See Light-Duty Vehicle Program Flexibilities for more information.
TABLE 2: Projected Fuel Economy Standard (mpg).
Combined Cars & Trucks
Combined Cars & Trucks
This table is based on CAFE certification data from model year 2010, a car-truck sales split from the Energy Information Administration's Annual Energy Outlook for 2012, and future sales forecasts by JD Powers.
NHTSA and EPA released medium- and heavy-duty vehicle standards for model years 2014 to 2018 in August of 2011. Table 3 defines the breakdown for medium- and heavy-duty vehicles by weight.
TABLE 3: Vehicle class breakdown for medium- and heavy-duty vehicles
Gross Vehicle Weight Rating (lb)
8,501 – 10,000
10,001 – 14,000
14,001 – 16,000
16,001 – 19,500
19,501 – 26,000
26,001 – 33,000
The medium- and heavy-duty standards for tractor-trailers, buses, etc., are the first of their kind in the world. The standards are divided into three segments:
1. Tractor-trailers, which are responsible for almost two-thirds of fuel consumption from medium- and heavy-duty trucks, will have to achieve about a 20 percent reduction in fuel consumption by model year 2018, or about 4 gallons of fuel every 100 miles traveled. The following table defines the fuel consumption standards for tractor-trailers.
TABLE 4: Fuel Consumption Standards for Tractor-Trailers
2014–2016 Model Year Gallons of Fuel per 1,000 Ton-Mile
2017 Model Year and Later Gallons of Fuel per 1,000 Ton-Mile
2. Heavy-duty pickup trucks and vans will have to improve fuel economy by model year 2018 by 10 percent for gasoline vehicles and by 15 percent for diesel vehicles, or one gallon of fuel per 100 miles traveled. The standards are phased in, increasing in stringency from model years 2014 to 2018. The standards rely on a "work" factor, which considers the vehicle's cargo capacity, towing capabilities, and whether it has 4-wheel drive. Similar to the light-duty standards, the standards are based on the manufacturer's sales mix. To provide flexibility, manufacturers can conform to the standards using one of two phase-in approaches:
3. Vocational vehicles (delivery trucks, buses, garbage trucks) will have to improve fuel economy by 10 percent by model year 2018, or about one gallon of fuel per 100 miles traveled. The following table defines the fuel consumption standards for vocational vehicles.
TABLE 5: Fuel Consumption Standards for Vocational Vehicles.
Light Heavy-Duty Class 2b-5
Medium Heavy-Duty Class 6-7
Heavy Heavy-Duty Class 8
Fuel Consumption Mandatory Standards (gallons per 1,000 ton-miles) Effective for Model Years 2017 and later
Fuel Consumption Standard
Effective for Model Years 2016
Fuel Consumption Standard
Fuel Consumption Voluntary Standards (gallons per 1,000 ton-miles) Effective for Model Years 2013 to 2015
Fuel Consumption Standard
NHTSA and EPA designed the standards based on the kind of work the vehicles undertake. Heavy-duty pickup trucks and vans must meet a standard specified similarly to passenger vehicles, gallons of fuel per mile and grams of CO2e per mile. The other two categories must meet a standard based on the amount of weight being hauled (fuel consumed or grams of CO2e emitted per ton of freight hauled a defined distance).
U.S. fuel economy and greenhouse gas standards exist because individual drivers tend to value savings from fuel economy much less than society as a whole, which leads to more oil consumption than would occur if soceital benefits were taken into account. The benefits to society of higher fuel economy include, but are not limited to, reduced impacts on global climate, improved energy security, and overall consumer savings. But those benefits are not top of mind when a consumer buys a car.
In addition, when making purchasing decisions, most people assume a dollar today is worth more than a dollar in the future since the dollar today can be invested and grow in value over time. The value people assign to a dollar in the future compared to a dollar today is known as the discount rate, or the interest rate they would expect on a dollar invested today. For example, a discount rate of 20 percent means consumers assume they will make 20 percent interest annually on money invested today, which is unlikely. Thus, the higher the discount rate a consumer uses, the more likely a consumer is to invest that money instead of spending it on a product. Consumers can exhibit different discount rates depending on the product.
For passenger cars, David Greene from Oak Ridge National Laboratory found that the value consumers place on fuel economy savings varies widely, but empirical research reveals a discount rate between 4 and 40 percent. The discount rate that society put on fuel savings is much closer to 4 percent, meaning consumers often substantially undervalue fuel economy compared to society.
Each automaker's fleet-wide average fuel economy consists of three potential fleets: domestic passenger cars, imported passenger cars, and light-duty trucks. (The split between domestic and imported cars exists to support domestic automobile production.) With its focus on fuel efficiency, the standard must capture the fuel economy of each vehicle traveling the same number of miles. The harmonic mean of the fleet accomplishes this task (versus the simpler arithmetic mean). That is, instead of dividing the sum of the fuel economy rates in mpg for each vehicle by the total number of vehicles (the arithmetic mean), the reciprocal of the arithmetic mean is used as follows:
Where Production is the number of vehicles produced for sale for each model and TARGET is the fuel economy target for the vehicle.
Before 2008, the target fuel economy was the same for all vehicles. In 2008, NHTSA changed the target to a bottom-up one based on attributes of each vehicle instead of a top-down uniform target across an entire automaker's fleet. The vehicle footprint target for light-duty trucks through model year 2016 and for automobiles through model year 2025 is determined as follows:
where FOOTPRINT is the product of the vehicle's wheelbase and average track width in square feet, a and b are high and low fuel economy targets that increase from 2012 to 2025 and are constant for all vehicles, and c and d are adjustment factors. Parameter c is measured in gallons per mile per foot-squared, and parameter d is measured in gallons per mile.
For light-duty trucks beginning in model year 2017, an additional variation of the TARGET calculation is considered. This additional variation establishes a "floor" term, which prevents any footprint target from declining between model years. The definitions of parameters a, b, c, and d correspond to e, f, g, h, accordingly. However, the values of these parameters are different.
The idea behind an attribute-based standard is that the level of difficulty of meeting the standards is the same for smaller and larger vehicles. A uniform standard, on the other hand, is easier to meet for smaller vehicles (i.e., those with a smaller footprint) than for larger vehicles.
The EPA and NHTSA programs have a number of features to make compliance for manufacturers more cost-effective, while also encouraging technological innovation like plug-in electric vehicles. Since there are two programs to comply with, the details of both programs are stipulated below.
- Credit Trading System: Both programs include a credit system allowing manufacturers to carry efficiency and greenhouse gas credits forward by up to five years and backward up to three years to achieve compliance and avoid fines. Manufacturers can also transfer credits between cars and trucks of their fleet and trade credits with other manufacturers. Additionally, CO2 credits generated for EPA compliance from model year 2010 to 2016 can be carried forward as far as model year 2021.
- Air Conditioning Improvements: Both programs allow manufacturers to use air conditioning (A/C) system efficiency improvements toward compliance. For the NHTSA program, credits will depend on fuel consumption reductions. The EPA program allows credits for reductions in fuel use and refrigerant leakage, as well as the use of alternative refrigerants with lower global warming potential.
- Off-Cycle Credits: Current test procedures do not capture all fuel efficiency and greenhouse gas improvements available. Technologies that qualify for additional credit might include solar panels on hybrid vehicles, active aerodynamics, or adaptive cruise control. In addition, manufacturers can apply for credit for newer technologies not yet considered if they can provide sufficient data to EPA.
- Zero Emission, Plug-in Hybrid, and Compressed Natural Gas Vehicle Incentives: To encourage plug-in electric vehicles, fuel cell vehicles, and compressed natural gas (CNG) vehicles, EPA has included a credit multiplier in the rule for model years 2017 to 2021. In the compliance calculation for GHG Emissions, all-electric and fuel cell vehicles count as two vehicles beginning with model year 2017 and phasing down to 1.7 by model year 2021. Plug-in hybrid electric vehicles begin with a multiplier of 1.6 in model year 2017 and phase down to a value of 1.3 by model year 2021. Electric and fuel cell vehicles sold during this period will count as emitting 0 grams of CO2e per mile. There is no multiplier for model years 2021 to 2025 and EPA limits the zero-grams credit based on vehicle sales during this period. The cap for model years 2021 to 2025 is 600,000 for companies that sell 300,000 of these vehicles from model year 2019 to 2021 and at 200,000 otherwise. Beyond that number, manufacturers of electric and fuel cell vehicles will need to account for their upstream emissions (i.e., electricity generation or hydrogen production) using accounting methodologies defined in the rule.
EPA has also included credit multipliers for CNG equivalent to plug-in hybrid electric vehicles: 1.6 in model year 2017 and a phase down to 1.3 by model year 2021. Unlike electric and fuel cell vehicles, GHG emissions from CNG vehicles will be measured by EPA.
In contrast, NHTSA does not believe it has the legal authority to offer credit multipliers. Existing legal authority does allow NHTSA to incentivize alternative fuels, like natural gas, however, by dividing vehicle fuel economy by 0.15; in other words, an electric, fuel cell, or CNG vehicle that has a fuel economy of 15 mpg-equivalent will be treated as a 100 mpg-equivalent vehicle.
- Truck Hybridization: Both programs offer incentives to add battery-electric hybrid support to full-size trucks. Mild hybrid pickup trucks (15-65 percent of braking energy is recaptured) would be eligible for a per vehicle credit of 10 grams of CO2e per mile during model years 2017 to 2025 so long as the technology is incorporated into 20 percent or more of the company's model year 2017 full-size pickup production, ramping up to at least 80 percent by model year 2021. Strong hybrid pickup trucks (at least 65 percent of braking energy is recaptured) would be eligible for a credit of 20 grams of CO2e per mile per vehicle during model years 2017 to 2025 as long as the technology is used in at least 10 percent of the company's full-size pickup trucks.
- Transportation Sector Emissions Overview
- Comparison of Actual and Projected Fuel Economy for New Passenger Vehicles
- EPA Office of Transportation and Air Quality Regulations and Standards
- NHTSA CAFE Program
- Greene, D. (2010, February 9-10). Why the Market for New Passenger Cars Generally Undervalues Fuel Economy. Retrieved August 5, 2011, from International Transport Forum.
Innovative financing program helps South Carolina homeowners save money through energy efficiency retrofits
An innovative energy-financing program has helped customers of South Carolina rural electric cooperatives to undertake energy efficiency retrofits for their homes, substantially reducing their energy use and saving money.
Through on-bill financing (OBF), customers pay back the cost of the retrofit through monthly installments on their electricity bill. This strategy helps to expand access to costly energy retrofits to low-income residents and makes the financial benefits immediately apparent. If monthly energy savings are greater than or equal to the loan repayment, then OBF will be “bill neutral” and result in the same or lower monthly electricity bills . In addition, the financial obligation of OBF is tied to the electricity meter of each house and can be passed on to subsequent owners and residents; thus, customers only pay for the energy retrofits for as long as they live there.
A preliminary review of South Carolina’s pilot program, called “Help my House,” found that the 125 participating households are projected to save an average of $400 each year after loan repayments. Energy use could be reduced by thirty-five percent, or approximately 11,000 kilowatt-hours each year. The retrofits, which included improvements to insulation, sealing, and heating, ventilation, and air-conditioning (HVAC) systems, cost an average of $7,200, with projected simple payback periods of 5.86 years. In addition, ninety-six percent of participants reported satisfaction with the efficiency installations and rated their homes as more comfortable after the retrofit.
The program was launched in 2011 by the Central Electric Power Cooperative, which supplies wholesale electricity to 20 rural South Carolina electric cooperatives, and the Electric Cooperatives of South Carolina, the co-ops’ marketing and policy partner, with support from the Environmental and Energy Study Institute. A full-scale OBF energy-efficiency program implemented by South Carolina cooperatives could save an estimated $270 million per year in electricity costs and create more than 7,000 jobs after 20 years, according to an analysis by Coastal Carolina University.
South Carolina utilities were authorized to offer OBF through the passage of Senate Bill 1096 in 2010. The bill eliminated the need for credit checks by tying the financial obligation to the meter rather than to the individual borrower, and allowed utilities to disconnect power if loan repayments are not made. Utilities in 22 other states offer OBF, with supporting state legislation in Illinois, Hawaii, Oregon, California, Kentucky, Georgia, Michigan, and New York.
In addition, “Help my House” was funded by a $740,000 loan from the U.S. Department of Agriculture’s (USDA) Rural Utility Service (RUS), which supports the development of electric, water, and telecommunications services in rural regions. This was the first time RUS funded an energy efficiency initiative, but more cooperatives around the country may follow South Carolina’s example. On July 17 USDA proposed a rule that would create a new RUS program to provide up to $250 million in loans for energy efficiency improvements. The proposed Energy Efficiency and Conservation Loan Program would allow rural electric cooperatives to provide energy efficiency retrofits, including those funded by OBF programs, audits, renewable energy systems, and more.
For more information:
Help My House Pilot Program – Summary Report
Environmental and Energy Study Institute – Fact Sheet
Today’s Senate hearing isn’t just about the science of climate change. It’s also about the actions that need to be taken now to adapt to the reality of a changing climate. Businesses and governments each have a critical role to play in building resilient communities and economies.
Business-as-usual is already being interrupted by extreme heat, historic drought, record-setting wildfires, and flooding. Events from water shortages to floods are disrupting the supply chains for such companies as Honda, Toyota, Kraft, Nestle and MillerCoors. By the end of 2011, the United States had recorded more billion-dollar disasters than it did during all of the 1980s, totaling about $55 billion in losses.
On June 28, 2012, New York State finalized its rule limiting carbon dioxide emissions from new power plants, and capacity additions to existing plants, within the state. The rule, 6 NYCRR Part 251, would effectively prevent the construction of new coal-fired power plants unless they are combined with carbon capture and sequestration technology. The new state standard is stricter than the federal rule proposed by the U.S. Environmental Protection Agency in April 2012. The regulation takes effect July 12, 2012.
Please see our original news story for the details of the regulatory standard.
U.S. States: Emissions Caps for Electricity
New York Dept. of Environmental Conservation: Adopted Part 251 CO2 Performance Standards for Major Electric Generating Facilities
On June 11, Ohio governor John Kasich signed a new energy law that establishes one of the United States’ strictest regulatory frameworks for new natural gas drilling technologies. The law, S.B. 315, also makes cogeneration an eligible option for meeting the state’s target of 12.5 percent renewable energy generation by 2025. Other measures address smart grids and electricity pricing, natural gas vehicles, alternative fuel loans, and green building standards for state-owned buildings.
New Regulations for Natural Gas Drilling
Eastern Ohio’s deep shale formations may be among the largest natural gas reservoirs in the U.S., and the new law will regulate the horizontal drilling and hydraulic fracturing (commonly known as “fracking”) necessary to explore these resources. Fracking, in particular, raises concerns for its use of industrial chemicals and potential impacts on water quality.
S.B. 315 addresses those concerns with requirements for the disclosure of chemicals and additives used in all stages of the drilling and fracking process. It also requires developers to conduct tests of water wells in the vicinity before drilling a new horizontal well or any well in an urbanized area. Developers must also identify in their permit applications all water sources that will be used for drilling.
Supported by the oil and gas industry, the law has met with criticism from environmental groups, since companies can avoid disclosing chemicals by claiming them as proprietary trade secrets. Other objections are that operators do not have to disclose chemicals until up to sixty days after the completion of drilling, and the lack of public commenting throughout the permit application process.
Cogeneration to Qualify as Renewable Energy
The new energy law reclassifies cogeneration as a renewable energy technology under Ohio’s alternative energy portfolio standard (AEPS). The portfolio standard, which governs the state’s electricity generation mix, includes separate targets of 12.5 percent each for both renewable (such as wind and solar) and advanced energy (such as clean coal or nuclear) generation by 2025. Previously, cogeneration counted toward the advanced energy target, but because the advanced energy standard lacks interim targets, electric utilities made little progress in developing new cogeneration projects.
To encourage faster development, S.B. 315 revises the AEPS to allow certain kinds of cogeneration to count toward the renewable energy standard, which does have yearly interim targets. Specifically, utilities can use electricity generated from waste energy recovery (WER) systems to fulfill either the renewable target or a separate energy efficiency standard, but not both. Under the new definition, Ohio is the only state to classify electricity generation from waste heat as a renewable energy source.
Critics worry that including WER systems under the renewable energy standard will undermine the development of renewable energy sources such as wind and solar in Ohio. Wind developers argue that the incremental targets are not ambitious enough to provide room for both renewables and WER systems, and may damage the prospects of several wind energy projects that are already underway.
Other Clean Energy Measures: Transportation, Grid, and Buildings
Finally, the new law includes several other clean energy measures, such as one supporting the wider adoption of natural gas vehicles. The Public Utilities Commission of Ohio (PUCO) and Ohio Department of Transportation (ODOT) will conduct a study on the cost-effectiveness of compressed natural gas vehicles, including the conversion of the state’s fleet to run on natural gas. The law also authorizes ODOT to work with other states on a regional study of the development of compressed natural gas infrastructure for transportation.
In addition, the law authorizes PUCO to undertake several electricity-related initiatives. The commission will periodically review any green pricing programs offered by utilities. It will also undertake a study on how increased energy efficiency, demand response, generation, transmission, and emerging technologies can increase opportunities for consumer choice. In addition, PUCO will review the electricity distribution and transmission infrastructure and evaluate the need for improvements, additions, and upgrades.
S.B. 315 also updates and expands several green-building codes for state-owned buildings. The law requires that cogeneration be considered as a potential energy source as part of the lifecycle cost analysis for state-funded facility projects with a construction cost of $50 million or more. The new law also expands the definition of energy conservation measures to include tri-generation systems (which produce electricity and both heat and cooling), renewable energy systems producing electricity for the building, and the optimization of computer servers, data storage devices, and other information technology infrastructure.
For more information:
Climate Techbook: Cogeneration / Combined Heat and Power (CHP)
Climate Techbook: Natural Gas
Ohio General Assembly: S.B. 315
Ohio.gov: Senate Bill 315 – Improving Regulatory Framework
Bricker & Eckler LLP: Ohio Senate Bill 315: A Summary of Governor Kasich’s Energy Bill
Midwest Energy News: Ohio could pit cogeneration against wind farms
U.S.’s first mandatory, market-based program to reduce greenhouse gas emissions reports 23 percent reduction
The Regional Greenhouse Gas Initiative (RGGI) is undertaking a review of its first compliance period, which ran from 2009 through 2011 and saw successful reductions in greenhouse gas emissions below its initial targets. The power sector of nine Northeast and North Atlantic states reported annual average carbon emissions of 126 million short tons during the three year-period, representing a 23 percent reduction compared to the previous three-year span of 2006 through 2008.
Overall, 206 out of the 211 power plants within RGGI's jurisdiction achieved their compliance objectives. Emission levels in the first compliance period were 33 percent below the program's annual cap of 188 million short tons.
The decline in carbon emissions was achieved without a comparable decline in the total quantity of electricity consumption, which dropped just 2.4 percent during the same timeframe. The reasons for the emission reduction include a greater use of natural gas for electricity generation instead of coal, investment in energy efficiency, and the increased use of renewable energy as part of states' renewable portfolio standards.
RGGI includes nine states of the Northeast and Mid-Atlantic and is the United States' first mandatory, market-based program to reduce carbon emissions through cap and trade. Regulated entities are required to purchase and hold one allowance, or credit, for each short ton of carbon dioxide they emit. The program limits the total amount of emissions by issuing a set number of allowances (the cap). Entities whose emissions exceed their allowances can purchase more from those that emit less (the trade), creating an incentive to reduce emissions for those that can do so cheaply. The cap can be decreased each year to reduce overall emissions.
In addition, RGGI has created many benefits for participating states, generating 16,000 job-years of work and $1.6 billion worth of economic activity over the three years, according to an Analysis Group study. Energy efficiency improvements funded through RGGI allowance auctions will also help customers save $1.3 billion on their electricity, natural gas, and heating bills over the next decade.
The second compliance period extends from 2012 through 2014, with an annual emissions cap of 165 million short tons. Starting in 2015, the cap will be reduced by 2.5 percent each year, for a total reduction of 10 percent from 2009 levels by 2018. But because the program has already outperformed this target, six out of the nine RGGI states are now considering tightening the cap for even further reductions.
For more information:
- The industrial sector directly consumed 27 percent of natural gas in the United States in 2010.
- Newly abundant and low-cost domestic sources provide economic benefits to industry using the fuel for power, heat, and as a feedstock.
- The Energy Information Agency projects total natural gas consumption for industrial heat and power to rise by 6.25 percent between 2012 and 2021 before declining to lower but steady levels through 2035, and it projects natural gas feedstock use to rise by 25 percent between 2012 and 2035.
- Boiler upgrades and replacements can offer measurable reductions in greenhouse gas emissions through efficiency improvements as well as displacing coal with gas.
- Combined heat and power systems offer the potential to efficiently use natural gas while reducing greenhouse gas emissions.
- Many industrial activities are energy- and emissions-intensive, but some uses of natural gas as a feedstock emit very few greenhouse gases.
|Figure 1: Natural Gas Use in the Industrial Sector (Industry Overall)|
|Source: EIA Manufacturing Energy Consumption Survey (MECS), 2010|
Overall, the largest direct use of energy by the industrial sector is for process heating, which is the production of heat directly from fuel sources, electricity, or steam to heat raw material inputs during manufacturing. In 2010 process heating using all fuel sources produced 315.4 million metric tons of C02e, which was 40 percent of the total emissions for the industrial sector. Natural gas is the dominant fuel used to generate heat, and process heating accounts for 42 percent of the natural gas use in the industrial sector (see Figure 1).
Industrial boilers for heat and steam are another significant user of natural gas, and, while some are fueled by coal or other fuel, the dominant fuel source is natural gas. Boilers are commonly used for a variety of purposes by chemical manufactures, food processors, pulp and paper manufactures, and the petroleum and coal derivatives industries (including chemicals, coke, and coal tar). Twenty-two percent of the natural gas used in manufacturing is consumed in boilers. As with process heating, industrial boilers are dependent on natural gas, with 83 percent of boilers running on the fuel (Figure 2).
Often, power generation and process heating can be more efficiently accomplished by coproducing heat and power from a single unit with technology commonly called combined heat and power (CHP). Additional efficiencies and emission reductions are also achieved through the generation of electricity onsite, because it avoids transmission loss. In 2010, 14 percent of natural gas used in manufacturing was consumed by CHP and other power systems. As illustrated in Figure 2, natural gas dominates the fuel used for CHP. Nationwide, the added efficiencies of CHP systems avoid the annual emission of 35 million metric tons of CO2e.
|Figure 2: Direct Consumption of Fuels in the Industrial Sector|
CHP & Other Power
|Source: EIA Manufacturing Energy Consumption Survey (MECS), 2010|
For the chemicals industry, natural gas also serves a unique function, providing a chemical feedstock in the form of methane and liquids found in the natural gas, including ethane, propane, and butane. These liquids, especially ethane, are processed and transformed to become additional intermediate and final products. Chemical companies are particularly heavy users of natural gas as a feedstock and may consume up to two-thirds of their delivered natural gas for this purpose. While U.S. companies are reliant on low-cost natural gas liquids as a feedstock, European competitors use more expensive, oil-based naphtha. In 2010, for example, domestic ethane sold at half the price of imported naphtha in Europe, and, consequently, U.S. chemical manufactures have reaped a competitive advantage in international markets for intermediate and final goods. The emissions implications of using natural gas as a feedstock are very different from its other uses because feedstock use transforms hydrocarbon molecules into other products, rather than combusting them. Consequently, when natural gas is used as a feedstock, very few greenhouse gases are emitted.
Potential for Expanded Use in the Industrial Sector
Increased availability and low prices of natural gas have significant implications for domestic manufacturing, which has historically been concerned about supply availability and price volatility. Recently, abundant supply and low prices have led to an increase in domestic manufacturing, creating new jobs and economic value. Numerous companies have cited natural gas supply and price in announcing plans to open new facilities in the chemicals, plastics, steel, and other industries in the United States. In the past few years, the number of firms disclosing the positive impact of new gas resources for facility power generation and feedstock use to the Securities and Exchange Commission has increased substantially. In 2010, exports of basic chemicals and plastics increased 28 percent from the previous year, yielding a trade surplus of $16.4 billion. If the expectation that low prices will continue is correct, these economic benefits would be significant over the long term. A study by the American Chemistry Council, for instance, estimates that a 25 percent increase in ethane supplies would yield a $32.8 billion increase in U.S. chemical production. Industry, however, needs more than just abundance and low prices to maintain use of natural gas. Price stability is necessary to encourage long-term investments in industry, and increased natural gas supplies also have the potential to stabilize prices.
|Figure 3: CHP versus Conventional Production|
|Source: EIA Manufacturing Energy Consumption Survey (MECS), 2010|
Potential for Industrial Sector Emission Reductions
If supply remains robust and prices low and stable, the U.S. industrial sector is likely to reap substantial economic benefits from the increased availability of low-cost natural gas. Even as the sector expands, there are opportunities to reduce its emission intensity. Improving the efficiency of industrial boilers is one such opportunity. Boilers tend to have a low turnover rate, and very often older units are less efficient than newer ones. The pre-1985 fleet of boilers has an efficiency rate of between 65 percent and 70 percent; while new boilers have efficiency rates of between 77 percent and 82 percent and new, super–high-efficiency units can reach efficiency rates of up to 95 percent.
A Massachusetts Institute of Technology (MIT) analysis found that replacing older natural gas boilers with high-efficiency or super-high-efficiency units would decrease CO2 emissions by 4,500 to 9,000 tons or more per year per boiler. The analysis also found a strong economic incentive to make these replacements, highlighting annualized monetary savings of 20 percent (given certain assumptions, including 2010 natural gas prices) with a payback period of 1.8 to 3.6 years for the new equipment.
|Figure 4: Projected Natural Gas Consumption (2009-2035) in…|
Projected Total Industrial Consumption of Natural Gas for Heat and Power
Projected Energy Consumption of Natural Gas for Heat and Power per Dollar of Shipments
Projected Total Industrial Consumption of Natural Gas Liquids Feedstock
Projected Energy Consumption Natural Gas Liquids Feedstock per Dollar of Shipments
Projected Total Industrial CHP Generation for All Fuels through 2035
|Source: EIA AEO 2012 Early Release, 2012|
While natural gas is the most commonly used fuel source for industrial boilers, 17 percent of boilers use coal or other fuels, as shown in Figure 2. Because of the air pollutants from these coal-fired boilers, these boilers are now subject to the Environmental Protection Agency’s (EPA) 2012 Mercury and Air Toxics Standards. MIT conducted a separate analysis to determine the results of replacing the affected coal boilers with efficient or super-high-efficiency natural gas boilers (these natural gas boilers are not regulated under the new EPA rule). This analysis found that replacement with natural gas boilers would reduce annual CO2 emissions by about 52,000 to 72,000 tons per year per boiler.
Increasing the use of CHP also has potential to reduce emissions. A 2008 Oak Ridge National Laboratory (ORNL) study analyzed the total U.S. energy system and calculated that increasing CHP’s share of total U.S. electricity generation capacity from 9 percent in 2008 to 20 percent by 2030 would lower U.S. GHG emissions by 600 million metric tons of CO2 compared to business as usual. Another study, by McKinsey & Company in 2009, sought to estimate the potential for expanding CHP by 2020 through net present value-positive investments. McKinsey estimated that the potential exists in the United States for an additional 50.4 GW of CHP capacity by 2020, which would avoid an estimated 100 million metric tons of CO2 emissions per year compared to business as usual. McKinsey found that 70 percent of the potential cost-effective incremental CHP capacity was through large-scale industrial cogeneration systems greater than 50MW.
While CHP results in few GHG emissions, barriers currently limit its application. Utilities often cite safety concerns as a barrier to deployment, particularly a fear of miscommunication between CHP operators and utilities in the event of an emergency, which utilities say could lead to dangerous situations where line workers are not certain whether lines are energized or not. Utilities may also have concerns about liability and risk associated with the interconnection between CHP operations and the grid, as utility employees may be affected by safety and technical decisions of CHP operators made independent of utilities. Like issues of safety, many utilities are concerned about the need to provide backup power to industrial facilities in case CHP systems are taken offline or are otherwise unavailable. For utilities, the ability to provide backup power to these facilities requires investments in capacity, and to pay for this capacity, utilities often charge higher, discriminatory rates and interconnection fees to CHP operators to compensate for these necessary investments.
In addition to these concerns, regulatory and corporate policies have inhibited the growth of CHP capacity. Power sector regulation in many states leads many utilities to view CHP as unprofitable and, accordingly, discourages its use. However, some innovative policy approaches can overcome this problem. One approach is decoupling, which eliminates the connection between utility sales volume and profitability. By doing so, decoupling makes CHP measures profitable to utilities, and, therefore, more likely to gain their support. Another potential policy solution is the implementation of lost-revenue adjustment policy, which compensates utilities for revenues lost because of efficiency measures. It allows utilities to collect a charge from customers to account for efficiency-related revenue losses. Lost-revenue adjustment policies also have the potential to encourage CHP. Other policy options include state incentives designed to encourage the use of CHP. State-level policies include standardizing interconnection guidelines, tax incentives, and inclusion of CHP as a compliance mechanism for clean energy standards. Some states have enacted these policies, but, as with many state-led policies, there is a diversity of approaches to, and success with, implementation.
Rooftop solar received a major boost in California with a new ruling from state regulators on May 24. The California Public Utilities Commission (CPUC) voted unanimously to reinterpret a cap on its net-metering program, more than doubling the potential amount of rooftop solar in the state.
Net metering provides a financial incentive for small businesses and homeowners to install energy generation on-site, usually solar photovoltaic panels. Any electricity in excess of customer usage is sold back to the utility at the retail rate – higher than the wholesale rate earned by traditional generators. This is credited to the customer's bill to offset consumption from the grid when the customer's electricity demand exceeds their own generation.
However, the program was approaching a cap that the utilities were allowed to set. This limited each utility’s available net-metering capacity to five percent of its "aggregated customer peak demand." Utility companies had previously interpreted this to mean their highest overall demand on one particular day. Using this definition, Pacific Gas & Electric (PG&E), the state’s largest electric utility, was expected to reach its limit in 2013, after which it would no longer accept participants. The new decision expands the cap by defining "aggregated customer peak demand" as the sum of the highest electricity demand of each utility customer. This more than doubles the potential size of the program from the current 1.2 gigawatts (GW) to 4 GW, according to Environment California. This is about six percent of California’s net summer capacity.
Utilities oppose the expansion, arguing that by paying less or no money on their bills, net-metering participants are passing on their fair share of system costs onto other customers. These costs include payments for transmission grid upgrades and maintenance, low-income customer assistance programs, and municipal electricity systems. PG&E has 65,000 net-metering customers out of a total of 5.1 million.
Clean energy supporters and the solar industry say that the program has been critical in driving development of the industry. The net-metering program has already brought in over one billion dollars of investment to California. In a statement, CPUC President Michael Peevey said, "Today’s decision ensures that the solar industry will continue to thrive for years to come, and we are fully committed to developing a long-term solution that secures the future of the industry in California."
The CPUC will commission a study analyzing the costs and benefits of solar net metering, including its impact on nonparticipants. Unless new policies are adopted, the net-metering program will be closed to new customers on January 1, 2015.
California leads the U.S. in installed solar energy capacity, whether it’s distributed rooftop installations or utility-scale solar farms. Indeed, PG&E's net-metering customers alone represent one-third of U.S. total rooftop solar capacity. In 2011, California installed 542.2 megawatts of solar photovoltaic panels, the highest amount in the nation and more than doubling its existing capacity in 2010. Much of this is due to the state’s plethora of policies, rebates, and incentives at all levels of government, from utility loans to city-level rebates to the $3.2 billion state-wide California Solar Initiative. In addition, the state is home to over 1,000 companies in the solar industry, employing more than 25,000 people.
For more information:
CPUC Press Release: CPUC takes action to support solar by clarifying net-metering cap
Wall Street Journal: California Expands Rooftop Solar-Power Program
Solar Energy Industries Association: California Solar Fact Sheet (pdf)
Clean Technica: 2011 U.S. Solar Market Report – Top 7 Findings & Charts
June 6, 2012
Contact: Rebecca Matulka, 703-516-4146, firstname.lastname@example.org
Report Highlights Climate Change Risks to Key Gulf Coast Industries
Recommends Steps to Reduce Impacts on Region’s Energy and Fishing Sectors
Climate change is already having major impacts on the Gulf Coast region and action is needed to protect its vital industries from the likely impacts of continued warming, according to a new report from the Center for Climate and Energy Solutions (C2ES).
The report, Impacts and Adaptation Options in the Gulf Coast, examines the risks that climate change poses to the region’s energy and fishing industries, and to its residents and local governments. It concludes that climate impacts are already being felt across these sectors, and outlines measures that can be taken to adapt to the growing risks, reducing the region’s vulnerability and the costs associated with future impacts.
The convergence of several geographical characteristics—an unusually flat terrain both offshore and inland, ongoing land subsidence, dwindling wetlands, and fewer barrier islands than along other coasts—make the Gulf Coast region especially vulnerable to climate change. Among the impacts and risks cited in the report:
- Over the past century, both air and water temperatures have been on the rise across the region;
- Rising ocean temperatures heighten hurricane intensity, and recent years have seen a number of large, damaging hurricanes;
- In some Gulf Coast locations, local sea level is increasing at over ten times the global rate, increasing the risk of severe flooding; and
- Saltwater intrusion from rising sea levels damages wetlands, an important line of coastal defense against storm surge and spawning grounds for commercially valuable fish and shellfish.
“Nowhere else in the U.S. do we see the same convergence of critical energy infrastructure and high vulnerability to climate change,” said C2ES President Eileen Claussen. “These risks are not borne by the Gulf Coast alone. A major energy supply disruption, for instance, would be felt nationwide. We must respond on two fronts: We have to work harder to reduce the greenhouse gas emissions causing climate change. And we must take steps, in the Gulf Coast and elsewhere, to prepare for the impacts that can’t be avoided.”
The report’s lead author is Hal Needham, a researcher at Louisiana State University’s Southern Climate Impacts Planning Program (SCIPP) and an expert on hurricane storm surges in the Gulf Coast. The co-authors are David Brown, an assistant professor in LSU’s Department of Geography and Anthropology, and Lynne Carter, associate director of SCIPP.
In their analysis of the Gulf Coast’s energy industry, which comprises about 90 percent of the region’s industrial assets, the authors found significant risks from hurricanes, sea level rise, rising temperatures and drought. The report noted the considerable damage the energy industry sustained from recent hurricanes in 2004, 2005 and 2008. Thirty percent of the nation’s refineries are located in Texas and Louisiana, and Louisiana Offshore Oil Port in Port Fourchon is the country’s only deep-water oil import facility. At its current elevation, Louisiana Highway 1, the only access to the port, is projected to be flooded 300 days a year by 2050.
For the region’s other major industry, fishing, the report details major infrastructure risks, especially relating to coastal docking and fish processing. Fish and shellfish populations are also vulnerable to climate impacts, with a combination of warmer water, ocean acidification, and excessive runoff from the Mississippi River combining to increase the risk of large-scale changes in the Gulf ecosystem.
The authors emphasize that advance planning can reduce the region’s vulnerability and the costs incurred from future climate impacts.
For the energy sector, adaptation strategies include learning from recent hurricanes to more rigorously assess vulnerabilities; strengthening design standards for drilling platforms and other infrastructure; and undertaking projects such as the planned raising of sections of Highway 1 to Port Fourchon. To reduce vulnerability in the fishing industry, options include strengthening docking facilities and other infrastructure subject to storm surges, and limiting fertilizer use upstream on the Mississippi River to reduce the incidence of hypoxia (oxygen-starved waters) in the Gulf.
“Climate change is already taking a toll on the Gulf Coast, but if we act now to become more resilient, we can reduce the risks, save billions in future costs, and preserve a way of life,” said Needham. “The Gulf Coast is one of the first regions to feel the impacts of climate change. It only makes sense to be a first mover on climate adaptation as well.”
The Center for Climate and Energy Solutions (C2ES) is an independent non-profit, non-partisan organization promoting strong policy and action to address the twin challenges of energy and climate change. Launched in November 2011, C2ES is the successor to the Pew Center on Global Climate Change, long recognized in the United States and abroad as an influential and pragmatic voice on climate issues. C2ES is led by Eileen Claussen, who previously led the Pew Center and is the former U.S. Assistant Secretary of State for Oceans and International Environmental and Scientific Affairs.
Impacts and Adaptation Options in the Gulf Coast
by Hal Needman, David Brown, and Lynne Carter
The central and western U.S. Gulf Coast is increasingly vulnerable to a range of potential hazards associated with climate change. Hurricanes are high-profile hazards that threaten this region with strong winds, heavy rain, storm surge and high waves. Sea-level rise is a longer-term hazard that threatens to exacerbate storm surges, and increases the rate of coastal erosion and wetland loss. Loss of wetlands threatens to damage the fragile coastal ecosystem and accelerates the rate of coastal erosion.
These hazards threaten to inflict economic and ecological losses in this region, as well as loss of life during destructive hurricanes. In addition, they impact vital economic sectors, such as the energy and fishing industries, which are foundational to the local and regional economy. Impacts to these sectors are also realized on a national scale; Gulf oil and gas is used throughout the country to heat homes, power cars, and generate a variety of products, such as rubber and plastics, while seafood from the region is shipped to restaurants across the country.
This report reviews observed and projected changes for each of these hazards, as well as potential impacts and adaptation options. Information about the scale and relative importance of the energy and fishing industries is also provided, as well as insight into potential vulnerabilities of these industries to climate change. This report also identifies some adaptation options for those industries.