consultation with the Technical Advisory Committee 
established under subsection (j), the Secretary, and 
the Director of the National Energy Technology Lab-
oratory to obtain advice and recommendations on 
plans, programs, and project selection criteria, the 
Board shall establish priorities for grants, contracts, 
and assistance; publish requests for proposals for 
grants, contracts, and assistance; and award grants, 
contracts, and assistance competitively, on the basis 
of merit, after the establishment of procedures that 
provide for scientific peer review by the Technical Ad-
visory Committee. The Board shall give preference to 
applications that reflect the best overall value and 
prospect for achieving the purposes of the section, such 
as those which demonstrate an integrated approach 
for capture and storage or capture and conversion 
technologies. The Board members shall not participate 
in making grants or awards to entities with whom 
they are affiliated. 
(6) USES OF GRANTS, CONTRACTS, AND ASSIST-
ANCE.—A grant, contract, or other assistance pro-
vided under this subsection may be used to purchase 
carbon dioxide when needed to conduct tests of carbon 
dioxide storage sites, in the case of established projects 
that are storing carbon dioxide emissions, or for other 
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purposes consistent with the purposes of this section. 
The Corporation shall make publicly available at no 
cost information learned as a result of projects which 
it supports financially. 
(7) INTELLECTUAL PROPERTY.—The Board shall 
establish policies regarding the ownership of intellec-
tual property developed as a result of Corporation 
grants and other forms of technology support. Such 
policies shall encourage individual ingenuity and in-
vention. 
(8) ADMINISTRATIVE EXPENSES.—Up to 5 per-
cent of the funds collected in any fiscal year under 
subsection (d) may be used for the administrative ex-
penses of operating the Corporation (not including 
costs incurred in the determination and collection of 
the assessments pursuant to subsection (d)). 
(9) PROGRAMS AND BUDGET.—Before August 1 
each year, the Corporation, after consulting with the 
Technical Advisory Committee and the Secretary and 
the Director of the Department’s National Energy 
Technology Laboratory and other interested parties to 
obtain advice and recommendations, shall publish for 
public review and comment its proposed plans, pro-
grams, project selection criteria, and projects to be 
funded by the Corporation for the next calendar year. 
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The Corporation shall also publish for public review 
and comment a budget plan for the next calendar 
year, including the probable costs of all programs, 
projects, and contracts and a recommended rate of as-
sessment sufficient to cover such costs. The Secretary 
may recommend programs and activities the Sec-
retary considers appropriate. The Corporation shall 
include in the first publication it issues under this 
paragraph a strategic plan or roadmap for the 
achievement of the purposes of the Corporation, as set 
forth in paragraph (2). 
(10) RECORDS; AUDITS.—The Corporation shall 
keep minutes, books, and records that clearly reflect 
all of the acts and transactions of the Corporation 
and make public such information. The books of the 
Corporation shall be audited by a certified public ac-
countant at least once each fiscal year and at such 
other times as the Corporation may designate. Copies 
of each audit shall be provided to the Congress, all 
Corporation board members, all qualified industry or-
ganizations, each State regulatory authority and, 
upon request, to other members of the industry. If the 
audit determines that the Corporation’s practices fail 
to meet generally accepted accounting principles the 
assessment collection authority of the Corporation 
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under subsection (d) shall be suspended until a cer-
tified public accountant renders a subsequent opinion 
that the failure has been corrected. The Corporation 
shall make its books and records available for review 
by the Secretary or the Comptroller General of the 
United States. 
(11) PUBLIC ACCESS.—The Corporation Board’s 
meetings shall be open to the public and shall occur 
after at least 30 days advance public notice. Meetings 
of the Board of Directors may be closed to the public 
where the agenda of such meetings includes only con-
fidential matters pertaining to project selection, the 
award of grants or contracts, personnel matters, or 
the receipt of legal advice. The minutes of all meetings 
of the Corporation shall be made available to and 
readily accessible by the public. 
(12) ANNUAL REPORT.—Each year the Corpora-
tion shall prepare and make publicly available a re-
port which includes an identification and description 
of all programs and projects undertaken by the Cor-
poration during the previous year. The report shall 
also detail the allocation or planned allocation of Cor-
poration resources for each such program and project. 
The Corporation shall provide its annual report to 
the Congress, the Secretary, each State regulatory au-
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thority, and upon request to the public. The Secretary 
shall, not less than 60 days after receiving such re-
port, provide to the President and Congress a report 
assessing the progress of the Corporation in meeting 
the objectives of this section. 
(d) ASSESSMENTS.— 
(1) AMOUNT.—(A) In all calendar years fol-
lowing its establishment, the Corporation shall collect 
an assessment on distribution utilities for all fossil 
fuel-based electricity delivered directly to retail con-
sumers (as determined under subsection (f)). The as-
sessments shall reflect the relative carbon dioxide 
emission rates of different fossil fuel-based electricity, 
and initially shall be not less than the following 
amounts for coal, natural gas, and oil: 
Fuel type 
Rate of assessment 
per kilowatt hour 
Coal ........................................................................
$0.00043 
Natural Gas ..........................................................
$0.00022 
Oil ..........................................................................
$0.00032. 
(B) The Corporation is authorized to adjust the 
assessments on fossil fuel-based electricity to reflect 
changes in the expected quantities of such electricity 
from different fuel types, such that the assessments 
generate not less than $1.0 billion and not more than 
$1.1 billion annually. The Corporation is authorized 
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to supplement assessments through additional finan-
cial commitments. 
(2) INVESTMENT OF FUNDS.—Pending disburse-
ment pursuant to a program, plan, or project, the 
Corporation may invest funds collected through as-
sessments under this subsection, and any other funds 
received by the Corporation, only in obligations of the 
United States or any agency thereof, in general obli-
gations of any State or any political subdivision 
thereof, in any interest-bearing account or certificate 
of deposit of a bank that is a member of the Federal 
Reserve System, or in obligations fully guaranteed as 
to principal and interest by the United States. 
(3) REVERSION OF UNUSED FUNDS.—If the Cor-
poration does not disburse, dedicate or assign 75 per-
cent or more of the available proceeds of the assessed 
fees in any calendar year 7 or more years following 
its establishment, due to an absence of qualified 
projects or similar circumstances, it shall reimburse 
the remaining undedicated or unassigned balance of 
such fees, less administrative and other expenses au-
thorized by this section, to the distribution utilities 
upon which such fees were assessed, in proportion to 
their collected assessments. 
(e) ERCOT.— 
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(1) ASSESSMENT, 
COLLECTION, 
AND
REMIT-
TANCE.—(A) Notwithstanding any other provision of 
this section, within ERCOT, the assessment provided 
for in subsection (d) shall be— 
(i) levied directly on qualified scheduling 
entities, or their successor entities; 
(ii) charged consistent with other charges 
imposed on qualified scheduling entities as a fee 
on energy used by the load-serving entities; and 
(iii) collected and remitted by ERCOT to 
the Corporation in the amounts and in the same 
manner as set forth in subsection (d). 
(B) The assessment amounts referred to in sub-
paragraph (A) shall be— 
(i) determined by the amount and types of 
fossil fuel-based electricity delivered directly to 
all retail customers in the prior calendar year 
beginning with the year ending immediately 
prior to the period described in subsection (b)(2); 
and 
(ii) take into account the number of renew-
able energy credits retired by the load-serving en-
tities represented by a qualified scheduling entity 
within the prior calendar year. 
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(2) ADMINISTRATION EXPENSES.—Up to 1 per-
cent of the funds collected in any fiscal year by 
ERCOT under the provisions of this subsection may 
be used for the administrative expenses incurred in 
the determination, collection and remittance of the as-
sessments to the Corporation. 
(3) AUDIT.—ERCOT shall provide a copy of its 
annual audit pertaining to the administration of the 
provisions of this subsection to the Corporation. 
(4) DEFINITIONS.—For the purposes of this sub-
section: 
(A) The term ‘‘ERCOT’’ means the Electric 
Reliability Council of Texas. 
(B) The term ‘‘load-serving entities’’ has the 
meaning adopted by ERCOT Protocols and in 
effect on the date of enactment of this Act. 
(C) The term ‘‘qualified scheduling entities’’ 
has the meaning adopted by ERCOT Protocols 
and in effect on the date of enactment of this 
Act. 
(D) The term ‘‘renewable energy credit’’ has 
the meaning as promulgated and adopted by the 
Public Utility Commission of Texas pursuant to 
section 39.904(b) of the Public Utility Regu-
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latory Act of 1999, and in effect on the date of 
enactment of this Act. 
(f) DETERMINATION OF FOSSIL FUEL-BASED ELEC-
TRICITY DELIVERIES.— 
(1) FINDINGS.—The Congress finds that: 
(A) The assessments under subsection (d) 
are to be collected based on the amount of fossil 
fuel-based electricity delivered by each distribu-
tion utility. 
(B) Since many distribution utilities pur-
chase all or part of their retail consumer’s elec-
tricity needs from other entities, it may not be 
practical to determine the precise fuel mix for 
the power sold by each individual distribution 
utility. 
(C) It may be necessary to use average 
data, often on a regional basis with reference to 
Regional Transmission Organization (‘‘RTO’’) 
or NERC regions, to make the determinations 
necessary for making assessments. 
(2) DOE PROPOSED RULE.—The Secretary, act-
ing in close consultation with the Energy Information 
Administration, shall issue for notice and comment a 
proposed rule to determine the level of fossil fuel elec-
tricity delivered to retail customers by each distribu-
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tion utility in the United States during the most re-
cent calendar year or other period determined to be 
most appropriate. Such proposed rule shall balance 
the need to be efficient, reasonably precise, and time-
ly, taking into account the nature and cost of data 
currently available and the nature of markets and 
regulation in effect in various regions of the country. 
Different methodologies may be applied in different 
regions if appropriate to obtain the best balance of 
such factors. 
(3) FINAL RULE.—Within 6 months after the 
date of enactment of this Act, and after opportunity 
for comment, the Secretary shall issue a final rule 
under this subsection for determining the level and 
type of fossil fuel-based electricity delivered to retail 
customers by each distribution utility in the United 
States during the appropriate period. In issuing such 
rule, the Secretary may consider opportunities and 
costs to develop new data sources in the future and 
issue recommendations for the Energy Information 
Administration or other entities to collect such data. 
After notice and opportunity for comment the Sec-
retary may, by rule, subsequently update and modify 
the methodology for making such determinations. 
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(4) ANNUAL DETERMINATIONS.—Pursuant to the 
final rule issued under paragraph (3), the Secretary 
shall make annual determinations of the amounts and 
types for each such utility and publish such deter-
minations in the Federal Register. Such determina-
tions shall be used to conduct the referendum under 
subsection (b) and by the Corporation in applying 
any assessment under this subsection. 
(5) REHEARING
AND
JUDICIAL
REVIEW.—The 
owner or operator of any distribution utility that be-
lieves that the Secretary has misapplied the method-
ology in the final rule in determining the amount 
and types of fossil fuel electricity delivered by such 
distribution utility may seek rehearing of such deter-
mination within 30 days of publication of the deter-
mination in the Federal Register. The Secretary shall 
decide such rehearing petitions within 30 days. The 
Secretary’s determinations following rehearing shall 
be final and subject to judicial review in the United 
States Court of Appeals for the District of Columbia. 
(g) 
COMPLIANCE
WITH
CORPORATION
ASSESS-
MENTS.—The Corporation may bring an action in the ap-
propriate court of the United States to compel compliance 
with an assessment levied by the Corporation under this 
section. A successful action for compliance under this sub-
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section may also require payment by the defendant of the 
costs incurred by the Corporation in bringing such action. 
(h) MIDCOURSE REVIEW.—Not later than 5 years fol-
lowing establishment of the Corporation, the Comptroller 
General of the United States shall prepare an analysis, and 
report to Congress, assessing the Corporation’s activities, 
including project selection and methods of disbursement of 
assessed fees, impacts on the prospects for commercializa-
tion of carbon capture and storage technologies, adequacy 
of funding, and administration of funds. The report shall 
also make such recommendations as may be appropriate in 
each of these areas. The Corporation shall reimburse the 
Government Accountability Office for the costs associated 
with performing this midcourse review. 
(i) RECOVERY OF COSTS.— 
(1) IN GENERAL.—A distribution utility whose 
transmission, delivery, or sales of electric energy are 
subject to any form of rate regulation shall not be de-
nied the opportunity to recover the full amount of the 
prudently incurred costs associated with complying 
with this section, consistent with applicable State or 
Federal law. 
(2) RATEPAYER REBATES.—Regulatory authori-
ties that approve cost recovery pursuant to paragraph 
(1) may order rebates to ratepayers to the extent that 
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distribution utilities are reimbursed undedicated or 
unassigned balances pursuant to subsection (d)(3). 
(j) TECHNICAL ADVISORY COMMITTEE.— 
(1) ESTABLISHMENT.—There is established an 
advisory committee, to be known as the ‘‘Technical 
Advisory Committee’’. 
(2) 
MEMBERSHIP.—The 
Technical 
Advisory 
Committee shall be comprised of not less than 7 mem-
bers appointed by the Board from among academic 
institutions, national laboratories, independent re-
search institutions, and other qualified institutions. 
No member of the Committee shall be affiliated with 
EPRI or with any organization having members serv-
ing on the Board. At least one member of the Com-
mittee shall be appointed from among officers or em-
ployees of the Department of Energy recommended to 
the Board by the Secretary of Energy. 
(3) CHAIRPERSON AND VICE CHAIRPERSON.—The 
Board shall designate one member of the Technical 
Advisory Committee to serve as Chairperson of the 
Committee and one to serve as Vice Chairperson of 
the Committee. 
(4) COMPENSATION.—The Board shall provide 
compensation to members of the Technical Advisory 
Committee for travel and other incidental expenses 
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and such other compensation as the Board determines 
to be necessary. 
(5) PURPOSE.—The Technical Advisory Com-
mittee shall provide independent assessments and 
technical evaluations, as well as make non-binding 
recommendations to the Board, concerning Corpora-
tion activities, including but not limited to the fol-
lowing: 
(A) Reviewing and evaluating the Corpora-
tion’s plans and budgets described in subsection 
(c)(9), as well as any other appropriate areas, 
which could include approaches to prioritizing 
technologies, appropriateness of engineering tech-
niques, monitoring and verification technologies 
for storage, geological site selection, and cost con-
trol measures. 
(B) 
Making 
annual 
non-binding 
rec-
ommendations to the Board concerning any of 
the matters referred to in subparagraph (A), as 
well as what types of investments, scientific re-
search, or engineering practices would best fur-
ther the goals of the Corporation. 
(6) PUBLIC AVAILABILITY.—All reports, evalua-
tions, and other materials of the Technical Advisory 
Committee shall be made available to the public by 
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the Board, without charge, at time of receipt by the 
Board. 
(k) LOBBYING RESTRICTIONS.—No funds collected by 
the Corporation shall be used in any manner for influ-
encing legislation or elections, except that the Corporation 
may recommend to the Secretary and the Congress changes 
in this section or other statutes that would further the pur-
poses of this section. 
(l) DAVIS-BACON
COMPLIANCE.—The Corporation 
shall ensure that entities receiving grants, contracts, or 
other financial support from the Corporation for the project 
activities authorized by this section are in compliance with 
the Davis-Bacon Act (40 U.S.C. 276a–276a–5). 
SEC. 115. COMMERCIAL DEPLOYMENT OF CARBON CAPTURE 
AND SEQUESTRATION TECHNOLOGIES. 
Part H of title VII of the Clean Air Act (as added 
by section 321 of this Act) is amended by adding the fol-
lowing new section after section 785: 
‘‘SEC. 786. COMMERCIAL DEPLOYMENT OF CARBON CAP-
TURE AND SEQUESTRATION TECHNOLOGIES. 
‘‘(a) REGULATIONS.—Not later than 2 years after the 
date of enactment of this title, the Administrator shall pro-
mulgate regulations providing for the distribution of emis-
sion allowances allocated pursuant to section 782(f), pursu-
ant to the requirements of this section, to support the com-
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mercial deployment of carbon capture and sequestration 
technologies in both electric power generation and indus-
trial operations. 
‘‘(b) ELIGIBILITY CRITERIA.—To be eligible to receive 
emission allowances under this section, the owner or oper-
ator of a project must— 
‘‘(1) implement carbon capture and sequestration 
technology— 
‘‘(A) at an electric generating unit that— 
‘‘(i) has a nameplate capacity of 200 
megawatts or more; 
‘‘(ii) in the case of a retrofit applica-
tion, applies the carbon capture and seques-
tration technology to the flue gas from at 
least 200 megawatts of the total nameplate 
generating capacity of the unit, provided 
that clause (i) shall apply without excep-
tion; 
‘‘(iii) derives at least 50 percent of its 
annual fuel input from coal, petroleum 
coke, or any combination of these 2 fuels; 
and 
‘‘(iv) upon implementation of capture 
and sequestration technology, will achieve 
an emission limit that is at least a 50 per-
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‘‘(2) geologically sequester carbon dioxide at a 
site that meets all applicable permitting and certifi-
cation requirements for geologic sequestration, or, 
pursuant to such requirements as the Administrator 
may prescribe by regulation, convert captured carbon 
dioxide to a stable form that will safely and perma-
nently sequester such carbon dioxide; 
‘‘(3) meet all other applicable State and Federal 
permitting requirements; and 
‘‘(4) be located in the United States. 
‘‘(c) PHASE I DISTRIBUTION TO ELECTRIC GENER-
ATING UNITS.— 
‘‘(1) APPLICATION.—This subsection shall apply 
only to projects at the first 6 gigawatts of electric gen-
erating units, measured in cumulative generating ca-
pacity of such units. 
‘‘(2) DISTRIBUTION.—The Administrator shall 
distribute emission allowances allocated under section 
782(f) to the owner or operator of each eligible project 
at an electric generating unit in a quantity equal to 
the quotient obtained by dividing— 
‘‘(A) the product obtained by multiplying— 
‘‘(i) the number of metric tons of car-
bon dioxide emissions avoided through cap-
ture and sequestration of emissions by the 
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project, as determined pursuant to such 
methodology as the Administrator shall pre-
scribe by regulation; and 
‘‘(ii) a bonus allowance value, pursu-
ant to paragraph (3); by 
‘‘(B) the average fair market value of an 
emission allowance during the preceding year. 
‘‘(3) BONUS ALLOWANCE VALUES.— 
‘‘(A) For a generating unit achieving the 
capture and sequestration of 85 percent or more 
of the carbon dioxide that otherwise would be 
emitted by such unit, the bonus allowance value 
shall be $90. 
‘‘(B) The Administrator shall by regulation 
establish a bonus allowance value for each rate 
of lower capture and sequestration achieved by a 
generating unit, from a minimum of $50 per ton 
for a 50 percent rate and varying directly with 
increasing rates of capture and sequestration up 
to $90 per ton for an 85 percent rate. 
‘‘(C) For a generating unit that achieves the 
capture and sequestration of at least 50 percent 
of the carbon dioxide that otherwise would be 
emitted by such unit by not later than January 
1, 2017, the otherwise applicable bonus allow-
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ance value under this paragraph shall be in-
creased by $10, provided that the owner of such 
unit notifies the Administrator of its intent to 
achieve such rate of capture and sequestration by 
not later than January 1, 2012. 
‘‘(D) For a carbon capture and sequestra-
tion project sequestering in a geological forma-
tion for purposes of enhanced hydrocarbon recov-
ery, the Administrator shall, by regulation, re-
duce the applicable bonus allowance value under 
this paragraph to reflect the lower net cost of the 
project when compared to sequestration into geo-
logical formations solely for purposes of seques-
tration. 
‘‘(E) All monetary values in this section 
shall be adjusted annually for inflation. 
‘‘(d) PHASE II DISTRIBUTION TO ELECTRIC GENER-
ATING UNITS.— 
‘‘(1) APPLICATION.—This subsection shall apply 
only to the distribution of emission allowances to car-
bon capture and sequestration projects at electric gen-
erating units after the capacity threshold identified in 
subsection (c)(1) is reached. 
‘‘(2) REGULATIONS.—Not later than 2 years 
prior to the date on which the capacity threshold 
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identified in subsection (c)(1) is projected to be 
reached, the Administrator shall promulgate regula-
tions to govern the distribution of emission allowances 
to the owners or operators of eligible projects under 
this subsection. 
‘‘(3) REVERSE AUCTIONS.— 
‘‘(A) IN GENERAL.—Except as provided in 
paragraph (4), the regulations promulgated 
under paragraph (2) shall provide for the dis-
tribution of emission allowances to the owners or 
operators of eligible projects under this sub-
section through reverse auctions, which shall be 
held no less frequently than once each calendar 
year. The Administrator may establish a sepa-
rate auction for each of no more than 5 different 
project categories, defined on the basis of coal 
type, capture technology, geological formation 
type, new unit versus retrofit application, such 
other factors as the Administrator may prescribe, 
or any combination thereof. The Administrator 
may establish appropriate minimum rates of 
capture and sequestration in implementing this 
paragraph. 
‘‘(B) AUCTION PROCESS.—At each reverse 
auction— 
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‘‘(i) the Administrator shall solicit bids 
from eligible projects; 
‘‘(ii) eligible projects participating in 
the auction shall submit a bid including the 
desired level of carbon dioxide sequestration 
incentive per ton and the estimated quan-
tity of carbon dioxide that the project will 
permanently sequester over 10 years; and 
‘‘(iii) the Administrator shall select 
bids, within each auction, for the sequestra-
tion amount submitted, beginning with the 
eligible project submitting the bid for the 
lowest level of sequestration incentive on a 
per ton basis and meeting such other re-
quirements as the Administrator may speci-
fy, until the amount of funds available for 
the reverse auction is committed. 
‘‘(C) FORM OF DISTRIBUTION.—The Admin-
istrator shall provide deployment incentives to 
the owners or operators of eligible projects se-
lected through a reverse auction under this para-
graph pursuant to a formula equivalent to that 
described in subsection (c)(2), except that the in-
centive level that is bid by the entity shall be 
substituted for the bonus allowance value. 
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‘‘(4) ALTERNATIVE DISTRIBUTION METHOD.— 
‘‘(A) IN
GENERAL.—If the Administrator 
determines that reverse auctions would not pro-
vide for efficient and cost-effective commercial 
deployment of carbon capture and sequestration 
technologies, the Administrator may instead, 
through regulations promulgated under para-
graph (2) or (5), prescribe a schedule for the 
award of bonus allowances to the owners or oper-
ators of eligible projects under this subsection, in 
accordance with the requirements of this para-
graph. 
‘‘(B) MULTIPLE TRANCHES.—The Adminis-
trator shall divide emission allowances available 
for distribution to the owners or operators of eli-
gible projects into a series of tranches, each sup-
porting the deployment of a specified quantity of 
cumulative electric generating capacity utilizing 
carbon capture and sequestration technology, 
each of which shall not be greater than 6 
gigawatts. 
‘‘(C) METHOD OF DISTRIBUTION.—The Ad-
ministrator shall distribute emission allowances 
within each tranche, on a first-come, first-served 
basis— 
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‘‘(i) based on the date of full-scale op-
eration of capture and sequestration tech-
nology; and 
‘‘(ii) pursuant to a formula, similar to 
that set forth in subsection (c)(2) (except 
that the Administrator shall prescribe bonus 
allowance values different than those set 
forth in subsection (c)(2)), establishing the 
number of allowances to be distributed per 
ton of carbon dioxide sequestered by the 
project. 
‘‘(D) REQUIREMENTS.—For each tranche 
established pursuant to subparagraph (A), the 
Administrator shall establish a schedule for dis-
tributing emission allowances that— 
‘‘(i) is based on a sliding scale that 
provides higher bonus allowance values for 
projects achieving higher rates of capture 
and sequestration; 
‘‘(ii) for each capture and sequestra-
tion rate, establishes a bonus allowance 
value that is lower than that established for 
such rate in the previous tranche (or, in the 
case of the first tranche, than that estab-
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lished for such rate under subsection (c)(3)); 
and 
‘‘(iii) may establish different bonus al-
lowance levels for no more than 5 different 
project categories, defined by coal type, cap-
ture technology, geological formation type, 
new unit versus retrofit application, such 
other factors as the Administrator may pre-
scribe, or any combination thereof. 
‘‘(E) CRITERIA FOR ESTABLISHING BONUS 
ALLOWANCE
VALUES.—In setting bonus allow-
ance values under this paragraph, the Adminis-
trator shall seek to cover no more than the rea-
sonable incremental capital and operating costs 
of a project that are attributable to implementa-
tion of carbon capture, transportation, and se-
questration technologies, taking into account— 
‘‘(i) the reduced cost of compliance 
with section 722 of this Act; 
‘‘(ii) the reduced cost associated with 
sequestering in a geological formation for 
purposes of enhanced hydrocarbon recovery 
when compared to sequestration into geo-
logical formations solely for purposes of se-
questration; 
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‘‘(iii) the relevant factors defining the 
project category; and 
‘‘(iv) such other factors as the Admin-
istrator determines are appropriate. 
‘‘(5) REVISION OF REGULATIONS.—The Adminis-
trator shall review, and as appropriate revise, the ap-
plicable regulations under this subsection no less fre-
quently than every 8 years. 
‘‘(e) LIMITS
FOR CERTAIN ELECTRIC GENERATING 
UNITS.— 
‘‘(1) DEFINITIONS.—For purposes of this sub-
section, the terms ‘covered EGU’ and ‘initially per-
mitted’ shall have the meaning given those terms in 
section 812 of this Act. 
‘‘(2) COVERED
EGUS
INITIALLY
PERMITTED 
FROM 2009 THROUGH 2014.—For a covered EGU that 
is initially permitted on or after January 1, 2009, 
and before January 1, 2015, the Administrator shall 
reduce the quantity of emission allowances that the 
owner or operator of such covered EGU would other-
wise be eligible to receive under this section as follows: 
‘‘(A) In the case of a unit commencing oper-
ation on or before January 1, 2019, if the date 
in clause (ii)(I) is earlier than the date in clause 
(ii)(II), by the product of— 
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‘‘(i) 20 percent; and 
‘‘(ii) the number of years, if any, that 
have elapsed between— 
‘‘(I) the earlier of January 1, 
2020, or the date that is 5 years after 
the commencement of operation of such 
covered EGU; and 
‘‘(II) the first year that such cov-
ered EGU achieves (and thereafter 
maintains) an emission limit that is 
at least a 50 percent reduction in 
emissions of the carbon dioxide pro-
duced by the unit, measured on an an-
nual basis, as determined in accord-
ance with section 812(b)(2). 
‘‘(B) In the case of a unit commencing op-
eration after January 1, 2019, by the product 
of— 
‘‘(i) 20 percent; and 
‘‘(ii) the number of years between— 
‘‘(I) the commencement of oper-
ation of such covered EGU; and 
‘‘(II) the first year that such cov-
ered EGU achieves (and thereafter 
maintains) an emission limit that is 
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at least a 50 percent reduction in 
emissions of the carbon dioxide pro-
duced by the unit, measured on an an-
nual basis, as determined in accord-
ance with section 812(b)(2). 
‘‘(3) COVERED
EGUS
INITIALLY
PERMITTED 
FROM 2015 THROUGH 2019.—The owner or operator of 
a covered EGU that is initially permitted on or after 
January 1, 2015, and before January 1, 2020, shall 
be ineligible to receive emission allowances pursuant 
to this section if such unit, upon commencement of 
operations (and thereafter), does not achieve and 
maintain an emission limit that is at least a 50 per-
cent reduction in emissions of the carbon dioxide pro-
duced by the unit, measured on an annual basis, as 
determined in accordance with section 812(b)(2). 
‘‘(f) INDUSTRIAL SOURCES.— 
‘‘(1) ALLOWANCES.—The Administrator may 
distribute not more than 15 percent of the allowances 
allocated under section 782(a) for any vintage year to 
the owners or operators of eligible industrial sources 
to support the commercial-scale deployment of carbon 
capture and sequestration technologies at such 
sources. 
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‘‘(2) DISTRIBUTION.—The Administrator shall, 
by regulation, prescribe requirements for the distribu-
tion of emission allowances to the owners or operators 
of industrial sources under this subsection, based on 
a bonus allowance formula that awards allowances to 
qualifying projects on the basis of tons of carbon diox-
ide captured and permanently sequestered. The Ad-
ministrator may provide for the distribution of emis-
sion allowances pursuant to— 
‘‘(A) a reverse auction method, similar to 
that described under subsection (d)(3), including 
the use of separate auctions for different project 
categories; or 
‘‘(B) an incentive schedule, similar to that 
described under subsection (d)(4), which shall en-
sure that incentives are set so as to satisfy the 
requirement described in subsection (d)(4)(E). 
‘‘(3) REVISION OF REGULATIONS.—The Adminis-
trator shall review, and as appropriate revise, the ap-
plicable regulations under this subsection no less fre-
quently than every 8 years. 
‘‘(g) LIMITATIONS.—Allowances may be distributed 
under this section only for tons of carbon dioxide emissions 
that have already been captured and sequestered. A quali-
fying project may receive annual emission allowances under 
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this section only for the first 10 years of operation. No 
greater than 72 gigawatts of total cumulative generating 
capacity (including industrial applications, measured by 
such equivalent metric as the Administrator may designate) 
may receive emission allowances under this section. Upon 
reaching the limit described in the preceding sentence, any 
emission allowances that are allocated for carbon capture 
and sequestration deployment under section 782(f) and are 
not yet obligated under this section shall be treated as allow-
ances not designated for distribution for purposes of section 
782(r). 
‘‘(h) EXHAUSTION OF ACCOUNT AND ANNUAL ROLL- 
OVER OF SURPLUS ALLOWANCES.— 
‘‘(1) In distributing bonus allowances under this 
subsection, the Administrator shall ensure that quali-
fying projects receiving allowances receive distribu-
tions for 10 years. 
‘‘(2) If the Administrator determines that the al-
lowances allocated under section 782(f) with a vintage 
year that matches the year of distribution will be ex-
hausted once the estimated full 10-year distributions 
will be provided to current eligible participants, the 
Administrator shall provide to new eligible projects 
allowances from vintage years after the year of the 
distribution. 
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‘‘(i) RETROFIT APPLICATIONS.—(1) In calculating 
bonus allowance values for retrofit applications eligible 
under subsections (b)(1)(A)(ii) and (b)(1)(A)(iv)(II), the 
Administrator shall apply the required capture rates with 
respect to the treated portion of flue gas from the unit. 
‘‘(2) No additional projects shall be eligible for allow-
ances under subsections (b)(1)(A)(ii) and (b)(1)(A)(iv)(II) 
as of such time as the Administrator reports, pursuant to 
section 812(d), that carbon capture and sequestration ret-
rofit projects at electric generating units that are eligible 
for allowances under this section have been applied, in the 
aggregate, to the flue gas generated by 1 gigawatt of total 
cumulative generating capacity. 
‘‘(j) DAVIS-BACON COMPLIANCE.—All laborers and 
mechanics employed on projects funded directly by or as-
sisted in whole or in part by this section through the use 
of bonus allowances shall be paid wages at rates not less 
than those prevailing on projects of a character similar in 
the locality as determined by the Secretary of Labor in ac-
cordance with subchapter IV, chapter 31, part A of subtitle 
II of title 40, United States Code. With respect to the labor 
standards specified in this section, the Secretary of Labor 
shall have the authority and functions set forth in Reorga-
nization Plan Numbered 14 of 1950 (64 Stat. 1267; 5 
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U.S.C. App.) and section 3145 of title 40, United States 
Code.’’. 
SEC. 116. PERFORMANCE STANDARDS FOR COAL-FUELED 
POWER PLANTS. 
(a) IN GENERAL.—Title VIII of the Clean Air Act (as 
added by section 331 of this Act) is amended by adding 
the following new section after section 811: 
‘‘SEC. 812. PERFORMANCE STANDARDS FOR NEW COAL- 
FIRED POWER PLANTS. 
‘‘(a) DEFINITIONS.—For purposes of this section: 
‘‘(1) COVERED EGU.—The term ‘covered EGU’ 
means a utility unit that is required to have a permit 
under section 503(a) and is authorized under state or 
federal law to derive at least 30 percent of its annual 
heat input from coal, petroleum coke, or any com-
bination of these fuels. 
‘‘(2) INITIALLY PERMITTED.—The term ‘initially 
permitted’ means that the owner or operator has re-
ceived a Clean Air Act preconstruction approval or 
permit, for the covered EGU as a new (not a modi-
fied) source, but administrative review or appeal of 
such approval or permit has not been exhausted. A 
subsequent modification of any such approval or per-
mits, ongoing administrative or court review, ap-
peals, or challenges, or the existence or tolling of any 
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time to pursue further review, appeals, or challenges 
shall not affect the date on which a covered EGU is 
considered to be initially permitted under this para-
graph. 
‘‘(b) STANDARDS.—(1) A covered EGU that is initially 
permitted on or after January 1, 2020, shall achieve an 
emission limit that is a 65 percent reduction in emissions 
of the carbon dioxide
produced by the
unit, as measured 
on an annual basis, or meet such more stringent standard 
as the Administrator may establish pursuant to subsection 
(c). 
‘‘(2) A covered EGU that is initially permitted after 
January 1, 2009, and before January 1, 2020, shall, by 
the applicable compliance date established under this para-
graph, achieve an emission limit that is a 50 percent reduc-
tion in emissions of the carbon dioxide produced by the
unit, as measured on an annual basis. Compliance with 
the requirement set forth in this paragraph shall be required 
by the earliest of the following: 
‘‘(A) Four years after the date the Administrator 
has published pursuant to subsection (d) a report that 
there are in commercial operation in the United 
States electric generating units or other stationary 
sources equipped with carbon capture and sequestra-
tion technology that, in the aggregate— 
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‘‘(i) have a total of at least 4 gigawatts of 
nameplate generating capacity of which— 
‘‘(I) at least 3 gigawatts must be elec-
tric generating units; and 
‘‘(II) up to 1 gigawatt may be indus-
trial applications, for which capture and se-
questration of 3 million tons of carbon diox-
ide per year on an aggregate annualized 
basis shall be considered equivalent to 1 
gigawatt; 
‘‘(ii) include at least 2 electric generating 
units, each with a nameplate generating capac-
ity of 250 megawatts or greater, that capture, 
inject, and sequester carbon dioxide into geologic 
formations other than oil and gas fields; and 
‘‘(iii) are capturing and sequestering in the 
aggregate at least 12 million tons of carbon diox-
ide per year, calculated on an aggregate 
annualized basis. 
‘‘(B) January 1, 2025. 
‘‘(3) If the deadline for compliance with paragraph (2) 
is January 1, 2025, the Administrator may extend the 
deadline for compliance by a covered EGU by up to 18 
months if the Administrator makes a determination, based 
on a showing by the owner or operator of the unit, that 
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it will be technically infeasible for the unit to meet the 
standard by the deadline. The owner or operator must sub-
mit a request for such an extension by no later than Janu-
ary 1, 2022, and the Administrator shall provide for public 
notice and comment on the extension request. 
‘‘(c) REVIEW
AND REVISION
OF STANDARDS.—Not 
later than 2025 and at 5-year intervals thereafter, the Ad-
ministrator shall review the standards for new covered 
EGUs under this section and shall, by rule, reduce the max-
imum carbon dioxide emission rate for new covered EGUs 
to a rate which reflects the degree of emission limitation 
achievable through the application of the best system of 
emission reduction which (taking into account the cost of 
achieving such reduction and any nonair quality health 
and environmental impact and energy requirements) the 
Administrator determines has been adequately dem-
onstrated. 
‘‘(d) REPORTS.—Not later than the date 18 months 
after the date of enactment of this title and semiannually 
thereafter, the Administrator shall publish a report on the 
nameplate capacity of units (determined pursuant to sub-
section (b)(2)(A)) in commercial operation in the United 
States equipped with carbon capture and sequestration 
technology, including the information described in sub-
section (b)(2)(A) (including the cumulative generating ca-
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pacity to which carbon capture and sequestration retrofit 
projects 
meeting 
the 
criteria 
described 
in 
section 
786(b)(1)(A)(ii) and (b)(1)(A)(iv)(II) has been applied and 
the quantities of carbon dioxide captured and sequestered 
by such projects). 
‘‘(e) REGULATIONS.—Not later than 2 years after the 
date of enactment of this title, the Administrator shall pro-
mulgate regulations to carry out the requirements of this 
section.’’. 
Subtitle C—Clean Transportation 
SEC. 121. ELECTRIC VEHICLE INFRASTRUCTURE. 
(a) AMENDMENT OF PURPA.—Section 111(d) of the 
Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 
2621(d)) is amended by adding at the end the following: 
‘‘(20) PLUG-IN ELECTRIC DRIVE VEHICLE INFRA-
STRUCTURE.— 
‘‘(A) UTILITY
PLAN
FOR
INFRASTRUC-
TURE.—Each electric utility shall develop a plan 
to support the use of plug-in electric drive vehi-
cles, including heavy-duty hybrid electric vehi-
cles. The plan may provide for deployment of 
electrical charging stations in public or private 
locations, including street parking, parking ga-
rages, parking lots, homes, gas stations, and 
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highway rest stops. Any such plan may also in-
clude— 
‘‘(i) battery exchange, fast charging in-
frastructure and other services; 
‘‘(ii) triggers for infrastructure deploy-
ment based upon market penetration of 
plug-in electric drive vehicles; and 
‘‘(iii) such other elements as the State 
determines necessary to support plug-in 
electric drive vehicles. 
Each plan under this paragraph shall provide 
for the deployment of the charging infrastructure 
or other infrastructure necessary to adequately 
support the use of plug-in electric drive vehicles. 
‘‘(B) 
SUPPORT
REQUIREMENTS.—Each 
State regulatory authority (in the case of each 
electric utility for which it has ratemaking au-
thority) and each utility (in the case of a non-
regulated utility) shall— 
‘‘(i) require that charging infrastruc-
ture deployed is interoperable with products 
of all auto manufacturers to the extent pos-
sible; and 
‘‘(ii) consider adopting minimum re-
quirements for deployment of electrical 
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100 
charging infrastructure and other appro-
priate requirements necessary to support the 
use of plug-in electric drive vehicles. 
‘‘(C) COST
RECOVERY.—Each State regu-
latory authority (in the case of each electric util-
ity for which it has ratemaking authority) and 
each utility (in the case of a nonregulated util-
ity) shall consider whether, and to what extent, 
to allow cost recovery for plans and implementa-
tion of plans. 
‘‘(D) 
SMART
GRID
INTEGRATION.—The 
State regulatory authority (in the case of each 
electric utility for which it has ratemaking au-
thority) and each utility (in the case of a non-
regulated utility) shall, in accordance with regu-
lations issued by the Federal Energy Regulatory 
Commission pursuant to section 1305(d) of the 
Energy Independence and Security Act of 
2007— 
‘‘(i) establish any appropriate proto-
cols and standards for integrating plug-in 
electric drive vehicles into an electrical dis-
tribution system, including Smart Grid sys-
tems and devices as described in title XIII 
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101 
of the Energy Independence and Security 
Act of 2007; 
‘‘(ii) include, to the extent feasible, the 
ability for each plug-in electric drive vehicle 
to be identified individually and to be asso-
ciated with its owner’s electric utility ac-
count, regardless of the location that the ve-
hicle is plugged in, for purposes of appro-
priate billing for any electricity required to 
charge the vehicle’s batteries as well as any 
crediting for electricity provided to the elec-
tric utility from the vehicle’s batteries; and 
‘‘(iii) review the determination made 
in response to section 1252 of the Energy 
Policy Act of 2005 in light of this section, 
including 
whether 
time-of-use 
pricing 
should be employed to enable the use of 
plug-in electric drive vehicles to contribute 
to meeting peak-load and ancillary service 
power needs.’’. 
(b) COMPLIANCE.— 
(1) TIME LIMITATIONS.—Section 112(b) of the 
Public Utility Regulatory Policies Act of 1978 (16 
U.S.C. 2622(b)) is amended by adding the following 
at the end thereof: 
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102 
‘‘(7)(A) Not later than 3 years after the date of enact-
ment of this paragraph, each State regulatory authority 
(with respect to each electric utility for which it has rate-
making authority) and each nonregulated utility shall com-
mence the consideration referred to in section 111, or set 
a hearing date for consideration, with respect to the stand-
ard established by paragraph (20) of section 111(d). 
‘‘(B) Not later than 4 years after the date of enactment 
of the this paragraph, each State regulatory authority (with 
respect to each electric utility for which it has ratemaking 
authority), and each nonregulated electric utility, shall 
complete the consideration, and shall make the determina-
tion, referred to in section 111 with respect to the standard 
established by paragraph (20) of section 111(d).’’. 
(2) FAILURE TO COMPLY.—Section 112(c) of the 
Public Utility Regulatory Policies Act of 1978 (16 
U.S.C. 2622(c)) is amended by adding the following 
at the end: ‘‘In the case of the standards established 
by paragraph (20) of section 111(d), the reference 
contained in this subsection to the date of enactment 
of this Act shall be deemed to be a reference to the 
date of enactment of such paragraph.’’. 
(3) PRIOR STATE ACTIONS.—Section 112(d) of 
the Public Utility Regulatory Policies Act of 1978 (16 
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