Legislation and Regulations
Introduction
Because baseline projections developed by EIA are required to be policy-neutral,
the projections in AEO2009 are based on Federal and State laws and regulations
as of November 2008 [1]. The potential impacts of pending or proposed legislation,
regulations, and standards—or of sections of legislation that have been
enacted but that require implementing regulations or appropriation of funds
that are not provided or specified in the legislation itself—are not reflected
in the projections. Throughout 2008, however, at the request of the Administration
and Congress, EIA has regularly examined the potential implications of
proposed legislation in Service Reports (see box on right).
Examples of Federal and State legislation that has been enacted over the
past few years and is incorporated in AEO2009 include:
- The tax provisions of EIEA2008, signed into law on October 3, 2008, as
part of Public Law 110-343, the Emergency Economic Stabilization Act of
2008 (see details below)
- The biofuel provisions of the Food, Conservation, and Energy Act of 2008
(Public Law 110-234) [2], which reduce the existing ethanol excise tax
credit in the first year after U.S. ethanol production and imports exceed
7.5 billion gallons and add an income tax credit for the production of
cellulosic biofuels
- The provisions of EISA2007 (Public Law 110-140) including: a renewable
fuel standard (RFS) requiring the use of 36 billion gallons of ethanol
by 2022; an attribute-based minimum CAFE standard for cars and trucks of
35 miles per gallon (mpg) by 2020; a program of CAFE credit trading and
transfer; various appliance efficiency standards; a lighting efficiency
standard starting in 2012; and a number of other provisions related to
industrial waste heat or natural gas efficiency, energy use in Federal
buildings, weatherization assistance, and manufactured housing
- Those provisions of the Energy Policy Act of 2005 (EPACT2005), Public Law
109-58, that remain in effect and have not been superseded by EISA2007,
including: mandatory energy conservation standards; numerous tax credits
for businesses and individuals; elimination of the oxygen content requirement
for Federal reformulated gasoline (RFG); extended royalty relief for offshore
oil and natural gas producers; authorization for DOE to issue loan guarantees
for new or improved technology projects that avoid, reduce, or sequester
GHGs; and a PTC for new nuclear facilities
- Public Law 108-324, the Military Construction Appropriations Act of 2005,
which contains provisions to encourage construction of an Alaska natural
gas pipeline, including Federal loan guarantees during construction
- State RPS programs, representing laws and regulations of 27 States and
the District of Columbia that require renewable electricity generation.
Examples of recent Federal and State regulations as well as earlier provisions
that have been affected by court decisions that are considered in AEO2009 include the following:
- Decisions by the D.C. Circuit Court of the U.S. Court of Appeals on February
8, 2008, to vacate and remand the Clean Air Mercury Rule (CAMR) and on
July 11, 2008, to vacate and remand the Clean Air Interstate Rule (CAIR)
[3]
- Release by the California Air Resources Board (CARB) in October 2008 of
updated regulations for RFG that went into effect on August 29, 2008, allowing
a 10-percent ethanol blend, by volume, in gasoline.
More detailed information on recent Federal and State legislative and regulatory
developments is provided below.
Energy Improvement and Extension Act of 2008: Summary of Provisions
The Emergency Economic Stabilization Act of 2008 (Public Law 110-343) [4],
which was signed into law on October 3, 2008, incorporates EIEA2008 in Division
B. Provisions in EIEA2008 that require funding appropriations to be implemented,
whose impact is highly uncertain or that require further specification
by Federal agencies or Congress, are not included in AEO2009. Moreover, AEO2009 does not include any provision that addresses a level of detail
beyond that modeled in NEMS. AEO2009 addresses those provisions in EIEA2008
that establish specific tax credits and incentives, including the following:
- Extension of the residential and business tax credits for renewable energy
as well as for the purchase and production of certain energy-efficient
appliances, many of which were originally enacted in EPACT2005
- Removal of the cap on the tax credit for purchases of residential solar
photovoltaic (PV) installations and an increase in the tax credit for residential
ground-source heat pumps
- Addition of a business investment tax credit (ITC) for combined heat and
power (CHP), small wind systems, and commercial ground-source heat pumps
- Provision of a tax credit for the purchase of new, qualified, plug-in electric
drive motor vehicles
- Extension of the income and excise tax credits for biodiesel and renewable
diesel to the end of 2009 and an increase in the amount of the tax credit
for biodiesel and renewable diesel produced from recycled feedstock
- Provision of tax credits for the production of liquid petroleum gas (LPG),
LNG, compressed natural gas (CNG), and aviation fuels from biomass
- Provision of an additional tax credit for the elimination of CO2 that would
otherwise be emitted into the atmosphere in enhanced oil recovery and non-enhanced
oil recovery operations
- Extension and modification of key renewable energy tax provisions that
were scheduled to expire at the end of 2008, including production tax credits
(PTCs) for wind, geothermal, landfill gas, and certain biomass and hydroelectric
facilities
- Expansion of the PTC-eligible technologies to include plants that use energy
from offshore, tidal, or river currents (in-stream turbines), ocean waves,
or ocean thermal gradients.
The following discussion provides a summary of the EIEA2008 provisions
included in AEO2009 and some of the provisions that could be included if
more complete information were available about their funding and implementation.
This discussion is not a complete summary of all the sections of EIEA2008.
End-Use Demand
Residential and Commercial Buildings
EIEA2008 reinstates and extends tax credits for renewable energy and for
the purchase and production of certain energy-efficient appliances, many
of which were originally enacted in EPACT2005. Some of the tax credits
are extended to 2016. In addition, the $2,000 cap for residential PV purchases
is removed, and the cap for ground-source heat pumps is raised from $300
to $2,000. The legislation also adds business ITCs for CHP, small wind
systems, and commercial ground-source heat pumps.
Residential Tax Credits
EIEA2008 Titles I and III include various extensions, modifications, and
additions to the tax code that have the potential to affect future energy
demand in the residential sector. Sections 103 through 106 of Title I reinstate
the tax credits that were implemented under EPACT2005 for efficient water
heaters, boilers, furnaces, heat pumps, air conditioners, and building
shell equipment, such as windows, doors, weather stripping, and insulation.
The amount of the credit varies by appliance type and ranges from $150
to $300. The maximum credit for ground-source heat pumps, which was $300
under EPACT2005, is $2,000 under EIEA2008. For solar installations, which
can receive a 30-percent tax credit under both EPACT2005 and EIEA2008,
the $2,000 cap has been removed. With the cost and unit size of residential
PV assumed in AEO2009, the credit can now reach nearly $10,000 per unit.
The tax credit for small wind generators is also extended through 2016
in EIEA2008; however, penetration of residential wind installations over
the next decade is projected to be negligible.
Sections 302, 304, and 305 of EIEA2008 Title III also contain provisions
that can directly or indirectly affect future residential energy demand.
Section 302 adds a provision to allow a tax credit for the use of biomass
fuel, which can include wood, wood pellets, and crops. In NEMS, the credit
is represented as a reduction in the cost of wood stoves used as the primary
space heating system. Section 304 extends the $2,000 tax credit for new
homes that are 50 percent more efficient than specified in the International
Energy Conservation Code through 2009. Section 305 extends the PTC for
refrigerators, dishwashers, and clothes washing machines that are a certain
percentage more efficient than the current Federal standard. The duration
and value of the credit vary by appliance and the level of efficiency achieved.
For AE02009, it is assumed that the full amount of the credit is realized
by consumers in the form of reduced purchase costs.
Commercial Tax Credits
Sections 103, 104, and 105 of EIEA2008 Title I extend or expand tax credits
to businesses for investment in energy efficiency and renewable energy
properties. Section 103 extends the EPACT2005 business ITCs (30 percent
for solar energy systems and fuel cells, 10 percent for microturbines)
through 2016; expands the ITC to include a 10-percent credit for CHP systems
through 2016; and increases the credit limit for fuel cells from $500 to
$1,500 per half kilowatt of capacity. Section 104 provides a 30-percent
business ITC through 2016 for wind turbines with an electrical capacity
of 100 kilowatts or less, capped at $4,000. Section 105 adds a 10-percent
business ITC for ground-source heat pumps through 2016. In the AEO2009 reference case, relative to a case without the tax credits, these provisions
result in a 3.2-percent increase in electrical capacity in the commercial
sector by 2016.
Section 303 of EIEA2008 Title III extends the EPACT2005 tax deduction allowed
for expenditures on energy-efficient commercial building property through
2013. This provision is not reflected in AEO2009, because NEMS does not
include economic analysis at the building level.
Industrial Sector
Under EIEA2008 Title I, “Energy Production Incentives,” Section 103 provides
an ITC for qualifying CHP systems placed in service before January 1, 2017.
Systems with up to 15 megawatts of electrical capacity qualify for an ITC
up to 10 percent of the installed cost. For systems between 15 and 50 megawatts,
the percentage tax credit declines linearly with the capacity, from 10
percent to 3 percent. To qualify, systems must exceed 60-percent fuel efficiency,
with a minimum of 20 percent each for useful thermal and electrical energy
produced. The provision was modeled in AEO2009 by adjusting the assumed
capital cost of industrial CHP systems to reflect the applicable credit.
Section 108 extends an existing PTC, originally created under the American
Jobs Creation Act of 2004 for new “refined coal” facilities producing steam
coal, to those that produce metallurgical coal for the steel industry.
The credit applies to coal processed with liquefied coal waste sludge and
“steel industry coal” (defined as coal used for feedstock in coke manufacture).
The production credit for steel industry coal is $2 per barrel of oil equivalent
actually produced (equivalent to 34 cents per million Btu or $8.55 per
short ton) over the first 10 years of operation for plants placed in service
in 2008 and 2009. Because the AEO2009 NEMS does not include the level of
detail addressed by this tax credit, its incremental effect is not reflected
in AEO2009. To the extent that the credit is passed on from coal suppliers
as a reduction in the price of metallurgical coal, the provision would
tend to reduce steel production costs and provide an incentive for domestic
manufacture of coke.
Transportation Sector
EIEA2008 Title II, Section 205, provides a tax credit for the purchase
of new, qualified plug-in electric drive motor vehicles. According to the
legislation, a qualified plug-in electric drive motor vehicle must draw
propulsion from a traction battery with at least 4 kilowatthours of capacity,
use an off-board source of energy to recharge the battery, and, depending
on the gross vehicle weight rating (GVWR), meet the U.S. Environmental
Protection Agency (EPA) Tier II vehicle emission standards or equivalent
California low-emission vehicle emission standards.
The tax credit for the purchase of a PHEV is $2,500 plus $417 per kilowatthour
of traction battery capacity in excess of the minimum required 4 kilowatthours,
up to a total of $7,500 for a PHEV with a GVWR of 10,000 pounds or less.
The limit is raised to $10,000 for any new eligible PHEV with a GVWR between
10,000 and 14,000 pounds, $12,500 for a PHEV between 14,000 and 26,000
pounds GVWR, and $15,000 for any eligible PHEV with a GVWR greater than
26,000 pounds.
The legislation also includes a phaseout period for the tax credit, beginning
two calendar quarters after the first quarter in which the cumulative number
of qualified plug-in electric vehicles sold in total by all manufacturers
reaches 250,000. The credit will be reduced by 50 percent in the first
two calendar quarters of the phaseout period and by another 25 percent
in the third and fourth calendar quarters. Thereafter, the credit will
be eliminated. Regardless of calendar quarter or whether 250,000 vehicles
are sold, the credit will be phased out after December 31, 2014. The tax
credits for PHEVs are included in AEO2009.
Liquids and Natural Gas
EIEA2008 includes tax provisions that address petroleum liquids and natural
gas. In Title II, “Transportation and Domestic Fuel Security Provisions,
Credits for Biodiesel and Renewable Diesel,” Section 202 extends income
and excise tax credits for biodiesel and renewable diesel to the end of
2009. The legislation also raises the credit from 50 cents per gallon to
$1 per gallon for biodiesel and renewable diesel from recycled feedstock.
It also removes the term “thermal depolymerization” from the definition
of renewable diesel and replaces it with “or other equivalent standard,”
allowing biomass-to-liquids (BTL) producers to obtain the $1 per gallon
income tax credit. The legislation further specifies that the term “renewable
diesel” shall include fuel derived from biomass that meets Defense Department
specifications for military jet fuel or American Society for Testing and
Materials specifications for aviation turbine fuel. These provisions are
included in AEO2009.
Section 204 extends the excise tax credit for alternative fuels under Section
6426 of the Internal Revenue Code through 2009. Beginning on October 1,
2009, qualified fuel derived from coal through gasification and liquefaction
processes must be produced at a facility that separates and sequesters
at least 50 percent of its CO2 emissions, increasing to 75 percent beginning
in 2010. Section 204 also provides credits applicable to biomass gas versions
of LPG, LNG, CNG, and aviation fuels. This provision is also included in AEO2009.
Coal
EIEA2008 Title I, Subtitle B, “Carbon Mitigation and Coal Provisions,”
modifies the tax credits available to coal consumers who sequester CO2.
In Section 111, an additional $1.25 billion is allocated to advanced coal-fired
plants that separate and sequester a minimum of 65 percent of the plant’s
CO2 emissions, bringing the aggregate ITC available for advanced coal projects
to $2.55 billion. For this additional ITC, the allowable credit is equivalent
to 30 percent of the project’s qualified investment cost. Qualified investments
include any expenses for property that is part of the project. For example,
expenses for equipment for coal handling and gas separation would be qualifying
investments if they were required for the project.
Section 112 provides an additional $250 million in ITCs for carbon sequestration
equipment at qualified gasification projects, including plants producing
transportation-grade liquid fuels. Eligible feedstocks for the projects
include coal, petroleum residues, and biomass. To qualify for the ITC,
a gasification facility must capture and sequester a minimum of 75 percent
of its potential CO2 emissions.
Section 115 of Subtitle B provides an additional tax credit for sequestration
of CO2 that would otherwise be emitted into the atmosphere from industrial
sources. Tax credits of $10 per ton for CO2 used in enhanced oil recovery
and $20 per ton for other CO2 sequestered are available. The Section 115
tax credit is limited to a total of 75 million metric tons of CO2. In the AEO2009 reference case, Sections 111, 112, and 115 are modeled together,
resulting in 1 gigawatt of advanced coal-fired capacity with CCS by 2017.
Section 113 of Subtitle B extends the phaseout of payments by coal producers
to the Black Lung Disability Trust Fund from 2013 to 2018. This provision
also is modeled in the AEO2009 reference case.
Other coal-related provisions of Subtitle B are not included in AEO2009,
either because their effects on energy markets are minimal or nonexistent,
or because they cannot be modeled directly in NEMS. They include: a provision
that refunds payments to the Black Lung Disability Trust Fund for U.S.
coal exports (Section 114); classification of income derived from industrial-source
CO2 by publicly traded partnerships as qualifying income (Section 116);
a request for a National Academy of Sciences review of GHG provisions in
the IRS Tax Code (Section 117); and a tax credit for alternative liquid
fuels that is valid only through the end of 2009 (Section 204).
Renewable Energy
EIEA2008 also contains several provisions that extend and modify key tax
provisions for renewable energy that were scheduled to expire at the end
of 2008. Section 101 extends the PTC for wind, geothermal, landfill gas,
and certain biomass and hydroelectric facilities. Wind facilities that
enter service before January 1, 2010, are eligible for a tax credit of
2 cents per kilowatthour, adjusted for inflation, on all generation sold
for the first 10 years of plant operation. Other eligible plants will receive
the tax credit if they are on line by December 31, 2010 (but biomass plants
that do not use “closed-loop” fuels [5] will receive a credit of 1 cent
per kilowatthour).
Section 102 expands the suite of PTC-eligible technologies to include plants
that use energy from offshore, tidal, or river currents (in-stream turbines),
ocean waves, or ocean thermal gradients. Projects must have at least 150
kilowatts of capacity and must be on line by December 31, 2011. The PTC
extension is included in AEO2009 for all eligible technologies, with the
exception of marine technologies, which are not represented in NEMS.
Section 103 extends the 30-percent ITC for business-owned solar facilities
to plants entering service through December 31, 2016. The tax credit is
valued at 30 percent of the initial investment cost for solar thermal and
PV generating facilities that are owned by tax-paying businesses (residential
owners can take advantage of tax credits discussed below; other forms of
government assistance may be available to tax-exempt owners). Starting
in 2017, eligible facilities will receive only a 10-percent ITC, which
is not scheduled to expire. The extension through 2016 and the permanent
10-percent ITC are represented in AEO2009.
Section 107 authorizes continuation of the Clean and Renewable Energy Bonds
(CREB) program at a level of $800 million. CREBs are issued by tax-exempt
project owners (municipals and cooperatives) to raise capital for the construction
of renewable energy plants. Interest on the bonds is paid by the Federal
Government in the form of tax credits to the bond holders, thus providing
the bond issuer with interest-free financing for qualified projects. Because
NEMS assumes that all new renewable generation capacity will come from
independent power producers, this provision, which targets public utilities,
is not included in AEO2009.
Federal Fuels Taxes and Tax Credits
This section provides a review and update of the handling of Federal fuels
taxes and tax credits, focusing primarily on areas for which regulations
have changed or the handling of taxes or credits has been updated in AEO2009.
Excise Taxes on Highway Fuel
The handling of Federal highway fuel taxes remains unchanged from AEO2008.
Consistent with current law, gasoline is assumed to be taxed at 18.4 cents
per gallon, diesel fuel at 24.4 cents per gallon, and jet fuel at 4.3 cents
per gallon. State fuel taxes, calculated as a volume-weighted average for
diesel, gasoline, and jet fuels sold, were updated as of July 2008 [6].
Unlike Federal highway taxes, which remain at today’s nominal levels throughout
the AEO2009 projection, State fuel taxes are assumed to remain fixed in
real terms.
Biofuels Tax Credits
The only change in the handling of Federal fuels taxes and credits has
been in those that pertain to biofuels. Section 15331 of the Food, Conservation,
and Energy Act of 2008 reduces the existing ethanol excise tax credit of
$0.51 per gallon to $0.45 per gallon in the first year after the year in
which U.S. ethanol production and imports exceed 7.5 billion gallons. In
the AEO2009 projections, U.S. ethanol production and imports exceed 7.5
billion gallons in 2008, and the tax credit is reduced in 2009. The excise
tax credit for ethanol is scheduled to expire at the end of 2010. In addition,
Section 15321 of the Act adds an income tax credit for the production of
cellulosic biofuels. The cellulosic biofuels represented in NEMS are cellulosic
ethanol, BTL diesel, and BTL naphtha. The tax credit is $1.01 per gallon,
but for cellulosic ethanol it is reduced by the amount of the excise tax
credit available for ethanol blends (assumed to be $0.45 per gallon). The
credit will be applied to fuel produced after December 31, 2008, and before
January 1, 2013.
In EIEA2008, the excise tax credit of $1.00 per gallon for biodiesel, which
previously was set to expire at the end of 2008, was extended through December
31, 2009. In addition, the excise tax credit of $0.50 per gallon for biodiesel
made from recycled vegetable oils or animal fat is increased to $1.00 per
gallon. A representation of renewable diesel—a diesel-like hydrocarbon
produced by reaction of vegetable oil or animal fat with hydrogen, also
known as “non-ester renewable diesel”—has been added to NEMS for AEO2009.
Ethanol Import Tariff
Currently, two duties are imposed on imported ethanol. The first is an ad valorem tariff of 2.5 percent. The second, which is a tariff of $0.54
per gallon after the application of the ad valorem tariff, allows for duty-free
imports from designated Central American and Caribbean countries up to
a limit of 7 percent of domestic production in the preceding year. The
$0.54 per gallon tariff, previously set to expire on January 1, 2009, is
extended to January 1, 2011, in Section 15333 of the Food, Conservation,
and Energy Act of 2008. In AEO2009, the second tariff is assumed to expire
on January 1, 2011.
New NHTSA CAFE Standards
EISA2007 requires the National Highway Traffic Safety Administration (NHTSA)
to raise the CAFE standards for passenger cars and light trucks to ensure
that the average tested fuel economy of the combined fleet of all new passenger
cars and light trucks sold in the United States in model year (MY) 2020
equals or exceeds 35 mpg, 34 percent above the current fleet average of
26.4 mpg [7]. Pursuant to this legislation, NHTSA recently proposed revised
CAFE standards that substantially increase the minimum fuel economy requirements
for passenger cars and light trucks for MY 2011 through MY 2015 [8].
The new CAFE proposal builds on NHTSA’s 2006 decision to use an attribute-based
methodology to determine a vehicle’s minimum fuel economy standard based
on vehicle footprint [9]. The attribute-based CAFE standard uses a mathematical
function that provides a unique fuel economy target for each vehicle footprint
and is the same across manufacturers. Fuel economy targets are revised
upward in subsequent model years to ensure improvement over time (Figures
4 and 5). Separate continuous mathematical functions are established for
passenger cars and light trucks, reflecting their different design capabilities,
and their combined fuel economy levels are required to reach 35 mpg by
2020.
Individual manufacturers will be required to comply with unique fuel economy
levels for their car and light truck fleets, based on the distribution
of their vehicle production by footprint in each model year. Individual
manufacturers face different required CAFE levels only to the extent that
their production distributions differ. NHTSA has estimated the impact of
the new CAFE standard on the fuel economy of new LDVs and has projected
that the proposed standards represent a 4.5-percent average annual increase
in fuel economy between MY 2010 and MY 2015 (Table 1) [10]. Because the
exact sales mix of different vehicle classes for a given manufacturer cannot
be known until after the model year, NHTSA projects industry-wide average
fuel economies for passenger cars and light trucks based on the manufacturers’
production plans.
From a fuel economy average of 31.6 mpg in MY 2015, the average annual
increase from MY 2015 to MY 2020 would need to be only 2 percent to reach
the EISA2007 mandate of 35 mpg by 2020. Thus, NHTSA’s latest proposal is
heavily front-loaded, in that it requires greater gains in the first 5-year
period than in the second.
Because AEO2009 uses NHTSA’s proposed CAFE standards to represent the implementation
path for the fuel economy standard required by EISA2007, the average fuel
economy for LDVs in the early years of the projection is higher than projected
in AEO2008 (Figure 6). In the AEO2009 reference case, the combined fuel
economy of new LDVs from MY 2011 through MY 2015 slightly exceeds NHTSA’s
estimated values, because AEO2009 allows shifting of sales between cars
and light trucks and among various size classes, whereas NHTSA’s estimates
are based on manufacturers’ production plans.
NHTSA’s proposal also seeks to provide added flexibility for manufacturers
to meet the new CAFE standards by: (1) allowing trading of credits between
manufacturers who exceed their standards and those who do not; (2) allowing
credit transfers between different vehicle classes for a single manufacturer;
(3) increasing from 3 to 5 the number of years during which a manufacturer
can “carry forward” credits earned from exceeding the CAFE standards in
earlier model years, while leaving in place the 3-year limit for manufacturers
to “carry back” credits earned in later years to meet shortfalls from previous
model years; and (4) extending through 2014 the ability of manufacturers
to earn a maximum 1.2 mpg of CAFE credit by producing alternative-fuel
vehicles, then phasing out the “carry-back” credits between 2015 and 2019.
NHTSA’s flexibility provisions do not, however, allow manufacturers to
miss their annual targets grossly and then make them up by using any or
all of the four provisions listed above. NHTSA retains a required minimum
(92 percent of the applicable CAFE standard). Before any credit can be
applied by a manufacturer, its fleet of LDVs for the model year must meet
an average fuel economy standard—either 27.5 mpg or 92 percent of the CAFE
for the industry-wide combined fleet of domestic and non-domestic passenger
cars for that model year, whichever is higher. It is important to note that
NHTSA’s proposed CAFE standards are subject to change in future rulemakings.
Regulations Related to the Outer Continental Shelf Moratoria and Implications
of Not Renewing the Moratoria
From 1982 through 2008, Congress annually enacted appropriations riders
prohibiting the Minerals Management Service (MMS) of the U.S. Department
of the Interior from conducting activities related to leasing, exploration,
and production of oil and natural gas on much of the Federal OCS [11].
Further, a separate executive ban (originally put in place in 1990 by President
George H.W. Bush and later extended by President William J. Clinton through
2012) also prohibited leasing on the OCS, with the exception of the Western
Gulf of Mexico, portions of the Central and Eastern Gulf of Mexico, and
Alaska. In combination, those actions prohibited drilling along the Atlantic
and Pacific coasts, in the eastern Gulf of Mexico, and in portions of the
central Gulf of Mexico. The Gulf of Mexico Energy Security Act of 2006
(Public Law 109-432) imposed yet a third ban on drilling through 2022 on
tracts in the Eastern Gulf of Mexico that are within 125 miles of Florida,
east of a dividing line known as the Military Mission Line, and in the
Central Gulf of Mexico within 100 miles of Florida.
High oil and natural gas prices in recent years have affected policy toward
oil and gas exploration and development of the OCS. On July 14, 2008, President
Bush lifted the executive ban; and on September 30, 2008, Congress allowed
the congressional ban to expire. Although the ban through 2022 on areas
in the Eastern and Central Gulf of Mexico remains in place, lifting the
executive and congressional bans removed key obstacles to development of
the Atlantic and Pacific OCS.
Jurisdiction
The Submerged Lands Act (SLA) passed by Congress in 1953 established the
Federal Government’s title to submerged lands located on most of the OCS
[12]. States were given jurisdiction over any natural resources within
3.45 miles (3 nautical miles) of the coastline, with the exception of Texas
and the west coast of Florida, where the SLA extends the States’ jurisdiction
to 10.35 miles (9 nautical miles). The Outer Continental Shelf Lands Act
(OCSLA), also passed in 1953, defined the OCS, separate from geologic definitions,
as any submerged land outside State jurisdiction [13]. It also reaffirmed
Federal jurisdiction over those waters and all resources therein. Further,
it outlined Federal responsibilities for managing and maintaining offshore
lands and authorized the Department of the Interior to formulate regulations
pertaining to the leasing process and to lease the defined areas for exploration
and development of OCS oil and natural gas resources.
The Coastal Zone Management Act of 1972 (CZMA) [14] gave States more input
on activities in waters under Federal jurisdiction that affected their
coastlines, encouraged coastal States to develop Coastal Zone Management
Plans, and required State review of Federal actions, such as offshore leasing,
that affect land and water use in their coastal areas. By virtue of the
CZMA, States have the power to object to any Federal action that they deem
inconsistent with their Coastal Zone Management Plan. At present, the vast
majority of the U.S. coastline is covered by such plans.
MMS 5-Year Leasing Program
The OCSLA was amended in 1978 to establish specific leasing guidelines,
which included the development of a 5-year leasing program. The purpose
of the leasing program is to schedule all specified and proposed lease
sales within a given 5-year period. The amendment also specifies a number
of requirements on which the decision to include specific areas in the
5-year leasing program are to be based, including:
- Adequate information regarding the environmental, social, and economic
effects of exploration and development in the area offered for lease must
be considered, with no new leasing taking place if this information is
not available.
- The timing and location of leasing must be based on geographic, geologic,
and ecological characteristics of the region as well as location-specific
risks, energy needs, laws, and stakeholder interests.
- The decisionmakers must seek balance between potential damage to the environment
and coastal areas and potential energy supply.
- Areas with the greatest resource potential should have greater priority
for development, particularly in areas where earlier development has proven
a rich resource base.
For every 5-year leasing program, the MMS publishes a comprehensive document
detailing the information and reasoning behind the leasing decisions. If
a block is not included in the current 5-year leasing program, it may not
be leased during the program. The first 5-year leasing program covered
the period from 1980 to 1985; the current program covers the period from
2007 to 2012.
In anticipation of the possible lifting of the congressional moratorium
after President Bush had lifted the executive moratorium, the MMS began
initial steps toward the development of a new 5-year leasing program that
would take into consideration the newly released areas. Development of
the new program, which would go into effect in 2010 rather than 2012 as previously
planned, began on August 1, 2008. Although its action would advance the
start date for the next leasing plan by 2 years, the MMS cautioned that
the development of a new 5-year leasing program remains a multi-step, multi-year
process that includes three separate public comment periods, two separate
draft proposals, and development of an environmental impact statement before
completion of the final proposal. The final proposal must then be approved
by the Secretary of the Interior. The MMS has indicated that a new 5-year
leasing program could not go into effect until mid-2010, which would be
the earliest that any block in the areas previously under moratoria could
be offered for lease.
Leasing, Exploration, and Development
Once the 5-year leasing program is in place, the first lease sale can be
offered. The actual leasing process will take 1 to 2 years, requiring preparation
of draft and final environmental impact statements, periods of public comment,
notices regarding the sale, approval from the governors of States bordering
the area covered by the lease as mandated by the CZMA, a bidding period,
the receipt and evaluation of bids, and the determination of winning bidders
for each block offered for sale.
Successful bidders cannot simply begin operations when they have obtained
a lease. An exploration plan must be developed and filed and must undergo
technical and environmental review by the MMS before any drilling can commence.
Only after obtaining the required approvals can the lease holder evaluate
the area and conduct exploratory drilling, which can take from 1 to 3 years
in the shallow offshore and up to 6 years in the deep offshore areas. When
an initial discovery is made, a development plan must be filed for technical
and environmental review by the MMS before any production can begin. Developmental
drilling, along with necessary approvals, can take another 1 to 3 years.
For major facilities, the MMS conducts on-site inspections, sometimes jointly
with the U.S. Coast Guard, before production is allowed to begin. Air emissions
permits and water discharge permits must also be obtained from the EPA.
Thus, the total time required to obtain a lease, explore and develop the
area, and begin actual production is between 4 and 12 years, or potentially
more.
Revenue
Once awarded a lease, the lease holder pays a one-time fee plus annual
rent for the right to develop the resources in the block. In addition,
lease holders pay royalties to the MMS based on the value of any natural
gas and oil actually produced. MMS, in turn, disburses the revenues to
the appropriate Federal or State agencies. The amounts collected and distributed
by the MMS in bonuses, rents, and royalties from Federal offshore oil and
gas leases totaled $7.0 billion in fiscal year 2007 and $8.1 billion in
fiscal year 2008 [15].
Under OCSLA, coastal States are entitled to 27 percent of the revenue from
leases of any blocks in Federal waters that fall partially within 3 miles
of the State’s seaward jurisdictional boundary [16], a provision intended
to compensate the States for any damage to or drainage from natural gas
and oil resources in State waters that are adjacent to Federal leases.
Between 1986 and 2003, coastal States received more than $3.1 billion in
revenue from such leases [17].
In addition to the revenues defined by OCSLA, EPACT2005 allocated additional
revenues to the States through the establishment of a new coastal impact
assistance program that provides $250 million from OCS revenues per year
for fiscal years 2007 to 2010 to six energy-producing coastal States: Alabama,
Alaska, California, Louisiana, Mississippi, and Texas [18]. The Gulf of
Mexico Energy Security Act of 2006 includes additional revenue-sharing
provisions (for Alabama, Louisiana, Mississippi, and Texas and their coastal
political subdivisions) for specific leases in the Central and Eastern
Gulf of Mexico.
Future Directions
Considerable uncertainty still surrounds the issue of offshore drilling
in previously restricted areas. Although the congressional moratorium was
allowed to expire, some members of Congress have stated publicly that they
will raise the issue again in 2009. They are joined by a number of groups
and individuals who favor the moratorium and predict that it will be reinstated
either partially or fully by the next Congress. Until further action is
taken, however, the Atlantic and Pacific coasts are available to be leased,
and offshore drilling in those areas could become a reality.
The key issue in developing the OCS is timing. A minimum of 4 years will
be required before production from any new leases can begin, and many leases
will require longer lead times. In addition, there is considerable uncertainty
about the actual size of oil and natural gas resources in areas that have
been or remain under moratorium. The actual level of technically recoverable
resources also may differ from the current MMS mean resource estimate of
approximately 14 billion barrels of oil and 85 trillion cubic feet of natural
gas in the Atlantic and Pacific areas that were just opened for leasing.
An estimated additional 3.7 billion barrels of oil and 21 trillion cubic
feet of natural gas in the central and eastern Gulf of Mexico remain under
moratorium through 2022 [19].
Loan Guarantee Program Established in EPACT2005
Title XVII of EPACT2005 [20] authorized DOE to issue loan guarantees to
new or improved technology projects that avoid, reduce, or sequester GHGs.
In 2006, DOE issued its first solicitation for $4 billion in loan guarantees
for non-nuclear technologies. The issue of the size of the program was
addressed subsequently in the Consolidated Appropriation Act of 2008 (the
“FY08 Appropriations Act”) passed in December 2008, which limited future
solicitations to $38.5 billion and stated that authority to make the guarantees
would end on September 30, 2009. The legislation also allocated the $38.5
billion cap as follows: $18.5 billion for nuclear plants; $6 billion for
CCS technologies; $2 billion for advanced coal gasification units; $2 billion
for “advanced nuclear facilities for the ‘front end’ of the nuclear fuel
cycle”; and $10 billion for renewable, conservation, distributed energy,
and transmission/ distribution technologies. DOE also was required to submit
all future solicitations to both the House and Senate Appropriations Committees
for approval [21].
DOE received all necessary approvals from Congress in the summer of 2008
and on June 30, 2008, issued two additional solicitations—one for nuclear
plants and another for renewable, conservation, distributed energy, and
transmission/distribution technologies [22, 23]. Another solicitation,
for advanced fossil fuel technologies, was issued on September 22, 2008
[24].
Even before it issued its 2008 solicitations, DOE had requested that Congress
extend its authority to provide loan guarantees, originally set to expire
at the end of fiscal year 2009, for an additional 2 years. As of November
2008, Congress had not acted on the request. Also, DOE’s budget request
for fiscal year 2009 indicated that only $2.2 billion in loan guarantees
from the 2006 solicitation would be issued during that fiscal year. It
is not clear what will happen to the rest of the program if DOE’s loan
guarantee authority expires as originally scheduled. AEO2009 includes only
the effects of the 2006 solicitation, which is assumed to result in the
construction of 1.2 gigawatts of capacity at advanced coal-fired power
plants and 250 megawatts at solar power plants [25].
Provisions of additional loan guarantees pursuant to the solicitations
issued in 2008 could have a further effect on the projections, depending
on whether the guarantees support projects that were already included in
the AEO2009 projections. For example, in October 2008 DOE received applications
from 17 private and public power companies for 21 nuclear units (14 plants
with a total of 28.8 gigawatts of capacity) in response to the nuclear
solicitation [26]. In total, the utilities requested $122 billion in guarantees
against total projected construction and financing costs of about $188
billion, suggesting that the $18.5 billion in the FY08 Appropriations Act
could cover about 4.4 gigawatts of new nuclear capacity. AEO2009 projects
additions of 13 gigawatts of new nuclear capacity between 2000 and 2030.
Clean Air Mercury Rule
On February 8, 2008, a three-judge panel on the D.C. Circuit of the U.S.
Court of Appeals issued a decision to vacate CAMR [27]. In its ruling,
the panel cited the history of hazardous air pollutant regulation under
Section 112 of the Clean Air Act (CAA) [28]. Section 112, as written by
Congress, listed emitted mercury as a hazardous air pollutant that must
be subject to regulation unless it can be proved harmless to public welfare
and the environment. In 2000, the EPA ruled that mercury was indeed hazardous
and must be regulated under Section 112 and, therefore, subjected to the
best available control technology for mitigation.
CAMR was promulgated under Section 111 of the CAA, which allows for the
use of a cap-and-trade approach rather than implementation of best available
control technology. The EPA had delisted mercury from Section 112 without
making the necessary findings to show that mercury emissions could be regulated
under Section 111 without harming human health or the environment. The
panel stated that the EPA overstepped its authority by ignoring Congressional
guidelines and the agency’s own earlier findings.
With the elimination of CAMR, there is no Federal mandate to regulate mercury
emissions. Even before the rule was vacated, however, many States were
adopting more stringent regulations that were allowed through an EPA waiver.
Most of those regulations called for the application of best available
control technology on all electricity generating units of a certain capacity.
After the court’s decision, more States imposed their own regulations.
At the time AEO2009 was published, roughly one-half of the States, including
most of those in the Northeast, had their own mercury mitigation laws in
place. Without Federal monitoring requirements, however, some of the States
that had previously passed regulations may have to make modest modifications
in their guidelines. At present, electricity generating units in States
without mercury laws are free to emit without limitations. Because the
State laws differ, a rough estimate was created that generalized the various
State programs into a format that could be used in NEMS, including a rough
estimate of mercury emissions within each State. Moreover, the regulatory
environment is extremely fluid, with many States planning to enact new
laws or make their existing laws more stringent.
Clean Air Interstate Rule
CAIR is a cap-and-trade program promulgated by the EPA in 2005, covering
28 eastern U.S. States and the District of Columbia [29]. It was designed
to reduce sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions in order
to help States meet their National Ambient Air Quality Standards (NAAQS)
for ozone and particulate matter (PM2.5) and to further emissions reductions
already achieved through the Acid Rain Program and the NOx State Implementation
Plan call program. The rule was set to commence in 2009 for seasonal and
annual NOx emissions and in 2010 for SO2 emissions.
On July 11, 2008, the U.S. District Court of Appeals court unanimously
overturned CAIR, ruling that it could not be implemented under the CAA
[30]. Electric utilities were caught off guard by the court’s decision
to vacate CAIR. Because the rule was less than 2 years away from implementation,
many power plant owners already had spent billions of dollars on pollution
control equipment [31]. In addition, many States were relying on reductions
from CAIR to meet their NAAQS for PM2.5 and ozone, and without the rule
they might not be able to meet those requirements. The price of seasonal
NOx and SO2 emissions allowances dropped significantly after the decision.
The value of SO2 allowances has fallen by 75 percent in 2008, and because
there is no market for annual NOx emissions allowances without CAIR, their
price has dropped to zero.
Several actions are pending. On September 24, 2008, the U.S. Department
of Justice (DOJ) and the EPA, along with several industry representatives
and environmental groups, filed petitions in the Court of Appeals asking
for the case to be reheard [32]. In the petition, the DOJ claimed that
the statement in the court’s decisions that CAIR was “fundamentally flawed”
was incorrect. It also claimed that vacating CAIR could potentially “result
in serious harms.” The court is considering their petition. On October 21,
2008, the court asked for briefs from the main plaintiffs in the case,
specifically asking whether they thought CAIR should be reinstated on an
interim basis until updated regulations are issued [33]. This development
raises the possibility that such a reinstatement could occur.
On December 23, 2008, the Court of Appeals issued a new ruling that remanded
but did not vacate CAIR, noting that: “Allowing CAIR to remain in effect
until it is replaced by a rule consistent with our opinion would at least
temporarily preserve the environmental values” [34]. The change allows
the EPA to modify CAIR to address the objections raised by the Court in
its earlier decisions while leaving the rule in place. Because the ruling
came well after the cutoff date for changes in Federal and State laws and
regulation to be included in AEO2009, it is not reflected in the projections.
Nonetheless, States still are required to meet their NAAQS, which will
require emissions reductions. Therefore, it is assumed that all emissions
limits in effect under CAIR remain in effect in the AEO2009 reference case,
but without the CAIR allowance trading provisions.
State Appliance Standards
State appliance standards have existed for decades, starting with California’s
enforcement of minimum efficiency requirements for refrigerators and several
other products in 1979. In 1987, recognizing that different efficiency
standards for the same products in different States could create problems
for manufacturers, Congress enacted the National Appliance Energy Conservation
Act (NAECA), which initially covered 12 products. The Energy Policy Act
of 1992 (EPACT92), EPACT2005, and EISA2007 added additional residential
and commercial products to the 12 products originally specified under NAECA.
Many different State appliance standards still exist today (Table 2); however,
a key point of NAECA was to enforce Federal preemption of any State appliance
standard. The preemption clause allows States to continue to mandate standards
for products not covered by Federal law and to enforce standards that might
have existed before Federal coverage, up to the date of Federal enforcement.
Because most major appliances are covered by Federal law, the majority
of State standards target less energy-intensive products. Most of the standards
for products listed in Table 2 will be preempted by Federal standards within
the next decade. For example, the California standard for general-service
lighting will be preempted in 2012 by the Federal standard for general-service
lighting required in EISA2007. States can petition DOE for a waiver to
continue to enforce their own standards, as opposed to a less strict Federal
standard. To date, however, no waivers have been granted.
The NEMS residential and commercial modules represent Federal appliance
standards for all major appliances covered under NAECA and subsequent legislation.
For products not explicitly covered in NEMS (residential dehumidifiers,
for example), an off-line estimate of the impact of the standard is included
in the projections by way of deducting the savings estimates from the projections
without the standards included. Given that the NEMS buildings modules are
specified at the Census Division level, State standards are not readily
amenable to direct modeling in NEMS. Furthermore, the paucity of data at
the State level does not allow for a direct accounting of equipment stock
or energy usage, which is needed to estimate energy savings. Although NEMS
does not represent State appliance standards explicitly, recent trends
in energy intensity are taken into account in the projections and should
represent recent State appliance efficiency standards to the extent that
they affect future energy demand in the buildings sectors.
California’s Move Toward E10
In AEO2009, E10—a gasoline blend containing 10 percent ethanol—is assumed
to be the maximum ethanol blend allowed in California RFG, as opposed to
the 5.7-percent blend assumed in earlier AEOs. The 5.7-percent blend had
reflected decisions made when California decided to phase out use of the
additive methyl tertiary butyl ether in its RFG program in 2003, opting
instead to use ethanol in the minimum amount that would meet the requirement
for 2.0 percent oxygen content under the CAA provisions in effect at that
time [35].
Recently, there has been a push in California to increase the use of ethanol,
for two reasons. First, the RFS mandate in EISA2007 Title II, Subtitle
A [36], requires greater use of renewable fuels, such as ethanol. Second,
California’s Low Carbon Fuel Standard (LCFS) mandates a reduction in the
State’s overall GHG emissions to 1990 levels by 2020 and require a 10-percent
reduction in GHG emissions from passenger vehicles by 2020. Although fuel
providers can use a variety of strategies to produce lower carbon fuel,
increasing the ethanol blends from 5.7 percent to 10 percent is thought
to be a first step toward achieving the LCFS goals. In fact, in October
2008, CARB released its first draft of the LCFS regulatory framework [37].
The calculation in the framework assumes that the baseline emissions for
gasoline in 2010 (from which CO2 emissions must be reduced in later years)
will be from E10 (California RFG with 10 percent ethanol content), implying
that most, if not all, gasoline sold in California by 2010 will be E10.
Modifications were made to California’s RFG regulations and the predictive
model that estimates emissions for different fuel mixes in order to increase
ethanol blends above 5.7 percent. The predictive model was revised to accommodate
the higher ethanol blends in determining evaporative and exhaust emissions,
providing the information needed by fuel providers to increase ethanol
content. For example, the increased ethanol content will result in higher
NOx emissions, and the increase must be mitigated by lowering the fuel’s
sulfur content.
Refineries in California may have to make substantial modifications to
produce compliant fuel under the new standards (most significantly, producing
fuel with only 5 parts per million sulfur), and all fuel sold in California
must be compliant with the new CARB Phase 3 standards after December 31,
2009. The final approved modifications in CARB Phase 3 gasoline and the
revisions in the predictive model provide refiners and importers of fuel
a formal framework with which to provide compliant fuel. Already, at least
one major refiner has stated that it will apply the amended CARB Phase
3 gasoline standards, presumably to increase ethanol content.
State Renewable Energy Requirements and Goals: Update Through 2008
State RPS programs continue to play an important role in AEO2009, growing
in number while existing programs are modified with more stringent targets.
In total, 28 States and the District of Columbia now have mandatory RPS
programs (Table 3), and at least 4 other States have voluntary renewable
energy programs. In the absence of a Federal renewable electricity standard,
each State determines its own levels of generation, eligible technologies,
and noncompliance penalties. The growth in State renewable energy requirements
has led to an expansion of renewable energy credit (REC) markets, which
vary from State to State. Credit prices depend on the State renewable requirements
and how easily they can be met.
In the AEO2009 reference case, most States are projected to meet their
RPS targets. California is an exception, as a result of limits on State
funding for renewable projects. Therefore, for California, the cost of
achieving each target increment is estimated, and the amount of renewable
capacity that exhausts the renewable funding is assumed to be built. Renewable
generation in most regions is approximated, because NEMS is not a State-level
model, and each State represents only a portion of one of the NEMS regions.
Compliance costs in each region are tracked, and the projection for total
renewable generation is adjusted as needed to be consistent with the individual
State provisions.
In 2008, three States (Michigan, Missouri, and Ohio) enacted new renewable
legislation, and three others (Delaware, Maryland, and Massachusetts) modified
existing legislation. Missouri’s new RPS was approved by voters in the
November 2008 election. In California, voters rejected two propositions
that would have strengthened the State RPS. One would have increased the
renewable requirement to 50 percent of electricity generated by 2025 and
allowed for the use of a 20-year feed-in tariff [38]; the other would have
established a $5 billion fund to support renewable electricity generation
and transportation projects. The propositions were not supported by many
environmentalists, who saw them as poorly written and potentially causing
harm to the renewable industry. Both were defeated easily.
Michigan. Public Act 295 [39] established Michigan’s first RPS. Signed
into law in October 2008, the Act requires that all electricity suppliers
generate 10 percent of their electricity from renewable sources by 2015.
There are also intermediate benchmarks. Each supplier has its own standard,
based on current levels of renewable generation. Coal-fired plants that sequester
at least 85 percent of their emissions also qualify toward the target,
as do all renewable technologies except new hydroelectric facilities; however,
improvements on existing hydroelectric facilities will receive energy credits.
Like most programs, Michigan’s RPS will use RECs to promote compliance.
Bonus credits are given to solar generators as well as facilities using
in-State labor and manufactured equipment [40]. Up to 10 percent of the
total requirement may be met through energy optimization and advanced system
credits, which lower electricity demand.
Missouri. On November 4, 2008, voters approved Proposition C [41], changing
Missouri’s renewable goal into an enforceable mandate. The requirement
goes into effect in 2011 with a 2-percent renewable target, which increases
in four phases to reach the final 15-percent target by 2021. REC trading
will be used, with in-State renewable generation eligible for 1.25 REC
for each megawatthour of electricity generated. A small percentage of the
overall renewable requirement must be met through solar generation. Suppliers
subject to the RPS are required to offer their retail costumers a rebate
of $2.00 per installed watt of small-scale solar systems.
Ohio. In May 2008, Ohio enacted legislation [42] that requires most retail
electricity providers to produce 25 percent of their electricity from alternative
energy resources by 2025. Alternatives are defined as low-carbon technologies,
including nuclear energy and coal with carbon sequestration. Plants that
come on line after 1998 are considered eligible toward meeting the target.
Within the 25-percent requirement is a separate provision that increases
the required renewable share of annual generation from 0.25 percent in 2009
to 12.5 percent in 2024. There are also energy efficiency and load-reducing
requirements. Municipal and cooperative suppliers are exempt from all provisions.
REC trading is expected to help Ohio achieve its requirements. The REC
prices will be capped at $45 per megawatthour, with more severe penalties
incurred if the solar requirement is not met; however, there is also a
provision that exempts suppliers from the mandates if they can show that
they would incur incremental costs 3 percent above the total cost of a
conventional alternative. Suppliers exempted from the annual requirement
may have to meet stiffer compensatory targets in subsequent years.
Delaware. Senate Bill 328 [43] amended Delaware’s existing RPS by awarding
offshore wind 3.5 times as many credits as are received by conventional
renewable technologies toward meeting the mandate. Analysis has shown that
this provision makes offshore wind development economical under business-as-usual
assumptions.
Maryland. House Bill 375 [44] increased the State’s renewable energy requirement
to 20 percent of total generation by 2022. The requirement must be met
with resources classified in the legislation as “tier 1,” which include
all renewable forms of generation except existing large hydroelectric facilities.
Senate Bill 348 [45], also enacted in 2008, expanded the definition of
tier 1 resources to include “poultry litter-to-energy” facilities. Also
included in the tier 1 resource target is a solar energy mandate that increases
annually until it reaches 2 percent in 2022. Smaller amounts of electricity
generated from tier 2 resources (large hydropower facilities) are included
until 2019.
Along with its increased mandatory target, House Bill 375 includes higher
compliance caps. A shortfall in renewable generation from tier 1 resources
other than solar energy will cost a supplier 4 cents per kilowatthour.
If it can be shown, however, that achieving the target would cost more
than one-tenth of the supplier’s total energy sales, the target may be
deferred until the next year (an “off-ramp” that was added with the higher
compliance caps in House Bill 375). Penalties for solar shortfalls are
much larger, 45 cents per kilowatthour in the initial shortfall year, but
they decrease by 5 cents annually until they reach and remain at 5 cents
per kilowatthour beginning in 2023. Funds generated from the penalties
will go to an energy investment fund for support of renewable energy technology
advancement and deployment.
Massachusetts. The State RPS requirements are modeled through 2014 in AEO2009.
Electricity suppliers in Massachusetts are required to increase their annual
renewable generation from 4 percent of total generation in 2009 to 9 percent
in 2014. The State DOER has the option of extending the 1-percent annual
increase through 2020. Renewable requirements beyond 2014 are not assumed
in AEO2009. In December 2008, the DOER enacted regulations establishing
a target of 15 percent renewable generation by 2020, with the presumption
of increasing the target thereafter. AEO2009 is based on regulations in
effect as of November 2008 and does not include the new target.
Updated State Air Emissions Regulations
Regional Greenhouse Gas Initiative
In September 2008, the first U.S. mandatory auction of CO2 emission permits
occurred among six States in the Northeast that are part of the Regional
Greenhouse Gas Initiative (RGGI). The RGGI program includes 10 Northeastern
States that have agreed to curtail and reverse growth in CO2 emissions.
It covers all electricity generating units with a capacity of at least
25 megawatts and requires them to hold an allowance for each ton of CO2 emitted [46].
The first year of mandatory compliance is 2009 and each State’s CO2 “carbon
budget” already has been determined. The budgets consist of historically
based baselines with a cushion for emissions growth, so that meeting the
cap is expected to be relatively easy initially and become more difficult
over time. Overall, the RGGI region must maintain emissions of 188 million
tons CO2 for the next 5 years, followed by a mandatory 2.5-percent annual
decrease through 2018, when the CO2 emissions level should be 10 percent
below the initial calculated budget. The requirements are expected to cover
95 percent of CO2 emissions from the region’s electric power sector. Each
State has its own emissions budget, and the allowances will be auctioned
at a uniform price across the entire region.
Before the first auction, several rules were agreed to by the States:
- Auctions will be held quarterly, following a single- round, sealed-bid
format.
- Allowances will be sold at a uniform price, which is the highest price
of the rejected bids.
- States may hold a small number of allowances for their own use; however,
most States have decided to auction all their allowances.
- Each emitter must buy one allowance for every ton of CO2 emitted.
- Future allowances will be made available for purchase up to 4 years before
their official vintage date, as a way to control price fluctuations.
- A reserve price of $1.86 per allowance in real dollars will be in effect
for each auction, as a way to preserve allowance prices in auctions where
demand is low and to avoid collusion among emitters that could threaten
a fair market.
- The revenue from the auctions can be spent at the State’s discretion, although
at least 25 percent must go to a fund that benefits consumers and promotes
low-carbon energy development.
In the first auction, the six participating States (Connecticut, Maine,
Maryland, Massachusetts, Rhode Island, and Vermont) sold 12,600,000 allowances
at a price of $3.07 per allowance [47]. The next auction, held in December
2008, included the original six States along with New York, New Jersey,
New Hampshire, and Delaware. Issues such as emission leakage [48], which
is especially relevant in the Mid-Atlantic region, have been studied, but
no specific solutions have been implemented.
RGGI is included in the AEO2009 reference case. The effect is minimal in
the early years, given the relatively generous emissions budget. Because
it is difficult to capture the nuances of State initiatives in NEMS, which
is a regional model, independent estimates were made for the Mid-Atlantic
region to determine eligible generation facilities and their emissions
caps (for Pennsylvania, an observing member that it is not participating
in the cap-and-trade program and is not subject to any mandatory reductions,
emissions are not restricted).
Western Climate Initiative
Developed independently of RGGI, the Western Climate Initiative (WCI) [49]
is also a regional GHG reduction program. Participants in the WCI include
seven U.S. States (Arizona, California, Montana, New Mexico, Oregon, Utah,
and Washington) and four Canadian Provinces, with additional observer States
and provinces in the United States, Canada, and Mexico.
The WCI seeks to reduce GHG emissions to levels 15 percent below 2005 emissions
by 2020. Reductions will be achieved through an allowance cap-and-trade
program, and each participating State or province will be able to determine
its own allowance allocation method. Allowances will be based on a regionally
agreed emissions estimate, likely taking into account some growth in GHG
emissions through the first year of mandatory compliance in 2012. Although
each jurisdiction will choose the specifics of allowance distribution,
a minimum of 10 percent of allowances must be auctioned in 2012, and the
requirement rises in subsequent years. In the initial compliance year,
electricity generators and large industrial facilities in the WCI region,
as well as outside facilities with energy products consumed in the region,
will be required to provide one allowance for each ton of CO2 equivalent
released into the atmosphere.
WCI is similar to RGGI, but they also have important differences. Although
the first phase of the WCI program (2012 to 2015) will not cover emissions
from fossil fuels used in smaller facilities or in mobile sources,
all fuels are expected to be covered by 2015, including those used in the
transportation, industrial, and residential sectors (none of which is covered
by RGGI in any period). All fuels will be regulated upstream at the distributor
level. The 2015 cap will grow above the first phase cap, which covers only
facilities emitting more than 10,000 tons CO2 equivalent annually. Those
sources will continue to be covered after the inclusion of combustion fuels,
but the emissions will not be counted twice. Larger stationary facilities
will be regulated at the emission source, and their fuels will not be subject
to upstream regulation. Mandatory emissions monitoring of the stationary
sources will begin in January 2010.
Another distinction is that the WCI will account for nitrous oxide, methane,
hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride, not just
CO2 as in RGGI. The additional GHGs will be measured in terms of their
CO2-equivalent global warming potentials, and allowances will be issued
accordingly. WCI documents estimate that 90 percent of the region’s GHG
emissions will be subject to regulation after additional combustion fuels
are included in 2015.
Although no final caps have been determined, the permissible GHG ceiling
will decline over the program, which currently ends in 2020. No formal
determination of how to continue the program beyond 2020 has been made.
In order to control the price of allowances, a reserve price will be set
as the floor. Up to 49 percent of emissions reductions may occur through
offset programs such as forestation and agriculture reform. The list of
qualifying offsets remains to be determined but must be agreed on by all
participants. There are still some details to be worked out between the
WCI and the individual jurisdictions within the region that have their
own GHG mitigation laws. Two prime examples are California, which has passed
its own GHG legislation, and British Columbia, which is mitigating emissions
through a tax. The issues will be addressed after the specifics of the
program have been determined.
Unlike RGGI, the WCI is not included in the AEO2009 reference case, because
the WCI model rules were released after November 2008. Similarly, the Midwestern
Climate Initiative, which is in a preliminary stage, is not included in AEO2009. Regional and State GHG initiatives continue to evolve rapidly,
and it is likely that AEO2010 will include additional programs. Legislation and Regulations End Notes |
