546
RTO or ISO (as defined in the Federal Power Act), ap-
proved by the Federal Energy Regulatory Commission. 
Such contract, agreement or arrangement shall include—
(1) performance standards for operation and 
use of the transmission system that the head of the 
Federal utility determines necessary or appropriate, 
including standards that assure recovery of all the 
Federal utility’s costs and expenses related to the 
transmission facilities that are the subject of the 
contract, agreement or other arrangement; consist-
ency with existing contracts and third-party financ-
ing arrangements; and consistency with said Federal 
utility’s statutory authorities, obligations, and limi-
tations; 
(2) provisions for monitoring and oversight by 
the Federal utility of the RTO’s or ISO’s fulfillment 
of the terms and conditions of the contract, agree-
ment or other arrangement, including a provision for 
the resolution of disputes through arbitration or 
other means with the regional transmission organi-
zation or with other participants, notwithstanding 
the obligations and limitations of any other law re-
garding arbitration; and 
(3) a provision that allows the Federal utility to 
withdraw from the RTO or ISO and terminate the
547
contract, agreement or other arrangement in accord-
ance with its terms. 
Neither this section, actions taken pursuant to it, nor any 
other transaction of a Federal utility using an RTO or 
ISO shall confer upon the Federal Energy Regulatory 
Commission jurisdiction or authority over the Federal util-
ity’s electric generation assets, electric capacity or energy 
that the Federal utility is authorized by law to market, 
or the Federal utility’s power sales activities. 
(c) EXISTING STATUTORY
AND OTHER OBLIGA-
TIONS.—
(1) SYSTEM OPERATION REQUIREMENTS.—No 
statutory provision requiring or authorizing a Fed-
eral utility to transmit electric power or to construct, 
operate or maintain its transmission system shall be 
construed to prohibit a transfer of control and use 
of its transmission system pursuant to, and subject 
to all requirements of subsection (b). 
(2) OTHER
OBLIGATIONS.—This subsection 
shall not be construed to—
(A) suspend, or exempt any Federal utility 
from, any provision of existing Federal law, in-
cluding but not limited to any requirement or 
direction relating to the use of the Federal util-
ity’s transmission system, environmental protec-
548
tion, fish and wildlife protection, flood control, 
navigation, water delivery, or recreation; or 
(B) authorize abrogation of any contract 
or treaty obligation. 
(3) REPEAL.—Section 311 of title III of Appen-
dix B of the Act of October 27, 2000 (P.L. 106–
377, section 1(a)(2); 114 Stat. 1441, 1441A–80; 16 
U.S.C. 824n) is repealed. 
SEC. 1235. STANDARD MARKET DESIGN. 
(a) REMAND.—The Commission’s proposed rule-
making entitled ‘‘Remedying Undue Discrimination 
through Open Access Transmission Service and Standard 
Electricity Market Design’’ (Docket No. RM01–12–000) 
(‘‘SMD NOPR’’) is remanded to the Commission for re-
consideration. No final rule mandating a standard elec-
tricity market design pursuant to the proposed rule-
making, including any rule or order of general applica-
bility within the scope of the proposed rulemaking, may 
be issued before October 31, 2006, or take effect before 
December 31, 2006. Any final rule issued by the Commis-
sion pursuant to the proposed rulemaking shall be pre-
ceded by a second notice of proposed rulemaking issued 
after the date of enactment of this Act and an opportunity 
for public comment.
549
(b) SAVINGS CLAUSE.—This section shall not be con-
strued to modify or diminish any authority or obligation 
the Commission has under this Act, the Federal Power 
Act, or other applicable law, including, but not limited to, 
any authority to—
(1) issue any rule or order (of general or par-
ticular applicability) pursuant to any such authority 
or obligation; or 
(2) act on a filing or filings by 1 or more trans-
mitting utilities for the voluntary formation of a Re-
gional Transmission Organization or Independent 
System Operator (as defined in the Federal Power 
Act) (and related market structures or rules) or vol-
untary modification of an existing Regional Trans-
mission Organization or Independent System Oper-
ator (and related market structures or rules). 
SEC. 1236. NATIVE LOAD SERVICE OBLIGATION. 
Part II of the Federal Power Act (16 U.S.C. 824 et 
seq.) is amended by adding at the end the following: 
‘‘SEC. 217. NATIVE LOAD SERVICE OBLIGATION. 
‘‘(a) MEETING SERVICE OBLIGATIONS.—(1) Any 
load-serving entity that, as of the date of enactment of 
this section—
‘‘(A) owns generation facilities, markets the 
output of Federal generation facilities, or holds
550
rights under 1 or more wholesale contracts to pur-
chase electric energy, for the purpose of meeting a 
service obligation, and 
‘‘(B) by reason of ownership of transmission fa-
cilities, or 1 or more contracts or service agreements 
for firm transmission service, holds firm trans-
mission rights for delivery of the output of such gen-
eration facilities or such purchased energy to meet 
such service obligation, 
is entitled to use such firm transmission rights, or, equiva-
lent tradable or financial transmission rights, in order to 
deliver such output or purchased energy, or the output of 
other generating facilities or purchased energy to the ex-
tent deliverable using such rights, to the extent required 
to meet its service obligation. 
‘‘(2) To the extent that all or a portion of the service 
obligation covered by such firm transmission rights or 
equivalent tradable or financial transmission rights is 
transferred to another load-serving entity, the successor 
load-serving entity shall be entitled to use the firm trans-
mission rights or equivalent tradable or financial trans-
mission rights associated with the transferred service obli-
gation. Subsequent transfers to another load-serving enti-
ty, or back to the original load-serving entity, shall be enti-
tled to the same rights.
551
‘‘(3) The Commission shall exercise its authority 
under this Act in a manner that facilitates the planning 
and expansion of transmission facilities to meet the rea-
sonable needs of load-serving entities to satisfy their serv-
ice obligations, and enables load-serving entities to secure 
firm transmission rights (or equivalent tradable or finan-
cial rights) on a long term basis for long term power sup-
ply arrangements made, or planned, to meet such needs. 
‘‘(b) ALLOCATION
OF
TRANSMISSION
RIGHTS.—
Nothing in subsections (a)(1) and (a) (2) of this section 
shall affect any existing or future methodology employed 
by an RTO or ISO for allocating or auctioning trans-
mission rights if such RTO or ISO was authorized by the 
Commission to allocate or auction financial transmission 
rights on its system as of January 1, 2005, and the Com-
mission determines that any future allocation or auction 
is just, reasonable and not unduly discriminatory or pref-
erential, provided, however, that if such an RTO or ISO 
never allocated financial transmission rights on its system 
that pertained to a period before January 1, 2005, with 
respect to any application by such RTO or ISO that would 
change its methodology the Commission shall exercise its 
authority in a manner consistent with the Act and the 
policies expressed in subsections (a)(1) and (a)(2) as ap-
plied to firm transmission rights held by a load serving
552
entity as of January 1, 2005, to the extent the associated 
generation ownership or power purchase arrangements re-
main in effect. 
‘‘(c) CERTAIN TRANSMISSION RIGHTS.—The Com-
mission may exercise authority under this Act to make 
transmission rights not used to meet an obligation covered 
by subsection (a) available to other entities in a manner 
determined by the Commission to be just, reasonable, and 
not unduly discriminatory or preferential. 
‘‘(d) OBLIGATION TO BUILD.—Nothing in this Act 
shall relieve a load-serving entity from any obligation 
under State or local law to build transmission or distribu-
tion facilities adequate to meet its service obligations. 
‘‘(e) CONTRACTS.—Nothing in this section shall pro-
vide a basis for abrogating any contract or service agree-
ment for firm transmission service or rights in effect as 
of the date of the enactment of this subsection. If an ISO 
in the Western Interconnection had allocated financial 
transmission rights prior to the date of enactment of this 
section but had not done so with respect to one or more 
load-serving entities’ firm transmission rights held under 
contracts to which the preceding sentence applies (or held 
by reason of ownership of transmission facilities), such 
load-serving entities may not be required, without their 
consent, to convert such firm transmission rights to
553
tradable or financial rights, except where the load-serving 
entity has voluntarily joined the ISO as a participating 
transmission owner (or its successor) in accordance with 
the ISO tariff. 
‘‘(f) WATER PUMPING FACILITIES.—The Commis-
sion shall ensure that any entity described in section 
201(f) that owns transmission facilities used predomi-
nately to support its own water pumping facilities shall 
have, with respect to such facilities, protections for trans-
mission service comparable to those provided to load-serv-
ing entities pursuant to this section. 
‘‘(g) FERC RULEMAKING ON LONG-TERM TRANS-
MISSION RIGHTS IN ORGANIZED MARKETS.—Within one 
year after the date of enactment of this section and after 
notice and an opportunity for comment, the Commission 
shall by rule or order implement subsection (a)(3) in Com-
mission-approved RTOs and ISOs with organized elec-
tricity markets. 
‘‘(h) ERCOT.—This section shall not apply within 
the area referred to in section 212(k)(2)(A). 
‘‘(i) JURISDICTION.—This section does not authorize 
the Commission to take any action not otherwise within 
its jurisdiction. 
‘‘(j) EFFECT OF EXERCISING RIGHTS.—An entity 
that lawfully exercises rights granted under subsection (a)
554
shall not be considered by such action as engaging in 
undue discrimination or preference under this Act. 
‘‘(k) TVA AREA.—For purposes of subsection 
(a)(1)(B), a load-serving entity that is located within the 
service area of the Tennessee Valley Authority and that 
has a firm wholesale power supply contract with the Ten-
nessee Valley Authority shall be deemed to hold firm 
transmission rights for the transmission of such power. 
‘‘(l) DEFINITIONS.—For purposes of this section: 
‘‘(1) The term ‘distribution utility’ means an 
electric utility that has a service obligation to end-
users or to a State utility or electric cooperative 
that, directly or indirectly, through 1 or more addi-
tional State utilities or electric cooperatives, provides 
electric service to end-users. 
‘‘(2) The term ‘load-serving entity’ means a dis-
tribution utility or an electric utility that has a serv-
ice obligation. 
‘‘(3) The term ‘service obligation’ means a re-
quirement applicable to, or the exercise of authority 
granted to, an electric utility under Federal, State 
or local law or under long-term contracts to provide 
electric service to end-users or to a distribution util-
ity.
555
‘‘(4) The term ‘State utility’ means a State or 
any political subdivision of a State, or any agency, 
authority, or instrumentality of any 1 or more of the 
foregoing, or a corporation which is wholly owned, 
directly or indirectly, by any 1 or more of the fore-
going, competent to carry on the business of devel-
oping, transmitting, utilizing or distributing power’’. 
SEC. 1237. STUDY ON THE BENEFITS OF ECONOMIC DIS-
PATCH. 
(a) STUDY.—The Secretary of Energy, in coordina-
tion and consultation with the States, shall conduct a 
study on—
(1) the procedures currently used by electric 
utilities to perform economic dispatch; 
(2) identifying possible revisions to those proce-
dures to improve the ability of nonutility generation 
resources to offer their output for sale for the pur-
pose of inclusion in economic dispatch; and 
(3) the potential benefits to residential, com-
mercial, and industrial electricity consumers nation-
ally and in each state if economic dispatch proce-
dures were revised to improve the ability of non-
utility generation resources to offer their output for 
inclusion in economic dispatch.
556
(b) DEFINITION.—The term ‘‘economic dispatch’’ 
when used in this section means the operation of genera-
tion facilities to produce energy at the lowest cost to reli-
ably serve consumers, recognizing any operational limits 
of generation and transmission facilities. 
(c) REPORT TO CONGRESS AND THE STATES.—Not 
later than 90 days after the date of enactment of this Act, 
and on a yearly basis following, the Secretary of Energy 
shall submit a report to Congress and the States on the 
results of the study conducted under subsection (a), in-
cluding recommendations to Congress and the States for 
any suggested legislative or regulatory changes. 
Subtitle D—Transmission Rate 
Reform 
SEC. 1241. TRANSMISSION INFRASTRUCTURE INVESTMENT. 
Part II of the Federal Power Act (16 U.S.C. 824 et 
seq.) is amended by adding at the end the following: 
‘‘SEC. 218. TRANSMISSION INFRASTRUCTURE INVESTMENT. 
‘‘(a) RULEMAKING REQUIREMENT.—Within 1 year 
after the enactment of this section, the Commission shall 
establish, by rule, incentive-based (including, but not lim-
ited to performance-based) rate treatments for the trans-
mission of electric energy in interstate commerce by public 
utilities for the purpose of benefiting consumers by ensur-
557
ing reliability and reducing the cost of delivered power by 
reducing transmission congestion. Such rule shall—
‘‘(1) promote reliable and economically efficient 
transmission and generation of electricity by pro-
moting capital investment in the enlargement, im-
provement, maintenance and operation of facilities 
for the transmission of electric energy in interstate 
commerce; 
‘‘(2) provide a return on equity that attracts 
new investment in transmission facilities (including 
related transmission technologies); 
‘‘(3) encourage deployment of transmission 
technologies and other measures to increase the ca-
pacity and efficiency of existing transmission facili-
ties and improve the operation of such facilities; and 
‘‘(4) allow recovery of all prudently incurred 
costs necessary to comply with mandatory reliability 
standards issued pursuant to section 215 of this 
Act. 
The Commission may, from time to time, revise such rule. 
‘‘(b) ADDITIONAL INCENTIVES FOR RTO PARTICIPA-
TION.—In the rule issued under this section, the Commis-
sion shall, to the extent within its jurisdiction, provide for 
incentives to each transmitting utility or electric utility 
that joins a Regional Transmission Organization or Inde-
558
pendent System Operator. Incentives provided by the 
Commission pursuant to such rule shall include—
‘‘(1) recovery of all prudently incurred costs to 
develop and participate in any proposed or approved 
RTO, ISO, or independent transmission company; 
‘‘(2) recovery of all costs previously approved by 
a State commission which exercised jurisdiction over 
the transmission facilities prior to the utility’s par-
ticipation in the RTO or ISO, including costs nec-
essary to honor preexisting transmission service con-
tracts, in a manner which does not reduce the reve-
nues the utility receives for transmission services for 
a reasonable transition period after the utility joins 
the RTO or ISO; 
‘‘(3) recovery as an expense in rates of the 
costs prudently incurred to conduct transmission 
planning and reliability activities, including the costs 
of participating in RTO, ISO and other regional 
planning activities and design, study and other 
precertification costs involved in seeking permits and 
approvals for proposed transmission facilities; 
‘‘(4) a current return in rates for construction 
work in progress for transmission facilities and full 
recovery of prudently incurred costs for constructing 
transmission facilities;
559
‘‘(5) formula transmission rates; and 
‘‘(6) a maximum 15 year accelerated deprecia-
tion on new transmission facilities for rate treatment 
purposes. 
The Commission shall ensure that any costs recoverable 
pursuant to this subsection may be recovered by such util-
ity through the transmission rates charged by such utility 
or through the transmission rates charged by the RTO 
or ISO that provides transmission service to such utility. 
‘‘(c) JUST AND REASONABLE RATES.—All rates ap-
proved under the rules adopted pursuant to this section, 
including any revisions to such rules, are subject to the 
requirement of sections 205 and 206 that all rates, 
charges, terms, and conditions be just and reasonable and 
not unduly discriminatory or preferential.’’. 
Subtitle E—Amendments to PURPA 
SEC. 1251. NET METERING AND ADDITIONAL STANDARDS. 
(a) ADOPTION OF STANDARDS.—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 fol-
lowing: 
‘‘(11) NET
METERING.—Each electric utility 
shall make available upon request net metering serv-
ice to any electric consumer that the electric utility 
serves. For purposes of this paragraph, the term
560
‘net metering service’ means service to an electric 
consumer under which electric energy generated by 
that electric consumer from an eligible on-site gener-
ating facility and delivered to the local distribution 
facilities may be used to offset electric energy pro-
vided by the electric utility to the electric consumer 
during the applicable billing period. 
‘‘(12) FUEL
SOURCES.—Each electric utility 
shall develop a plan to minimize dependence on 1 
fuel source and to ensure that the electric energy it 
sells to consumers is generated using a diverse range 
of fuels and technologies, including renewable tech-
nologies. 
‘‘(13) 
FOSSIL
FUEL
GENERATION
EFFI-
CIENCY.—Each electric utility shall develop and im-
plement a 10-year plan to increase the efficiency of 
its fossil fuel generation.’’. 
(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 at the end 
the following: 
‘‘(3)(A) Not later than 2 years after the enactment 
of this paragraph, each State regulatory authority (with 
respect to each electric utility for which it has ratemaking
561
authority) and each nonregulated electric utility shall com-
mence the consideration referred to in section 111, or set 
a hearing date for such consideration, with respect to each 
standard established by paragraphs (11) through (13) of 
section 111(d). 
‘‘(B) Not later than 3 years after the date of the en-
actment of this paragraph, each State regulatory authority 
(with respect to each electric utility for which it has rate-
making authority), and each nonregulated electric utility, 
shall complete the consideration, and shall make the deter-
mination, referred to in section 111 with respect to each 
standard established by paragraphs (11) through (13) 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 at the 
end the following: 
‘‘In the case of each standard established by paragraphs 
(11) through (13) of section 111(d), the reference con-
tained in this subsection to the date of enactment of this 
Act shall be deemed to be a reference to the date of enact-
ment of such paragraphs (11) through (13).’’. 
(3) PRIOR STATE ACTIONS.—
(A) IN
GENERAL.—Section 112 of the 
Public Utility Regulatory Policies Act of 1978
562
(16 U.S.C. 2622) is amended by adding at the 
end the following: 
‘‘(d) PRIOR STATE ACTIONS.—Subsections (b) and 
(c) of this section shall not apply to the standards estab-
lished by paragraphs (11) through (13) of section 111(d) 
in the case of any electric utility in a State if, before the 
enactment of this subsection—
‘‘(1) the State has implemented for such utility 
the standard concerned (or a comparable standard); 
‘‘(2) the State regulatory authority for such 
State or relevant nonregulated electric utility has 
conducted a proceeding to consider implementation 
of the standard concerned (or a comparable stand-
ard) for such utility; or 
‘‘(3) the State legislature has voted on the im-
plementation of such standard (or a comparable 
standard) for such utility.’’. 
(B) CROSS REFERENCE.—Section 124 of 
such Act (16 U.S.C. 2634) is amended by add-
ing the following at the end thereof: ‘‘In the 
case of each standard established by paragraphs 
(11) through (13) of section 111(d), the ref-
erence contained in this subsection to the date 
of enactment of this Act shall be deemed to be
563
a reference to the date of enactment of such 
paragraphs (11) through (13).’’. 
SEC. 1252. SMART METERING. 
(a) IN GENERAL.—Section 111(d) of the Public Utili-
ties Regulatory Policies Act of 1978 (16 U.S.C. 2621(d)) 
is amended by adding at the end the following: 
‘‘(14) TIME-BASED
METERING
AND
COMMU-
NICATIONS.—
‘‘(A) Not later than 18 months after the 
date of enactment of this paragraph, each elec-
tric utility shall offer each of its customer class-
es, and provide individual customers upon cus-
tomer request, a time-based rate schedule under 
which the rate charged by the electric utility 
varies during different time periods and reflects 
the variance, if any, in the utility’s costs of gen-
erating and purchasing electricity at the whole-
sale level. The time-based rate schedule shall 
enable the electric consumer to manage energy 
use and cost through advanced metering and 
communications technology. 
‘‘(B) The types of time-based rate sched-
ules that may be offered under the schedule re-
ferred to in subparagraph (A) include, among 
others—
564
‘‘(i) time-of-use pricing whereby elec-
tricity prices are set for a specific time pe-
riod on an advance or forward basis, typi-
cally not changing more often than twice a 
year, based on the utility’s cost of gener-
ating and/or purchasing such electricity at 
the wholesale level for the benefit of the 
consumer. Prices paid for energy consumed 
during these periods shall be pre-estab-
lished and known to consumers in advance 
of such consumption, allowing them to 
vary their demand and usage in response 
to such prices and manage their energy 
costs by shifting usage to a lower cost pe-
riod or reducing their consumption overall; 
‘‘(ii) critical peak pricing whereby 
time-of-use prices are in effect except for 
certain peak days, when prices may reflect 
the costs of generating and/or purchasing 
electricity at the wholesale level and when 
consumers may receive additional discounts 
for reducing peak period energy consump-
tion; 
‘‘(iii) real-time pricing whereby elec-
tricity prices are set for a specific time pe-
565
riod on an advanced or forward basis, re-
flecting the utility’s cost of generating and/
or purchasing electricity at the wholesale 
level, and may change as often as hourly; 
and 
‘‘(iv) credits for consumers with large 
loads who enter into pre-established peak 
load reduction agreements that reduce a 
utility’s planned capacity obligations. 
‘‘(C) Each electric utility subject to sub-
paragraph (A) shall provide each customer re-
questing a time-based rate with a time-based 
meter capable of enabling the utility and cus-
tomer to offer and receive such rate, respec-
tively. 
‘‘(D) For purposes of implementing this 
paragraph, any reference contained in this sec-
tion to the date of enactment of the Public Util-
ity Regulatory Policies Act of 1978 shall be 
deemed to be a reference to the date of enact-
ment of this paragraph. 
‘‘(E) In a State that permits third-party 
marketers to sell electric energy to retail elec-
tric consumers, such consumers shall be entitled 
to receive the same time-based metering and
566
communications device and service as a retail 
electric consumer of the electric utility. 
‘‘(F) Notwithstanding subsections (b) and 
(c) of section 112, each State regulatory au-
thority shall, not later than 18 months after the 
date of enactment of this paragraph conduct an 
investigation in accordance with section 115(i) 
and issue a decision whether it is appropriate to 
implement the standards set out in subpara-
graphs (A) and (C).’’. 
(b) STATE INVESTIGATION OF DEMAND RESPONSE 
AND TIME-BASED METERING.—Section 115 of the Public 
Utilities Regulatory Policies Act of 1978 (16 U.S.C. 2625) 
is amended as follows: 
(1) By inserting in subsection (b) after the 
phrase ‘‘the standard for time-of-day rates estab-
lished by section 111(d)(3)’’ the following: ‘‘and the 
standard for time-based metering and communica-
tions established by section 111(d)(14)’’. 
(2) By inserting in subsection (b) after the 
phrase ‘‘are likely to exceed the metering’’ the fol-
lowing: ‘‘and communications’’. 
(3) By adding the at the end the following: 
‘‘(i) TIME-BASED
METERING
AND
COMMUNICA-
TIONS.—In making a determination with respect to the
567
standard established by section 111(d)(14), the investiga-
tion requirement of section 111(d)(14)(F) shall be as fol-
lows: Each State regulatory authority shall conduct an in-
vestigation and issue a decision whether or not it is appro-
priate for electric utilities to provide and install time-based 
meters and communications devices for each of their cus-
tomers which enable such customers to participate in time-
based pricing rate schedules and other demand response 
programs.’’. 
(c) 
FEDERAL
ASSISTANCE
ON
DEMAND
RE-
SPONSE.—Section 132(a) of the Public Utility Regulatory 
Policies Act of 1978 (16 U.S.C. 2642(a)) is amended by 
striking ‘‘and’’ at the end of paragraph (3), striking the 
period at the end of paragraph (4) and inserting ‘‘; and’’, 
and by adding the following at the end thereof: 
‘‘(5) technologies, techniques, and rate-making 
methods related to advanced metering and commu-
nications and the use of these technologies, tech-
niques and methods in demand response programs.’’. 
(d) FEDERAL GUIDANCE.—Section 132 of the Public 
Utility Regulatory Policies Act of 1978 (16 U.S.C. 2642) 
is amended by adding the following at the end thereof: 
‘‘(d) DEMAND RESPONSE.—The Secretary shall be 
responsible for—
568
‘‘(1) educating consumers on the availability, 
advantages, and benefits of advanced metering and 
communications technologies, including the funding 
of demonstration or pilot projects; 
‘‘(2) working with States, utilities, other energy 
providers and advanced metering and communica-
tions experts to identify and address barriers to the 
adoption of demand response programs; and 
‘‘(3) not later than 180 days after the date of 
enactment of the Energy Policy Act of 2005, pro-
viding Congress with a report that identifies and 
quantifies the national benefits of demand response 
and makes a recommendation on achieving specific 
levels of such benefits by January 1, 2007.’’. 
(e) DEMAND RESPONSE AND REGIONAL COORDINA-
TION.—
(1) IN GENERAL.—It is the policy of the United 
States to encourage States to coordinate, on a re-
gional basis, State energy policies to provide reliable 
and affordable demand response services to the pub-
lic. 
(2) TECHNICAL ASSISTANCE.—The Secretary of 
Energy shall provide technical assistance to States 
and regional organizations formed by 2 or more 
States to assist them in—
569
(A) identifying the areas with the greatest 
demand response potential; 
(B) identifying and resolving problems in 
transmission and distribution networks, includ-
ing through the use of demand response; 
(C) developing plans and programs to use 
demand response to respond to peak demand or 
emergency needs; and 
(D) identifying specific measures con-
sumers can take to participate in these demand 
response programs. 
(3) REPORT.—Not later than 1 year after the 
date of enactment of the Energy Policy Act of 2005, 
the Commission shall prepare and publish an annual 
report, by appropriate region, that assesses demand 
response resources, including those available from all 
consumer classes, and which identifies and reviews—
(A) saturation and penetration rate of ad-
vanced 
meters 
and 
communications 
tech-
nologies, devices and systems; 
(B) existing demand response programs 
and time-based rate programs; 
(C) the annual resource contribution of de-
mand resources;
570
(D) the potential for demand response as 
a quantifiable, reliable resource for regional 
planning purposes; 
(E) steps taken to ensure that, in regional 
transmission planning and operations, demand 
resources are provided equitable treatment as a 
quantifiable, reliable resource relative to the re-
source obligations of any load-serving entity, 
transmission provider, or transmitting party; 
and 
(F) regulatory barriers to improved cus-
tomer participation in demand response, peak 
reduction and critical period pricing programs. 
(f) FEDERAL ENCOURAGEMENT
OF DEMAND RE-
SPONSE DEVICES.—It is the policy of the United States 
that time-based pricing and other forms of demand re-
sponse, whereby electricity customers are provided with 
electricity price signals and the ability to benefit by re-
sponding to them, shall be encouraged, the deployment of 
such technology and devices that enable electricity cus-
tomers to participate in such pricing and demand response 
systems shall be facilitated, and unnecessary barriers to 
demand response participation in energy, capacity and an-
cillary service markets shall be eliminated. It is further 
the policy of the United States that the benefits of such
571
demand response that accrue to those not deploying such 
technology and devices, but who are part of the same re-
gional electricity entity, shall be recognized. 
(g) TIME LIMITATIONS.—Section 112(b) of the Pub-
lic Utility Regulatory Policies Act of 1978 (16 U.S.C. 
2622(b)) is amended by adding at the end the following: 
‘‘(4)(A) Not later than 1 year after the enact-
ment of this paragraph, each State regulatory au-
thority (with respect to each electric utility for which 
it has ratemaking authority) and each nonregulated 
electric utility shall commence the consideration re-
ferred to in section 111, or set a hearing date for 
such consideration, with respect to the standard es-
tablished by paragraph (14) of section 111(d). 
‘‘(B) Not later than 2 years after the date of 
the enactment of this paragraph, each State regu-
latory authority (with respect to each electric utility 
for which it has ratemaking authority), and each 
nonregulated electric utility, shall complete the con-
sideration, and shall make the determination, re-
ferred to in section 111 with respect to the standard 
established by paragraph (14) of section 111(d).’’. 
(h) 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 at the end the following:
572
‘‘In the case of the standard established by paragraph (14) 
of section 111(d), the reference contained in this sub-
section to the date of enactment of this Act shall be 
deemed to be a reference to the date of enactment of such 
paragraph (14).’’. 
(i) PRIOR STATE ACTIONS REGARDING SMART ME-
TERING STANDARDS.—
(1) IN GENERAL.—Section 112 of the Public 
Utility Regulatory Policies Act of 1978 (16 U.S.C. 
2622) is amended by adding at the end the fol-
lowing: 
‘‘(e) PRIOR STATE ACTIONS.—Subsections (b) and 
(c) of this section shall not apply to the standard estab-
lished by paragraph (14) of section 111(d) in the case of 
any electric utility in a State if, before the enactment of 
this subsection—
‘‘(1) the State has implemented for such utility 
the standard concerned (or a comparable standard); 
‘‘(2) the State regulatory authority for such 
State or relevant nonregulated electric utility has 
conducted a proceeding to consider implementation 
of the standard concerned (or a comparable stand-
ard) for such utility within the previous 3 years; or 
‘‘(3) the State legislature has voted on the im-
plementation of such standard (or a comparable
573
standard) for such utility within the previous 3 
years.’’. 
(2) CROSS REFERENCE.—Section 124 of such 
Act (16 U.S.C. 2634) is amended by adding the fol-
lowing at the end thereof: ‘‘In the case of the stand-
ard established by paragraph (14) of section 111(d), 
the reference contained in this subsection to the date 
of enactment of this Act shall be deemed to be a ref-
erence to the date of enactment of such paragraph 
(14).’’. 
SEC. 1253. COGENERATION AND SMALL POWER PRODUC-
TION PURCHASE AND SALE REQUIREMENTS. 
(a) TERMINATION OF MANDATORY PURCHASE AND 
SALE REQUIREMENTS.—Section 210 of the Public Utility 
Regulatory Policies Act of 1978 (16 U.S.C. 824a–3) is 
amended by adding at the end the following: 
‘‘(m) TERMINATION OF MANDATORY PURCHASE AND 
SALE REQUIREMENTS.—
‘‘(1) OBLIGATION
TO
PURCHASE.—After the 
date of enactment of this subsection, no electric util-
ity shall be required to enter into a new contract or 
obligation to purchase electric energy from a quali-
fying cogeneration facility or a qualifying small 
power production facility under this section if the 
Commission finds that the qualifying cogeneration
574
facility or qualifying small power production facility 
has nondiscriminatory access to—
‘‘(A)(i) independently administered, auc-
tion-based day ahead and real time wholesale 
markets for the sale of electric energy; and (ii) 
wholesale markets for long-term sales of capac-
ity and electric energy; or 
‘‘(B)(i) transmission and interconnection 
services that are provided by a Commission-ap-
proved regional transmission entity and admin-
istered pursuant to an open access transmission 
tariff that affords nondiscriminatory treatment 
to all customers; and (ii) competitive wholesale 
markets that provide a meaningful opportunity 
to sell capacity, including long-term and short-
term sales, and electric energy, including long-
term, short-term and real-time sales, to buyers 
other than the utility to which the qualifying fa-
cility is interconnected. In determining whether 
a meaningful opportunity to sell exists, the 
Commission shall consider, among other fac-
tors, evidence of transactions within the rel-
evant market; or 
‘‘(C) wholesale markets for the sale of ca-
pacity and electric energy that are, at a min-
575
imum, of comparable competitive quality as 
markets described in subparagraphs (A) and 
(B). 
‘‘(2) REVISED PURCHASE AND SALE OBLIGA-
TION FOR NEW FACILITIES.—(A) After the date of 
enactment of this subsection, no electric utility shall 
be required pursuant to this section to enter into a 
new contract or obligation to purchase from or sell 
electric energy to a facility that is not an existing 
qualifying cogeneration facility unless the facility 
meets the criteria for qualifying cogeneration facili-
ties established by the Commission pursuant to the 
rulemaking required by subsection (n). 
‘‘(B) For the purposes of this paragraph, the 
term ‘existing qualifying cogeneration facility’ means 
a facility that—
‘‘(i) was a qualifying cogeneration facility 
on the date of enactment of subsection (m); or 
‘‘(ii) had filed with the Commission a no-
tice of self-certification, self recertification or 
an application for Commission certification 
under 18 C.F.R. 292.207 prior to the date on 
which the Commission issues the final rule re-
quired by subsection (n).
576
‘‘(3) COMMISSION REVIEW.—Any electric utility 
may file an application with the Commission for re-
lief from the mandatory purchase obligation pursu-
ant to this subsection on a service territory-wide 
basis. Such application shall set forth the factual 
basis upon which relief is requested and describe 
why the conditions set forth in subparagraphs (A), 
(B) or (C) of paragraph (1) of this subsection have 
been met. After notice, including sufficient notice to 
potentially affected qualifying cogeneration facilities 
and qualifying small power production facilities, and 
an opportunity for comment, the Commission shall 
make a final determination within 90 days of such 
application regarding whether the conditions set 
forth in subparagraphs (A), (B) or (C) of paragraph 
(1) have been met. 
‘‘(4) REINSTATEMENT OF OBLIGATION TO PUR-
CHASE.—At any time after the Commission makes a 
finding under paragraph (3) relieving an electric 
utility of its obligation to purchase electric energy, 
a qualifying cogeneration facility, a qualifying small 
power production facility, a State agency, or any 
other affected person may apply to the Commission 
for an order reinstating the electric utility’s obliga-
tion to purchase electric energy under this section.
577
Such application shall set forth the factual basis 
upon which the application is based and describe 
why the conditions set forth in subparagraphs (A), 
(B) or (C) of paragraph (1) of this subsection are 
no longer met. After notice, including sufficient no-
tice to potentially affected utilities, and opportunity 
for comment, the Commission shall issue an order 
within 90 days of such application reinstating the 
electric utility’s obligation to purchase electric en-
ergy under this section if the Commission finds that 
the conditions set forth in subparagraphs (A), (B) or 
(C) of paragraph (1) which relieved the obligation to 
purchase, are no longer met. 
‘‘(5) OBLIGATION TO SELL.—After the date of 
enactment of this subsection, no electric utility shall 
be required to enter into a new contract or obliga-
tion to sell electric energy to a qualifying cogenera-
tion facility or a qualifying small power production 
facility under this section if the Commission finds 
that—
‘‘(A) competing retail electric suppliers are 
willing and able to sell and deliver electric en-
ergy to the qualifying cogeneration facility or 
qualifying small power production facility; and
578
‘‘(B) the electric utility is not required by 
State law to sell electric energy in its service 
territory. 
‘‘(6) NO
EFFECT
ON
EXISTING
RIGHTS
AND 
REMEDIES.—Nothing in this subsection affects the 
rights or remedies of any party under any contract 
or obligation, in effect or pending approval before 
the appropriate State regulatory authority or non-
regulated electric utility on the date of enactment of 
this subsection, to purchase electric energy or capac-
ity from or to sell electric energy or capacity to a 
qualifying cogeneration facility or qualifying small 
power production facility under this Act (including 
the right to recover costs of purchasing electric en-
ergy or capacity). 
‘‘(7) RECOVERY OF COSTS.—(A) The Commis-
sion shall issue and enforce such regulations as are 
necessary to ensure that an electric utility that pur-
chases electric energy or capacity from a qualifying 
cogeneration facility or qualifying small power pro-
duction facility in accordance with any legally en-
forceable obligation entered into or imposed under 
this section recovers all prudently incurred costs as-
sociated with the purchase.